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| 1 | WOJP2023/000734 | WOJP2023/000734|JP2023517246 | JPWO2024/150398|WO2024/150398|JP7297278 | 105528804 | WO2024/150398 A1 2024-07-18 [WO2024150398]|JPWO2024/150398 A1 2024-07-18 [JP2024150398W]|JP7297278 B1 2023-06-26 [JP7297278] | 2023-01-13 | 2023-01-13|2023-01-13 | 2024-07-18|2024-07-18|2023-06-26 | |(JP2024150398W)|2023-06-26 | (WO2024/150398)|2026-07-13|(JP7297278)|2043-01-13 | (WO2024/150398)|Green power and carbon-neutral equivalent natural gas production system using beccs | (WO2024/150398)|This system comprises: a biomass power generation device 10; a carbon dioxide recovery device 25; a device 30 for generating carbon-neutral thermal energy; and an LNG vaporization device 41. The biomass power generation device 10 produces green power, and the carbon dioxide recovery device 25 recovers carbon dioxide generated through biomass power generation. The LNG vaporization device 41 performs heat exchange between stored carbon dioxide which is part of the recovered carbon dioxide and is to be isolated from the atmosphere, and a liquefied natural gas in which the amount of carbon dioxide generated by combustion is smaller by a prescribed ratio than the amount of the stored carbon dioxide, to thereby vaporize and deliver the liquefied natural gas into a carbon-neutral equivalent natural gas, and cool the stored carbon dioxide to a low temperature. Accordingly, it is possible to produce green power, produce carbon-neutral equivalent natural gas for which emission credits can be said to already have been acquired, and cool a stored carbon dioxide to a low temperature at low cost. | EUREKA ENGINEERING | (WO2024/150398)|EUREKA ENGINEERING INC ([JP])|(JP7297278)|EUREKA ENGINEERING INC| | ITO SHINZO | (WO2024/150398)|ITO SHINZO | (WO2024/150398)|KYORITSU INTERNATIONAL ([JP])|(JP7297278)|KYORITSU INTERNATIONAL|Reg. Nb: 110000604|KOBAYASHI, Osamu|Reg. Nb: 100089082 | (JP7297278)|By simply exchanging heat in the LNG vaporizer 41 between the liquefied natural gas and the stored carbon dioxide gas such that the amount of the carbon dioxide gas supplied from the LNG feeder 40 and generated by combustion is less than the amount of the stored carbon dioxide gas by a prescribed ratio α, This makes it possible to produce natural gas equivalent to carbon neutral, which can also be said to have acquired discharge rights, and also makes it possible to cool the stored carbon dioxide to a low temperature at low cost.| | (WO2024/150398)|1. A biomass power generation device provided with: a power generator driven by a condensate turbine and sending out electric power; a boiler that combusts biomass supplied from a biomass supply device and supplies superheated steam to the condensate turbine; a condenser that condenses low-pressure steam discharged from the condensate turbine into condensed water; an absorption unit that is supplied with exhaust gas from the boiler and generates a CO2-containing absorption liquid by causing carbon dioxide gas contained in the exhaust gas to be absorbed into the absorption liquid; and a CO2-containing absorption liquid from the absorption unit The carbon dioxide recovery device is provided with: a regeneration unit to which liquid is supplied, and which heats the CO2-containing absorption liquid by means of thermal energy for regeneration and releases carbon dioxide gas; and a thermal energy supply unit for regeneration, which supplies the thermal energy delivered from a device that generates carbon neutral thermal energy to the regeneration unit as the thermal energy for regeneration. The carbon dioxide gas released by the regeneration unit is delivered as recovered carbon dioxide gas. The amount of carbon dioxide gas generated by burning is within the recovered carbon dioxide gas An LNG supply device for supplying liquefied natural gas in an amount smaller by a predetermined ratio than the amount of stored carbon dioxide; and a method for exchanging heat of cold LNG generated when the liquefied natural gas is supplied from the LNG supply device, the stored carbon dioxide is supplied from the carbon dioxide recovery device, and the liquefied natural gas is vaporized into natural gas and sent as natural gas equivalent to carbon neutrality, and the stored carbon dioxide is cooled The BECCS-based natural gas production system is equipped with an LNG vaporizer that delivers low-temperature stored carbon dioxide gas.| | (WO2024/150398)| The present invention relates to a bioenergy with carbon dioxide capture and storage (BECCS) whereby green power and the like are produced using biomass energy and carbon dioxide gas generated by biomass combustion is recovered and stored.| The purpose of the present invention is to produce green power by biomass power generation, and to produce green power and a system for producing natural gas equivalent to carbon neutrality that utilize BECCS, which are capable of producing natural gas equivalent to carbon neutrality and of cooling the stored carbon dioxide to a low temperature, by exchanging heat between stored carbon dioxide stored in the carbon dioxide generated by biomass power generation and liquefied natural gas in which the amount of carbon dioxide generated by burning is a prescribed percentage of the amount of stored carbon dioxide The purpose of the present invention is to provide. The present invention is a biomass power generation device provided with: a generator that is driven by a condensate turbine and that sends out electric power; a boiler that combusts biomass supplied from a biomass supply device and that supplies superheated steam to the condensate turbine; a condenser that condenses low-pressure steam discharged from the condensate turbine into condensed water; an absorption unit that is supplied with exhaust gas from the boiler and that generates a CO2-containing absorption liquid by causing carbon dioxide gas contained in the exhaust gas to be absorbed into the absorption liquid; and a CO from the absorption unit The carbon dioxide gas recovery device is provided with a regeneration unit to which a CO2-containing absorption liquid is supplied and which heats the CO2-containing absorption liquid by means of thermal energy for regeneration and releases carbon dioxide gas, and a regeneration thermal energy supply unit which supplies the thermal energy delivered from a device which generates carbon neutral thermal energy to the regeneration unit as the thermal energy for regeneration.| | (WO2024/150398)|BIOMASS POWER GENERATION(100,22)|GREEN POWER(100,20)|BECCS(100,18)|CONDENSATE TURBINE(100,17)|PRODUCTION SYSTEM(100,14)|CARBON NEUTRAL(100,4)|EQUIVALENT NATURAL GAS(100,2)|LNG VAPORIZATION(68,13)|REGENERATION(66,42)|LNG VAPORIZER(51,14)|COLD LNG EXCHANGING HEAT(51,1)|CARBON DIOXIDE(44,190)|BIOMASS COMBUSTION(43,1)|CARBON DIOXIDE GAS(40,46)|ADSORPTION DEHUMIDIFIER(40,1)|COLD LNG(39,1)|CO2(37,19)|BIOMASS SUPPLY(34,5)|ABSORPTION LIQUID(33,13)|BOILER(32,14)|STORED CARBON DIOXIDE(31,46)|CARBON DIOXIDE RECOVERY(30,16)|CARBON NEUTRALITY(28,25)|HEAT EXCHANGER(26,11)|BIOENERGY(25,1)|ELIMINATOR(23,10)|SUPERHEATED STEAM(23,6)|LNG SUPPLY(22,10)|COGENERATION(22,9)|BIOMASS(22,8)|WATER CONDENSATION(22,8)|CARBON DIOXIDE CAPTURE(22,1)|COOLING COIL(21,24)|CONDENSATION(21,8)|LNG(20,10)|CONDENSED WATER OUTFLOW(20,2)|NATURAL GAS(19,39)|CARBON NEUTRAL EQUIVALENT(19,10)|CARBON NEUTRAL THERMAL ENERGY(18,5)|LIQUEFIED NATURAL GAS SUPPLY(18,1)|EXHAUST GAS(17,11)|SYNTHETIC FUEL PRODUCTION(17,8)|CARBON DIOXIDE LIQUEFACTION(17,2)|ANTIFREEZE HEAT MEDIUM FLOWING(17,1)|REGENERATION TRANSFER HEAT(17,1)|LIQUEFIED NATURAL GAS(16,35)|ABSORPTION UNIT(16,6)|RECOVERING GAS(16,6)|HEAT CIRCULATION CIRCUIT(14,1)|WATER SATURATION(14,1)|RECOVERED CARBON DIOXIDE(13,11)|EMISSION CREDIT(12,2)|MEDIUM EXCHANGE(12,2)|CARBON DIOXIDE GAS RECOVERY(11,6)|LNG COLD HEAT(11,3)|BIOMASS ENERGY(11,2)|ENERGY SUPPLY(10,6)|NATURAL GAS EQUIVALENT(10,5)|REGENERATIVE ABSORPTION LIQUID(10,5)|SUPPLYING HEAT(10,2)|POWER GENERATOR(10,1)|SYNTHETIC GAS SYNTHETIC REACTION(10,1)|HEAT MEDIUM CIRCULATION CIRCUIT(9,16)|GAS PASSAGE(9,10)|DRAIN PAN(9,5)|REGENERATIVE THERMAL ENERGY SUPPLY(9,3)|HYDROGENATION REACTION CATALYST(8,3)|REGENERATIVE HEAT ENERGY SUPPLY(8,3)|ANTIFREEZE OUTLET(8,2)|CARBON DIOXIDE GAS FLOW(8,2)|COLLECTING BIOMASS(8,2)|GENERATING CARBON NEUTRAL THERMAL ENERGY(8,2)|NATURAL GAS EQUIVALENT PRODUCT(8,2)|LOW TEMPERATURE LIQUEFACTION(8,1)|URBAN COMBUSTIBLE WASTE(8,1)|CARBON DIOXIDE EMISSION(7,7)|ANTIFREEZE HEAT MEDIUM CIRCULATING(7,4)|SUPPLYING UNIT(7,1)|HYDROCARBON PRODUCTION(6,3)|FUEL SYNTHESIS(6,2)|OUTFLOW PORT(6,2)|WOODY BIOMASS(6,1)|HEAT EXCHANGE(5,6)|COOLING PIPE(5,4)|CARBON DIOXIDE GAS LIQUEFIER(5,3)|CARBON DIOXIDE UTILIZATION(5,3)|GREEN POWER PRODUCTION(5,3)|INFLOW PORT(5,2)|POSITIVE EMISSION(5,2)|REGENERATION ABSORPTION LIQUID(5,2)|BIOMASS COLLECTION(5,1)|CONDENSER TURBINE(5,1)|DESCENDING CO2(5,1)|LNG VAPORIZER CONFIGURATION(5,1)|POLICY FORMULATION(5,1)|URGENT ISSUE(5,1)|GAS COOLING DEVICE(4,6)|SATURATED STEAM(4,5)|EXTRA POWER(4,2)|FREEZING TEMPERATURE(4,2)|GLOBAL WARMING(4,2)|SEAWATER(4,2)|TRANSPORTATION(4,2)|COOLED ANTIFREEZE(4,1)|FLOWING ANTIFREEZE(4,1)|REGENERATED ABSORBING LIQUID(4,1)|REGENERATING LIQUID ABSORPTION(4,1)|REGENERATIVE ABSORBING LIQUID(4,1)|SENDING OUT ELECTRICAL POWER(4,1)|TURBINE EXTRACTION(4,1)|NATURAL GAS PRODUCTION SYSTEM(3,5)|COMBUSTION CHAMBER(3,4)|NATURAL GAS UTILIZATION(3,4)|ENERGY GENERATION(3,3)|LOW PRESSURE(3,3)|SATURATED WATER VAPOR(3,3)|CARBON DIOXIDE LIQUEFIER(3,1)|COOLING ENERGY SAVING(3,1)|EMITTING NEGATIVE(3,1)|NEGATIVE EMISSION(3,1)|OUT ELECTRICAL POWER(3,1)|TECHNOLOGY AGENCY(3,1)|TEMPERATURE SIDE(2,4)||(JP7297278)|NATURAL GAS(100,40)|LNG VAPORIZER(100,27)|BECCS(100,17)|GREEN POWER(100,16)|PRODUCTION SYSTEM(100,9)|CARBON NEUTRAL EQUIVALENT(100,4)|BIOMASS TREATMENT(100,2)|CONDENSER TURBINE(95,14)|REGENERATION(69,49)|CARBON DIOXIDE GAS(65,113)|CARBON DIOXIDE(57,189)|LIQUID ABSORPTION(54,13)|CARBON DIOXIDE RECOVERY(44,11)|BIOMASS COMBUSTION(43,1)|REGENERATION SUPPLY(41,8)|LNG SUPPLY(41,3)|BIOMASS SUPPLY(40,3)|ADSORPTION DEHUMIDIFIER(38,1)|COMBUSTION(33,9)|BOILER(32,14)|LNG FEEDER(31,6)|ABSORPTION SECTION(31,5)|LIQUEFIED NATURAL GAS(30,39)|LNG(28,13)|ANTIFREEZE(27,5)|ABSORBENT(27,4)|WATER CONDENSATION(26,10)|ACQUIRE DISCHARGE RIGHT(26,4)|SYNTHESIS FUEL(25,4)|CO2(24,14)|STORED CARBON DIOXIDE(24,11)|SUPERHEATED STEAM(23,6)|BIOENERGY(23,1)|CARBON DIOXIDE CAPTURE(22,1)|COOLING COIL(21,24)|BIOMASS POWER GENERATION(21,14)|BIOMASS(21,13)|CONDENSATION(21,9)|CONDENSED WATER OUTFLOW(21,2)|CARBON NEUTRAL THERMAL ENERGY(20,8)|CARBON NEUTRALITY EQUIVALENT(20,2)|GREEN POWER PRODUCTION(18,6)|NONFREEZING HEAT MEDIUM FLOWING(18,1)|EXHAUST GAS(17,11)|HEAT EXCHANGER(17,10)|ELECTRICAL POWER(16,3)|SATURATED STEAM(16,2)|ELLIPSE(16,1)|NATURAL GAS VAPORIZATION(14,1)|CARBON NEUTRAL(13,23)|HEAT EXCHANGE(13,11)|CARBON DIOXIDE GAS LIQUEFIER(13,3)|LNG COLD HEAT(13,1)|HEATING MEDIUM CIRCULATION CIRCUIT(12,16)|EJECTOR(12,4)|ELUENT(12,2)|VAPORIZE LIQUEFIED NATURAL GAS(12,2)|HEAT COMBINATION(11,7)|CONDENSATE TURBINE(11,3)|BIOMASS ENERGY(11,2)|RECOVERING GAS(10,12)|SYNTHESIS REACTION(10,3)|REGENERATED ABSORBING LIQUID(9,4)|REGENERATING LIQUID ABSORPTION(9,4)|GAS PASSAGE(9,3)|SUPPLYING HEAT(9,3)|HEATING SUPPLY(9,1)|REACTION TRANSFERRING HEAT(9,1)|HYDROGENATION REACTION CATALYST(8,3)|OUTFLOW PORT(8,3)|MUNICIPAL COMBUSTIBLE WASTE(8,1)|MEDIUM CIRCULATING(7,6)|NATURAL GAS EQUIVALENT(7,5)|INFLOW PORT(7,3)|CARBON DIOXIDE GAS RECOVERY(6,12)|HYDROCARBON PRODUCTION(6,3)|REGENERATION ABSORPTION LIQUID(6,3)|FUEL SYNTHESIS(6,2)|WOODY BIOMASS(6,1)|SYNTHETIC FUEL(5,8)|CARBON DIOXIDE GAS UTILIZATION(5,7)|NATURAL GAS UTILIZATION(5,7)|BIOMASS POWER PLANT(5,6)|COOLING PIPE(5,4)|FREEZING TEMPERATURE(5,3)|REGENERATION BASE(5,3)|CAUSE HEAT EXCHANGE(5,2)|CONDENSATION TURBINE(5,1)|DRAFT CHALLENGE(5,1)|LNG VAPORIZER CONFIGURATION(5,1)|GAS FLOW PASSAGE(4,8)|SATURATED WATER VAPOR(4,5)|CARBON DIOXIDE GAS FLOW(4,2)|SEAWATER(4,2)|COOLED ANTIFREEZE(4,1)|DEVELOPMENT SYSTEM(4,1)|GLOBAL WARMING ISSUE(4,1)|NATIONAL RESEARCH(4,1)|REGENERATING ABSORPTION LIQUID(4,1)|SUPPLYING BIOMASS(4,1)|TECHNOLOGY SHINKO STRATEGY CENTER(4,1)|COMBUSTION CHAMBER(3,4)|ENERGY GENERATION(3,4)|COOLANT(3,2)|CARBON DIOXIDE LIQUEFIER(3,1)|CARBON DISCOVERY(3,1)|COOLING ENERGY SAVING(3,1)|DRAIN OUTLET(3,1)|DRAIN PAN(3,1)|EMITTING NEGATIVE(3,1)|REGENERATION THERMAL ENERGY(3,1)|LOW PRESSURE(2,4)|ABSORB CARBON DIOXIDE(2,1)|CARBON DIOXIDE EMISSION(2,1)|CARBON DIOXIDE NEGATIVE EMISSION(2,1)||(JPWO2024/150398)|NATURAL GAS(100,40)|LNG VAPORIZER(100,27)|BECCS(100,17)|GREEN POWER(100,16)|PRODUCTION SYSTEM(100,9)|CARBON NEUTRAL EQUIVALENT(100,4)|BIOMASS TREATMENT(100,2)|CONDENSER TURBINE(95,14)|REGENERATION(69,49)|CARBON DIOXIDE GAS(65,113)|CARBON DIOXIDE(57,189)|LIQUID ABSORPTION(54,13)|CARBON DIOXIDE RECOVERY(44,11)|BIOMASS COMBUSTION(43,1)|REGENERATION SUPPLY(41,8)|LNG SUPPLY(41,3)|BIOMASS SUPPLY(40,3)|ADSORPTION DEHUMIDIFIER(38,1)|COMBUSTION(33,9)|BOILER(32,14)|LNG FEEDER(31,6)|ABSORPTION SECTION(31,5)|LIQUEFIED NATURAL GAS(30,39)|LNG(28,13)|ANTIFREEZE(27,5)|ABSORBENT(27,4)|WATER CONDENSATION(26,10)|ACQUIRE DISCHARGE RIGHT(26,4)|SYNTHESIS FUEL(25,4)|CO2(24,14)|STORED CARBON DIOXIDE(24,11)|SUPERHEATED STEAM(23,6)|BIOENERGY(23,1)|CARBON DIOXIDE CAPTURE(22,1)|COOLING COIL(21,24)|BIOMASS POWER GENERATION(21,14)|BIOMASS(21,13)|CONDENSATION(21,9)|CONDENSED WATER OUTFLOW(21,2)|CARBON NEUTRAL THERMAL ENERGY(20,8)|CARBON NEUTRALITY EQUIVALENT(20,2)|GREEN POWER PRODUCTION(18,6)|NONFREEZING HEAT MEDIUM FLOWING(18,1)|EXHAUST GAS(17,11)|HEAT EXCHANGER(17,10)|ELECTRICAL POWER(16,3)|SATURATED STEAM(16,2)|ELLIPSE(16,1)|NATURAL GAS VAPORIZATION(14,1)|CARBON NEUTRAL(13,23)|HEAT EXCHANGE(13,11)|CARBON DIOXIDE GAS LIQUEFIER(13,3)|LNG COLD HEAT(13,1)|HEATING MEDIUM CIRCULATION CIRCUIT(12,16)|EJECTOR(12,4)|ELUENT(12,2)|VAPORIZE LIQUEFIED NATURAL GAS(12,2)|HEAT COMBINATION(11,7)|CONDENSATE TURBINE(11,3)|BIOMASS ENERGY(11,2)|RECOVERING GAS(10,12)|SYNTHESIS REACTION(10,3)|REGENERATED ABSORBING LIQUID(9,4)|REGENERATING LIQUID ABSORPTION(9,4)|GAS PASSAGE(9,3)|SUPPLYING HEAT(9,3)|HEATING SUPPLY(9,1)|REACTION TRANSFERRING HEAT(9,1)|HYDROGENATION REACTION CATALYST(8,3)|OUTFLOW PORT(8,3)|MUNICIPAL COMBUSTIBLE WASTE(8,1)|MEDIUM CIRCULATING(7,6)|NATURAL GAS EQUIVALENT(7,5)|INFLOW PORT(7,3)|CARBON DIOXIDE GAS RECOVERY(6,12)|HYDROCARBON PRODUCTION(6,3)|REGENERATION ABSORPTION LIQUID(6,3)|FUEL SYNTHESIS(6,2)|WOODY BIOMASS(6,1)|SYNTHETIC FUEL(5,8)|CARBON DIOXIDE GAS UTILIZATION(5,7)|NATURAL GAS UTILIZATION(5,7)|BIOMASS POWER PLANT(5,6)|COOLING PIPE(5,4)|FREEZING TEMPERATURE(5,3)|REGENERATION BASE(5,3)|CAUSE HEAT EXCHANGE(5,2)|CONDENSATION TURBINE(5,1)|DRAFT CHALLENGE(5,1)|LNG VAPORIZER CONFIGURATION(5,1)|GAS FLOW PASSAGE(4,8)|SATURATED WATER VAPOR(4,5)|CARBON DIOXIDE GAS FLOW(4,2)|SEAWATER(4,2)|COOLED ANTIFREEZE(4,1)|DEVELOPMENT SYSTEM(4,1)|GLOBAL WARMING ISSUE(4,1)|NATIONAL RESEARCH(4,1)|REGENERATING ABSORPTION LIQUID(4,1)|SUPPLYING BIOMASS(4,1)|TECHNOLOGY SHINKO STRATEGY CENTER(4,1)|COMBUSTION CHAMBER(3,4)|ENERGY GENERATION(3,4)|COOLANT(3,2)|CARBON DIOXIDE LIQUEFIER(3,1)|CARBON DISCOVERY(3,1)|COOLING ENERGY SAVING(3,1)|DRAIN OUTLET(3,1)|DRAIN PAN(3,1)|EMITTING NEGATIVE(3,1)|REGENERATION THERMAL ENERGY(3,1)|LOW PRESSURE(2,4)|ABSORB CARBON DIOXIDE(2,1)|CARBON DIOXIDE EMISSION(2,1)|CARBON DIOXIDE NEGATIVE EMISSION(2,1)| | (WO2024/150398)|1. A biomass power generation device provided with: a power generator driven by a condensate turbine and sending out electric power; a boiler that combusts biomass supplied from a biomass supply device and supplies superheated steam to the condensate turbine; a condenser that condenses low-pressure steam discharged from the condensate turbine into condensed water; an absorption unit that is supplied with exhaust gas from the boiler and generates a CO2-containing absorption liquid by causing carbon dioxide gas contained in the exhaust gas to be absorbed into the absorption liquid; and a CO2-containing absorption liquid from the absorption unit The carbon dioxide recovery device is provided with: a regeneration unit to which liquid is supplied, and which heats the CO2-containing absorption liquid by means of thermal energy for regeneration and releases carbon dioxide gas; and a thermal energy supply unit for regeneration, which supplies the thermal energy delivered from a device that generates carbon neutral thermal energy to the regeneration unit as the thermal energy for regeneration. The carbon dioxide gas released by the regeneration unit is delivered as recovered carbon dioxide gas. The amount of carbon dioxide gas generated by burning is within the recovered carbon dioxide gas An LNG supply device for supplying liquefied natural gas in an amount smaller by a predetermined ratio than the amount of stored carbon dioxide; and a method for exchanging heat of cold LNG generated when the liquefied natural gas is supplied from the LNG supply device, the stored carbon dioxide is supplied from the carbon dioxide recovery device, and the liquefied natural gas is vaporized into natural gas and sent as natural gas equivalent to carbon neutrality, and the stored carbon dioxide is cooled The BECCS-based natural gas production system is equipped with an LNG vaporizer that delivers low-temperature stored carbon dioxide gas.|2. The regenerative thermal energy supply unit supplies heat emitted by steam bled from the condensate turbine to the regenerative unit as the regenerative thermal energy and heats the CO2-containing absorption liquid. The natural gas production system is equivalent to green power and carbon neutrality and utilizes the BECCS described in claim 1.|3. A cogeneration device is provided for supplying heat and power using a portion of the natural gas, which is supplied from the LNG vaporizer and corresponds to carbon neutrality. The heat energy supply unit for regeneration transfers heat generated by the cogeneration device to the regeneration unit as the heat energy for regeneration, and heats the CO2-containing absorbing liquid. The green power and natural gas production system utilizing the BECCS described in claim 1 utilizes the BECCS.|4. A system for producing green power and natural gas equivalent to carbon neutrality by utilizing the BECCS described in claim 1, wherein the system is provided with a synthetic fuel production device for producing a synthetic fuel by performing a synthetic reaction of a synthetic gas produced from the natural gas equivalent to carbon neutrality supplied from the LNG vaporization device, and the regenerative heat energy supply unit thermally transfers reaction heat generated in the synthetic reaction performed in the synthetic fuel production device to the regeneration unit as the regenerative heat energy and heats the CO2-containing absorption liquid.|5. A green power and carbon neutral equivalent natural gas production system utilizing the BECCS described in any one of claims 1 to 4, provided with a carbon dioxide liquefaction device for liquefying the low temperature stored carbon dioxide discharged from the LNG vaporization device.|6. The LNG vaporizer is provided with a vaporizer and a stored carbon dioxide gas cooling device. The vaporizer supplies the liquefied natural gas from the LNG supply device to the low temperature side, and circulates a second cooling coil provided in the stored carbon dioxide gas cooling device and an antifreeze heat medium flowing in the heat exchanger to the high temperature side. The liquefied natural gas and the antifreeze heat medium exchange LNG cold heat, vaporize the liquefied natural gas into natural gas, and deliver it as natural gas equivalent to carbon neutrality In the stored carbon dioxide gas cooling device, a first cooling coil, an eliminator, an adsorption-type dehumidifier, and the second cooling coil are arranged in series from one side to the other side, and the stored carbon dioxide gas flows in from an inlet on the one side and the low-temperature stored carbon dioxide gas flows out from an outlet on the other side; a second heat circulation circuit in which an antifreeze heat medium circulates between the low-temperature side of the second cooling coil and the heat exchanger and the high-temperature side of the vaporizer; and the first cooling coil and the heat exchanger The present invention is provided with: a first heat medium circulation circuit in which an antifreeze heat medium circulates through the high-temperature side; and a condensed water outflow unit in which the first cooling coil and the eliminator condense saturated water contained in the stored carbon dioxide gas, collect the captured condensed water, and flow out of the gas passage. The first cooling coil cools the stored carbon dioxide gas to condense the saturated water, the eliminator captures the condensed saturated water, and the adsorption type dehumidifier dries the stored carbon dioxide gas after drying The BECCS described in claim 5, which cools the stored carbon dioxide gas to a low temperature by the second cooling coil and sends the cooled carbon dioxide gas, is utilized in the green power and carbon neutral equivalent natural gas production system. | (WO2024/150398)|[0001] The present invention relates to a bioenergy with carbon dioxide capture and storage (BECCS) whereby green power and the like are produced using biomass energy and carbon dioxide gas generated by biomass combustion is recovered and stored.|[0002] Global warming is becoming increasingly serious, and measures to limit the increase in the global average temperature to 2 °C or less and at least 1.5 °C or less prior to the Industrial Revolution during the 21st century have become an urgent issue. Countries are trying to achieve this by expanding the supply of renewable energy sources (wind, solar, geothermal, hydro, biomass, etc.) and fading out fossil-fuel-derived power generation. It is expected to reduce carbon dioxide in the atmosphere by combining power generation by biomass energy and recovery and storage of carbon dioxide generated by biomass power generation. In addition, in order to reduce carbon dioxide emissions, which are a cause of global warming, a cap cap on carbon dioxide emissions (emission rights) is allocated to companies in advance, and companies that exceed the cap on carbon dioxide emissions can sell surplus carbon dioxide emissions rights to companies that exceed the cap on carbon dioxide emissions. Patent document 1 describes that green power is generated by biomass power generation, carbon dioxide generated by biomass power generation is recovered, and carbon neutral methane gas is generated from the recovered carbon dioxide and low carbon hydrogen gas. The nonpatent document 1 describes a technique in which carbon dioxide gas in the atmosphere is fixed by photosynthesis by plants, the plants (biomass) are used to generate electricity, and the emitted carbon dioxide gas is recovered and isolated from the atmosphere.|[0003] Patent No. 7136523|[0004] Published by Japan Science and Technology Agency, Research and Development Center for Low-Carbon Society Proposal for Policy Formulation for Realizing a Low-Carbon Society Life Cycle Evaluation of Carbon Emission Reduction by BECCS Using Biomass Co-firing Power, May 2022|[0005] Neither Patent Reference 1 nor Non-Patent Reference 1 describe a system for producing natural gas equivalent to carbon neutrality, which can be regarded as carbon neutral and can be used without emission credits, while producing green power using BECCS.|[0006] The purpose of the present invention is to produce green power by biomass power generation, and to produce green power and a system for producing natural gas equivalent to carbon neutrality that utilize BECCS, which are capable of producing natural gas equivalent to carbon neutrality and of cooling the stored carbon dioxide to a low temperature, by exchanging heat between stored carbon dioxide stored in the carbon dioxide generated by biomass power generation and liquefied natural gas in which the amount of carbon dioxide generated by burning is a prescribed percentage of the amount of stored carbon dioxide The purpose of the present invention is to provide.|[0007] The present invention is a biomass power generation device provided with: a generator that is driven by a condensate turbine and that sends out electric power; a boiler that combusts biomass supplied from a biomass supply device and that supplies superheated steam to the condensate turbine; a condenser that condenses low-pressure steam discharged from the condensate turbine into condensed water; an absorption unit that is supplied with exhaust gas from the boiler and that generates a CO2-containing absorption liquid by causing carbon dioxide gas contained in the exhaust gas to be absorbed into the absorption liquid; and a CO from the absorption unit The carbon dioxide gas recovery device is provided with a regeneration unit to which a CO2-containing absorption liquid is supplied and which heats the CO2-containing absorption liquid by means of thermal energy for regeneration and releases carbon dioxide gas, and a regeneration thermal energy supply unit which supplies the thermal energy delivered from a device which generates carbon neutral thermal energy to the regeneration unit as the thermal energy for regeneration. The carbon dioxide gas released by the regeneration unit is delivered as recovered carbon dioxide gas. The amount of carbon dioxide gas generated by burning is the amount of the recovered carbon dioxide gas The liquefied natural gas is supplied from the LNG supply device, the stored carbon dioxide is supplied from the carbon dioxide recovery device, and the cold heat of the LNG generated when the liquefied natural gas is vaporized is heat-exchanged with the stored carbon dioxide, thereby the liquefied natural gas is vaporized into natural gas, which is delivered as natural gas equivalent to carbon neutrality, and the stored carbon dioxide is delivered A system for producing green power and carbon neutral equivalent natural gas utilizing BECCS is provided with an LNG vaporizer for cooling, storing carbon dioxide at a low temperature, and sending the carbon dioxide.|[0008] According to the present invention, green power is produced by a biomass power generation device, carbon dioxide discharged from the biomass power generation device is recovered as recovered carbon dioxide by a carbon dioxide recovery device, and stored carbon dioxide separated from the atmosphere within the recovered carbon dioxide is supplied to an LNG vaporization device. The LNG supply device supplies liquefied natural gas in which the amount of carbon dioxide generated by combustion is a predetermined percentage smaller than the amount of stored carbon dioxide. The LNG vaporization device exchanges heat between the liquefied natural gas supplied from the LNG supply device and the stored carbon dioxide supplied from the carbon dioxide recovery device, vaporizes the liquefied natural gas and delivers it as natural gas equivalent to carbon neutrality, and cools the stored carbon dioxide to deliver it as low-temperature stored carbon dioxide. The predetermined ratio takes into account the amount of carbon dioxide emitted during the course of producing energy necessary for collecting biomass used in biomass power generation, manufacturing and transporting chips, manufacturing and transporting liquefied natural gas supplied from an LNG supply device, and storing stored carbon dioxide, and the amount of carbon dioxide in negative emissions generated by the storage of stored carbon dioxide is the amount of positive emissions generated by burning LNG liquefied natural gas supplied from the LNG supply device Set to be more. Thus, the green power and natural gas production system utilizing the BECCS according to the present invention can supply green power and can send natural gas equivalent to carbon neutrality, which can be said that an emission right has already been acquired. Further, the stored carbon dioxide is cooled to low-temperature stored carbon dioxide by utilizing the heat of vaporization of the liquefied natural gas supplied from an LNG supply device, whereby the stored carbon dioxide can be liquefied to liquefied natural gas convenient for carrying to the storage place 65 with lower energy and lower cost than usual.|[0009] This block diagram shows the overall structure of a green power and carbon neutral equivalent natural gas production system using BECCS according to a first embodiment. The figure shows the configuration of the LNG vaporizer used in a first embodiment. This is a block diagram that shows the overall structure of a green power and carbon neutral equivalent natural gas production system using BECCS according to the second embodiment. This is a block diagram that shows the overall structure of a green power and carbon neutral equivalent natural gas production system using BECCS according to the third embodiment.|[0010] 1. Configuration of a first embodiment A natural gas production system (1a) that is equivalent to green power and carbon neutrality and that utilizes BECCS in a first embodiment is provided with: a biomass power generation device (10); a carbon dioxide gas recovery device (25); a device (30) that generates carbon-neutral thermal energy; an LNG supply device (40); an LNG vaporization device (41); a carbon dioxide gas utilization device (50); and a carbon dioxide liquefaction device (60), as shown in Fig. 1.|[0011] In the biomass power generation device 10, a condensate turbine 15 is rotated by superheated steam supplied from a boiler 12, and a generator 16 is driven by the condensate turbine 15 to generate power. Part of the generated power is used as in-house power in a natural gas production system (1a) equivalent to carbon neutrality and green power using BECCS, and surplus power is sold to a power grid (17) connected to a grid so as to be capable of backflow. The low pressure steam reduced in pressure by rotating the condensate turbine 15 is cooled by the condenser 18 to be condensed water and circulated to the heat exchange part 13 of the boiler 12. The boiler 12 is supplied with biomass from a biomass supply device 21 to the combustion chamber 14, burns it, and heats the condensed water supplied to the heat exchange part 13 to produce superheated steam. As the biomass, woody biomass, urban combustible waste, agricultural waste, etc., are used.|[0012] The condenser 18 is provided with a cooling pipe 19 for circulating cooling water, and low pressure steam discharged from the condenser turbine 15 and flowed into the condenser 18 transfers heat of condensation to the cooling water to become condensed water. A well-known cooling water supply device 20 is connected to the cooling pipe 19, and cooling water is circulated. The cooling water supply device 20 is configured, for example, to pump up seawater as cooling water by a pump, circulate in the cooling pipe 19, and return the seawater heated at a high temperature to the sea. The cooling water supply device 20 may be provided with a cooling tower to circulate cooling water between the cooling tower and the cooling pipe 19.|[0013] A carbon dioxide gas recovery device (25), which is publicly known as, for example, described in Patent No. 4956519 Gazette, comprises: an absorption unit (26) that causes carbon dioxide gas contained in exhaust gas to be absorbed in a regenerative absorption liquid to produce a CO2-containing absorption liquid; a regeneration unit (27) that causes carbon dioxide gas to be separated from the CO2-containing absorption liquid to produce a regenerative absorption liquid; and a regenerative thermal energy supply unit (28) that heats the regenerative absorption liquid to produce high-temperature steam. In the absorption part 26, the exhaust gas is supplied from the bottom part from the combustion chamber 14 of the boiler 12, the regenerative absorption liquid cooled halfway to return to the absorption part 26 from the regeneration part 27 is supplied from the upper part, carbon dioxide contained in the exhaust gas is absorbed in the regenerative absorption liquid to make the regenerative absorption liquid a CO2-containing absorption liquid, and the exhaust gas from which the carbon dioxide is recovered is discharged from the upper part.|[0014] In the regeneration part 27, the CO2-containing absorption liquid heated on the way to the regeneration part 27 from the absorption part 26 is supplied from the upper part, and the descending CO2-containing absorption liquid is heated by the steam supplied from the lower part to emit the carbon dioxide gas, and thereby is made into the regeneration absorption liquid. The heat energy supply part 28 for regeneration is supplied with steam extracted from a condensate turbine 15 of the biomass power generation device 10. In the heat energy supply part 28 for regeneration, heat emitted by the supplied steam heats the regeneration absorption liquid supplied from the bottom part of the regeneration part 27 and evaporates part of the moisture to produce steam. Water vapor generated by heating the regenerative absorption liquid is supplied to the regeneration part 27 from the lower part. Thus, the heat energy supply part 28 for regeneration supplies the heat discharged from the steam bled and supplied from the condensate turbine 15 of the biomass power generation device 10 to the regeneration part 27 as heat energy for regeneration supplied from a device 30 generating carbon neutral heat energy. The regenerative absorbing liquid in which a part of the moisture is evaporated by the thermal energy supply part 28 for regeneration is returned to the absorbing part 26. The steam having released heat by the heat energy supply part 28 for regeneration is converted into condensed water and circulated to the condenser 18.|[0015] A part of the recovered carbon dioxide discharged from the carbon dioxide recovery device 25 is effectively utilized by the carbon dioxide utilization device 50. The carbon dioxide gas utilization apparatus 50 is, for example, a well-known hydrocarbon production apparatus. In the hydrocarbon production apparatus, hydrogen gas and carbon dioxide gas at a temperature and pressure suitable for a hydrogenation reaction are supplied to a reaction tube filled with a hydrogenation reaction catalyst in a prescribed molar ratio, and the hydrogen gas and carbon dioxide are subjected to the hydrogenation reaction under the hydrogenation reaction catalyst to produce high-temperature reaction gas containing hydrocarbons, and the high-temperature reaction gas is sent out.|[0016] When the recovered carbon dioxide discharged from the carbon dioxide recovery device 25 is utilized by the carbon dioxide utilizing device 50, the remaining part of the recovered carbon dioxide, and when the carbon dioxide utilizing device 50 is not installed, all the recovered carbon dioxide are supplied as the stored carbon dioxide to the LNG vaporizer 41.|[0017] The liquefied natural gas is supplied from an LNG supply device 40 to the LNG vaporization device 41, and the stored carbon dioxide is supplied from a carbon dioxide recovery device 25. The LNG vaporizer 41 exchanges heat of LNG cold generated at vaporization of the liquefied natural gas with the stored carbon dioxide, vaporizes the liquefied natural gas into natural gas, sends the natural gas as carbon neutral equivalent natural gas to the natural gas utilization device 55, cools the stored carbon dioxide, and sends the cooled stored carbon dioxide as low-temperature stored carbon dioxide. The LNG supply device 40 supplies the liquefied natural gas to the LNG vaporization device 41 in which the amount of carbon dioxide generated by combustion is smaller by a predetermined rate α to the amount of stored carbon dioxide stored in the recovered carbon dioxide. Thus, the LNG vaporizer 41 can send out the natural gas equivalent to carbon neutrality, which can be said that the emission right has been acquired. The low-temperature stored carbon dioxide cooled by the LNG vaporizer 41 is sent to a carbon dioxide liquefier 60.|[0018] An LNG vaporizer 41 includes: a vaporizer 43 for vaporizing liquefied natural gas supplied from an LNG supply device 40 as shown in Fig. 2, and sending the liquefied natural gas as carbon neutral equivalent natural gas to a natural gas utilization device 55; and a stored carbon dioxide cooling device 42 for drying stored carbon dioxide supplied from a carbon dioxide recovery device 25 to a state containing little saturated steam, and then cooling the stored carbon dioxide to low-temperature stored carbon dioxide to send it. That is, the stored carbon dioxide cooling device 42 cools the stored carbon dioxide to the vicinity of freezing temperature of water, condenses and dehumidifies saturated steam, and then cools the stored carbon dioxide to a low temperature suitable for manufacturing the liquefied carbon dioxide. The vaporizer 43 includes a low-temperature side 43b for vaporizing the liquefied natural gas into the natural gas during flowing, and a high-temperature side 43a for flowing an antifreeze heating medium heated by the stored carbon dioxide cooling device 42. The antifreeze heat medium flowing in the high-temperature side (43a) transfers LNG cold from the liquefied natural gas flowing in the low-temperature side (43b).|[0019] In the stored carbon dioxide cooling device (42), a gas passage (44c) through which the stored carbon dioxide flows in through an inflow port (44a) and becomes a low-temperature stored carbon dioxide and flows out through an outflow port (44b) is formed in a housing (44). A first cooling coil (45), an eliminator (46), an adsorption type dehumidifier (54), and a second cooling coil (47) are sequentially stored in the gas passage (44c) in series from one side (inflow port (44a side)) to the other side (outflow port (44b side). The first cooling coil 45 is provided with an outlet of the antifreeze heat medium on one side of the gas passage 44b and an inlet on the other side. The second cooling coil 47 is provided with an outlet of the antifreeze heat medium on one side of the gas passage 44b and an inlet on the other side. On the bottom surface of the gas passage 44b, a drain pan 48 is formed opposite to the lower surfaces of the first cooling coil 45 and the eliminator 46. A water flow port (48a) is provided on the bottom surface of the drain pan (48). The condensed water which has almost condensed and dropped the saturated water vapor by lowering the stored carbon dioxide gas by the first cooling coil (45) to the vicinity of the freezing temperature of the water and the droplets of the condensed water captured by the eliminator (46) are collected on a drain pan (48) and flowed out from a water flow port (48a) through a water seal (49) to be reused or discharged. The drain pan (48), the water flow opening (48a), and the water seal (49) form a condensed water outflow unit in which the saturated steam contained in the stored carbon dioxide gas is condensed by the first cooling coil (45) and the eliminator (46), collects the captured condensed water, and discharges the condensed water to the outside of the gas passage (44c). Electric heat or turbine extraction is utilized as a heat source for regeneration of the adsorption type dehumidifier 54.|[0020] The stored carbon dioxide gas cooling device 42 includes a first heat medium circulation circuit 51, a second heat medium circulation circuit 52, and a heat exchanger 53 performing heat exchange between an antifreeze heat medium circulating in the first heat medium circulation circuit 51 and an antifreeze heat medium circulating in the second heat medium circulation circuit 52. In a first heat medium circulation circuit (51), an antifreeze heat medium is circulated by a pump in the form of a first cooling coil (45) and a high-temperature side (53a) of a heat exchanger (53). In a second heat medium circulation circuit (52), an antifreeze heat medium is circulated by means of a pump not shown in the figure, through a second cooling coil (47), a low-temperature side (53b) of a heat exchanger (53), and a high-temperature side (43a) of a carburetor (43). The stored carbon dioxide gas cooling device 42 cools the stored carbon dioxide gas to a low temperature and sends it out.|[0021] The predetermined ratio α is set in consideration of the amount of carbon dioxide gas generated in a course for producing energy necessary for collecting biomass used for biomass power generation, manufacturing and transporting chips, manufacturing and transporting liquefied natural gas supplied from an LNG supply device 40, storing stored carbon dioxide gas, and the like. For example, the amount of carbon dioxide gas generated in a course for generating energy necessary for biomass collection and chip production and transportation is β of a predetermined rate of stored carbon dioxide gas, the amount of carbon dioxide gas generated in a course for generating energy necessary for production and transportation of liquefied natural gas supplied from an LNG supply device 40 is θ of a predetermined rate of stored carbon dioxide gas, and the amount of carbon dioxide gas generated in a course for generating energy necessary for storing stored carbon dioxide gas Assuming that is the prescribed rate δ of the stored carbon dioxide, the amount by which the stored carbon dioxide substantially removes carbon dioxide from the atmosphere becomes the amount obtained by multiplying the stored carbon dioxide by the prescribed rate α=(1-β-θ-δ)・η). When the coefficient η is set to an appropriate positive number of not more than 1, the carbon dioxide amount of a substantial negative emission generated by storage of the stored carbon dioxide can be not less than the amount of carbon dioxide gas of a positive emission generated by combustion of LNG liquefied natural gas supplied from an LNG supply device. The predetermined ratio (α) varies depending on various conditions in each of the courses, etc., but preferably is set to about 0.6-0.7. Thus, the LNG supply device 40 supplies the liquefied natural gas of which the amount of carbon dioxide generated by combustion is smaller by a prescribed rate α to the amount of stored carbon dioxide to the LNG vaporization device 41, and the LNG vaporization device 41 can deliver natural gas equivalent to carbon neutrality, which can be considered as having acquired an emission right.|[0022] 2. A boiler 12 of a working biomass power generation device 10 of a first embodiment burns the biomass supplied from a biomass supply device 21 in a combustion chamber 14, and superheats the condensed water returned from a condenser 18 to a heat exchange part 13 to generate superheated steam. The condensate turbine 15 is operated by the superheated steam supplied from the boiler 12 and drives the generator 16. A part of the power output from the generator 16 is used as in-house power, and the surplus power is sold to the power grid 17. The steam lowered in pressure by rotating the condensate turbine 15 becomes condensate in the condenser 18 and is circulated to the heat exchange part 13 of the boiler 12.|[0023] In the carbon dioxide recovering device 25, the exhaust gas is supplied to an absorbing part 26 from a combustion chamber 14 of a boiler 12, and the regenerated absorbing liquid absorbs carbon dioxide contained in the exhaust gas, and becomes a CO2-containing absorbing liquid. The CO2-containing absorbing liquid fed to the regeneration part 27 is bled from the condensate turbine 15, heated by the heat released by the steam supplied to the regeneration energy supply part 28, releases the carbon dioxide gas, becomes a regeneration absorbing liquid and is returned to the absorption part 26.|[0024] A part of the recovered carbon dioxide discharged from the carbon dioxide recovery device 25 is effectively utilized by the carbon dioxide utilization device 50. A hydrocarbon production apparatus, which is an example of the carbon dioxide utilization apparatus 50, produces hydrocarbons by hydrogenating a part of the recovered carbon dioxide with hydrogen gas in a hydrogenation reaction catalyst.|[0025] The LNG vaporizer 41 exchanges heat between supplied stored carbon dioxide and liquefied natural gas in which the amount of carbon dioxide generated by combustion is smaller by a predetermined ratio than the amount of stored carbon dioxide, vaporizes the liquefied natural gas, delivers the liquefied natural gas as natural gas equivalent to carbon neutrality, in which an exhaust right can be considered already acquired, and delivers the stored carbon dioxide by cooling it to a low temperature. The low-temperature stored carbon dioxide gas is liquefied by a carbon dioxide gas liquefier 60.|[0026] That is, in the LNG vaporizer 41, LNG is supplied from an LNG supply device 40 to the low temperature side 43b of the vaporizer 43, and the antifreeze heat medium circulating in a second heat medium circulation circuit 52 is supplied to the high temperature side 43a. Thus, the liquefied natural gas and the antifreeze heating medium exchange heat with LNG cold in the vaporizer 43, the liquefied natural gas is vaporized into natural gas equivalent to carbon neutrality and sent to the natural gas utilizing device 55, and the antifreeze heating medium is transmitted with the LNG cold heat, cooled to a temperature lower than stored carbon dioxide, and sent back to the second cooling coil 47. The cooled antifreeze heat medium cools the dry stored carbon dioxide gas flowing through the gas passage 44b to a low temperature and increases its temperature while flowing through the second cooling coil 47. The temperature-raised antifreeze heat medium flows through the second heat medium circulation circuit (52) to the low-temperature side (53b) of the heat exchanger (53) and flows through the first heat medium circulation circuit (51) to the high-temperature side (53a) of the heat exchanger (53). Thus, the antifreeze heat medium circulating in the second heat medium circulation circuit (52) is heated to a temperature not lower than the freezing temperature of water and supplied to the high temperature side (43a) of the vaporizer (43). The antifreeze heat medium circulating in the first heat medium circulation circuit 51 is cooled to the vicinity of the freezing temperature of water and supplied to the first cooling coil 45.|[0027] The stored carbon dioxide gas delivered from the carbon dioxide gas recovery device (25) flows into the gas passage (44c) from the inlet (44a), exchanges heat with an antifreeze heat medium circulating in the first heat medium circulation circuit (51) while crossing the first cooling coil (45), and is cooled to the vicinity of the freezing temperature of the water, and the saturated water vapor is almost condensed and becomes a dried stored carbon dioxide gas. Large droplets in which the saturated water vapor is condensed fall on a drain pan 48, and small droplets floating in the stored carbon dioxide are captured by an eliminator 46, dropped on the drain pan 48, collected, and discharged through a drain port 48a and a water seal 49. Stored carbon dioxide gas passed through an eliminator 46 and dried by an adsorption type dehumidifier 54 exchanges heat with an antifreeze heat medium circulating in a second heat medium circulation circuit 52 while crossing a second cooling coil 47, is cooled to a low temperature, is fed from an outlet 44a and is liquefied by a carbon dioxide gas liquefier 60. According to the LNG vaporizer 41 shown in Fig. 2, the saturated steam contained in the stored carbon dioxide is removed and dried, so that the stored carbon dioxide can be cooled to a low temperature lower than the freezing temperature of water without freezing the saturated steam.|[0028] 3. Effect of a first embodiment According to a first embodiment, a biomass power generation device 10 produces green power, and an LNG vaporization device 41 cools stored carbon dioxide isolated from the atmosphere within recovered carbon dioxide recovered from exhaust gas generated in a boiler 12 by a carbon dioxide recovery device 25. By only exchanging heat between the liquefied natural gas and the stored carbon dioxide in which the amount of carbon dioxide gas supplied from the LNG supply device (40) and burned becomes a predetermined ratio α smaller than the amount of stored carbon dioxide by the LNG vaporization device (41), it is possible to produce natural gas equivalent to carbon neutrality, which can be said that an emission right has been acquired, and to cool the stored carbon dioxide gas to a low temperature at a low cost. Further, the stored carbon dioxide gas is cooled to a low temperature by the LNG vaporizer 41, so that it can be liquefied into liquefied natural gas convenient for transportation by saving cooling energy.|[0029] 4. Configuration of a second embodiment In a first embodiment, the heat energy supply unit 28 for regeneration of a carbon dioxide gas recovery device 25 supplies heat emitted by steam bled from a condensate turbine 15 of a biomass power generation device 10 to a regeneration unit 27 as heat energy for regeneration to heat a CO2-containing absorption liquid, while in a second embodiment, the point of supplying heat generated by a cogeneration device 31 to the regeneration unit 27 as heat energy for regeneration differs from the first embodiment, so the difference is only explained The same component as the first embodiment is given the same reference number and the description is omitted.|[0030] A cogeneration device 31, one of the natural gas utilizing devices 55, uses the natural gas, which corresponds to carbon neutrality and is supplied from the LNG vaporizer 41, for example, drives a gas turbine to operate a generator to generate power, and cools the turbine exhaust gas to collect and send the heat.|[0031] In the regenerative thermal energy supply part 28, heat fed from the cogeneration device 31 is supplied as regenerative thermal energy, regenerative absorption liquid supplied from the bottom part of the regenerative part 27 is heated, part of moisture is converted to steam and supplied from the bottom part to the regenerative part 27, and thus regenerative thermal energy is supplied to the regenerative part 27. The cogeneration device 31 also functions as a device 30 for generating carbon neutral thermal energy.|[0032] 5. The operation and effect cogeneration device 31 of the second embodiment generates power, and at the same time, heat generated is transferred to a heat energy supply part 28 for regeneration of the carbon dioxide recovery device 25 as heat energy for regeneration, and the CO2-containing absorption liquid is heated. Thereby, in addition to effects exerted by the first embodiment, electric power whose carbon dioxide emission amount is zero can be produced by using the natural gas equivalent to carbon neutrality as fuel in the cogeneration device 31.|[0033] 6. Constitution of a third embodiment In a second embodiment, a heat energy supply part 28 for regeneration of a carbon dioxide gas recovery device 25 supplies heat generated in a cogeneration device 31 as heat energy for regeneration to a regeneration part 27 to heat a CO2-containing absorption liquid, whereas in a third embodiment, the point of supplying the reaction heat generated in a synthetic fuel production device 32 as heat energy for regeneration differs from the second embodiment. Therefore, it is explained only about the difference and the same reference number for the same components as the first and second embodiments Omit the description with.|[0034] The synthetic fuel production apparatus 32 is a natural gas utilization apparatus 55. The synthetic fuel production apparatus 32 includes a synthetic gas production part and a fuel synthesis part. A synthesis gas production part produces synthesis gas from natural gas corresponding to carbon neutrality supplied from an LNG vaporizer 41, and a fuel synthesis part synthesizes and reacts the synthesis gas to produce synthetic fuel. A regenerative heat energy supply part 28 supplies reaction heat generated when synthetic gas is synthesized into synthetic fuel by a synthetic fuel manufacturing device 32 using natural gas corresponding to carbon neutrality as a raw material, as regenerative heat energy, heats regenerative absorption liquid supplied from the bottom part of a regenerative part 27, changes part of moisture into steam and supplies it from the bottom part to the regenerative part 27, and thereby supplies the regenerative heat energy to the regenerative part 27. A synthetic fuel production device 32 using natural gas corresponding to carbon neutrality as a raw material is a device 30 generating carbon neutral thermal energy, and reaction heat generated in a synthetic reaction performed in the synthetic fuel production device 32 is thermal energy delivered from the device 30 generating carbon neutral thermal energy.|[0035] 7. Operation and effect in a third embodiment A synthetic fuel manufacturing device 32 manufactures a synthetic fuel, heat-transfers the generated reaction heat to a regenerative heat energy supply part 28 of a carbon dioxide recovery device 25 as regenerative heat energy, and heats a CO2-containing absorption liquid. Thus, in addition to the effect exerted by the first embodiment, the synthetic fuel can be produced with the carbon dioxide emission amount substantially zero by using the natural gas equivalent to carbon neutrality as a raw material in the synthetic fuel production apparatus 32.|[0036] 1a-1c:BECCS Green Power and Carbon Neutral Equivalent Natural Gas Production System, 10: Biomass Power Generation Unit, 12: Boiler, 15: Condensate Turbine, 16: Generator, 17: Power Grid, 18: Condenser, 21: Biomass Supply Unit, 25: Carbon Dioxide Recovery Unit, 26: Absorption Unit, 27: Regeneration Unit, 28: Heat Energy Supply Unit for Regeneration, 30: Equipment for Generating Carbon Neutral Heat Energy, 31: Cogeneration Unit, 32: Synthetic Fuel Production System, 41: LNG Vaporization Unit, 42: Stored Gas Cooling device, 43: Vaporizer, 44: Gas passage, 45: First cooling coil, 46: Eliminator, 47: Second cooling coil, 51: First heat medium circulation circuit, 52: Second heat medium circulation circuit, 53: Heat exchanger, 54: Adsorption type dehumidifier, 55: Natural gas utilization device, 60: Carbon dioxide gas liquefier | (WO2024/150398)|[0001] The present invention relates to a bioenergy with carbon dioxide capture and storage (BECCS) whereby green power and the like are produced using biomass energy and carbon dioxide gas generated by biomass combustion is recovered and stored.|[0002] Global warming is becoming increasingly serious, and measures to limit the increase in the global average temperature to 2 °C or less and at least 1.5 °C or less prior to the Industrial Revolution during the 21st century have become an urgent issue. Countries are trying to achieve this by expanding the supply of renewable energy sources (wind, solar, geothermal, hydro, biomass, etc.) and fading out fossil-fuel-derived power generation. It is expected to reduce carbon dioxide in the atmosphere by combining power generation by biomass energy and recovery and storage of carbon dioxide generated by biomass power generation. In addition, in order to reduce carbon dioxide emissions, which are a cause of global warming, a cap cap on carbon dioxide emissions (emission rights) is allocated to companies in advance, and companies that exceed the cap on carbon dioxide emissions can sell surplus carbon dioxide emissions rights to companies that exceed the cap on carbon dioxide emissions. Patent document 1 describes that green power is generated by biomass power generation, carbon dioxide generated by biomass power generation is recovered, and carbon neutral methane gas is generated from the recovered carbon dioxide and low carbon hydrogen gas. The nonpatent document 1 describes a technique in which carbon dioxide gas in the atmosphere is fixed by photosynthesis by plants, the plants (biomass) are used to generate electricity, and the emitted carbon dioxide gas is recovered and isolated from the atmosphere.|[0003] Patent No. 7136523|[0004] Published by Japan Science and Technology Agency, Research and Development Center for Low-Carbon Society Proposal for Policy Formulation for Realizing a Low-Carbon Society Life Cycle Evaluation of Carbon Emission Reduction by BECCS Using Biomass Co-firing Power, May 2022|[0005] Neither Patent Reference 1 nor Non-Patent Reference 1 describe a system for producing natural gas equivalent to carbon neutrality, which can be regarded as carbon neutral and can be used without emission credits, while producing green power using BECCS.|[0006] The purpose of the present invention is to produce green power by biomass power generation, and to produce green power and a system for producing natural gas equivalent to carbon neutrality that utilize BECCS, which are capable of producing natural gas equivalent to carbon neutrality and of cooling the stored carbon dioxide to a low temperature, by exchanging heat between stored carbon dioxide stored in the carbon dioxide generated by biomass power generation and liquefied natural gas in which the amount of carbon dioxide generated by burning is a prescribed percentage of the amount of stored carbon dioxide The purpose of the present invention is to provide.|[0007] The present invention is a biomass power generation device provided with: a generator that is driven by a condensate turbine and that sends out electric power; a boiler that combusts biomass supplied from a biomass supply device and that supplies superheated steam to the condensate turbine; a condenser that condenses low-pressure steam discharged from the condensate turbine into condensed water; an absorption unit that is supplied with exhaust gas from the boiler and that generates a CO2-containing absorption liquid by causing carbon dioxide gas contained in the exhaust gas to be absorbed into the absorption liquid; and a CO from the absorption unit The carbon dioxide gas recovery device is provided with a regeneration unit to which a CO2-containing absorption liquid is supplied and which heats the CO2-containing absorption liquid by means of thermal energy for regeneration and releases carbon dioxide gas, and a regeneration thermal energy supply unit which supplies the thermal energy delivered from a device which generates carbon neutral thermal energy to the regeneration unit as the thermal energy for regeneration. The carbon dioxide gas released by the regeneration unit is delivered as recovered carbon dioxide gas. The amount of carbon dioxide gas generated by burning is the amount of the recovered carbon dioxide gas The liquefied natural gas is supplied from the LNG supply device, the stored carbon dioxide is supplied from the carbon dioxide recovery device, and the cold heat of the LNG generated when the liquefied natural gas is vaporized is heat-exchanged with the stored carbon dioxide, thereby the liquefied natural gas is vaporized into natural gas, which is delivered as natural gas equivalent to carbon neutrality, and the stored carbon dioxide is delivered A system for producing green power and carbon neutral equivalent natural gas utilizing BECCS is provided with an LNG vaporizer for cooling, storing carbon dioxide at a low temperature, and sending the carbon dioxide.|[0008] According to the present invention, green power is produced by a biomass power generation device, carbon dioxide discharged from the biomass power generation device is recovered as recovered carbon dioxide by a carbon dioxide recovery device, and stored carbon dioxide separated from the atmosphere within the recovered carbon dioxide is supplied to an LNG vaporization device. The LNG supply device supplies liquefied natural gas in which the amount of carbon dioxide generated by combustion is a predetermined percentage smaller than the amount of stored carbon dioxide. The LNG vaporization device exchanges heat between the liquefied natural gas supplied from the LNG supply device and the stored carbon dioxide supplied from the carbon dioxide recovery device, vaporizes the liquefied natural gas and delivers it as natural gas equivalent to carbon neutrality, and cools the stored carbon dioxide to deliver it as low-temperature stored carbon dioxide. The predetermined ratio takes into account the amount of carbon dioxide emitted during the course of producing energy necessary for collecting biomass used in biomass power generation, manufacturing and transporting chips, manufacturing and transporting liquefied natural gas supplied from an LNG supply device, and storing stored carbon dioxide, and the amount of carbon dioxide in negative emissions generated by the storage of stored carbon dioxide is the amount of positive emissions generated by burning LNG liquefied natural gas supplied from the LNG supply device Set to be more. Thus, the green power and natural gas production system utilizing the BECCS according to the present invention can supply green power and can send natural gas equivalent to carbon neutrality, which can be said that an emission right has already been acquired. Further, the stored carbon dioxide is cooled to low-temperature stored carbon dioxide by utilizing the heat of vaporization of the liquefied natural gas supplied from an LNG supply device, whereby the stored carbon dioxide can be liquefied to liquefied natural gas convenient for carrying to the storage place 65 with lower energy and lower cost than usual.|[0009] This block diagram shows the overall structure of a green power and carbon neutral equivalent natural gas production system using BECCS according to a first embodiment. The figure shows the configuration of the LNG vaporizer used in a first embodiment. This is a block diagram that shows the overall structure of a green power and carbon neutral equivalent natural gas production system using BECCS according to the second embodiment. This is a block diagram that shows the overall structure of a green power and carbon neutral equivalent natural gas production system using BECCS according to the third embodiment.|[0010] 1. Configuration of a first embodiment A natural gas production system (1a) that is equivalent to green power and carbon neutrality and that utilizes BECCS in a first embodiment is provided with: a biomass power generation device (10); a carbon dioxide gas recovery device (25); a device (30) that generates carbon-neutral thermal energy; an LNG supply device (40); an LNG vaporization device (41); a carbon dioxide gas utilization device (50); and a carbon dioxide liquefaction device (60), as shown in Fig. 1.|[0011] In the biomass power generation device 10, a condensate turbine 15 is rotated by superheated steam supplied from a boiler 12, and a generator 16 is driven by the condensate turbine 15 to generate power. Part of the generated power is used as in-house power in a natural gas production system (1a) equivalent to carbon neutrality and green power using BECCS, and surplus power is sold to a power grid (17) connected to a grid so as to be capable of backflow. The low pressure steam reduced in pressure by rotating the condensate turbine 15 is cooled by the condenser 18 to be condensed water and circulated to the heat exchange part 13 of the boiler 12. The boiler 12 is supplied with biomass from a biomass supply device 21 to the combustion chamber 14, burns it, and heats the condensed water supplied to the heat exchange part 13 to produce superheated steam. As the biomass, woody biomass, urban combustible waste, agricultural waste, etc., are used.|[0012] The condenser 18 is provided with a cooling pipe 19 for circulating cooling water, and low pressure steam discharged from the condenser turbine 15 and flowed into the condenser 18 transfers heat of condensation to the cooling water to become condensed water. A well-known cooling water supply device 20 is connected to the cooling pipe 19, and cooling water is circulated. The cooling water supply device 20 is configured, for example, to pump up seawater as cooling water by a pump, circulate in the cooling pipe 19, and return the seawater heated at a high temperature to the sea. The cooling water supply device 20 may be provided with a cooling tower to circulate cooling water between the cooling tower and the cooling pipe 19.|[0013] A carbon dioxide gas recovery device (25), which is publicly known as, for example, described in Patent No. 4956519 Gazette, comprises: an absorption unit (26) that causes carbon dioxide gas contained in exhaust gas to be absorbed in a regenerative absorption liquid to produce a CO2-containing absorption liquid; a regeneration unit (27) that causes carbon dioxide gas to be separated from the CO2-containing absorption liquid to produce a regenerative absorption liquid; and a regenerative thermal energy supply unit (28) that heats the regenerative absorption liquid to produce high-temperature steam. In the absorption part 26, the exhaust gas is supplied from the bottom part from the combustion chamber 14 of the boiler 12, the regenerative absorption liquid cooled halfway to return to the absorption part 26 from the regeneration part 27 is supplied from the upper part, carbon dioxide contained in the exhaust gas is absorbed in the regenerative absorption liquid to make the regenerative absorption liquid a CO2-containing absorption liquid, and the exhaust gas from which the carbon dioxide is recovered is discharged from the upper part.|[0014] In the regeneration part 27, the CO2-containing absorption liquid heated on the way to the regeneration part 27 from the absorption part 26 is supplied from the upper part, and the descending CO2-containing absorption liquid is heated by the steam supplied from the lower part to emit the carbon dioxide gas, and thereby is made into the regeneration absorption liquid. The heat energy supply part 28 for regeneration is supplied with steam extracted from a condensate turbine 15 of the biomass power generation device 10. In the heat energy supply part 28 for regeneration, heat emitted by the supplied steam heats the regeneration absorption liquid supplied from the bottom part of the regeneration part 27 and evaporates part of the moisture to produce steam. Water vapor generated by heating the regenerative absorption liquid is supplied to the regeneration part 27 from the lower part. Thus, the heat energy supply part 28 for regeneration supplies the heat discharged from the steam bled and supplied from the condensate turbine 15 of the biomass power generation device 10 to the regeneration part 27 as heat energy for regeneration supplied from a device 30 generating carbon neutral heat energy. The regenerative absorbing liquid in which a part of the moisture is evaporated by the thermal energy supply part 28 for regeneration is returned to the absorbing part 26. The steam having released heat by the heat energy supply part 28 for regeneration is converted into condensed water and circulated to the condenser 18.|[0015] A part of the recovered carbon dioxide discharged from the carbon dioxide recovery device 25 is effectively utilized by the carbon dioxide utilization device 50. The carbon dioxide gas utilization apparatus 50 is, for example, a well-known hydrocarbon production apparatus. In the hydrocarbon production apparatus, hydrogen gas and carbon dioxide gas at a temperature and pressure suitable for a hydrogenation reaction are supplied to a reaction tube filled with a hydrogenation reaction catalyst in a prescribed molar ratio, and the hydrogen gas and carbon dioxide are subjected to the hydrogenation reaction under the hydrogenation reaction catalyst to produce high-temperature reaction gas containing hydrocarbons, and the high-temperature reaction gas is sent out.|[0016] When the recovered carbon dioxide discharged from the carbon dioxide recovery device 25 is utilized by the carbon dioxide utilizing device 50, the remaining part of the recovered carbon dioxide, and when the carbon dioxide utilizing device 50 is not installed, all the recovered carbon dioxide are supplied as the stored carbon dioxide to the LNG vaporizer 41.|[0017] The liquefied natural gas is supplied from an LNG supply device 40 to the LNG vaporization device 41, and the stored carbon dioxide is supplied from a carbon dioxide recovery device 25. The LNG vaporizer 41 exchanges heat of LNG cold generated at vaporization of the liquefied natural gas with the stored carbon dioxide, vaporizes the liquefied natural gas into natural gas, sends the natural gas as carbon neutral equivalent natural gas to the natural gas utilization device 55, cools the stored carbon dioxide, and sends the cooled stored carbon dioxide as low-temperature stored carbon dioxide. The LNG supply device 40 supplies the liquefied natural gas to the LNG vaporization device 41 in which the amount of carbon dioxide generated by combustion is smaller by a predetermined rate α to the amount of stored carbon dioxide stored in the recovered carbon dioxide. Thus, the LNG vaporizer 41 can send out the natural gas equivalent to carbon neutrality, which can be said that the emission right has been acquired. The low-temperature stored carbon dioxide cooled by the LNG vaporizer 41 is sent to a carbon dioxide liquefier 60.|[0018] An LNG vaporizer 41 includes: a vaporizer 43 for vaporizing liquefied natural gas supplied from an LNG supply device 40 as shown in Fig. 2, and sending the liquefied natural gas as carbon neutral equivalent natural gas to a natural gas utilization device 55; and a stored carbon dioxide cooling device 42 for drying stored carbon dioxide supplied from a carbon dioxide recovery device 25 to a state containing little saturated steam, and then cooling the stored carbon dioxide to low-temperature stored carbon dioxide to send it. That is, the stored carbon dioxide cooling device 42 cools the stored carbon dioxide to the vicinity of freezing temperature of water, condenses and dehumidifies saturated steam, and then cools the stored carbon dioxide to a low temperature suitable for manufacturing the liquefied carbon dioxide. The vaporizer 43 includes a low-temperature side 43b for vaporizing the liquefied natural gas into the natural gas during flowing, and a high-temperature side 43a for flowing an antifreeze heating medium heated by the stored carbon dioxide cooling device 42. The antifreeze heat medium flowing in the high-temperature side (43a) transfers LNG cold from the liquefied natural gas flowing in the low-temperature side (43b).|[0019] In the stored carbon dioxide cooling device (42), a gas passage (44c) through which the stored carbon dioxide flows in through an inflow port (44a) and becomes a low-temperature stored carbon dioxide and flows out through an outflow port (44b) is formed in a housing (44). A first cooling coil (45), an eliminator (46), an adsorption type dehumidifier (54), and a second cooling coil (47) are sequentially stored in the gas passage (44c) in series from one side (inflow port (44a side)) to the other side (outflow port (44b side). The first cooling coil 45 is provided with an outlet of the antifreeze heat medium on one side of the gas passage 44b and an inlet on the other side. The second cooling coil 47 is provided with an outlet of the antifreeze heat medium on one side of the gas passage 44b and an inlet on the other side. On the bottom surface of the gas passage 44b, a drain pan 48 is formed opposite to the lower surfaces of the first cooling coil 45 and the eliminator 46. A water flow port (48a) is provided on the bottom surface of the drain pan (48). The condensed water which has almost condensed and dropped the saturated water vapor by lowering the stored carbon dioxide gas by the first cooling coil (45) to the vicinity of the freezing temperature of the water and the droplets of the condensed water captured by the eliminator (46) are collected on a drain pan (48) and flowed out from a water flow port (48a) through a water seal (49) to be reused or discharged. The drain pan (48), the water flow opening (48a), and the water seal (49) form a condensed water outflow unit in which the saturated steam contained in the stored carbon dioxide gas is condensed by the first cooling coil (45) and the eliminator (46), collects the captured condensed water, and discharges the condensed water to the outside of the gas passage (44c). Electric heat or turbine extraction is utilized as a heat source for regeneration of the adsorption type dehumidifier 54.|[0020] The stored carbon dioxide gas cooling device 42 includes a first heat medium circulation circuit 51, a second heat medium circulation circuit 52, and a heat exchanger 53 performing heat exchange between an antifreeze heat medium circulating in the first heat medium circulation circuit 51 and an antifreeze heat medium circulating in the second heat medium circulation circuit 52. In a first heat medium circulation circuit (51), an antifreeze heat medium is circulated by a pump in the form of a first cooling coil (45) and a high-temperature side (53a) of a heat exchanger (53). In a second heat medium circulation circuit (52), an antifreeze heat medium is circulated by means of a pump not shown in the figure, through a second cooling coil (47), a low-temperature side (53b) of a heat exchanger (53), and a high-temperature side (43a) of a carburetor (43). The stored carbon dioxide gas cooling device 42 cools the stored carbon dioxide gas to a low temperature and sends it out.|[0021] The predetermined ratio α is set in consideration of the amount of carbon dioxide gas generated in a course for producing energy necessary for collecting biomass used for biomass power generation, manufacturing and transporting chips, manufacturing and transporting liquefied natural gas supplied from an LNG supply device 40, storing stored carbon dioxide gas, and the like. For example, the amount of carbon dioxide gas generated in a course for generating energy necessary for biomass collection and chip production and transportation is β of a predetermined rate of stored carbon dioxide gas, the amount of carbon dioxide gas generated in a course for generating energy necessary for production and transportation of liquefied natural gas supplied from an LNG supply device 40 is θ of a predetermined rate of stored carbon dioxide gas, and the amount of carbon dioxide gas generated in a course for generating energy necessary for storing stored carbon dioxide gas Assuming that is the prescribed rate δ of the stored carbon dioxide, the amount by which the stored carbon dioxide substantially removes carbon dioxide from the atmosphere becomes the amount obtained by multiplying the stored carbon dioxide by the prescribed rate α=(1-β-θ-δ)・η). When the coefficient η is set to an appropriate positive number of not more than 1, the carbon dioxide amount of a substantial negative emission generated by storage of the stored carbon dioxide can be not less than the amount of carbon dioxide gas of a positive emission generated by combustion of LNG liquefied natural gas supplied from an LNG supply device. The predetermined ratio (α) varies depending on various conditions in each of the courses, etc., but preferably is set to about 0.6-0.7. Thus, the LNG supply device 40 supplies the liquefied natural gas of which the amount of carbon dioxide generated by combustion is smaller by a prescribed rate α to the amount of stored carbon dioxide to the LNG vaporization device 41, and the LNG vaporization device 41 can deliver natural gas equivalent to carbon neutrality, which can be considered as having acquired an emission right.|[0022] 2. A boiler 12 of a working biomass power generation device 10 of a first embodiment burns the biomass supplied from a biomass supply device 21 in a combustion chamber 14, and superheats the condensed water returned from a condenser 18 to a heat exchange part 13 to generate superheated steam. The condensate turbine 15 is operated by the superheated steam supplied from the boiler 12 and drives the generator 16. A part of the power output from the generator 16 is used as in-house power, and the surplus power is sold to the power grid 17. The steam lowered in pressure by rotating the condensate turbine 15 becomes condensate in the condenser 18 and is circulated to the heat exchange part 13 of the boiler 12.|[0023] In the carbon dioxide recovering device 25, the exhaust gas is supplied to an absorbing part 26 from a combustion chamber 14 of a boiler 12, and the regenerated absorbing liquid absorbs carbon dioxide contained in the exhaust gas, and becomes a CO2-containing absorbing liquid. The CO2-containing absorbing liquid fed to the regeneration part 27 is bled from the condensate turbine 15, heated by the heat released by the steam supplied to the regeneration energy supply part 28, releases the carbon dioxide gas, becomes a regeneration absorbing liquid and is returned to the absorption part 26.|[0024] A part of the recovered carbon dioxide discharged from the carbon dioxide recovery device 25 is effectively utilized by the carbon dioxide utilization device 50. A hydrocarbon production apparatus, which is an example of the carbon dioxide utilization apparatus 50, produces hydrocarbons by hydrogenating a part of the recovered carbon dioxide with hydrogen gas in a hydrogenation reaction catalyst.|[0025] The LNG vaporizer 41 exchanges heat between supplied stored carbon dioxide and liquefied natural gas in which the amount of carbon dioxide generated by combustion is smaller by a predetermined ratio than the amount of stored carbon dioxide, vaporizes the liquefied natural gas, delivers the liquefied natural gas as natural gas equivalent to carbon neutrality, in which an exhaust right can be considered already acquired, and delivers the stored carbon dioxide by cooling it to a low temperature. The low-temperature stored carbon dioxide gas is liquefied by a carbon dioxide gas liquefier 60.|[0026] That is, in the LNG vaporizer 41, LNG is supplied from an LNG supply device 40 to the low temperature side 43b of the vaporizer 43, and the antifreeze heat medium circulating in a second heat medium circulation circuit 52 is supplied to the high temperature side 43a. Thus, the liquefied natural gas and the antifreeze heating medium exchange heat with LNG cold in the vaporizer 43, the liquefied natural gas is vaporized into natural gas equivalent to carbon neutrality and sent to the natural gas utilizing device 55, and the antifreeze heating medium is transmitted with the LNG cold heat, cooled to a temperature lower than stored carbon dioxide, and sent back to the second cooling coil 47. The cooled antifreeze heat medium cools the dry stored carbon dioxide gas flowing through the gas passage 44b to a low temperature and increases its temperature while flowing through the second cooling coil 47. The temperature-raised antifreeze heat medium flows through the second heat medium circulation circuit (52) to the low-temperature side (53b) of the heat exchanger (53) and flows through the first heat medium circulation circuit (51) to the high-temperature side (53a) of the heat exchanger (53). Thus, the antifreeze heat medium circulating in the second heat medium circulation circuit (52) is heated to a temperature not lower than the freezing temperature of water and supplied to the high temperature side (43a) of the vaporizer (43). The antifreeze heat medium circulating in the first heat medium circulation circuit 51 is cooled to the vicinity of the freezing temperature of water and supplied to the first cooling coil 45.|[0027] The stored carbon dioxide gas delivered from the carbon dioxide gas recovery device (25) flows into the gas passage (44c) from the inlet (44a), exchanges heat with an antifreeze heat medium circulating in the first heat medium circulation circuit (51) while crossing the first cooling coil (45), and is cooled to the vicinity of the freezing temperature of the water, and the saturated water vapor is almost condensed and becomes a dried stored carbon dioxide gas. Large droplets in which the saturated water vapor is condensed fall on a drain pan 48, and small droplets floating in the stored carbon dioxide are captured by an eliminator 46, dropped on the drain pan 48, collected, and discharged through a drain port 48a and a water seal 49. Stored carbon dioxide gas passed through an eliminator 46 and dried by an adsorption type dehumidifier 54 exchanges heat with an antifreeze heat medium circulating in a second heat medium circulation circuit 52 while crossing a second cooling coil 47, is cooled to a low temperature, is fed from an outlet 44a and is liquefied by a carbon dioxide gas liquefier 60. According to the LNG vaporizer 41 shown in Fig. 2, the saturated steam contained in the stored carbon dioxide is removed and dried, so that the stored carbon dioxide can be cooled to a low temperature lower than the freezing temperature of water without freezing the saturated steam.|[0028] 3. Effect of a first embodiment According to a first embodiment, a biomass power generation device 10 produces green power, and an LNG vaporization device 41 cools stored carbon dioxide isolated from the atmosphere within recovered carbon dioxide recovered from exhaust gas generated in a boiler 12 by a carbon dioxide recovery device 25. By only exchanging heat between the liquefied natural gas and the stored carbon dioxide in which the amount of carbon dioxide gas supplied from the LNG supply device (40) and burned becomes a predetermined ratio α smaller than the amount of stored carbon dioxide by the LNG vaporization device (41), it is possible to produce natural gas equivalent to carbon neutrality, which can be said that an emission right has been acquired, and to cool the stored carbon dioxide gas to a low temperature at a low cost. Further, the stored carbon dioxide gas is cooled to a low temperature by the LNG vaporizer 41, so that it can be liquefied into liquefied natural gas convenient for transportation by saving cooling energy.|[0029] 4. Configuration of a second embodiment In a first embodiment, the heat energy supply unit 28 for regeneration of a carbon dioxide gas recovery device 25 supplies heat emitted by steam bled from a condensate turbine 15 of a biomass power generation device 10 to a regeneration unit 27 as heat energy for regeneration to heat a CO2-containing absorption liquid, while in a second embodiment, the point of supplying heat generated by a cogeneration device 31 to the regeneration unit 27 as heat energy for regeneration differs from the first embodiment, so the difference is only explained The same component as the first embodiment is given the same reference number and the description is omitted.|[0030] A cogeneration device 31, one of the natural gas utilizing devices 55, uses the natural gas, which corresponds to carbon neutrality and is supplied from the LNG vaporizer 41, for example, drives a gas turbine to operate a generator to generate power, and cools the turbine exhaust gas to collect and send the heat.|[0031] In the regenerative thermal energy supply part 28, heat fed from the cogeneration device 31 is supplied as regenerative thermal energy, regenerative absorption liquid supplied from the bottom part of the regenerative part 27 is heated, part of moisture is converted to steam and supplied from the bottom part to the regenerative part 27, and thus regenerative thermal energy is supplied to the regenerative part 27. The cogeneration device 31 also functions as a device 30 for generating carbon neutral thermal energy.|[0032] 5. The operation and effect cogeneration device 31 of the second embodiment generates power, and at the same time, heat generated is transferred to a heat energy supply part 28 for regeneration of the carbon dioxide recovery device 25 as heat energy for regeneration, and the CO2-containing absorption liquid is heated. Thereby, in addition to effects exerted by the first embodiment, electric power whose carbon dioxide emission amount is zero can be produced by using the natural gas equivalent to carbon neutrality as fuel in the cogeneration device 31.|[0033] 6. Constitution of a third embodiment In a second embodiment, a heat energy supply part 28 for regeneration of a carbon dioxide gas recovery device 25 supplies heat generated in a cogeneration device 31 as heat energy for regeneration to a regeneration part 27 to heat a CO2-containing absorption liquid, whereas in a third embodiment, the point of supplying the reaction heat generated in a synthetic fuel production device 32 as heat energy for regeneration differs from the second embodiment. Therefore, it is explained only about the difference and the same reference number for the same components as the first and second embodiments Omit the description with.|[0034] The synthetic fuel production apparatus 32 is a natural gas utilization apparatus 55. The synthetic fuel production apparatus 32 includes a synthetic gas production part and a fuel synthesis part. A synthesis gas production part produces synthesis gas from natural gas corresponding to carbon neutrality supplied from an LNG vaporizer 41, and a fuel synthesis part synthesizes and reacts the synthesis gas to produce synthetic fuel. A regenerative heat energy supply part 28 supplies reaction heat generated when synthetic gas is synthesized into synthetic fuel by a synthetic fuel manufacturing device 32 using natural gas corresponding to carbon neutrality as a raw material, as regenerative heat energy, heats regenerative absorption liquid supplied from the bottom part of a regenerative part 27, changes part of moisture into steam and supplies it from the bottom part to the regenerative part 27, and thereby supplies the regenerative heat energy to the regenerative part 27. A synthetic fuel production device 32 using natural gas corresponding to carbon neutrality as a raw material is a device 30 generating carbon neutral thermal energy, and reaction heat generated in a synthetic reaction performed in the synthetic fuel production device 32 is thermal energy delivered from the device 30 generating carbon neutral thermal energy.|[0035] 7. Operation and effect in a third embodiment A synthetic fuel manufacturing device 32 manufactures a synthetic fuel, heat-transfers the generated reaction heat to a regenerative heat energy supply part 28 of a carbon dioxide recovery device 25 as regenerative heat energy, and heats a CO2-containing absorption liquid. Thus, in addition to the effect exerted by the first embodiment, the synthetic fuel can be produced with the carbon dioxide emission amount substantially zero by using the natural gas equivalent to carbon neutrality as a raw material in the synthetic fuel production apparatus 32.|[0036] 1a-1c:BECCS Green Power and Carbon Neutral Equivalent Natural Gas Production System, 10: Biomass Power Generation Unit, 12: Boiler, 15: Condensate Turbine, 16: Generator, 17: Power Grid, 18: Condenser, 21: Biomass Supply Unit, 25: Carbon Dioxide Recovery Unit, 26: Absorption Unit, 27: Regeneration Unit, 28: Heat Energy Supply Unit for Regeneration, 30: Equipment for Generating Carbon Neutral Heat Energy, 31: Cogeneration Unit, 32: Synthetic Fuel Production System, 41: LNG Vaporization Unit, 42: Stored Gas Cooling device, 43: Vaporizer, 44: Gas passage, 45: First cooling coil, 46: Eliminator, 47: Second cooling coil, 51: First heat medium circulation circuit, 52: Second heat medium circulation circuit, 53: Heat exchanger, 54: Adsorption type dehumidifier, 55: Natural gas utilization device, 60: Carbon dioxide gas liquefier | Family Number|(105528804)|105528804|Object of Invention|(JP2024150398W A1)| (...) which the amount of carbon dioxide gas generated by combustion becomes less than the amount of stored carbon dioxide gas by a prescribed percentage, To provide a green power and carbon neutral-equivalent natural gas production system using BECCS that can produce carbon neutral-equivalent natural gas and cool stored carbon dioxide to a low temperature. |The present invention relates to an BECCS (Bioenergy with Carbon dioxide Capture and Storage) that produces green power and the like using biomass energy and recovers and stores carbon dioxide gas produced by biomass combustion.|(JP7297278 B1)| (...) which the amount of carbon dioxide gas generated by combustion becomes less than the amount of stored carbon dioxide gas by a prescribed percentage, To provide a green power and carbon neutral-equivalent natural gas production system using BECCS that can produce carbon neutral-equivalent natural gas and cool stored carbon dioxide to a low temperature. |The present invention relates to an BECCS (Bioenergy with Carbon dioxide Capture and Storage) that produces green power and the like using biomass energy and recovers and stores carbon dioxide gas produced by biomass combustion.|(WO2024150398 A1)| The present invention relates to a bioenergy with carbon dioxide capture and storage (BECCS) whereby green power and the like are produced using biomass energy and carbon dioxide gas generated by biomass combustion is recovered and stored.| The purpose of the present invention is to produce green power by biomass power generation, and to produce green power and a system for producing natural gas equivalent to carbon neutrality that utilize BECCS, which are capable of producing natural gas equivalent to carbon neutrality and of cooling the stored carbon dioxide to a low temperature, by exchanging heat between stored carbon dioxide stored in the carbon dioxide generated by biomass power (...) |Title|(JP2024150398W A1)|Green Power and Carbon-Neutral Equivalent Natural Gas Production System Utilizing BECCS|(JP7297278 B1)|Green power and carbon neutral equivalent natural gas production system using BECCS|(WO2024150398 A1)|Green power and carbon-neutral equivalent natural gas production system using beccs|Système de production d'énergie verte et de gaz naturel équivalent neutre en carbone faisant appel à une beccs|Independent Claims|(WO2024150398 A1)| (...) the stored carbon dioxide is supplied from the carbon dioxide recovery device, and the liquefied natural gas is vaporized into natural gas and sent as natural gas equivalent to carbon neutrality, and the stored carbon dioxide is cooled The BECCS-based natural gas production system is equipped with an LNG vaporizer that delivers low-temperature stored carbon dioxide gas.| | Engines, pumps, turbines | F01K-017/02 | F01K-017/02 | F01K-017/02 | C10L-003/00|F01K-017/02 | WO202642305 | WO202642305 117908270 WHO=Examiner SELF=N CAT=A | JP7136523|WO2022180740|JP2001159318|JP7136523|WO2022180740|JP2001159318|JP07136523 | JP7136523 98323904 WHO=Examiner SELF=Y CAT=A|WO2022180740 96562855 WHO=Examiner SELF=Y CAT=A|JP2001159318 31379170 WHO=Examiner SELF=N CAT=A|JP7136523 98323904 WHO=Examiner SELF=Y|WO2022180740 96562855 WHO=Examiner SELF=Y|JP2001159318 31379170 WHO=Examiner SELF=N|JP07136523 28564565 WHO=Applicant SELF=N | 国立研究開発法人科学技術振興機構出版 低炭素社会戦略センター著 「低炭素社会実現に向けた政策立案のための提案書 バイオマス混焼発電を用いたＢＥＣＣＳによる炭素排出量削減のライフサイクル評価」２０２２年５月|特許第７１３６５２３号公報 | JP2001159318; 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Pat. without A|Publication country=JP|Publication number=JP7297278|Publication stage code=B1|Publication date=2023-06-26|Standardized publication number=JP7297278|Event publication date=2024-07-18|Event code=JP/A1|Event group=Examination events|Domestic re-publication of PCT application|Publication country=JP|Publication number=JPWO2024150398|Publication stage code=A1|Publication date=2024-07-18|Standardized publication number=JP2024150398W | (WO2024/150398)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2024/150398)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2024/150398)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, ME, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2024/150398)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2024/150398)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IQ, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, JM, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, CV, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (WO2024/150398)|WO; JP|(JP7297278)|JP | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=icjTorqguCDPmcyH0bktN90P/F2Pwh1EkaV0SMUACwOllNWWvacaWhEyjmCehg6RdJNcKluWvdhS0llBJ/BQPQ==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=WO0000000006540093&ekey=2687&xpn=WO2024150398&kind=A1 | http://www.wipo.int/patentscope/search/en/detail.jsf?docId=WO2024150398&redirectedID=true | https://permalink.orbit.com/RenderStaticFirstPage?XPN=iMDL9rKz2rQcBmEYBOpwmbmsLuw%252FR4oY%252BQgpgFzVRnM%3D%26n%3D1&id=0&base=FAMPAT | WO | (WO2024/150398)|JP | (WO2024/150398)|NAME=EUREKA ENGINEERING INC , COUNTRY=JP | (WO2024/150398)|JP| | (WO2024/150398)|NAME=KYORITSU INTERNATIONAL , COUNTRY=JP|(JP7297278)|NAME=KYORITSU INTERNATIONAL , REG=110000604NAME=KOBAYASHI, Osamu , REG=100089082 | (WO2024/150398)|JP| | (WO2024/150398)|NAME=ITO SHINZO, COUNTRY=JP|(JP7297278)|NAME=ITO SHINZO | (WO2024/150398)|2|(JP7297278)|2 | 1 | 2 | (JP7297278)|WO2024/150398 | (WO2024/150398)|Number of Claims: NCL=6|Extended kind: EXTK=x||(JP7297278)|Number of Claims: NCL=6|Primary examiner: 古▲瀬▼ 裕介||Primary examiner: 古▲瀬▼ 裕介| | (WO2024/150398)|JAPANESE (JPN) | (JP2024150398W)|Patent|(WO2024150398)|Patent|(JP7297278)|Patent | Titre: (WO2024/150398)|Green power and carbon-neutral equivalent natural gas production system using beccs Résumé: (WO2024/150398)|This system comprises: a biomass power generation device 10; a carbon dioxide recovery device 25; a device 30 for generating carbon-neutral thermal energy; and an LNG vaporization device 41. The biomass power generation device 10 produces green power, and the carbon dioxide recovery device 25 recovers carbon dioxide generated through biomass power generation. The LNG vaporization device 41 performs heat exchange between stored carbon dioxide which is part of the recovered carbon dioxide and is to be isolated from the atmosphere, and a liquefied natural gas in which the amount of carbon dioxide generated by combustion is smaller by a prescribed ratio than the amount of the stored carbon dioxide, to thereby vaporize and deliver the liquefied natural gas into a carbon-neutral equivalent natural gas, and cool the stored carbon dioxide to a low temperature. Accordingly, it is possible to produce green power, produce carbon-neutral equivalent natural gas for which emission credits can be said to already have been acquired, and cool a stored carbon dioxide to a low temperature at low cost. Autre: (WO2024/150398)|1. A biomass power generation device provided with: a power generator driven by a condensate turbine and sending out electric power; a boiler that combusts biomass supplied from a biomass supply device and supplies superheated steam to the condensate turbine; a condenser that condenses low-pressure steam discharged from the condensate turbine into condensed water; an absorption unit that is supplied with exhaust gas from the boiler and generates a CO2-containing absorption liquid by causing carbon dioxide gas contained in the exhaust gas to be absorbed into the absorption liquid; and a CO2-containing absorption liquid from the absorption unit The carbon dioxide recovery device is provided with: a regeneration unit to which liquid is supplied, and which heats the CO2-containing absorption liquid by means of thermal energy for regeneration and releases carbon dioxide gas; and a thermal energy supply unit for regeneration, which supplies the thermal energy delivered from a device that generates carbon neutral thermal energy to the regeneration unit as the thermal energy for regeneration. The carbon dioxide gas released by the regeneration unit is delivered as recovered carbon dioxide gas. The amount of carbon dioxide gas generated by burning is within the recovered carbon dioxide gas An LNG supply device for supplying liquefied natural gas in an amount smaller by a predetermined ratio than the amount of stored carbon dioxide; and a method for exchanging heat of cold LNG generated when the liquefied natural gas is supplied from the LNG supply device, the stored carbon dioxide is supplied from the carbon dioxide recovery device, and the liquefied natural gas is vaporized into natural gas and sent as natural gas equivalent to carbon neutrality, and the stored carbon dioxide is cooled The BECCS-based natural gas production system is equipped with an LNG vaporizer that delivers low-temperature stored carbon dioxide gas.|2. The regenerative thermal energy supply unit supplies heat emitted by steam bled from the condensate turbine to the regenerative unit as the regenerative thermal energy and heats the CO2-containing absorption liquid. The natural gas production system is equivalent to green power and carbon neutrality and utilizes the BECCS described in claim 1.|3. A cogeneration device is provided for supplying heat and power using a portion of the natural gas, which is supplied from the LNG vaporizer and corresponds to carbon neutrality. The heat energy supply unit for regeneration transfers heat generated by the cogeneration device to the regeneration unit as the heat energy for regeneration, and heats the CO2-containing absorbing liquid. The green power and natural gas production system utilizing the BECCS described in claim 1 utilizes the BECCS.|4. A system for producing green power and natural gas equivalent to carbon neutrality by utilizing the BECCS described in claim 1, wherein the system is provided with a synthetic fuel production device for producing a synthetic fuel by performing a synthetic reaction of a synthetic gas produced from the natural gas equivalent to carbon neutrality supplied from the LNG vaporization device, and the regenerative heat energy supply unit thermally transfers reaction heat generated in the synthetic reaction performed in the synthetic fuel production device to the regeneration unit as the regenerative heat energy and heats the CO2-containing absorption liquid.|5. A green power and carbon neutral equivalent natural gas production system utilizing the BECCS described in any one of claims 1 to 4, provided with a carbon dioxide liquefaction device for liquefying the low temperature stored carbon dioxide discharged from the LNG vaporization device.|6. The LNG vaporizer is provided with a vaporizer and a stored carbon dioxide gas cooling device. The vaporizer supplies the liquefied natural gas from the LNG supply device to the low temperature side, and circulates a second cooling coil provided in the stored carbon dioxide gas cooling device and an antifreeze heat medium flowing in the heat exchanger to the high temperature side. The liquefied natural gas and the antifreeze heat medium exchange LNG cold heat, vaporize the liquefied natural gas into natural gas, and deliver it as natural gas equivalent to carbon neutrality In the stored carbon dioxide gas cooling device, a first cooling coil, an eliminator, an adsorption-type dehumidifier, and the second cooling coil are arranged in series from one side to the other side, and the stored carbon dioxide gas flows in from an inlet on the one side and the low-temperature stored carbon dioxide gas flows out from an outlet on the other side; a second heat circulation circuit in which an antifreeze heat medium circulates between the low-temperature side of the second cooling coil and the heat exchanger and the high-temperature side of the vaporizer; and the first cooling coil and the heat exchanger The present invention is provided with: a first heat medium circulation circuit in which an antifreeze heat medium circulates through the high-temperature side; and a condensed water outflow unit in which the first cooling coil and the eliminator condense saturated water contained in the stored carbon dioxide gas, collect the captured condensed water, and flow out of the gas passage. The first cooling coil cools the stored carbon dioxide gas to condense the saturated water, the eliminator captures the condensed saturated water, and the adsorption type dehumidifier dries the stored carbon dioxide gas after drying The BECCS described in claim 5, which cools the stored carbon dioxide gas to a low temperature by the second cooling coil and sends the cooled carbon dioxide gas, is utilized in the green power and carbon neutral equivalent natural gas production system. | 1 | Abstract | gpt-4o-mini | yes | The article describes a system that combines biomass power generation with carbon dioxide recovery and storage, aligning with the BECCS definition. | |||||||||||||||
| 2 | SU3378179 | SU3378179 | SU1015261 | 37493595 | SU1015261 A1 1983-04-30 [SU1015261] | 1981-12-31 | 1981-12-31 | 1983-04-30 | (SU1015261)|1983-04-30 | (SU1015261)|1996-12-31 | (SU1015261)|Method of graduating lever-type aerodynamic balance using ac control circuit | (SU1015261)|THE METHOD OF CALIBRATION RY-, CHAZHNYKH OF AERODYNAMIC BECCS WITH THE DIAGRAM OF ADMINISTRATION ON ALTERNATING CURRENT, vktochayushiy adjustment sensitive g and iemertgelnogo to romyula by a change in the clearance by stator-rotor unit tsifferentsialno-trano the form of trodden oatchika of the deflection of yoke, posletsovatelnoe load R unloading by useful loads with off vibrovozbuaiteyae and the determination of the price of oeleniya of the tachometer of actuating screw is mobile of the weight of measuring yoke and error of measurement, about t l and ch and yu cabbage soups, also, I fact that, for the purpose of an increase in the accuracy of rhenium via iaslyucheniya of dynamic error, is carried out additional nag|: however, in zhenie and the unloading of weights by useful loads with start to vnbrovozbuditele, measure the minimum and maximum values of indications it echet the snip of the number Of Kh$orotov of the actuating screw of mobile weight, they calculate arithmetic mean value of counter readouts, determine values and sign of the difference between these average values and counter readouts for the same of Ra (I chikh loads with the load the weight of prt switched off of vibr (m of ovbudnte1Yu, after which produce a change in the angle of the slope of the stator of the sensor of the deflection of measuring yoke relative to rotor in the plane of rocking of the value of difference and in the direction of the sign of difference. | PREDPRIYATIE P YA G 4974 | (SU1015261)|PREDPRIYATIE P/YA G-4974 | KARULIN EVGENIJ I|RYLKOV VALERIJ D|TSAREV VALENTIN I | (SU1015261)|KARULIN EVGENIJ I,SU|RYLKOV VALERIJ D,SU|TSAREV VALENTIN I,SU | (SU1015261)|The latter applies to experimental aerodynamics, namely to many locking lever scales. Lime. method for graauing lever airfoil scales by loading a rocker with working weights -1. However, this method does not cover all the necessary stages of scale calibration with contactless rocker-head meters. The inventive method for plotting lever aerodynamic scales consists in adjusting the responsiveness of a measuring rocker by modifying the gap between a stator and the rotor of a weighting transformer of a rocker switching-off sensor, in successively loading and unloading said rocker weights with the vibro exciter disconnected and in determining the dividing price of the ticker of the speed of rotation of the traveling wing of the measuring rocker shaft and a measurement error 23. The disadvantage of the known zanlk method consists in that loading and unloading are carried out in the absence of vibration excitation, since this calibration method does not provide for the detection of a dynamic error. The aim of the invention is to increase measurement accuracy by excluding a dynamic error. The aim is achieved in that according to a method for calibrating lever aerodynamic scales with an alternating-current control circuit which includes adjusting the sensitivity of a measuring rocker, changing the gap between the stator and the rotor of the differential transformer sensor for deflecting the rocker, subsequently loading and unloading working loads with the vibration exciter disconnected and dividing the counter value for the number of turns of a moving weight propeller, the measurement rocker and the measurement error, additional loading is carried out and the scales are unloaded by the same working loads with the vibration exciter switched on, and the measurement is carried out the minimum and maximum values of the readings of a counter for the number of pieces of a propeller in a moving weight are deducted, the arithmetic mean value according to the instructions of the counter is calculated, the values and sign of the difference between these average values and the readings of the counter for the same working loads when the balance is balanced with the external exciter switched off, and then the angle of inclination of the casing of the sensor of the deflection of the measuring rocker to the rocking planes is adjusted by the value of the difference and in the direction of the sign of difference. Fig. 1 a and b show respectively the experimentally removed Nesimmet (the sheer characteristic of the motor starting moment and the dynamic measurement error caused by Nesimmet s characteristic; Fig. 2 -, the Illustrnr cozy calculation definition of the possible dynamic error at some value of the unsymmetry coefficient {I 1,6) of the electric motor characteristic; fig.. 3 - structural design for the first automatic rocker-beam measuring device which makes it possible to implement the proposed method. The aerodynamic balance comprises a rocker arm 1 which is fastened to a base 2 with the aid of two elastic supports 3. A movable loader (weight) 5 which can be moved by the neck of a nut 6, a sailing wing 7 and a rumped pair 8 by means of a two-phase asynchronous electric motor 9 is arranged on guides 4. The electric motor 9 is controlled via an amplifier (not shown) by a differential transformer sensor 10, which expresses a control signal, the sign of which depends on the direction of deviation of the rocker arm under the action of moments from the measured load directed along the thrust 11, n from the weight of the weight weight weight weight weight 5. For remote transmission of S.TUZHIT readings selsin - sensor 12, connected by coupling 13 and gear pair 8, respectively, to the running gear by screw 7 and electric motor 9. K (The measured load indicator shall be a decimal counter 14 connected by couplingA1 15 to a propeller 7. For the initial balancing of rocker arms, counterweights 16 are used. An inertial vibrator 17 having two oppositely rotating eccentric masses and a drive motor 18 is fixed to the rocker 1 to excite the involuntary oscillations of the measuring rocker 1 and the electric motor 9. The frequency of the excitatory force, which is directed perpendicular to the longitudinal axis of the rocker 1, is changed by changing the rotational frequency of the electric motor 18, and the amplitude of the moment at which the exciters are exited is changed by moving the vibrator along the rocker 1's sounding. In the setting of the device inamics, the oil damper 2O, the arreger 21 with additional springs and the built-in electroswing unit 9 of the tachogenerator of negative feedback by speed (not shown) are used. The stator of the digital sensor 10 for the deflection of the rocker arm 1 is equipped with an I2 bracket, to which it is fastened, with the aid of a 23-pin axis,{I1nno, on the post 24 of the base 2 of the instrument. To tilt the stator of the transducer relative to the rotor thereof, screws 25 are used, which counternut 26. The aerodynamic scales operate as follows. Under the constant load, h, with the symmetrical characteristic of the starting torque of the electric motor 9, the measuring rocker 1 oscillates around a position of equilibrium corresponding to the average position of the rotor of the sensor 1O relative to the stator of the sensor. Furthermore, the movable weight 5 oscillates around a position which it would occupy by the nfNo. measurement of the load in the absence of oscillations of the rocker arm 1 and of the positive motion of the rotor of the electric motor. When the measured load increases, the center of oscillations of the rocker arm 1 is shifted, wherein the center of oscillations of the rotor of the sensor 1LO is shifted, the sensor emits a signal, the constant component of which causes displacement, to the input of the amplifier feeding the electric motor 9. the center of oscillations of the electric motor rotor and the corresponding displacement of the center of oscillations of the movable weight in the direction of the increase of the working arm thereof. With the unchanged load and with the asymmetrical characteristic of the starting torque of the electric motor 9, the measuring beam 1 oscillates around the position of equilibrium which is mixed from the media of the position of the rotor of the sensor 1O relative to the stator of the sensor. Let the touching torque characteristic of the motor 9, taken by measuring it at various fixed values of the deflection of the rocker arm 1 with the aid of adjustable arresters 21, have a ring, represented on figure 10, i.e., the view when the maximum torque value is greater when the rocker arm is deflected upwards than when the rocker arm is deflected downwards. In this case, the center of oscillation of the rocker arm 1 when the vibrator is switched on shifts to an angle C) of ionise, and the center of oscillation of the rotor of the electric motor is shifted on the Uth hU in a direction corresponding to the uv-/1 angle of the arm of the weigh 5 relative to the area which it would occupy npt from the actual oscillations of the measuring rocker arm 1, and the constant component of the annamical measurement error has a gapos sign. The offset value g of the raider 5 is determined by the non-symmegrove characteristic coefficient n the ratio of the specific reducing moment C and emerv ° of the rocker 1 to the coefficient m of the weight of the load 5, according to the expression. Li-t.io A similar phenomenon occurs when the base of the automatic rocker arm tester vibrates at L1 chia of variable compositions in the measured load; and when the measuring rocker does not vibrate. The weights are graded using the following o6pa3ON4.... When the vibrator 17 (figure 3) is switched off, a calibration load equal to some (usually 1/16) part of the measuring range is applied with the aid of working loads along the 11th traction, wherein the measuring rocker 1 is deflected and the torus of the differential transformer sensor 10 of the rocker is offset vertically. The sensor signal is fed via an amplifier (not shown) to the control winding of a two-phase asynchronous electric motor 9, which moves the movable weight 5 along guides 4 with the aid of a toothed pair 8 and a travel screw 7 in the direction of restoring the equilibrium of the measuring rocker, which, in the event of a shocking shape, takes place in the middle position of the rotor of the sensor of the rocker deflection relative to the sensor stator. The decimal counter readings for the 14th speed of the propeller are recorded in the calibration protocol, and the weighing and unloading of the I weights are performed over the entire measurement range. Then, the weights are loaded with the same 1O working loads with the vibrator switched on. In the position of the light weight, the wind weight and the wind weight are in the mode of the frequency-induced oscillations with the chao toga equal to 1-2 Hz and the amplitude to the oscillations of the wind weight equal to 1-th and nioam of the counter of the number €Kk pOTOB of the propeller. During loading, the minimum and maximum readings of the reporter are recorded, the arithmetic mean of the readings of each pH ° and the value of working loads is calculated, the JeLines and the difference sign between said average readings and the counter readings for the same working loads when the weights are loaded in the absence are determined. VIA vibration excitation. The inclination angle of the stator of the sensor for deflecting the rocker relative to the rotor is then changed in the rocker swing plane with the aid of screws 25 and KOHTI 61"nuts 26. The magnitude and direction of the change in the angle of inclination are determined according to a greater1 and the sign of calculated differences between the readings of the meters in two types of weight loading. Thus, if the readings of the counter during the vibration{wakeup of the measuring rocker exceed the readings during the same working loads in the absence of vibration excitation, the rotation of the stator increases the gap between the stator and the rotor in the upper Purity thereof, the stator adjustment cycle is repeated until the difference in the readings of the counter does not reach an acceptable L of measurement error. ; The technical and economic effectiveness of the proposed method consists in increasing the accuracy of high-speed aerodynamic scales with an alternating-current control circuit, which results in preventing any repetition of model testing. ftuSff iyfifr|f|if «V|.f O-itmt tf iOKf Ktfmifep tetKpim about -tUfrnfff iairfMt SK | (SU1015261)|The latter applies to experimental aerodynamics, namely to many locking lever scales. Lime. method for graauing lever airfoil scales by loading a rocker with working weights -1. However, this method does not cover all the necessary stages of scale calibration with contactless rocker-head meters. The inventive method for plotting lever aerodynamic scales consists in adjusting the responsiveness of a measuring rocker by modifying the gap between a stator and the rotor of a weighting transformer of a rocker switching-off sensor, in successively loading and unloading said rocker weights with the vibro exciter disconnected and in determining the dividing price of the ticker of the speed of rotation of the traveling wing of the measuring rocker shaft and a measurement error 23. The disadvantage of the known zanlk method consists in that loading and unloading are carried out in the absence of vibration excitation, since this calibration method does not provide for the detection of a dynamic error. The aim of the invention is to increase measurement accuracy by excluding a dynamic error. The aim is achieved in that according to a method for calibrating lever aerodynamic scales with an alternating-current control circuit which includes adjusting the sensitivity of a measuring rocker, changing the gap between the stator and the rotor of the differential transformer sensor for deflecting the rocker, subsequently loading and unloading working loads with the vibration exciter disconnected and dividing the counter value for the number of turns of a moving weight propeller, the measurement rocker and the measurement error, additional loading is carried out and the scales are unloaded by the same working loads with the vibration exciter switched on, and the measurement is carried out the minimum and maximum values of the readings of a counter for the number of pieces of a propeller in a moving weight are deducted, the arithmetic mean value according to the instructions of the counter is calculated, the values and sign of the difference between these average values and the readings of the counter for the same working loads when the balance is balanced with the external exciter switched off, and then the angle of inclination of the casing of the sensor of the deflection of the measuring rocker to the rocking planes is adjusted by the value of the difference and in the direction of the sign of difference. Fig. 1 a and b show respectively the experimentally removed Nesimmet (the sheer characteristic of the motor starting moment and the dynamic measurement error caused by Nesimmet s characteristic; Fig. 2 -, the Illustrnr cozy calculation definition of the possible dynamic error at some value of the unsymmetry coefficient {I 1,6) of the electric motor characteristic; fig.. 3 - structural design for the first automatic rocker-beam measuring device which makes it possible to implement the proposed method. The aerodynamic balance comprises a rocker arm 1 which is fastened to a base 2 with the aid of two elastic supports 3. A movable loader (weight) 5 which can be moved by the neck of a nut 6, a sailing wing 7 and a rumped pair 8 by means of a two-phase asynchronous electric motor 9 is arranged on guides 4. The electric motor 9 is controlled via an amplifier (not shown) by a differential transformer sensor 10, which expresses a control signal, the sign of which depends on the direction of deviation of the rocker arm under the action of moments from the measured load directed along the thrust 11, n from the weight of the weight weight weight weight weight 5. For remote transmission of S.TUZHIT readings selsin - sensor 12, connected by coupling 13 and gear pair 8, respectively, to the running gear by screw 7 and electric motor 9. K (The measured load indicator shall be a decimal counter 14 connected by couplingA1 15 to a propeller 7. For the initial balancing of rocker arms, counterweights 16 are used. An inertial vibrator 17 having two oppositely rotating eccentric masses and a drive motor 18 is fixed to the rocker 1 to excite the involuntary oscillations of the measuring rocker 1 and the electric motor 9. The frequency of the excitatory force, which is directed perpendicular to the longitudinal axis of the rocker 1, is changed by changing the rotational frequency of the electric motor 18, and the amplitude of the moment at which the exciters are exited is changed by moving the vibrator along the rocker 1's sounding. In the setting of the device inamics, the oil damper 2O, the arreger 21 with additional springs and the built-in electroswing unit 9 of the tachogenerator of negative feedback by speed (not shown) are used. The stator of the digital sensor 10 for the deflection of the rocker arm 1 is equipped with an I2 bracket, to which it is fastened, with the aid of a 23-pin axis,{I1nno, on the post 24 of the base 2 of the instrument. To tilt the stator of the transducer relative to the rotor thereof, screws 25 are used, which counternut 26. The aerodynamic scales operate as follows. Under the constant load, h, with the symmetrical characteristic of the starting torque of the electric motor 9, the measuring rocker 1 oscillates around a position of equilibrium corresponding to the average position of the rotor of the sensor 1O relative to the stator of the sensor. Furthermore, the movable weight 5 oscillates around a position which it would occupy by the nfNo. measurement of the load in the absence of oscillations of the rocker arm 1 and of the positive motion of the rotor of the electric motor. When the measured load increases, the center of oscillations of the rocker arm 1 is shifted, wherein the center of oscillations of the rotor of the sensor 1LO is shifted, the sensor emits a signal, the constant component of which causes displacement, to the input of the amplifier feeding the electric motor 9. the center of oscillations of the electric motor rotor and the corresponding displacement of the center of oscillations of the movable weight in the direction of the increase of the working arm thereof. With the unchanged load and with the asymmetrical characteristic of the starting torque of the electric motor 9, the measuring beam 1 oscillates around the position of equilibrium which is mixed from the media of the position of the rotor of the sensor 1O relative to the stator of the sensor. Let the touching torque characteristic of the motor 9, taken by measuring it at various fixed values of the deflection of the rocker arm 1 with the aid of adjustable arresters 21, have a ring, represented on figure 10, i.e., the view when the maximum torque value is greater when the rocker arm is deflected upwards than when the rocker arm is deflected downwards. In this case, the center of oscillation of the rocker arm 1 when the vibrator is switched on shifts to an angle C) of ionise, and the center of oscillation of the rotor of the electric motor is shifted on the Uth hU in a direction corresponding to the uv-/1 angle of the arm of the weigh 5 relative to the area which it would occupy npt from the actual oscillations of the measuring rocker arm 1, and the constant component of the annamical measurement error has a gapos sign. The offset value g of the raider 5 is determined by the non-symmegrove characteristic coefficient n the ratio of the specific reducing moment C and emerv ° of the rocker 1 to the coefficient m of the weight of the load 5, according to the expression. Li-t.io A similar phenomenon occurs when the base of the automatic rocker arm tester vibrates at L1 chia of variable compositions in the measured load; and when the measuring rocker does not vibrate. The weights are graded using the following o6pa3ON4.... When the vibrator 17 (figure 3) is switched off, a calibration load equal to some (usually 1/16) part of the measuring range is applied with the aid of working loads along the 11th traction, wherein the measuring rocker 1 is deflected and the torus of the differential transformer sensor 10 of the rocker is offset vertically. The sensor signal is fed via an amplifier (not shown) to the control winding of a two-phase asynchronous electric motor 9, which moves the movable weight 5 along guides 4 with the aid of a toothed pair 8 and a travel screw 7 in the direction of restoring the equilibrium of the measuring rocker, which, in the event of a shocking shape, takes place in the middle position of the rotor of the sensor of the rocker deflection relative to the sensor stator. The decimal counter readings for the 14th speed of the propeller are recorded in the calibration protocol, and the weighing and unloading of the I weights are performed over the entire measurement range. Then, the weights are loaded with the same 1O working loads with the vibrator switched on. In the position of the light weight, the wind weight and the wind weight are in the mode of the frequency-induced oscillations with the chao toga equal to 1-2 Hz and the amplitude to the oscillations of the wind weight equal to 1-th and nioam of the counter of the number €Kk pOTOB of the propeller. During loading, the minimum and maximum readings of the reporter are recorded, the arithmetic mean of the readings of each pH ° and the value of working loads is calculated, the JeLines and the difference sign between said average readings and the counter readings for the same working loads when the weights are loaded in the absence are determined. VIA vibration excitation. The inclination angle of the stator of the sensor for deflecting the rocker relative to the rotor is then changed in the rocker swing plane with the aid of screws 25 and KOHTI 61"nuts 26. The magnitude and direction of the change in the angle of inclination are determined according to a greater1 and the sign of calculated differences between the readings of the meters in two types of weight loading. Thus, if the readings of the counter during the vibration{wakeup of the measuring rocker exceed the readings during the same working loads in the absence of vibration excitation, the rotation of the stator increases the gap between the stator and the rotor in the upper Purity thereof, the stator adjustment cycle is repeated until the difference in the readings of the counter does not reach an acceptable L of measurement error. ; The technical and economic effectiveness of the proposed method consists in increasing the accuracy of high-speed aerodynamic scales with an alternating-current control circuit, which results in preventing any repetition of model testing. ftuSff iyfifr|f|if «V|.f O-itmt tf iOKf Ktfmifep tetKpim about -tUfrnfff iairfMt SK | Family Number|(37493595)|37493595|Abstract|(SU1015261 A1)|THE METHOD OF CALIBRATION RY-, CHAZHNYKH OF AERODYNAMIC BECCS WITH THE DIAGRAM OF ADMINISTRATION ON ALTERNATING CURRENT, vktochayushiy adjustment sensitive g and iemertgelnogo to romyula by a change in the clearance by stator-rotor unit tsifferentsialno-trano the form of trodden oatchika of the deflection of yoke, posletsovatelnoe load R unloading by useful loads with off vibrovozbuaiteyae and the determination of the price of oeleniya of the tachometer of actuating screw is mobile of the weight of measuring yoke and error of measurement, about t l and ch and yu cabbage soups, also, I fact that, for the purpose of an increase in the accuracy of rhenium via iaslyucheniya of dynamic error, is carried out additional nag|: however, in zhenie and the unloading of weights by useful loads with start to vnbrovozbuditele, measure the minimum and maximum values of indications it echet the snip of the number Of Kh$orotov of the actuating screw of mobile weight, they calculate arithmetic mean value of counter readouts, determine values and sign of the difference between these average values and counter readouts for the same of Ra (I chikh loads with the load the weight of prt switched off of vibr (m of ovbudnte1Yu, after which produce a change in the angle of the slope of the stator of the sensor of the deflection of measuring yoke relative to rotor in the plane of rocking of the value of difference and in the direction of the sign of difference.|СПОСОБ ГРАДУИРОВКИ РЫ-, ЧАЖНЫХ АЭРОДИНАМИЧЕСКИХ BECCS СО СХЕМОЙ УПРАВЛЕНИЯ НА ПЕРЕМЕННОМ ТОКЕ, вкточаюший регулировку чувствительное г и иэмертгельного ко ромьюла изменением зазора статором и ротором цифференциально-трано форма торного оатчика отклонения коромысла, послецовательное нагружение R разгружение рабочими грузами при отключенном вибровозбуаитеяе и определение цены оеления счетчика Числа оборотов ходового винта подвижное гири измерительного коромысла и погрешности измерения, о т л и ч а ю щи и с я тем, что, с целью повышения точности рения путем иаслючения динамической ошибки, проводят дополнительное наг|: у- жение и разгружение весов же рабочими грузами при включением внбровозбудителе, измеряют минимальные и максимальные значения показаний ечет чика числа Х$оротов ходового винта подвижной гири, вычисляют среднее арифметическое значение показаний счетчика, определяют величины и знак разности между этими средними значениями и показаниями счетчиков для тех же ра(Я чих грузов при нагружении весе прт выключенном вибр(м овбуднте1Ю, после чего производят изменение угла наклона статора датчика отклонения измерительного коромысла относительно ротора в плоскости качания на величину разности и в направлении знака разности.| | Measurement | G01G-009/00 | G01G-009/00 | US8763440 | US8763440 66654332 WHO=Examiner SELF=N | EXPIRED | (SU1015261)|EXPIRED | DEAD | (SU1015261)|DEAD | (SU1015261)|LEGAL DETAILS FOR SU1015261|Actual or expected expiration date=1996-12-31|Legal state=DEAD|Status=EXPIRED|Event publication date=1981-12-31|Event code=SU/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=SU SU3378179|Application date=1981-12-31|Standardized application number=1981SU-3378179|Event publication date=1983-04-30|Event code=SU/A1|Event indicator=Pos|Event group=Event indicating In Force|Description of the invention for an inventor's certificate|Publication country=SU|Publication number=SU1015261|Publication stage code=A1|Publication date=1983-04-30|Standardized publication number=SU1015261|Event publication date=1996-12-31|Event code=SU/EEDX|Event indicator=Neg|Event group=Event indicating Not In Force|Patent has expired | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=Nao+aqRGcc2vIIZm8w5JnKCa4vFyxJplNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=SU1015261&ekey=894&xpn=SU1015261&kind=A1 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=i7Ff6VrOclsuw56Xk6cpNXfDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | SU | (SU1015261)|NAME=KARULIN EVGENIJ I,SU|NAME=RYLKOV VALERIJ D,SU|NAME=TSAREV VALENTIN I,SU | 1 | 1 | (SU1015261)|RUSSIAN (RUS) | (SU1015261)|Patent | Titre: (SU1015261)|Method of graduating lever-type aerodynamic balance using ac control circuit Résumé: (SU1015261)|THE METHOD OF CALIBRATION RY-, CHAZHNYKH OF AERODYNAMIC BECCS WITH THE DIAGRAM OF ADMINISTRATION ON ALTERNATING CURRENT, vktochayushiy adjustment sensitive g and iemertgelnogo to romyula by a change in the clearance by stator-rotor unit tsifferentsialno-trano the form of trodden oatchika of the deflection of yoke, posletsovatelnoe load R unloading by useful loads with off vibrovozbuaiteyae and the determination of the price of oeleniya of the tachometer of actuating screw is mobile of the weight of measuring yoke and error of measurement, about t l and ch and yu cabbage soups, also, I fact that, for the purpose of an increase in the accuracy of rhenium via iaslyucheniya of dynamic error, is carried out additional nag|: however, in zhenie and the unloading of weights by useful loads with start to vnbrovozbuditele, measure the minimum and maximum values of indications it echet the snip of the number Of Kh$orotov of the actuating screw of mobile weight, they calculate arithmetic mean value of counter readouts, determine values and sign of the difference between these average values and counter readouts for the same of Ra (I chikh loads with the load the weight of prt switched off of vibr (m of ovbudnte1Yu, after which produce a change in the angle of the slope of the stator of the sensor of the deflection of measuring yoke relative to rotor in the plane of rocking of the value of difference and in the direction of the sign of difference. Autre: nan | 6 | Abstract | gpt-4o-mini | no | The article discusses a method related to aerodynamic balance calibration and control circuits, which is unrelated to bioenergy or carbon capture and storage. | ||||||||||||||||||||||||||||||||||||||
| 3 | CN202610015675 | CN202610015675 | CN121775630 | 118365787 | CN121775630 A 2026-04-03 [CN121775630] | 2026-01-07 | 2026-01-07 | 2026-04-03 | (CN121775630)|2046-01-07 | (CN121775630)|Natural carbon fixation and sealing method | (CN121775630)|The invention belongs to the field of environmental protection, and particularly relates to a natural carbon sequestration method. The method comprises the steps of collecting and drying biomass to obtain dry biomass, distributing sealing units around a biomass collecting point, wherein the sealing units are dug landfill pits and/or built warehouses, water and air insulation liners are arranged in the landfill pits and the warehouses, the dry biomass is filled into the sealing units, the filled biomass is compacted, and then the sealing units are sealed. The method provides an economical, safe, scalable carbon removal path that overcomes the deficiencies of BECCS, BBCCS, and CCS. | TSINGHUA UNIVERSITY | (CN121775630)|TSINGHUA UNIVERSITY ([CN]) | WANG ZHE|YAN CHENYU|WU CHUNLEI|CHEN SHU|MA XINGHAO | (CN121775630)|WANG ZHE|YAN CHENYU|WU CHUNLEI|CHEN SHU|MA XINGHAO | (CN121775630)|LIU YING;UNITALEN INTELLECTUAL PROPERTY AGENTS LTD.|Reg. Nb: 11227 | (CN121775630)|The method provided by the invention has the technical advantages of 1) reducing the carbon removal cost, capturing carbon by utilizing natural photosynthesis, avoiding high-energy-consumption capturing equipment, controlling the unit cost to be less than or equal to 27 USD/t CO _2, 2) reducing the energy consumption and simplifying engineering, saving long-distance transportation and geological injection links by nearby distributed deployment and storage units, realizing mature technology and easy operation, 3) improving the safety, adopting solid carbon for storage and avoiding supercritical fluid risks, and 4) enhancing the deployment flexibility, namely realizing county scale distributed deployment based on biomass resource distribution without depending on geological conditions.|The technology of the invention, natural carbon sequestration and sequestration (Nature-based Carbon Capture and Storage, NBCCS), has a core advantage in terms of its economy.|3) Engineering complexity and deployment barriers are high in ① full-chain integration difficulty, BECCS needs to integrate a biomass supply chain, a power plant and geological storage facilities, system boundaries are complex, flexibility is low, ② geological dependence is strong, CCS and BECCS require specific geological structures (such as saline water layers) for storage, deployment is geographically limited, ③ long-term monitoring burden is that geological storage needs to continuously monitor leakage risks, and operation cost and uncertainty are increased.|BECCS, BBCCS and CCS suffer from the following key drawbacks that directly limit their scale deployment and economic viability:|① Without geologic matching, CCS and BECCS require specific geologic structures (e.g., brine layers), deployment is geographically limited, and NBCCS is buried shallow (5-10 m deep).| | (CN121775630)|1. The natural carbon fixation and sealing method is characterized by comprising the following steps of: collecting and drying biomass to obtain dry biomass; The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. | | (CN121775630)|Accordingly, it is an object of the present invention to provide a natural carbon sequestration process that provides an economical, safe, scalable carbon removal route that overcomes the deficiencies of BECCS, BBCCS and CCS.The invention provides a natural carbon fixation and sealing method, which comprises the following steps:|The invention provides a natural carbon fixation and sealing method, which comprises the following steps:| | (CN121775630)|SEALING(100,36)|CARBON FIXATION(100,6)|NATURAL CARBON FIXATION(100,5)|BECCS DEFICIENCY(100,2)|LANDFILL PIT(98,13)|NATURAL CARBON SEQUESTRATION(75,9)|NEARBY DISTRIBUTED DEPLOYMENT(74,1)|GEOLOGICAL DEPENDANCE(67,1)|ECONOMIC VIABILITY(61,1)|GEOLOGIC MATCHING(59,1)|GEOLOGICAL STORAGE FACILITY(59,1)|WAREHOUSE BUILDING(57,5)|DEPLOYMENT BARRIER(56,1)|GEOLOGICAL INJECTION(53,1)|DRYING BIOMASS(52,6)|ENGINEERING COMPLEXITY(52,1)|FILLED BIOMASS(51,5)|INTEGRATION DIFFICULTY(48,1)|DRY BIOMASS(47,6)|BIOMASS RESOURCE DISTRIBUTION(47,1)|DRIED FORESTRY RESIDUE(47,1)|SCALE DEPLOYMENT(47,1)|CARBON SEQUESTRATION(43,9)|COMPACTED BIOMASS DENSITY(43,2)|DEPLOYMENT FLEXIBILITY(41,3)|GEOLOGICAL STORAGE(41,1)|CAPTURING CARBON(40,1)|SCALABLE CARBON REMOVAL(40,1)|GAS INSULATION LINER(39,4)|NATURAL PHOTOSYNTHESIS(39,3)|MOISTURE CONTENT(38,2)|DISTRIBUTED DEPLOYMENT(37,3)|SUPERCRITICAL FLUID RISK(37,1)|DEPLOYMENT(36,3)|BECCS(35,14)|WAREHOUSE(35,6)|BIOMASS(33,15)|SEQUESTRATION(33,8)|CCS(32,16)|GEOLOGICAL CONDITION(31,2)|BIOMASS COLLECTION POINT(30,8)|BRINE LAYER(30,1)|BBCCS(29,11)|LEAKAGE RISK(29,2)|ECONOMY(29,1)|FULL CHAIN INTEGRATION DIFFICULTY(29,1)|AGRICULTURAL RESIDUE DRYING(28,1)|GEOLOGIC STRUCTURE(28,1)|PLANTING ENERGY CROP(28,1)|CEMENT MORTAR LAYER(27,4)|BIOMASS COLLECTING POINT(26,1)|BIOMASS SUPPLY CHAIN(26,1)|GEOLOGICAL STRUCTURE(26,1)|UNCERTAINTY(25,2)|NATURE CARBON CAPTURE(25,1)|NBCCS(24,8)|SCALABLE CARBON REMOVAL PATH(24,1)|SAFE(23,2)|ENGINEERING(22,2)|CARBON REMOVAL COST(22,1)|AIR INSULATION LINER(21,1)|WATER RESISTANT GEOMEMBRANE(21,1)|COUNTY(20,2)|GAS BARRIER LINER(20,1)|WATERPROOF GEOMEMBRANE(18,3)|LONG TERM MONITORING BURDEN(18,1)|SWEET SORGHUM(17,5)|MISCANTHUS(17,4)|SAVING LONG DISTANCE TRANSPORTATION(17,1)|GAS PROTECTION(16,5)|ORGANIZATION BOUNDARY(16,1)|SALINE WATER LAYER(16,1)|SOLID CARBON(15,3)|MARGINAL LAND(14,6)|ENVIRONMENTAL PROTECTION(14,2)|SOLVENT REGENERATION(13,4)|BIOMASS COMPACTION DENSITY(13,2)|SALINE WATER(13,1)|CARBON CAPTURE(12,4)|ANAEROBIC ENVIRONMENT(11,3)|COUNTY GDP(11,2)|SHIELDING GAS(10,3)|CCS TRAPPING(10,1)|DISTRIBUTING SEQUESTRATION(10,1)|FORESTRY RESIDUE COMPACTED DENSITY(10,1)|LANDFILL PIT DEPTH(10,1)|SUPPLY CHAIN(10,1)|ENERGY CROP PLANTING(9,3)|GEOLOGICAL SEALING(9,2)|ROLLER DRYER(9,2)|COUNTY DEPLOYMENT(9,1)|DEEP GEOLOGICAL INJECTION(9,1)|DISTRIBUTED DEPLOYMENT DECISION(9,1)|ECONOMIC SYNERGISTIC BENEFIT(9,1)|LANDFILL PIT VOLUME(9,1)|LOCALIZATION ECONOMY(9,1)|MONTE CARLO SIMULATION(9,1)|NEARBY DEPLOYMENT(9,1)|OPERATION COST(9,1)|OPTIMIZATION STRATEGY(9,1)|PIT DEPTH BASELINE(9,1)|STRAW COMPACTED DENSITY(9,1)|TRANSPORTATION EXPENDITURE(9,1)|USD T(8,15)|ENERGY CONSUMPTION(8,14)|POWER PLANT(8,3)|CAPTURING FACILITY(8,1)|CCS CAPTURE(8,1)|CENTRALIZED FACILITY(8,1)|COUNTY PURCHASING COST(8,1)|ECONOMIC SYNERGY(8,1)|LINING LAYING(8,1)|NBCCS ENERGY INTENSIVE TRAPPING(8,1)|NBCCS SKIP(8,1)|RAPID REPLICATION(8,1)|RESOURCE ASSESSMENT(8,1)|RESOURCE RICH(8,1)|STORAGE UNIT(8,1)|TUNNEL HUMIDITY(8,1)|REMOVING CARBON(6,4)|NBCCS COST(6,2)|ANNUAL EMISSION(6,1)|ANNUAL SAMPLING COST(6,1)|CHINESE CARBON MARKET PRICE(6,1)|COLLECTED BIOMASS(6,1)|COLLECTION COEFFICIENT(6,1)|CORE INNOVATION(6,1)|CROP CARBON(6,1)|CROP RESIDUE ANNUAL YIELD(6,1)|DRY BIOMASS MASS(6,1)|GLOBAL CARBON CIRCULATION(6,1)|LAND OCCUPANCY RATE(6,1)|MOISTURE INSULATION(6,1)|NATURAL STACKING HEIGHT(6,1)|SEQUESTRATION DENSITY(6,1)|UTILIZATION COEFFICIENT(6,1)|VEHICLE TRANSPORTATION(6,1)|COMPACTING(5,2)|MICROORGANISM(5,2)|AVAILABLE BIOMASS RESOURCE(5,1)|BIOENERGY CARBON CAPTURE(5,1)|BIOMASS CARBON CONTENT(5,1)|BIOMASS CARBON REMOVAL(5,1)|BURYING CONDITION(5,1)|CAP FRACTURE(5,1)|CCUS(5,1)|DRYING EQUIPMENT(5,1)|ENERGY PENALTY(5,1)|EQUIPMENT SHARING(5,1)|MAINSTREAM(5,1)|MEDIUM SCENARIO(5,1)|NBCCS ENERGY CONSUMPTION(5,1)|NBCCS TUNNEL AREA(5,1)|SHALLOW BURIED ENGINEERING FLOW(5,1)|SIMPLIFY ENGINEERING CHAIN(5,1)|STACK HEIGHT(5,1)|STORAGE INFRASTRUCTURE(5,1)|WATERPROOF FILM(5,1)| | (CN121775630)|1. The natural carbon fixation and sealing method is characterized by comprising the following steps of:| collecting and drying biomass to obtain dry biomass; | The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; | and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. |2. A natural carbon sequestration process according to claim 1, characterised in that the biomass comprises agricultural residues and/or forestry residues.|3. The natural carbon sequestration method of claim 2, wherein the moisture content of the dried agricultural residues is 15-20% and the moisture content of the dried forestry residues is 20-25%.|4. The method for sequestration of natural carbon as in claim 1, wherein the sequestration unit is less than or equal to 20km from the biomass collection point.|5. The method of claim 1, wherein the water-and gas-barrier liner is a water-resistant geomembrane or a cement mortar layer.|6. The method of claim 1, wherein the density of the compacted biomass is 0.2-0.3 t/m 3.|7. The method of claim 1, further comprising the steps of:| Before sealing, a protective gas is injected into the sealing unit. |8. The natural carbon sequestration process of claim 7 wherein the shielding gas is N 2 and/or CO 2.|9. The method of claim 1, further comprising the steps of:| After the sealing is completed, the CH 4 concentration, the CO 2 concentration and the humidity in the sealing unit are monitored for a long time. |10. The method of claim 1, further comprising the steps of:| Planting energy crops in marginal lands; | the energy crops include one or more of switchgrass, miscanthus and sweet sorghum. | (CN121775630)|TECHNICAL FIELD|Technical Field|[0001] The invention belongs to the field of environmental protection, and particularly relates to a natural carbon sequestration method.|BACKGROUND ART|[0002] According to Paris's protocol, global temperature rise needs to be controlled to within 2 ℃ and efforts are made to be limited to within 1.5 ℃. IPCC and International Energy Agency (IEA) state that global CO 2 emissions need to reach net zero in the middle of the century, carbon capture, utilization and storage (CCUS) technologies are an integral part of achieving this goal. However, the current technology path faces serious challenges in global carbon circulation, with annual carbon flux of land system up to 477 Gt CO 2 yr-1 and marine system 294 Gt CO 2 yr-1, far exceeding annual emissions from humans (about 40 Gt CO 2 yr-1), suggesting that large scale carbon removal can be achieved by regulating organic matter breakdown.|[0003] Existing carbon removal (CDR) technologies mainly include bioenergy carbon capture and storage (BECCS), biochar-based carbon capture and storage (BBCCS) and traditional Carbon Capture and Storage (CCS), all of which aim to achieve carbon fixation by engineering means, but the routes are different, 1) BECCS is currently the most mainstream biomass-based carbon removal scheme, the core of which is to use biomass (such as crop residues, forestry residues) for energy production (such as power generation) and capture CO 2 during combustion, and then transport and injection into geological formation for sequestration, 2) BBCCS is to produce biochar by pyrolysis of biomass and apply it to soil for long-term carbon sequestration, BBCCS can provide economic synergistic benefits such as synthesis gas recovery and crop yield increase by soil improvement, and 3) traditional CCS as a reference technology, CCS captures CO 2 from fossil fuel power plants (such as coal electricity) and compresses into supercritical fluid and then injects into deep geological formations.|[0004] BECCS, BBCCS and CCS suffer from the following key drawbacks that directly limit their scale deployment and economic viability:|[0005] 1) The cost is too high, the unit carbon removal cost of BECCS, BBCCS and CCS is far higher than the current carbon market price, BECCS average cost is 102.96 USD/t CO 2, BBCCS is 97.10 USD/t CO 2, CCS is 92.81 USD/t CO 2, and Chinese carbon market price is generally lower than 50 USD/t CO 2. The high cost is mainly caused by ① capturing stage energy consumption, wherein the CCS needs to consume 200-300 kWh/t CO 2 power for solvent regeneration, and ② transportation and storage infrastructure, namely BECCS and CCS depend on long-distance pipeline or vehicle transportation, so that expenditure is increased. |[0006] 2) The energy consumption is huge, and the prior art is an energy-intensive process. For example, the CCS trapping system needs additional steam (2600-3500 MJ/t CO 2) and power to cause energy penalty, BECCS can generate energy, but occupies externally available power resources to introduce system energy consumption loss.|[0007] 3) Engineering complexity and deployment barriers are high in ① full-chain integration difficulty, BECCS needs to integrate a biomass supply chain, a power plant and geological storage facilities, system boundaries are complex, flexibility is low, ② geological dependence is strong, CCS and BECCS require specific geological structures (such as saline water layers) for storage, deployment is geographically limited, ③ long-term monitoring burden is that geological storage needs to continuously monitor leakage risks, and operation cost and uncertainty are increased.|[0008] 4) Safety risks deep geological injection of supercritical CO 2 may cause cap fracture, groundwater contamination or seismic activity. Supercritical CO 2 has a density (0.65-0.75 t/m 3) lower than solid carbon, low sequestration density and high risk.|DISCLOSURE|Disclosure of Invention|[0009] Accordingly, it is an object of the present invention to provide a natural carbon sequestration process that provides an economical, safe, scalable carbon removal route that overcomes the deficiencies of BECCS, BBCCS and CCS.|[0010] The invention provides a natural carbon fixation and sealing method, which comprises the following steps:|[0011] collecting and drying biomass to obtain dry biomass; |[0012] The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; |[0013] and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. |[0014] Preferably, the biomass comprises agricultural residues and/or forestry residues.|[0015] Preferably, the water content of the agricultural residues after drying is 15-20%, and the water content of the forestry residues after drying is 20-25%.|[0016] Preferably, the distance between the sealing unit and the biomass collection point is less than or equal to 20km.|[0017] Preferably, the waterproof and gas-barrier lining is a waterproof geomembrane or a cement mortar layer.|[0018] Preferably, the density of the biomass after compaction is 0.2-0.3 t/m 3.|[0019] Preferably, the method further comprises the step of injecting a protective gas into the sealing unit before sealing.|[0020] Preferably, the shielding gas is N 2 and/or CO 2.|[0021] Preferably, the method further comprises the step of monitoring the CH 4 concentration, the CO 2 concentration and the humidity in the sealing unit for a long time after the sealing is completed.|[0022] Preferably, the method further comprises the step of planting an energy crop on the marginal land, the energy crop comprising one or more of switchgrass, miscanthus and sweet sorghum.|[0023] Compared with the prior art, the natural carbon sequestration method comprises the steps of collecting and drying biomass to obtain dry biomass, distributing sequestration units around biomass collection points, wherein the sequestration units are dug landfill pits and/or built warehouses, water and gas insulation liners are arranged in the landfill pits and the warehouses, the dry biomass is filled into the sequestration units, then the filled biomass is compacted, and then the sequestration units are sealed. The method provided by the invention has the technical advantages of 1) reducing the carbon removal cost, capturing carbon by utilizing natural photosynthesis, avoiding high-energy-consumption capturing equipment, controlling the unit cost to be less than or equal to 27 USD/t CO 2, 2) reducing the energy consumption and simplifying engineering, saving long-distance transportation and geological injection links by nearby distributed deployment and storage units, realizing mature technology and easy operation, 3) improving the safety, adopting solid carbon for storage and avoiding supercritical fluid risks, and 4) enhancing the deployment flexibility, namely realizing county scale distributed deployment based on biomass resource distribution without depending on geological conditions.|INVENTION MODE|Detailed Description|[0024] The following description of the embodiments of the present invention will be made clearly and completely, and it is apparent that the described embodiments are only some embodiments of the present invention, but not all embodiments. All other embodiments, which can be made by those skilled in the art based on the embodiments of the invention without making any inventive effort, are intended to be within the scope of the invention.|[0025] The invention provides a natural carbon fixation and sealing method, which comprises the following steps:|[0026] collecting and drying biomass to obtain dry biomass; |[0027] The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; |[0028] and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. |[0029] In the methods provided herein, the available biomass resources are preferably precisely quantified and analyzed for spatial distribution prior to collection and drying of the biomass to support distributed deployment decisions. In the present invention, resource assessment is based on annual yield of crop residues and forestry residues, and the annual yield of residues can be calculated using formula (I):|[0030] Formula (I); |[0031] In the formula (I), Y i is crop yield, alpha i is residue-yield ratio, eta i is collection coefficient, and mu i is utilization coefficient. |[0032] In the method provided by the invention, the carbon removal potential is quantified, preferably based on the amount of resources, using monte carlo simulation (n=10000) and the uncertainty is evaluated, before biomass is collected and dried. The core formula is shown as formula (II):|[0033] Formula (II); |[0034] In the formula (II), M bio is the mass of dry biomass, f c is the biomass carbon content, and eta sequest is the sequestration efficiency, which can be assumed to be 0.95, based on the resource evaluation result. |[0035] In the method provided by the invention, the biomass preferably comprises agricultural residues and/or forestry residues, the water content of the agricultural residues after drying is preferably 15-20%, and the water content of the forestry residues after drying is preferably 20-25%.|[0036] In the method provided by the invention, the drying mode is preferably natural air drying and/or mechanical drying. The stacking height of the natural air drying is preferably 0.4-0.8 m, the time consumption of the natural air drying is preferably 50-70 days, and the mechanical drying equipment is preferably a roller dryer.|[0037] In the method provided by the invention, the sealing units are distributed around the biomass collection point, and the distance between the sealing units and the biomass collection point is preferably less than or equal to 20km, more preferably less than or equal to 5km.|[0038] In the method provided by the invention, the sealing unit preferentially digs the landfill pit, and when no burying condition exists, a warehouse can be selectively built.|[0039] In the method provided by the invention, the depth of the landfill pit can be specifically selected according to actual geological conditions, available land area and economical efficiency, preferably 5-10 m, the volume of the landfill pit is calculated according to the biomass compaction density, and the calculation formula is shown as formula (III):|[0040] Formula (III); |[0041] In formula (II), M bio is the dry biomass mass and ρ bulk is the compacted biomass density. |[0042] In the method provided by the invention, the lining is arranged for isolating moisture, oxygen and microorganisms, the lining is preferably a waterproof geomembrane or a cement mortar layer, and the thickness of the cement mortar layer is preferably 0.02-0.08 m, more preferably 0.05m.|[0043] In the method provided by the invention, the density of the biomass after compaction is preferably 0.2-0.3 t/m 3.|[0044] In the method provided by the invention, the method preferably further comprises the step of injecting a protective gas into the sealing unit before sealing. In the present invention, the purpose of the injection of the shielding gas is to create an anaerobic environment, preferably N 2 and/or CO 2.|[0045] In the method provided by the invention, the sealing mode is preferably to cover the waterproof membrane.|[0046] In the method provided by the invention, in order to ensure the anaerobic environment in the tunnel to be stable, the method preferably further comprises the step of monitoring the CH 4 concentration, the CO 2 concentration and the humidity in the sealing unit for a long time after the sealing is completed.|[0047] In the method provided by the invention, the method preferably further comprises the step of planting energy crops on marginal lands. Wherein the energy crop preferably comprises one or more of switchgrass, miscanthus and sweet sorghum.|[0048] The method provided by the invention preferably further comprises the step of carrying out cost optimization, wherein the optimization strategy comprises 1) minimizing the transportation distance, namely defining the transportation rate to be 0.112-0.168 USD/t & km, controlling the average distance to be within 20km through nearby deployment, 2) improving the equipment sharing and utilization rate, namely reducing the unit cost median to 31 USD/t CO 2 through a county-level village sharing model, only needing 1-4 sealing units for county deployment, and improving the equipment utilization rate, and 3) adjusting the cost based on county GDP, namely adjusting the labor cost scaling factor to be 0.50 based on county GDP (GDP high), wherein the resource rich and county purchasing cost scaling factor is 0.25, so that the localization economy is ensured.|[0049] The method provided by the invention has at least the following key points:|[0050] 1) Natural photosynthesis driven carbon capture, namely natural carbon fixation is realized by utilizing biological carbon of crops and forestry residues through photosynthesis, so that energy-intensive capture equipment is avoided, the solvent regeneration and compression links of the traditional CCUS are omitted, and the energy consumption is reduced to 2.90% -10.74% of the CCS. |[0051] 2) The distributed solid-state sealing unit is used for closely processing biomass to avoid long-distance transportation, the volume sealing density reaches 0.33-0.36 t CO 2/m3 which is 6 times of geological sealing, and the median of county-level land occupation rate is only 0.0062%, so that the deployment flexibility is realized.|[0052] 3) Engineering flow is simplified by reducing complexity through standardized flow (collection-drying-sequestration-monitoring).|[0053] 4) Integrated energy crop expansion potential, namely planting energy crops (such as switchgrass, miscanthus and sweet sorghum) on marginal lands, and increasing sealing potential.|[0054] The method provided by the invention has at least the following advantages:|[0055] 1) Cost advantage: |[0056] The technology of the invention, natural carbon sequestration and sequestration (Nature-based Carbon Capture and Storage, NBCCS), has a core advantage in terms of its economy. The unit carbon removal cost average for NBCCS in medium scenario is 27.04 USD/t CO 2, while the costs for BECCS, BBCCS and CCS are 102.96 USD/t CO 2、97.10 USD/t CO2 and 92.81 USD/t CO 2, respectively. This means that the cost of NBCCS is only 26.26% of BECCS, 27.85% of BBCCS and 29.13% of CCS. The low cost is mainly due to the following: |[0057] ① The energy-intensive trapping of NBCCS is avoided, the natural photosynthesis is utilized to fix carbon, and links such as solvent regeneration and compression are omitted. |[0058] ② The transportation expenditure is reduced, the average transportation distance is controlled within 20km by distributed deployment, the transportation cost is only 0.112-0.168 USD/t.km, and BECCS and CCS are required to be transported by long-distance pipelines, so that the cost is increased by 5-15 USD/t CO 2.|[0059] 2) Energy consumption advantage:|[0060] the energy consumption of NBCCS is extremely low, and the energy consumption of the full life cycle is only 2.90% -10.74% of that of CCS. The specific reasons are as follows: |[0061] ① No trapping energy consumption is that the trapping stage of CCS and BECCS consumes 200-300 kWh/t CO 2 power for solvent regeneration, and NBCCS skips this step. |[0062] ② The process is simplified, the energy consumption for drying and compacting is low, the natural air drying ratio can reach more than 50%, and the energy consumption for mechanical drying is only 0.225 kWh/m 3.|[0063] 3) Deployment flexibility:|[0064] NBCCS supports county scale distributed deployment, whereas the prior art relies on centralized facilities. Key advantages include: |[0065] ① Without geologic matching, CCS and BECCS require specific geologic structures (e.g., brine layers), deployment is geographically limited, and NBCCS is buried shallow (5-10 m deep). |[0066] ② The land occupancy rate is low, the tunnel area of NBCCS only occupies 0.0062 percent (median) of administrative area of county, and the pit depth can be further reduced to 0.00450 percent by optimizing.|[0067] ③ And the quick replication is realized by utilizing the existing agricultural machinery, the deployment period is short, and BECCS times of 3-5 years are required to construct a power plant and a capturing facility.|[0068] 4) Safety advantage:|[0069] The NBCCS adopts solid carbon for sealing, and the safety is far higher than that of the prior art: |[0070] ① There is no risk of leakage, avoiding cap layer cracking or earthquakes that may be caused by supercritical CO 2 injection. The NBCCS sealing density reaches 0.33-0.36 t CO 2/m3, which is 4.5 times of that of geological sealing (0.65-0.75 t/m 3), and the stability is high. |[0071] ② The monitoring is simple, only the air and the humidity of the tunnel are required to be tracked, and the CCS is required to monitor the network in a deep part, so that the cost is high and complex.|[0072] 5) Expansibility and synergistic benefits:|[0073] NBCCS can expand sequestration potential through energy crop planting, whereas the prior art is limited: |[0074] ① And (3) utilizing marginal land, namely planting switchgrass or sweet sorghum in the marginal land, wherein the sealing potential can be increased by 0.84 Gt CO 2yr-1. |[0075] ② Economic synergy, the switchgrass path cost can be reduced to 20.55 USD/t CO 2, and the farmland is not occupied.|[0076] In summary, NBCCS is superior to BECCS, BBCCS and CCS in terms of cost, energy consumption, deployment, security and scalability. The core innovation is to simplify the engineering chain by utilizing the natural process, and realize the carbon removal with low threshold and high efficiency. The NBCCS cost is aligned with the current carbon market price (about 50 USD/t CO 2 in China) and provides a viable path for large-scale deployment.|[0077] For clarity, the following examples are provided in detail.|[0078] Example 1|[0079] The shallow buried engineering flow is specifically introduced as follows:|[0080] Step 1, collecting and drying biomass |[0081] Biomass is collected, the collected biomass needs to be dried to reduce the water content to 15-20% (agricultural residues) or 20-25% (forestry residues), and two alternative drying schemes are provided:|[0082] ① Natural air drying, namely piling up for 0.4-0.8 m, which takes 50-70 days, and only renting the land (0.07-0.14 USD/m 2 yr); |[0083] ② Mechanical drying, namely adopting a roller dryer (capacity is 3 t/h), wherein the energy consumption is the heat value required by heating the water. |[0084] Step 2, excavation of tunnels and lining laying|[0085] Digging a tunnel on the land, wherein the pit depth baseline is 5m, the volume is calculated according to the compaction density of biomass, paving a lining in the tunnel, wherein the lining adopts a waterproof geomembrane (the cost is 0.42 USD/m 2) or cement mortar (the thickness is 0.05m, the cost is 70 USD/t), and the lining needs to be isolated from moisture, oxygen and microorganisms.|[0086] Step 3, compacting and injecting gas into the biomass|[0087] Filling dry biomass into the tunnel, compacting the biomass to a target density (the compacted density of forestry residues can reach 0.30 t/m 3 and the compacted density of straws is 0.20-0.25 t/m 3) by using a compactor (the speed is 9000 m 2/h and the oil consumption is 22L/h), and then injecting protective gas (the injection rate of N 2 or CO 2):N2 is 750 m 3/h, the energy consumption is 0.225 kWh/m 3;CO2 and the injection rate is the same, but outsourcing CO 2 is needed).|[0088] Step 4, sealing and long-term monitoring|[0089] After the injection of the protective gas is finished, the surface of the tunnel is covered with a waterproof film for sealing, and then the concentration of CH 4, the concentration of CO 2 and the humidity of soil in the tunnel are monitored for a long time through a gas and humidity sensor (the cost of a monitoring unit is 3500 USD and the annual sampling cost is 420 USD), so that the anaerobic environment in the tunnel is ensured to be stable.|[0090] The foregoing is merely a preferred embodiment of the present invention and it should be noted that modifications and adaptations to those skilled in the art may be made without departing from the principles of the present invention, which are intended to be comprehended within the scope of the present invention. | (CN121775630)|TECHNICAL FIELD|Technical Field|[0001] The invention belongs to the field of environmental protection, and particularly relates to a natural carbon sequestration method.|BACKGROUND ART|[0002] According to Paris's protocol, global temperature rise needs to be controlled to within 2 ℃ and efforts are made to be limited to within 1.5 ℃. IPCC and International Energy Agency (IEA) state that global CO 2 emissions need to reach net zero in the middle of the century, carbon capture, utilization and storage (CCUS) technologies are an integral part of achieving this goal. However, the current technology path faces serious challenges in global carbon circulation, with annual carbon flux of land system up to 477 Gt CO 2 yr-1 and marine system 294 Gt CO 2 yr-1, far exceeding annual emissions from humans (about 40 Gt CO 2 yr-1), suggesting that large scale carbon removal can be achieved by regulating organic matter breakdown.|[0003] Existing carbon removal (CDR) technologies mainly include bioenergy carbon capture and storage (BECCS), biochar-based carbon capture and storage (BBCCS) and traditional Carbon Capture and Storage (CCS), all of which aim to achieve carbon fixation by engineering means, but the routes are different, 1) BECCS is currently the most mainstream biomass-based carbon removal scheme, the core of which is to use biomass (such as crop residues, forestry residues) for energy production (such as power generation) and capture CO 2 during combustion, and then transport and injection into geological formation for sequestration, 2) BBCCS is to produce biochar by pyrolysis of biomass and apply it to soil for long-term carbon sequestration, BBCCS can provide economic synergistic benefits such as synthesis gas recovery and crop yield increase by soil improvement, and 3) traditional CCS as a reference technology, CCS captures CO 2 from fossil fuel power plants (such as coal electricity) and compresses into supercritical fluid and then injects into deep geological formations.|[0004] BECCS, BBCCS and CCS suffer from the following key drawbacks that directly limit their scale deployment and economic viability:|[0005] 1) The cost is too high, the unit carbon removal cost of BECCS, BBCCS and CCS is far higher than the current carbon market price, BECCS average cost is 102.96 USD/t CO 2, BBCCS is 97.10 USD/t CO 2, CCS is 92.81 USD/t CO 2, and Chinese carbon market price is generally lower than 50 USD/t CO 2. The high cost is mainly caused by ① capturing stage energy consumption, wherein the CCS needs to consume 200-300 kWh/t CO 2 power for solvent regeneration, and ② transportation and storage infrastructure, namely BECCS and CCS depend on long-distance pipeline or vehicle transportation, so that expenditure is increased. |[0006] 2) The energy consumption is huge, and the prior art is an energy-intensive process. For example, the CCS trapping system needs additional steam (2600-3500 MJ/t CO 2) and power to cause energy penalty, BECCS can generate energy, but occupies externally available power resources to introduce system energy consumption loss.|[0007] 3) Engineering complexity and deployment barriers are high in ① full-chain integration difficulty, BECCS needs to integrate a biomass supply chain, a power plant and geological storage facilities, system boundaries are complex, flexibility is low, ② geological dependence is strong, CCS and BECCS require specific geological structures (such as saline water layers) for storage, deployment is geographically limited, ③ long-term monitoring burden is that geological storage needs to continuously monitor leakage risks, and operation cost and uncertainty are increased.|[0008] 4) Safety risks deep geological injection of supercritical CO 2 may cause cap fracture, groundwater contamination or seismic activity. Supercritical CO 2 has a density (0.65-0.75 t/m 3) lower than solid carbon, low sequestration density and high risk.|DISCLOSURE|Disclosure of Invention|[0009] Accordingly, it is an object of the present invention to provide a natural carbon sequestration process that provides an economical, safe, scalable carbon removal route that overcomes the deficiencies of BECCS, BBCCS and CCS.|[0010] The invention provides a natural carbon fixation and sealing method, which comprises the following steps:|[0011] collecting and drying biomass to obtain dry biomass; |[0012] The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; |[0013] and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. |[0014] Preferably, the biomass comprises agricultural residues and/or forestry residues.|[0015] Preferably, the water content of the agricultural residues after drying is 15-20%, and the water content of the forestry residues after drying is 20-25%.|[0016] Preferably, the distance between the sealing unit and the biomass collection point is less than or equal to 20km.|[0017] Preferably, the waterproof and gas-barrier lining is a waterproof geomembrane or a cement mortar layer.|[0018] Preferably, the density of the biomass after compaction is 0.2-0.3 t/m 3.|[0019] Preferably, the method further comprises the step of injecting a protective gas into the sealing unit before sealing.|[0020] Preferably, the shielding gas is N 2 and/or CO 2.|[0021] Preferably, the method further comprises the step of monitoring the CH 4 concentration, the CO 2 concentration and the humidity in the sealing unit for a long time after the sealing is completed.|[0022] Preferably, the method further comprises the step of planting an energy crop on the marginal land, the energy crop comprising one or more of switchgrass, miscanthus and sweet sorghum.|[0023] Compared with the prior art, the natural carbon sequestration method comprises the steps of collecting and drying biomass to obtain dry biomass, distributing sequestration units around biomass collection points, wherein the sequestration units are dug landfill pits and/or built warehouses, water and gas insulation liners are arranged in the landfill pits and the warehouses, the dry biomass is filled into the sequestration units, then the filled biomass is compacted, and then the sequestration units are sealed. The method provided by the invention has the technical advantages of 1) reducing the carbon removal cost, capturing carbon by utilizing natural photosynthesis, avoiding high-energy-consumption capturing equipment, controlling the unit cost to be less than or equal to 27 USD/t CO 2, 2) reducing the energy consumption and simplifying engineering, saving long-distance transportation and geological injection links by nearby distributed deployment and storage units, realizing mature technology and easy operation, 3) improving the safety, adopting solid carbon for storage and avoiding supercritical fluid risks, and 4) enhancing the deployment flexibility, namely realizing county scale distributed deployment based on biomass resource distribution without depending on geological conditions.|INVENTION MODE|Detailed Description|[0024] The following description of the embodiments of the present invention will be made clearly and completely, and it is apparent that the described embodiments are only some embodiments of the present invention, but not all embodiments. All other embodiments, which can be made by those skilled in the art based on the embodiments of the invention without making any inventive effort, are intended to be within the scope of the invention.|[0025] The invention provides a natural carbon fixation and sealing method, which comprises the following steps:|[0026] collecting and drying biomass to obtain dry biomass; |[0027] The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; |[0028] and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. |[0029] In the methods provided herein, the available biomass resources are preferably precisely quantified and analyzed for spatial distribution prior to collection and drying of the biomass to support distributed deployment decisions. In the present invention, resource assessment is based on annual yield of crop residues and forestry residues, and the annual yield of residues can be calculated using formula (I):|[0030] Formula (I); |[0031] In the formula (I), Y i is crop yield, alpha i is residue-yield ratio, eta i is collection coefficient, and mu i is utilization coefficient. |[0032] In the method provided by the invention, the carbon removal potential is quantified, preferably based on the amount of resources, using monte carlo simulation (n=10000) and the uncertainty is evaluated, before biomass is collected and dried. The core formula is shown as formula (II):|[0033] Formula (II); |[0034] In the formula (II), M bio is the mass of dry biomass, f c is the biomass carbon content, and eta sequest is the sequestration efficiency, which can be assumed to be 0.95, based on the resource evaluation result. |[0035] In the method provided by the invention, the biomass preferably comprises agricultural residues and/or forestry residues, the water content of the agricultural residues after drying is preferably 15-20%, and the water content of the forestry residues after drying is preferably 20-25%.|[0036] In the method provided by the invention, the drying mode is preferably natural air drying and/or mechanical drying. The stacking height of the natural air drying is preferably 0.4-0.8 m, the time consumption of the natural air drying is preferably 50-70 days, and the mechanical drying equipment is preferably a roller dryer.|[0037] In the method provided by the invention, the sealing units are distributed around the biomass collection point, and the distance between the sealing units and the biomass collection point is preferably less than or equal to 20km, more preferably less than or equal to 5km.|[0038] In the method provided by the invention, the sealing unit preferentially digs the landfill pit, and when no burying condition exists, a warehouse can be selectively built.|[0039] In the method provided by the invention, the depth of the landfill pit can be specifically selected according to actual geological conditions, available land area and economical efficiency, preferably 5-10 m, the volume of the landfill pit is calculated according to the biomass compaction density, and the calculation formula is shown as formula (III):|[0040] Formula (III); |[0041] In formula (II), M bio is the dry biomass mass and ρ bulk is the compacted biomass density. |[0042] In the method provided by the invention, the lining is arranged for isolating moisture, oxygen and microorganisms, the lining is preferably a waterproof geomembrane or a cement mortar layer, and the thickness of the cement mortar layer is preferably 0.02-0.08 m, more preferably 0.05m.|[0043] In the method provided by the invention, the density of the biomass after compaction is preferably 0.2-0.3 t/m 3.|[0044] In the method provided by the invention, the method preferably further comprises the step of injecting a protective gas into the sealing unit before sealing. In the present invention, the purpose of the injection of the shielding gas is to create an anaerobic environment, preferably N 2 and/or CO 2.|[0045] In the method provided by the invention, the sealing mode is preferably to cover the waterproof membrane.|[0046] In the method provided by the invention, in order to ensure the anaerobic environment in the tunnel to be stable, the method preferably further comprises the step of monitoring the CH 4 concentration, the CO 2 concentration and the humidity in the sealing unit for a long time after the sealing is completed.|[0047] In the method provided by the invention, the method preferably further comprises the step of planting energy crops on marginal lands. Wherein the energy crop preferably comprises one or more of switchgrass, miscanthus and sweet sorghum.|[0048] The method provided by the invention preferably further comprises the step of carrying out cost optimization, wherein the optimization strategy comprises 1) minimizing the transportation distance, namely defining the transportation rate to be 0.112-0.168 USD/t & km, controlling the average distance to be within 20km through nearby deployment, 2) improving the equipment sharing and utilization rate, namely reducing the unit cost median to 31 USD/t CO 2 through a county-level village sharing model, only needing 1-4 sealing units for county deployment, and improving the equipment utilization rate, and 3) adjusting the cost based on county GDP, namely adjusting the labor cost scaling factor to be 0.50 based on county GDP (GDP high), wherein the resource rich and county purchasing cost scaling factor is 0.25, so that the localization economy is ensured.|[0049] The method provided by the invention has at least the following key points:|[0050] 1) Natural photosynthesis driven carbon capture, namely natural carbon fixation is realized by utilizing biological carbon of crops and forestry residues through photosynthesis, so that energy-intensive capture equipment is avoided, the solvent regeneration and compression links of the traditional CCUS are omitted, and the energy consumption is reduced to 2.90% -10.74% of the CCS. |[0051] 2) The distributed solid-state sealing unit is used for closely processing biomass to avoid long-distance transportation, the volume sealing density reaches 0.33-0.36 t CO 2/m3 which is 6 times of geological sealing, and the median of county-level land occupation rate is only 0.0062%, so that the deployment flexibility is realized.|[0052] 3) Engineering flow is simplified by reducing complexity through standardized flow (collection-drying-sequestration-monitoring).|[0053] 4) Integrated energy crop expansion potential, namely planting energy crops (such as switchgrass, miscanthus and sweet sorghum) on marginal lands, and increasing sealing potential.|[0054] The method provided by the invention has at least the following advantages:|[0055] 1) Cost advantage: |[0056] The technology of the invention, natural carbon sequestration and sequestration (Nature-based Carbon Capture and Storage, NBCCS), has a core advantage in terms of its economy. The unit carbon removal cost average for NBCCS in medium scenario is 27.04 USD/t CO 2, while the costs for BECCS, BBCCS and CCS are 102.96 USD/t CO 2、97.10 USD/t CO2 and 92.81 USD/t CO 2, respectively. This means that the cost of NBCCS is only 26.26% of BECCS, 27.85% of BBCCS and 29.13% of CCS. The low cost is mainly due to the following: |[0057] ① The energy-intensive trapping of NBCCS is avoided, the natural photosynthesis is utilized to fix carbon, and links such as solvent regeneration and compression are omitted. |[0058] ② The transportation expenditure is reduced, the average transportation distance is controlled within 20km by distributed deployment, the transportation cost is only 0.112-0.168 USD/t.km, and BECCS and CCS are required to be transported by long-distance pipelines, so that the cost is increased by 5-15 USD/t CO 2.|[0059] 2) Energy consumption advantage:|[0060] the energy consumption of NBCCS is extremely low, and the energy consumption of the full life cycle is only 2.90% -10.74% of that of CCS. The specific reasons are as follows: |[0061] ① No trapping energy consumption is that the trapping stage of CCS and BECCS consumes 200-300 kWh/t CO 2 power for solvent regeneration, and NBCCS skips this step. |[0062] ② The process is simplified, the energy consumption for drying and compacting is low, the natural air drying ratio can reach more than 50%, and the energy consumption for mechanical drying is only 0.225 kWh/m 3.|[0063] 3) Deployment flexibility:|[0064] NBCCS supports county scale distributed deployment, whereas the prior art relies on centralized facilities. Key advantages include: |[0065] ① Without geologic matching, CCS and BECCS require specific geologic structures (e.g., brine layers), deployment is geographically limited, and NBCCS is buried shallow (5-10 m deep). |[0066] ② The land occupancy rate is low, the tunnel area of NBCCS only occupies 0.0062 percent (median) of administrative area of county, and the pit depth can be further reduced to 0.00450 percent by optimizing.|[0067] ③ And the quick replication is realized by utilizing the existing agricultural machinery, the deployment period is short, and BECCS times of 3-5 years are required to construct a power plant and a capturing facility.|[0068] 4) Safety advantage:|[0069] The NBCCS adopts solid carbon for sealing, and the safety is far higher than that of the prior art: |[0070] ① There is no risk of leakage, avoiding cap layer cracking or earthquakes that may be caused by supercritical CO 2 injection. The NBCCS sealing density reaches 0.33-0.36 t CO 2/m3, which is 4.5 times of that of geological sealing (0.65-0.75 t/m 3), and the stability is high. |[0071] ② The monitoring is simple, only the air and the humidity of the tunnel are required to be tracked, and the CCS is required to monitor the network in a deep part, so that the cost is high and complex.|[0072] 5) Expansibility and synergistic benefits:|[0073] NBCCS can expand sequestration potential through energy crop planting, whereas the prior art is limited: |[0074] ① And (3) utilizing marginal land, namely planting switchgrass or sweet sorghum in the marginal land, wherein the sealing potential can be increased by 0.84 Gt CO 2yr-1. |[0075] ② Economic synergy, the switchgrass path cost can be reduced to 20.55 USD/t CO 2, and the farmland is not occupied.|[0076] In summary, NBCCS is superior to BECCS, BBCCS and CCS in terms of cost, energy consumption, deployment, security and scalability. The core innovation is to simplify the engineering chain by utilizing the natural process, and realize the carbon removal with low threshold and high efficiency. The NBCCS cost is aligned with the current carbon market price (about 50 USD/t CO 2 in China) and provides a viable path for large-scale deployment.|[0077] For clarity, the following examples are provided in detail.|[0078] Example 1|[0079] The shallow buried engineering flow is specifically introduced as follows:|[0080] Step 1, collecting and drying biomass |[0081] Biomass is collected, the collected biomass needs to be dried to reduce the water content to 15-20% (agricultural residues) or 20-25% (forestry residues), and two alternative drying schemes are provided:|[0082] ① Natural air drying, namely piling up for 0.4-0.8 m, which takes 50-70 days, and only renting the land (0.07-0.14 USD/m 2 yr); |[0083] ② Mechanical drying, namely adopting a roller dryer (capacity is 3 t/h), wherein the energy consumption is the heat value required by heating the water. |[0084] Step 2, excavation of tunnels and lining laying|[0085] Digging a tunnel on the land, wherein the pit depth baseline is 5m, the volume is calculated according to the compaction density of biomass, paving a lining in the tunnel, wherein the lining adopts a waterproof geomembrane (the cost is 0.42 USD/m 2) or cement mortar (the thickness is 0.05m, the cost is 70 USD/t), and the lining needs to be isolated from moisture, oxygen and microorganisms.|[0086] Step 3, compacting and injecting gas into the biomass|[0087] Filling dry biomass into the tunnel, compacting the biomass to a target density (the compacted density of forestry residues can reach 0.30 t/m 3 and the compacted density of straws is 0.20-0.25 t/m 3) by using a compactor (the speed is 9000 m 2/h and the oil consumption is 22L/h), and then injecting protective gas (the injection rate of N 2 or CO 2):N2 is 750 m 3/h, the energy consumption is 0.225 kWh/m 3;CO2 and the injection rate is the same, but outsourcing CO 2 is needed).|[0088] Step 4, sealing and long-term monitoring|[0089] After the injection of the protective gas is finished, the surface of the tunnel is covered with a waterproof film for sealing, and then the concentration of CH 4, the concentration of CO 2 and the humidity of soil in the tunnel are monitored for a long time through a gas and humidity sensor (the cost of a monitoring unit is 3500 USD and the annual sampling cost is 420 USD), so that the anaerobic environment in the tunnel is ensured to be stable.|[0090] The foregoing is merely a preferred embodiment of the present invention and it should be noted that modifications and adaptations to those skilled in the art may be made without departing from the principles of the present invention, which are intended to be comprehended within the scope of the present invention. | Family Number|(118365787)|118365787|Object of Invention|(CN121775630 A)|Accordingly , it is an object of the present invention to provide a natural carbon sequestration process that provides an economical , safe , scalable carbon removal route that overcomes the deficiencies of BECCS , BBCCS and CCS . |Abstract|(CN121775630 A)|The invention belongs to the field of environmental protection , and particularly relates to a natural carbon sequestration method . The method comprises the steps of collecting and drying biomass to obtain dry biomass , distributing sealing units around a biomass collecting point , wherein the sealing units are dug landfill pits and / or built warehouses , water and air insulation liners are arranged in the landfill pits and the warehouses , the dry biomass is filled into the sealing units , the filled biomass is compacted , and then the sealing units are sealed . The method provides an economical , safe , scalable carbon removal path that overcomes the deficiencies of BECCS , BBCCS , and CCS . |Advantages / Prev. Drawbacks|(CN121775630 A)|3 ) Engineering complexity and deployment barriers are high in ①full - chain integration difficulty , BECCS needs to integrate a biomass supply chain , a power plant and geological storage facilities , system boundaries are complex , flexibility is low , ②geological dependence is strong , CCS and BECCS require specific geological structures ( such as saline water layers ) for storage , deployment is geographically limited , ③long - term monitoring burden is that geological storage needs to continuously monitor leakage risks , and operation cost ( . . . ) |BECCS , BBCCS and CCS suffer from the following key drawbacks that directly limit their scale deployment and economic viability : |①Without geologic matching , CCS and BECCS require specific geologic structures ( e . g . , brine layers ) , deployment is geographically limited , and NBCCS is buried shallow ( 5-10 m deep ) . | | Environmental technology | B01D-053/62|B01D-053/85|Y02A-050/2359 | B01D-053/62|B01D-053/85|Y02A-050/2359 | B01D-053/62|B01D-053/85 | B01D-053/62|B01D-053/85 | PENDING | (CN121775630)|PENDING | ALIVE | (CN121775630)|ALIVE | (CN121775630)|LEGAL DETAILS FOR CN121775630|Actual or expected expiration date=2046-01-07|Legal state=ALIVE|Status=PENDING|Event publication date=2026-01-07|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202610015675|Application date=2026-01-07|Standardized application number=2026CN-0015675|Event publication date=2026-04-03|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN121775630|Publication stage code=A|Publication date=2026-04-03|Standardized publication number=CN121775630|Event publication date=2026-04-03|Event code=CN/PB01|Event group=Examination events|Publication | (CN121775630)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=r6DqxGvtRKf3sgQOErcFKVfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000081417547&ekey=2098&xpn=CN121775630&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=eJyXSLTmRnwClF4jusd%252BrpNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN121775630)|CN | (CN121775630)|NAME=TSINGHUA UNIVERSITY , COUNTRY=CN | (CN121775630)|NAME=LIU YING;UNITALEN INTELLECTUAL PROPERTY AGENTS LTD. , REG=11227 | (CN121775630)|CN | (CN121775630)|NAME=WANG ZHE, COUNTRY=CN |NAME=YAN CHENYU|NAME=WU CHUNLEI|NAME=CHEN SHU|NAME=MA XINGHAO | 1 | 1 | (CN121775630)|Number of Claims: NCL=10|Gazette date: GAZDATE=2026-04-03|Gazette number: GAZNUM=42-1402|Number of Pages: NPAGES=8| | (CN121775630)|CHINESE (CHI) | (CN121775630)|Patent | Titre: (CN121775630)|Natural carbon fixation and sealing method Résumé: (CN121775630)|The invention belongs to the field of environmental protection, and particularly relates to a natural carbon sequestration method. The method comprises the steps of collecting and drying biomass to obtain dry biomass, distributing sealing units around a biomass collecting point, wherein the sealing units are dug landfill pits and/or built warehouses, water and air insulation liners are arranged in the landfill pits and the warehouses, the dry biomass is filled into the sealing units, the filled biomass is compacted, and then the sealing units are sealed. The method provides an economical, safe, scalable carbon removal path that overcomes the deficiencies of BECCS, BBCCS, and CCS. Autre: (CN121775630)|1. The natural carbon fixation and sealing method is characterized by comprising the following steps of:| collecting and drying biomass to obtain dry biomass; | The method comprises the steps that sealing units are distributed around biomass collection points, wherein the sealing units are dug landfill pits and/or built warehouses, and water and gas insulation liners are arranged in the landfill pits and the warehouses; | and filling the dry biomass into the sealing unit, compacting the filled biomass, and sealing the sealing unit. |2. A natural carbon sequestration process according to claim 1, characterised in that the biomass comprises agricultural residues and/or forestry residues.|3. The natural carbon sequestration method of claim 2, wherein the moisture content of the dried agricultural residues is 15-20% and the moisture content of the dried forestry residues is 20-25%.|4. The method for sequestration of natural carbon as in claim 1, wherein the sequestration unit is less than or equal to 20km from the biomass collection point.|5. The method of claim 1, wherein the water-and gas-barrier liner is a water-resistant geomembrane or a cement mortar layer.|6. The method of claim 1, wherein the density of the compacted biomass is 0.2-0.3 t/m 3.|7. The method of claim 1, further comprising the steps of:| Before sealing, a protective gas is injected into the sealing unit. |8. The natural carbon sequestration process of claim 7 wherein the shielding gas is N 2 and/or CO 2.|9. The method of claim 1, further comprising the steps of:| After the sealing is completed, the CH 4 concentration, the CO 2 concentration and the humidity in the sealing unit are monitored for a long time. |10. The method of claim 1, further comprising the steps of:| Planting energy crops in marginal lands; | the energy crops include one or more of switchgrass, miscanthus and sweet sorghum. | 2 | Abstract | gpt-4o-mini | no | The article focuses on a natural carbon sequestration method without integrating energy production or CO₂ capture from biomass for storage, which is central to BECCS. | ||||||||||||||||||||||||||
| 4 | CN202210102805 | CN202210102805 | CN114380314 | 99735170 | CN114380314 A 2022-04-22 [CN114380314] | 2022-01-27 | 2022-01-27 | 2022-04-22 | (CN114380314)|2023-10-17 | (CN114380314)|Industrial negative carbon emission biomass energy utilization technology device BECCU | (CN114380314)|Biomass energy is used for replacing fossil energy and a light calcium carbonate CO2 collection and utilization process, a biomass energy utilization negative carbon emission technology BECCU is created, and the method is more economical, practical and effective compared with a power plant carbon capture and storage BECCS. In light calcium carbonate production, lime calcination and calcium carbonate drying need to consume energy, and a carbonation process needs to consume a CO2 raw material. In the prior art, fossil energy produced from calcium carbonate is used as fuel, and CO2 is recycled as carbonation raw material. The world-recognized zero-carbon-emission biomass energy is used for replacing fossil energy, CO2 produced by the biomass energy is converted into a light calcium carbonate industrial raw material, and the recycled CO2 is from CO2 absorbed from the atmosphere and soil during plant photosynthesis and is not from crustal fossil energy, so that the energy consumption is reduced, and the environmental pollution is reduced. The part of CO2 is combined into a component of a calcium carbonate final product and a byproduct thereof in a carbonation process and each production link, and is removed from the atmosphere to realize a negative emission effect, and a negative carbon emission estimation model BECCU is that CO2 emission source = production source-capture source. | SHENZHEN CARBONNEUTRAL BIO GAS|SHENZHEN QIANHAI CARBONNEUTRAL LITHIUM INDUSTRY | (CN114380314)|SHENZHEN CARBONNEUTRAL BIO-GAS CO., LTD.|SHENZHEN QIANHAI CARBONNEUTRAL LITHIUM INDUSTRY CO., LTD. | ZHANG WENBIN | (CN114380314)|ZHANG WENBIN | (CN114380314)|HUANG DA;SHENZHEN SHUOFA INTELLECTUAL PROPERTY AGENCY (GENERAL PARTNERSHIP)|Reg. Nb: 44321 | (CN114380314)|"chapter 2 mining industry carbon emissions-2.3 lime production" stipulates that the production of lime involves a series of steps including raw material collection, crushing and sizing and calcining the raw material to produce quicklime and, if necessary, hydrating the lime to calcium hydroxide.|It is a good practice to consider emissions capture using detailed country-specific or more appropriate enterprise-level data. "," Add Capture to formula by adding other terms to formula representing number of observations captured or efficiency of emission reduction system in conjunction with annual system usage, "" Enterprise isWhether or not to install and use CO2Capture technique, preferably by deducting captured CO in high-level process emission calculations2"" other than on List consider CO2Emission of CO for later use2Amount and short term storage should not be from CO2Deducting the discharge.|The invention is a brand new process, and has the advantages of high efficiency, low investment and low operating cost.|Pre-combustion capture is the gasification of fossil fuels to synthesis gas (with H as the major component)2And CO) and then converting the CO to CO by a shift reaction2And then H is absorbed by a solvent or the like2And CO2Separation and collection of CO2The technology is limited to a coal gasification combined power generation device for capturing CO before combustion2The cost is about $ 20/t CO2(ii) a The oxygen-enriched combustion technology adopts pure oxygen or oxygen enrichment to combust fossil fuel, and the main product after combustion is CO2Water and some inert components, because pure oxygen is obtained by air low-temperature separation or membrane separation, the energy consumption is large, and the cost of oxygen-enriched combustion is high; common methods for post-combustion capture technology such as chemical absorption, membrane separation, physical adsorption, etc., and post-combustion capture of CO2The cost of (A) is about $ 40/t CO2.|The initial strong thermal decomposition temperature of cellulose is 280-290 ℃, the thermal decomposition temperature of lignin is 350-450 ℃, the carbon content of lignin is 55-65%, the complex aromatic structure and the thermal stability are high, and the effective utilization is not achieved at present.|United nations inter-government climate Change organization (IPCC) on CO in 20052Special reports on capture and storage and 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC guide) indicate that fossil fuels are kept in use throughout the 21 st century, avoiding large amounts of CO, according to the third assessment report on IPCC2Discharge, realize the concentration stability of greenhouse gas in the atmosphere and CO2Capture and Storage (CCS) should be one of the combination options for greenhouse gas concentration stabilization, in particular CO captured from biofuel combustion, injected underground and stored2The amounts are included as negative emissions in the list of greenhouse gases, chapter 5, the CCS System and CO, Chapter 5, volume II (energy source)2Capture, transport, inject into the underground storage and discharge and clear up the estimation method; united nations climate change congress, published 2050 via the coordinated Organisation (OCED) environmental agency in 2011, with the expectation of achieving lower concentration targets (450ppm), largely dependent on carbon capture and sequestration using biomass energy (BECCS or BioCCS); in 2015, climate change of Paris United nations will set a positive target, and the global temperature rise is limited to be below 1.5 ℃ to be restored to the level before industrialization.| | (CN114380314)|1. An industrial negative carbon emission biomass energy utilization technical device BECCU is technically characterized in that biomass energy is used for replacing fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, namely precipitated calcium carbonate.|2. The technical device is technically characterized in that biomass energy is used for replacing fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide is collected in the light calcium carbonate production process, the prior art is utilized to collect and utilize biomass energy Carbon, and the negative Carbon emission of zero-Carbon biomass energy Utilization is realized through the industrial Carbon dioxide collection and Utilization process.|3. A technical device BECCU for utilizing industrial negative Carbon emission biomass energy is technically characterized in that biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide in light calcium carbonate production is collected and utilized by the prior art to Capture and utilize Carbon, Carbon dioxide generated in light calcium carbonate industrial production is sealed in light calcium carbonate industrial products and byproducts thereof, Carbon Capture and long-term or permanent industrial product sealing of Carbon dioxide sealed in CCUS Carbon Capture Utilization and Storage are realized, namely, Carbon dioxide is sealed by industrial products and byproducts permanently or long-term Carbon, and negative Carbon emission of zero-Carbon biomass energy Utilization is realized.| | (CN114380314)|In order to realize the aim, the invention provides a non-power plant industrialized biomass energy utilization negative carbon emission technology, biomass energy is used for completely replacing fire coal to produce light calcium carbonate, and the biomass fuel is directly combusted in the calcium carbonate calcination process and CO produced by biomass gasification combustion in the drying of calcium carbonate cooked pulp2The whole is recycled and used in the carbonation process as the raw material for producing calcium carbonate, and CO absorbed by the biomass from the atmosphere2Permanently fixed and sealed in industrial products and byproducts to realize industrialized removal of atmospheric CO2A fraction of the total amount.|The invention relates to the technical field of biomass energy source replacement of fossil energy and carbon dioxide capture and utilization of negative carbon emission.|in the present invention, FIG. 1 is a schematic illustration of a process diagram of biomass energy utilization with negative carbon emission, which illustrates BECCU CO in detail2DischargingSourceWhy it must be negative (i.e.| | (CN114380314)|BIOMASS ENERGY(100,42)|NEGATIVE CARBON EMISSION(100,30)|CARBON EMISSION(100,12)|REPLACING FOSSIL ENERGY COAL(100,2)|TECHNICAL DEVICE BECCU(100,2)|CARBON EMISSION BIOMASS ENERGY(100,1)|UTILIZATION TECHNICAL DEVICE BECCU(100,1)|LIKE2AND CO2SEPARATION(76,1)|FOSSIL ENERGY COAL(75,3)|SYSTEM COORDINATION(68,1)|ENTERPRISE ISWHETHER(65,1)|ATMOSPHERIC CO2A FRACTION(62,1)|REPLACING FIRE COAL(60,1)|UNITED NATIONS INTERGOVERNMENT(60,1)|CALCIUM CARBONATE(59,119)|ASSESSMENT REPORT(57,1)|LATE USE2AMOUNT(57,1)|BIOMASS GASIFICATION COMBUSTION(55,1)|CO2THE COLLECTION(54,5)|OXYGEN ENRICHED COMBUSTION(53,2)|BIO FUEL COMBUSTION(53,1)|CCUS CARBON CAPTURE UTILIZATION(53,1)|INDUSTRIALIZED BIOMASS ENERGY UTILIZATION(52,1)|DERIVING ENERGY(51,5)|BIOMASS ENERGY UTILIZATION(48,25)|FOSSIL ENERGY(48,14)|PRECOMBUSTION CAPTURE(47,2)|INJECTED UNDERGROUND(47,1)|IPCC GUIDELINE(46,17)|PLANT PHOTOSYNTHESIS2NOT(45,1)|LIME CALCINATION(44,1)|BYPRODUCT(43,15)|GASEOUS NONGREENHOUSE GAS PRECURSOR(43,1)|OXYGEN ENRICHMENT(43,1)|PYROLIGNEOUS LIQUOR(43,1)|CALCIUM CARBONATE CO2THE COLLECTION(41,1)|REMOVAL INDUSTRIALIZATION(41,1)|PULP2THE WHOLE(39,1)|CALCIUM CARBONATE DRYING(38,4)|NONPOWER PLANT(38,3)|LIGNIN CARBON CONTENT(38,1)|CALCIUM CARBONATE INDUSTRY(35,3)|CO2CAPTURE(35,1)|IPCC GUIDE(35,1)|FOSSIL FUEL COMBUSTION(34,2)|GREENHOUSE GAS CONCENTRATION STABILIZATION(34,1)|POWER PLANT SEQUESTRATION BECCS(34,1)|PRECIPITATED CALCIUM CARBONATE(33,9)|CARBON DIOXIDE(31,66)|CENTURY(31,1)|CONCENTRATION TARGET(31,1)|IPCC2DISCHARGE(31,1)|LIGHT CALCIUM CARBONATE(30,44)|NEGATIVE EMISSION(30,8)|CHAPTER(30,6)|EXPECTATION(30,1)|NATIONAL GREENHOUSE GAS INVENTORY(30,1)|OXYGEN ENRICHED COMBUSTION COST(30,1)|FUEL OIL(29,5)|CARBON DIOXIDE PERMANENT SEQUESTRATION(29,1)|CLIMATE CHANGE CONGRESS(29,1)|CONCENTRATION STABILITY(29,1)|INVESTMENT(28,1)|ZERO CARBON BIOMASS ENERGY(27,7)|NEGATIVE CARBON EMISSION UTILIZATION(27,1)|POSITIVE TARGET(27,1)|INDUSTRIALIZATION(26,2)|UTILIZING CARBON CAPTURE(26,2)|CARBONATION PROCESS2RAW MATERIAL(26,1)|GREENHOUSE GAS CONCENTRATION STABILITY(26,1)|CALCINING(25,12)|ESTIMATING CARBON EMISSION(25,1)|LIGNIN THERMAL DECOMPOSITION TEMPERATURE(25,1)|PERMANENT INDUSTRIAL PRODUCT(25,1)|SITUTHE PRODUCT(25,1)|MEMBRANE SEPARATION(24,2)|THERMAL DECOMPOSITION TEMPERATURE(24,2)|INDUSTRIAL PRODUCT(23,7)|FUEL GAS(23,6)|FOSSIL FUEL(23,4)|CALCIUM CARBONATE CALCINATION(23,2)|CARBON DIOXIDE COLLECTION(23,2)|CARBON CONTENT(23,1)|CARBON DIOXIDE SEQUESTRATION(23,1)|CRUSHING(23,1)|ENVIRONMENTAL AGENCY(23,1)|FRACTION2IN(23,1)|INERT COMPONENT(23,1)|CALCIUM CARBONATE PRODUCTION(22,7)|BIOMASS ENERGY CARBON(22,2)|COAL GASIFICATION(22,2)|METHANE GREENHOUSE GAS(22,1)|PRECIPITATED CALCIUM CARBONATE PRODUCTION(22,1)|GREENHOUSE GAS(21,14)|UTILIZATION(21,2)|PRODUCING CALCIUM CARBONATE(21,1)|SIZING(21,1)|LIME PRODUCTION(20,7)|BIOMASS GASIFICATION(20,6)|CARBONATION(20,5)|NEGATIVE CARBON EMISSION ESTIMATION(20,2)|ANNUAL SYSTEM USAGE(20,1)|CARBON DIOXIDE INVENTORY(20,1)|CELLULOSE THERMAL DECOMPOSITION TEMPERATURE(20,1)|LIMESTONE CALCINING(20,1)|PROCESS EMISSION CALCULATION(20,1)|UNSTABLE GAS(20,1)|BIOMASS(19,12)|SEQUESTRATION(19,8)|THERMAL DECOMPOSITION(19,5)|BIOMASS ENERGY SOURCE(19,3)|INERT CARBONATE(19,3)|POST COMBUSTION CAPTURE(19,3)|MINING INDUSTRY CARBON EMISSION(19,2)|PURE OXYGEN(19,2)|ZERO CARBON EMISSION(19,2)|CONSENT(19,1)|QUICKLIME(18,5)|GLOBAL TEMPERATURE RISE(18,1)|SECONDARY ENERGY BIOMASS(18,1)|UNDERGROUND STORAGE(18,1)|ZERO CARBON(17,9)|CARBON DIOXIDE CAPTURE(17,8)|CO2THE TRAPPING CAPACITY(17,5)|BIOCCS(17,4)|BECCU CO2NEGATIVE EMISSION ESTIMATION(17,1)|GREENHOUSE GAS INVENTORY(17,1)|PHYSICAL ADSORPTION(17,1)|CARBON CAPTURE(16,15)|BIOMASS FUEL(16,11)|MEMBRANE ELECTROLYSIS(16,5)|BIOMASS PARTICLE BRIQUETTE FUEL(16,2)|ENERGY SOURCE CATEGORY(16,2)|BECCS(15,3)|CALCIUM CARBONATE INDUSTRIAL PRODUCTION(15,3)|CALCIUM CARBONATE INDUSTRIAL PRODUCT(15,2)|CARBONIZATION TOWER CO2INDUSTRIAL UTILIZATION(15,1)|CO2(15,1)|CO2ALTHOUGH METHANATION REFORMING(15,1)|CO2THE ANNUAL SEQUESTRATION(15,1)|COLLECTED CARBON DIOXIDE(15,1)|COMPLEX AROMATIC STRUCTURE(15,1)|IPCC GUIDELINE2TECHNICAL INNOVATION(15,1)|CLIMATE CHANGE(14,13)|LIGHT CALCIUM CARBONATE PRODUCTION(14,9)|COMBUSTION(14,6)|LIME(14,6)|MINING INDUSTRY(14,3)|CALCIUM HYDROXIDE(14,2)|CARBONACEOUS FEEDSTOCK HYDROMETHANATION(14,1)|CCUS TECHNOLOGYHUGE INVESTMENT(14,1)|HYDROMETHANATING CARBONACEOUS FEEDSTOCK(14,1)|INEXHAUSTIBLE SUBSTANCES2NEGATIVE EMISSION(14,1)|INTERMITTENT BUBBLE CARBONIZATION TOWER(14,1)|WEYBURN OILFIELD FLOODING(14,1)|ABSORPTION TOWER(13,6)|CHINESE ENVIRONMENTAL SCIENCE SOCIETY(13,3)|CLINKER COOLER(13,3)|DESORPTION TOWER(13,3)|CARBONATE TON CO2PER TON(13,1)|DOMESTIC CCUS DEMONSTRATION(13,1)|ENERGY CONSUMPTION(13,1)|ENTERPRISE LEVEL DATA(13,1)|GEOLOGICAL SEQUESTRATION EXPERIMENT PROJECT(13,1)|INTERMITTENT BUBBLING CARBONATION(13,1)|MAGNESIUM CARBONATE(13,1)|NATIVE LIGNIN WORLD14TONS(13,1)|THERMAL STABILITY(13,1)|INTAKE PIPE(12,5)|ACCOUNTED2CARBON FOOTPRINT EMISSION(12,1)|ARMORALCOHOL CALCULATION TON(12,1)|BIOMASS ENERGY2NEGATIVE EMISSION(12,1)|CARBONATION RAW MATERIAL(12,1)|CO2THE CAPACITY ANNUAL SEQUESTRATION(12,1)|DOMESTIC CO2THE TRAPPING(12,1)|LONG TERM SEQUESTRATION(12,1)|SYNTHESIS GAS(12,1)|REPLACING FOSSIL ENERGY(11,4)|BIOMASS GASIFICATION FURNACE(11,2)|CALCINING LIMESTONE(11,2)|DUST ABSORPTION JAR(11,2)|HYDROMETHANATION REACTOR(11,2)|TECHNICAL STANDARD(11,2)|ANTHROPOGENIC CO2THE TECHNICAL ROUTE(11,1)|ATMOSPHERIC CO2CARBON SINK ABSORPTION(11,1)|BIOMASS ASH ACCOUNTING(11,1)|CCUS INDUSTRIALIZATION(11,1)|CO2TOTAL COGENERATION(11,1)|DALIAN UNION INSTITUTE(11,1)|DALIAN UNION UNIVERSITY(11,1)|GUIDELINE FUTURE REVISION(11,1)|IPCC RECORD APPROVAL(11,1)|LIMESTONE CALCINATION DECOMPOSITION(11,1)|LIMESTONE CALCINATION FUEL REQUIREMENT(11,1)|PROCESSESSOURCE CLASSDISCHARGING(11,1)|RAW MATERIAL COLLECTION(11,1)|ZHONGPETROCHEMICAL SHENGLI OILFIELD(11,1)|INDUSTRIAL PRODUCTION(10,16)|DUST REMOVER(10,3)|EMISSION REDUCTION(10,3)|CALCIUM CARBONATE PRODUCTION(10,2)|FOSSIL ENERGY SOURCE(10,2)|SCRUBBING TOWER(10,2)|BIOMASS GASIFICATION COMBUSTION2AFTER(10,1)|BOILED SLURRY AGING TANK(10,1)|BRAND NEW(10,1)|CALCINATION PROCESS2PARTIAL(10,1)|CANADIAN QUEST PROJECT(10,1)|CO2CHEMICAL FERTILIZER(10,1)|CO2NEGATIVE EMISSION ESTIMATION MODEL(10,1)|COAL FIRED GENERATOR2AFTER CAPTURE(10,1)|KILN BIOMASS WOOD(10,1)|LIMESTONE ORE CONSUMPTION(10,1)|LONG TERM CARBON(10,1)|MAJOR RENEWABLE BIOMASS RESOURCE(10,1)|NGLUCOSE TRIELEMENT POLYMER(10,1)|ORE RAW MATERIAL2IS(10,1)|TRAPPING DEMONSTRATION PROJECT(10,1)|UNDERGROUND CARBON DEPOT COAL(10,1)|FINE PULP(9,4)|COAL BED(9,3)|ANALYTICAL TOWER(9,2)|CALCIUM CARBONATE COOKED SLURRY(9,2)|CARBOHYDRATE TAR(9,2)|CO2OIL DISPLACEMENT(9,2)|NUCLEAR POLYMERIZATION(9,2)|BIOMASS CALCINING KILN GAS(9,1)|CALCINATION PROCESS2CAN(9,1)|CALCIUM CARBONATE CALCINATION PROCESS2AND(9,1)|CALCIUM CARBONATE DRYING(9,1)|CALCIUM CARBONATE FINAL PRODUCT(9,1)|CARBONATE PRODUCTS2THE(9,1)|CEMENT BURNING FURNACE(9,1)|CEMENT CCUS(9,1)|CEMENT DECOMPOSITION FURNACE(9,1)|CHINESE ACADEMY RESEARCH INSTITUTE(9,1)|CO2METHANATION REFORMING(9,1)|CULTIVATING SEAWEED(9,1)|DESULFURIZE TOWER(9,1)|KILN GAS DISSIPATION BYPRODUCT(9,1)|LATE INTERNATIONAL DYNAMIC TREND(9,1)|LIME MILK COARSE PULP(9,1)|LIME REFINED EMULSION(9,1)|MATURE SLURRY AGING TANK(9,1)|PRECOMBUSTION TRAPPING(9,1)|PYROLYZING BIOMASS(9,1)|QILU PETROCHEMICAL(9,1)|SCREENING LIME ASH(9,1)|USED2THE FINE SLURRY EMULSION(9,1)|VICTORY OILFIELD(9,1)|WOOD BIOMASS BRIQUETTE FUEL(9,1)|WOODY PLANT LIGNIN CONTENT(9,1)|YEAR2THE TRAPPING CAPACITY(9,1)|CEMENT ROTARY KILN(8,2)|GASEOUS DRYING TANK(8,2)|IPPU SOURCE CATEGORY(8,2)|LAND UTILIZATION(8,2)|SHORT TERM STORAGE(8,2)|ENERGY SOURCE(7,3)|GAS TRANSMISSION PIPELINE(7,3)|WASTE RESIDUE(7,3)|POST COMBUSTION TRAPPING(7,2)|ADAPTIVE TECHNICAL TRANSFORMATION(7,1)|AFOLU DEPARTMENT(7,1)|ANNUAL TRAPPING(7,1)|ATMOSPHERE2NEGATIVE DISCHARGE(7,1)|ATMOSPHERE2REDUCED TOTAL CO2NEGATIVE DISCHARGE(7,1)|ATMOSPHERIC CO2INCREASED(7,1)|AUSTRALIA WEST(7,1)|BALO ISLAND SALINE LAYER(7,1)|BIOMASS CARBON POND(7,1)|BIOMASS LIMESTONE(7,1)|BIOMASS PLANT CARBON LIBRARY(7,1)|BIOMASS2CO COMBUSTION(7,1)|CALCIUM CARBONATE COOKED PULP2WITH(7,1)|CAPTURE CO2ANY(7,1)|CARBONIZATION REACTION IMPURITY(7,1)|CEMENT PRODUCTION PROCESS2THE(7,1)|CO2SUBSEQUENT EMISSION(7,1)|EUROPEAN BIOCCS(7,1)|FUNDAMENTAL COUNTERMEASURE(7,1)|GACO COMBUSTION(7,1)|HEATING(7,1)|HYPERGRAVITY REACTION CRYSTALIZATION(7,1)|IMPROVED2THE COLLECTION(7,1)|INVENTORY MAKER(7,1)|IPCC GUIDELINE SOURCE CATEGORY(7,1)|IPPU CATEGORY(7,1)|LIMESTONE BURNING(7,1)|LONG TERM INDUSTRIAL PRODUCT(7,1)|NONGREENHOUSE GAS BYPRODUCT(7,1)|OILFIELD EXHAUSTION(7,1)|OILFIELD EXTRACTION(7,1)|PROCESS2EMISSION DEFAULT EMISSION FACTOR(7,1)|SLAKED LIME FINE MILK(7,1)|SPRAY CARBONATION(7,1)|TECHNOLOGY2CARBON FIBER(7,1)|TON CO2CARBONATE(7,1)|TRAPPED2FOR EATINGTHE PRODUCT INDUSTRY(7,1)|UTILIZATION2AFTER PURIFICATION TREATMENT(7,1)|ZHONGPETROCHEMICAL CENTRAL OILFIELD(7,1)|WASTEWATER(6,4)|PROCESS DIAGRAM(6,3)|ANODE CHAMBER(6,2)|BIOMASS ENERGY UTILIZATION GENERATION(6,2)|CARBON DIOXIDE DESORPTION(6,2)|CARBON DIOXIDE ENTRAPMENT(6,2)|CARBON POOL(6,2)|CARBON UTILIZATION(6,2)|CATHODE CHAMBER(6,2)|CO2HYDROGENATION(6,2)|CONSTANT SUBSTANCE LAW(6,2)|ECONOMIC BENEFIT(6,2)|EXHAUST CAP(6,2)|KILN GAS INLET(6,2)|MAIN PRODUCT(6,2)|OVERFLOW PORT(6,2)|RAW MATERIAL SOURCE(6,2)|AMMONIUM COMPOUND FERTILIZER(6,1)|ASH EMULSION INLET(6,1)|ASH FINE EMULSION INLET(6,1)|ASH KILN(6,1)|AUTHORITATIVE SCIENTIFIC RESEARCH INSTITUTION(6,1)|BIOMASS CARBON RESERVOIR(6,1)|BIOMASS COMBUSTION2THE TOTAL(6,1)|BIOMASS IPPU SOURCE EMISSION(6,1)|BOILED SLURRY OUTLET(6,1)|CALCINING FN(6,1)|CALCIUM CARBONATE RAW MATERIAL2AND(6,1)|CALCIUM CARBONATE2VOLUME(6,1)|CARBOHYDRATE POLYMER CELLULOSE(6,1)|CARBONATE COMBUSTION INDUSTRY(6,1)|CATALYTIC PYROLYSIS(6,1)|CCUS MONITORING TERM(6,1)|CENTRAL OILFIELD REFINERY(6,1)|CHINESE CCUS TERM(6,1)|CO2A COLLECTION(6,1)|CO2CO EMISSION(6,1)|CO2RELEASING CO2AND RELEASE HEAT(6,1)|CO2THE CLEANING(6,1)|CO2THE MAIN CANDIDATE(6,1)|CO2THE NEGATIVE EMISSION(6,1)|CO2THEN DISCHARGING(6,1)|DAILY PRODUCTIVITY(6,1)|DEFAULT ASSUMPTION(6,1)|DISSIPATION TAIL GAS EMISSION(6,1)|EMISSION INVENTORY GUIDELINE(6,1)|ENERGY2THE EMISSION(6,1)|ENTERPRISE PERSONNEL CARBON EMISSION(6,1)|ESTABLISHED NEGATIVE EMISSION ESTIMATION(6,1)|FIELD2THE COLLECTION(6,1)|FUNDAMENTAL PAIN(6,1)|GORGON PROJECT(6,1)|GRASS HOUSE2A PILOT TEST(6,1)|GROUND BIOMASS(6,1)|INTERNATIONAL ENTERPRISE(6,1)|IPCC CAPTURE(6,1)|IPCC REPORT(6,1)|MAJOR TECHNICAL BREAKTHROUGH(6,1)|MICROALGAE CARBON SEQUESTRATION(6,1)|MNCO3AND HYDROCARBON(6,1)|MNCO3RHODOCHROSITE DISCHARGE(6,1)|NA2CO3SODIUM CARBONATE(6,1)|NATURAL GAS2THE INJECTION(6,1)|NEGATIVE EMISSION FRAMEWORK(6,1)|NONCALCINED CARBONATE(6,1)|NONPOWER PLANT BIOMASS ENERGY(6,1)|OPERATING COST(6,1)|PLANT SYNFUEL(6,1)|QUICKLIME DISCHARGE(6,1)|RAW SUGARCANE JUICE(6,1)|REFINED LIME MILK INLET(6,1)|RESOURCE RECYCLING(6,1)|SALINE AQUIFER(6,1)|SEA SNAIL CEMENT(6,1)|SIGMA CO2AT(6,1)|SPECIALIZED SYSTEM(6,1)|SUBTERRANEAN PROJECT(6,1)|TECHNICAL ROUTE2CONVERSION(6,1)|TECHNOLOGY BECCU(6,1)|TECHNOLOGY UTILIZATION SCENARIO(6,1)|TERRELL PROJECT(6,1)|TRANSPORTATION SECTOR(6,1)|TREATED CO2CALCIUM CARBONATE(6,1)|UNCALCINED CARBONATE EMISSION FACTOR(6,1)|WOOD BIOFUEL(6,1)|LIME KILN DUST(5,17)|RAW MATERIAL(5,13)|BLAST PIPE(5,5)|BIOMASS GAS HOT BLAST(5,4)|BYPRODUCT CARBON(5,4)|COMPOUND CARBONATE(5,3)|INERT INORGANIC CARBONATE SOLID(5,3)|ABANDONED OILFIELD(5,1)|ANNUAL INJECTION(5,1)|ATMOSPHERIC CO2THE TOTAL EMISSION(5,1)|BIOMASS ENERGY SOURCES2COLLECTING(5,1)|BIOMASS FUEL CONSUMPTION(5,1)|BIOMASS GROWTH(5,1)|BIOMASS PYROLYSIS GASIFICATION(5,1)|BIOMASS WASTE(5,1)|BOUNDARY PROJECT(5,1)|CALCINING ATMOSPHERE(5,1)|CALCIUM CARBONATE ORE ACCOUNT(5,1)|CALCIUM CARBONATE PRODUCTION2WITH(5,1)|CAPTURE UTILIZATION TERM(5,1)|CAPTURED CO2THE TOTAL(5,1)|CARBONATION REACTION EQUATION(5,1)|CCUS TECHNICAL TEST(5,1)|CCUS TEST(5,1)|CEMENT MANUFACTURE ENVIRONMENT(5,1)|CHEMICAL FERTILIZER PLANT2OIL DISPLACEMENT(5,1)|CHINESE ENERGY SAVING SOCIETY(5,1)|CLEAN UTILIZATION(5,1)|CO2 EMISSION(5,1)|CO2THE MEASUREMENT(5,1)|CO2TRAPPING(5,1)|COAL METHANOL(5,1)|COUNTRY TOTAL EMISSION(5,1)|DECARBONIZATION REACTION(5,1)|DEMONSTRATION PROJECT PHASE(5,1)|DIVIDING HOOD(5,1)|EFN CARBONATE EMISSION FACTOR(5,1)|EMANATION ESTIMATION(5,1)|EMISSION CALCULATION BASIS(5,1)|EMISSION INDUSTRY(5,1)|EMISSION PROPORTION(5,1)|ENERGY MINISTRY(5,1)|ENID PROJECT(5,1)|EXTRACTION NOTCH(5,1)|GEOLOGICAL SEALING(5,1)|GREEN TRANSFORMATION(5,1)|INDUSTRY2THE CRUDE OIL(5,1)|IPCC DEVELOPMENT(5,1)|LIMESTONE3THE CONTENT(5,1)|LOW TEMPERATURE SEPARATION(5,1)|MEASUREMENT ACCOUNTING(5,1)|METHANOL ABSORPTION(5,1)|MGCO3MAGNESITE EMISSION FACTOR(5,1)|PHOTON WAVELENGTH(5,1)|PROJECT TRAP(5,1)|PROLONGED PETROLEUM(5,1)|QUICKLIME YIELD(5,1)|RECOVERY ANNUAL TREATMENT CAPACITY(5,1)|SEQUESTRATION DEMONSTRATION AREA(5,1)|SLAKED LIME CA(5,1)|SLAKED LIME YIELD(5,1)|SYNTHETIC CRUDE OIL2SUCCESSFULLY(5,1)|TIMELY MASTER(5,1)|TON LIME(5,1)|UNCALCINED CALCIUM CARBONATE(5,1)|UTILIZATION2THE CARBON(5,1)|WITHDRAWAL NOTCH(5,1)|PRODUCING LIGHT CALCIUM CARBONATE(4,4)|SRCCS(4,4)|TOTAL CONTENT(4,4)|ANNUAL NEGATIVE CARBON EMISSION(4,2)|BIOCCU(4,2)|BIOMASS FUEL GAS(4,2)|CARBONATOR STRUCTURE(4,2)|CATALYTIC REACTION TOWER(4,2)|CO2EMISSIONS(4,2)|COAL SEAM(4,2)|DECADE(4,2)|HYDRATED LIME(4,2)|KILOCALORIE(4,2)|NIGHT(4,2)|WOOD VINEGAR(4,2)|ACCOUNTING CARBON FOOTPRINT(4,1)|ACCUMULATIVELY2UP(4,1)|AIR LOW TEMPERATURE SEPARATION(4,1)|AMERICAN SITUATION(4,1)|AMOUNT2THE(4,1)|ANNUAL PRODUCTION(4,1)|ARTIFICIALLY INCREASING CARBON SEQUESTRATION(4,1)|ASH RESIDUE(4,1)|ATMOSPHERE2REMOVED(4,1)|BIOASS ENERGY(4,1)|BIOMASS GASIFICATION PROCESSING(4,1)|BIOMASS2QUANTITY(4,1)|BOILED SLURRY TANK(4,1)|CALCINATION PROCESS BIOMASS CONSUMPTION(4,1)|CAPTURE SCALE(4,1)|CARBON CAPTURE INDUSTRIALIZATION(4,1)|CARBON SINK EFFECT2AND(4,1)|CARBONIZATION TOWER STRUCTURE(4,1)|CATALYST RESEARCH(4,1)|CEMENT MANUFACTURING FACILITY(4,1)|CH4AND GREENHOUSE GAS(4,1)|CHINA ELECTRIC(4,1)|CO2REDUCED(4,1)|CO2THE NOVEL RECYCLING TECHNOLOGY(4,1)|CONDENSATE WATER RECOVERY(4,1)|CONDITIONS2IS(4,1)|CORRECTION FACTOR(4,1)|CROSSCHECK(4,1)|DIRECTLY ELIMINATED2THE EMISSION(4,1)|DISPLACING OIL(4,1)|DOLOMITE EMISSION FACTOR(4,1)|DUST EMISSION(4,1)|EMISSION BASIS(4,1)|EMITTING NEGATIVE(4,1)|EQUIPMENT2THE DIFFERENCE(4,1)|EXCESS LIME(4,1)|EXPELLING COALBED GAS(4,1)|FECO3SIDERITE EMISSION FACTOR(4,1)|FIELD2ACCUMULATING(4,1)|FIELD2COLLECTING(4,1)|FILTER PASTE(4,1)|FINAL PRODUCTCO(4,1)|FULL FLOW INDUSTRIAL PRODUCTION(4,1)|GENERATION BIOMASS ENERGY UTILIZATION(4,1)|GEOLOGICAL STORAGE(4,1)|GUIDE IPCC(4,1)|IMPURITY CONTENT(4,1)|INCREMENTAL PRODUCTION(4,1)|INDUSTRIAL PRODUCTION PROCESS2REMOVED(4,1)|INDUSTRIALIZED COMMERCIAL LIGHT CALCIUM(4,1)|INDUSTRIESTHE CARBONIZATION(4,1)|INEVITABLE CARBON EMISSION(4,1)|INTEGRATED CREATION(4,1)|JINGDU(4,1)|LIGNIN SULFATE COMBUSTION HEAT(4,1)|LIME KILN FEED(4,1)|MATURE BIOMASS ENERGY(4,1)|MEETING INTERNATIONAL STANDARD PACE(4,1)|MIXED WOOD BIOMASS BRIQUETTE(4,1)|NATIONAL GREENHOUSE GAS LIST(4,1)|PEAK REACHING CARBON NEUTRALIZATION(4,1)|POLLUTION REDUCTION(4,1)|POSITIVE SIGNIFICANCE(4,1)|POWER PLANT2CAPTURE PROJECT(4,1)|PROCESS2EMISSIONS(4,1)|PRODUCED CO2INPUTTING(4,1)|PRODUCTION PROCESS2WHEN GREENHOUSE GAS(4,1)|QUICKLIME PRODUCTION(4,1)|QUICKLIME SLAKING(4,1)|RAW CALCIUM CARBONATE MASS(4,1)|REACTION TANK DEPTH(4,1)|REGENERATION(4,1)|REMAINING IMPURITY(4,1)|SALINE WATER LAYER2THE PROJECT(4,1)|SANITARY TREATMENT(4,1)|SCIENTIFICITY(4,1)|SMOKE CHAMBER(4,1)|SODA ASH DISCHARGE(4,1)|STORAGE2MARINE STORAGE(4,1)|TON HOUR LIMESTONE(4,1)|UTILIZATION ITEM(4,1)|WHITE CEMENT(4,1)|WORLD BIOMASS ENERGY(4,1)|WORLD2INJECTION(4,1)|NEGATIVE CARBON EMISSION(3,9)|LIGHT PRODUCTION(3,6)|LITHIUM CARBONATE(3,3)|POWER GENERATION(3,3)|THERMAL DECOMPOSITION GAS(3,3)|TON DAY(3,3)|ABSORB CARBON DIOXIDE(3,1)|ABSORBENT(3,1)|ABSORPTION REACTION(3,1)|AGRICULTURE(3,1)|AGROFORESTRY(3,1)|ANTHRACITE(3,1)|ARAGONITE(3,1)|AVERAGE PERSON(3,1)|AVERAGE SHAFT KILN(3,1)|BIODIESEL(3,1)|BIOGAS(3,1)|BIOMASS ENERGY UTILIZATION MODE(3,1)|BIOMASS POWER PLANT BECCS(3,1)|BIOMASS TOTAL CARBON CONTENT(3,1)|BIOMASS2AND(3,1)|BRINE LAYER(3,1)|BURNED PRODUCT COOLING(3,1)|CACO3BOTH(3,1)|CALCINATION RATIO(3,1)|CALCITE(3,1)|CALCIUM OXIDE CAO(3,1)|CARBOHYDRATE LIQUID(3,1)|CARBON DIOXIDE EMISSION(3,1)|CARBON EMISSION ESTIMATION(3,1)|CARBONATE CALCINING(3,1)|CARBONATE WEIGHT PROPORTION(3,1)|CARBONATE2CO(3,1)|CARBONIC ACIDTHE KEY(3,1)|CARBONIZER(3,1)| | (CN114380314)|1. An industrial negative carbon emission biomass energy utilization technical device BECCU is technically characterized in that biomass energy is used for replacing fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, namely precipitated calcium carbonate.|2. The technical device is technically characterized in that biomass energy is used for replacing fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide is collected in the light calcium carbonate production process, the prior art is utilized to collect and utilize biomass energy Carbon, and the negative Carbon emission of zero-Carbon biomass energy Utilization is realized through the industrial Carbon dioxide collection and Utilization process.|3. A technical device BECCU for utilizing industrial negative Carbon emission biomass energy is technically characterized in that biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide in light calcium carbonate production is collected and utilized by the prior art to Capture and utilize Carbon, Carbon dioxide generated in light calcium carbonate industrial production is sealed in light calcium carbonate industrial products and byproducts thereof, Carbon Capture and long-term or permanent industrial product sealing of Carbon dioxide sealed in CCUS Carbon Capture Utilization and Storage are realized, namely, Carbon dioxide is sealed by industrial products and byproducts permanently or long-term Carbon, and negative Carbon emission of zero-Carbon biomass energy Utilization is realized.|4. The industrial negative-carbon-emission biomass energy utilization device BECCU according to claim 1, wherein the calcium carbonate calcination process replaces fossil energy coal, fuel oil, fuel gas and derived energy with internationally recognized zero-carbon biomass energy and biomass briquette to achieve zero-carbon emission of the energy source category of the calcination process.|5. The BECCU according to claim 1, wherein the precipitated calcium carbonate drying and heating process uses internationally recognized zero-carbon biomass energy secondary energy biomass pyrolysis gas to replace fossil energy coal, fuel oil, fuel gas and derived energy for heating, or uses biomass briquette fuel to directly burn to replace fossil energy for heating, thereby realizing zero-carbon emission in the energy source category of the drying and heating process.|6. The industrial negative carbon emission biomass energy utilization device BECCU according to claim 2, which is technically characterized in that the existing technology and device are fully utilized for collecting and utilizing carbon dioxide in the production of light calcium carbonate, the existing technology and device are adaptively modified, and carbon dioxide generated by two production processes, namely a limestone calcining process and a precipitated calcium carbonate drying process, is collected and utilized for recycling.|7. The BECCU according to claim 6, wherein the collected carbon dioxide used in the production of precipitated calcium carbonate includes not only carbon dioxide generated by the calcination and drying of biomass energy source type, but also carbon dioxide decomposed by the calcination of limestone, which is a raw material source type in the calcination process, and carbon dioxide generated by the energy source type and the raw material source type in the industrial production process.|8. The BECCU according to claim 3, wherein the industrial products and by-products produced by precipitated calcium carbonate industry are used for long-term and permanent sequestration of carbon dioxide, and the by-products include all the by-product process wastes produced by the precipitated calcium carbonate industry from limestone ore to the full-flow industrial production of the final product, including inert carbonates such as calcium carbonate, magnesium carbonate and tar, pyroligneous liquor, solid, liquid and gaseous non-greenhouse gas precursor stable substances which will not naturally form greenhouse gas emissions for a long time in the future, but not CO unstable gases and methane greenhouse gases emitted by the light calcium carbonate industry, and which may form subsequent greenhouse gas emissions or greenhouse gases emitted in the future and in the short-term, must be deducted from the carbon dioxide inventory.|9. The device BECCU according to claim 2 and claim 3, wherein the negative carbon emission of zero-carbon biomass energy utilization is realized by a carbon dioxide sequestration process using industrial processes and industrial products and byproducts, and the estimation model of the negative carbon emission is BECCU CO2DischargingSourceProduction ofSource-capturingSource。|10. The device BECCU as claimed in claim 9, wherein the method and related technical standards for developing the device BECCU as an industrial negative carbon emission biomass energy utilization device according to the model for estimating the amount of carbon emission of the device BECCU as a zero-carbon biomass energy utilization device according to the present invention are not limited to the applicant, and any person other than the applicant must have written the consent of the applicant or be developed together with the applicant for developing the method and related technical standards for developing the device BECCU as an industrial negative carbon emission biomass energy utilization device according to the present invention. | (CN114380314)|TECHNICAL FIELD|[0001] The invention relates to the technical field of biomass energy source replacement of fossil energy and carbon dioxide capture and utilization of negative carbon emission.|BACKGROUND ART|[0002] Artificially created atmospheric CO2The concentration is increased, and the greenhouse effect threatens the survival and development of human beings. Reduction of anthropogenic CO2The technical route of (1) has two routes: the first is to develop renewable energy sources such as solar energy, wind energy and biomass energy to replace fossil energy sources vigorously or reduce CO from the source by improving the utilization efficiency of the fossil energy sources2Discharging; second, to the CO produced2Atmospheric CO increased by human activity is removed by artificially increasing carbon sequestration and carbon Capture using sequestration techniques CCUS (carbon Capture Utilization and storage)2。|[0003] United nations inter-government climate Change organization (IPCC) on CO in 20052Special reports on capture and storage and 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC guide) indicate that fossil fuels are kept in use throughout the 21 st century, avoiding large amounts of CO, according to the third assessment report on IPCC2Discharge, realize the concentration stability of greenhouse gas in the atmosphere and CO2Capture and Storage (CCS) should be one of the combination options for greenhouse gas concentration stabilization, in particular CO captured from biofuel combustion, injected underground and stored2The amounts are included as negative emissions in the list of greenhouse gases, chapter 5, the CCS System and CO, Chapter 5, volume II (energy source)2Capture, transport, inject into the underground storage and discharge and clear up the estimation method; united nations climate change congress, published 2050 via the coordinated Organisation (OCED) environmental agency in 2011, with the expectation of achieving lower concentration targets (450ppm), largely dependent on carbon capture and sequestration using biomass energy (BECCS or BioCCS); in 2015, climate change of Paris United nations will set a positive target, and the global temperature rise is limited to be below 1.5 ℃ to be restored to the level before industrialization. However, it is possible to use a single-layer,the positive value of carbon emission (positive carbon emission) such as clean power generation technology and energy-saving measures is not enough to solve the problem fundamentally even if CO2Reduced amount and slower rate of emission of CO2The net concentration is still rising; the 20 th group of countries (G20) in 2019, the Ministry of energy and environment, incorporated the CCUS technology for carbon capture, utilization and sequestration. IPCC reports suggest that the CCUS technology is significant for realizing zero carbon emission in 2050 years, and large-scale negative carbon emission application technologies need to be deployed in 2040 years.|[0004] CCUS is essentially an artificial, industrial carbon sequestration approach. Wherein, CO2The trapping method comprises 3 trapping methods including pre-combustion trapping, oxygen-enriched or pure oxygen combustion and post-combustion trapping. Pre-combustion capture is the gasification of fossil fuels to synthesis gas (with H as the major component)2And CO) and then converting the CO to CO by a shift reaction2And then H is absorbed by a solvent or the like2And CO2Separation and collection of CO2The technology is limited to a coal gasification combined power generation device for capturing CO before combustion2The cost is about $ 20/t CO2(ii) a The oxygen-enriched combustion technology adopts pure oxygen or oxygen enrichment to combust fossil fuel, and the main product after combustion is CO2Water and some inert components, because pure oxygen is obtained by air low-temperature separation or membrane separation, the energy consumption is large, and the cost of oxygen-enriched combustion is high; common methods for post-combustion capture technology such as chemical absorption, membrane separation, physical adsorption, etc., and post-combustion capture of CO2The cost of (A) is about $ 40/t CO2。|[0005] The CCUS technical test is carried out firstly, the petrochemical industry enhanced oil recovery is carried out, and CO is passed2Connecting carbon source produced by coal chemical industry or natural gas chemical industry with oil field to obtain CCUS-EOR (enhanced oil recovery), and collecting CO2Injecting into oil field to recover oil from exhausted oil field and CO2Permanently stored underground; thereafter, attempts were made to use CO2Fertilizer and food grade CO2Utilization, etc., and also industrially produced CO2Inputting the green as greenhouse gas to strengthen plant growth, etc.|[0006] The earliest large CCUS project in humans was the U.S. construction in 1972Finished Terrell project, CO2The trapping capacity reaches 40 ten thousand t/a; enid project, Okla, USA, was built in 1982 by CO produced by chemical fertilizer plant2Oil displacement of oil field, CO2The trapping capacity reaches 70 ten thousand t/a; the Norwegian Sleipner project in 1996 was the first CO to be established in the world2Injection into underground (saline aquifer) projects, annual sequestration of CO2The quantity is close to million tons; in the United states, in 2000, in cooperation with Canada, the CO of Great Plant Synfuels plants and Sask Power plants was injected at the Weyburn oil field2Accumulating and storing CO while improving the oil extraction rate of the oil field near exhaustion2Up to 2600 or more tens of thousands t; the project of Boundary Dam Power of Sask Power company of Canada in 2014 is the first successful application of the project to CO Power plant2Capture project, CO generated by 150MW coal-fired generator2After capture, a portion was sequestered underground and a portion was used for U.S. Weyburn oil field flooding, CO2The trapping capacity reaches 100 million t/a, and the project traps CO in 20192Up to 61.6 ten thousand t; 2015 Canadian Quest project CO produced in hydrogen production process of synthetic crude oil2Successfully injected into a saline water layer for sealing and storing, and CO is injected every year2The trapping capacity reaches 100 million/a, the project is the first CCS project in the oil sand industry, the carbon emission can be reduced by 100 million every year, and by 2019, the Quest project can trap CO accumulatively2Up to 400 million t, is the maximum CO capture in the world2And successfully injected into a subterranean project; the Gorgon project in the west of australia in 2016 is a complement to the Gorgon natural gas project, the largest global unit LNG project, which projects CO by liquefaction technology2Separating CO from natural gas2The injection amount can reach 350 ten thousand t/a when the injection is injected into a saline layer of the Balo island.|[0007] China starts to research CCUS technology later, and the government continues to come out of the CCUS technical policy in 2006, and the CCUS technology is one of the key points in China national plan for climate change handling (national scheme for climate change handling science and technology action handling in China), Chinese policy and action for climate change handling in China, and the like. In 2007, the China Petroleum Jilin oil field and the China petrochemical east China division company grass House oil field opened domestic CO2The trapping project firstly realizes the industrialization of the CCUS-EOR technology and establishes five types of CO2Oil displacement and sequestration demonstration area, annual sequestration of CO2The capacity can reach 35 ten thousand t; in the same year, China petrochemical east China division builds CO in the oil field of the grass house2A pilot test project with 4 ten thousand of annual injection amount is built with CO in the later period2The annual treatment capacity of the recovery device can reach 2 ten thousand t. Subsequently, the Zhongpetrochemical Shengli oil field, China Shenhua, prolonged Petroleum and the Zhongpetrochemical Central oil field accelerate the propulsion of CO2Industrialization of the collection item. In 2010, the China petrochemical industry victory oil field is built into the first domestic CCUS demonstration project of a coal-fired power plant, and the flue gas CO of the coal-fired power plant is used2Adopting combustion-trapping technology to trap CO as source2Injecting into oil field for displacing oil and CO2The trapping capacity reaches 3-4 million t/a; in 2011, a CCS demonstration project of Shenhua Ordos 10 ten thousand t/a is completed, and a methanol absorption method is adopted to capture CO in tail gas of a coal gasification hydrogen production project2Injecting CO into saline water layer2The project is the first domestic saline water layer geological sequestration experiment project; in 2012, the oil is prolonged to build 5 ten thousand t/a of CO2A collection and utilization item for utilizing CO generated in coal chemical industry2The crude oil is purified, pressurized and liquefied by a low-temperature methanol washing technology and then injected into an oil field, so that the viscosity of the crude oil is reduced, the recovery ratio of the crude oil is improved, and CO is realized2Permanently sealing and storing; in 2015, CCUS project for tail gas of central oil field refinery in medium petrochemical industry was built, and the project approaches to abandoned oil field through CO2Oil displacement improves the oil field extraction rate by 15 percent, and million tons of CO exist at present2Is injected into the ground.|[0008] In addition to the conventional CO2Trapping technology, China also developed CO2The novel recycling technology is applied to the industries of food, fine chemicals and the like, in 2009, a second power plant carbon capture project at the Shanghai stone cave entrance is built, the capture scale is 10 ten thousand t/a, and the captured CO is2The method is mainly used in the food industry; 2011 CO produced by IGCC in research institute of clean coal energy and power system in Hongyun harbor2Trapping the latter part for urea and sodium carbonate industry, injecting the other part into brine layer for sealing; china electric group CO of Tianjin north pond in 20122The trapping demonstration project adopts a post-combustion trapping technology, the annual trapping amount is 2 ten thousand t, and CO is trapped2For eatingThe product industry; in 2010, the Xinao group in inner Mongolian Dallas utilizes a microalgae carbon sequestration technology to absorb tail gas of a coal-based methanol/dimethyl ether device, wherein one part of tail gas is used as biodiesel and the other part of tail gas is used for producing feed, and the treatment capacity reaches 2 ten thousand t/a; the sea snail cement establishes an industrial CCUS test project of 5 ten thousand tons; qilu petrochemical under construction CCUS-EOR project (2020) CO2The trapping capacity was 4 ten thousand t/a. The utilization direction of the emerging carbon in China is mainly CO2Hydrogenation for preparing methanol and CO2Hydrogenation for preparing isoparaffin and CO2Hydrogenation for preparing aromatic hydrocarbon and CO2Although methanation reforming and the like, such as Shanxi coal chemical institute, Dalian union institute, Shanghai research institute of Chinese academy, university of Dalian union, and the like, have studied these technologies, they are mostly in the theoretical research stage or pilot plant stage of catalyst research, and there is no CCUS practical technology for industrial application.|[0009] The Chinese environmental science society, release the Chinese head CCUS group standard 'carbon dioxide capture utilization and sealing term' T/CSES 41-2021 at 22.12.1.2021, comprises related terms of CCUS, related terms of carbon dioxide, capture and transportation terms of carbon dioxide, related terms of CCUS monitoring and measuring performance, related terms of risk and the like, and regulates related terms of the capture utilization and sealing field of carbon dioxide, and is mainly suitable for scientific research, management, teaching and production activities in related fields of carbon dioxide capture, chemical utilization, geological sealing and the like in high emission industries such as chemical industry, thermal power, steel, cement and the like. The T/CSES 41-2021 has positive significance for scientific research and production activities in the CCUS field, promotes the scientificity and normalization of the use of Chinese CCUS terms, and accelerates the pace of meeting international standards. The community standard does not relate to the related patent technology in the CCUS field. The prior patent technology in the CCUS field is few in China, and the real practical technology is almost none.|[0010] CN201711383170.2 discloses a negative carbon emission system and method thereof, which utilizes photosynthesis of growing plants to absorb carbon dioxide molecules, and properly designs photon wavelength for inducing photosynthesis of plants to increase efficiency of photosynthesis of plants, and selects LED light source with carbon footprint lower than threshold and conversion efficiency higher than threshold, and combines low carbon power source with carbon footprint lower than threshold, such as solar cell panel. The system can be applied to the capture of carbon dioxide.|[0011] CN201810173639.8 discloses carbon dioxide entrapment device in cement manufacture, including gas collecting channel, first intake pipe, air pump, first blast pipe, filter, the gas collecting channel top is provided with first intake pipe, one side of first intake pipe is provided with the air pump, one side of air pump is provided with first blast pipe, one side of first blast pipe is provided with the filter, one side of filter is provided with the dust absorption jar, one side of dust absorption jar is provided with the second blast pipe, one side of second blast pipe is provided with gaseous drying tank, one side of gaseous drying tank is provided with the second intake pipe, one side of second intake pipe is provided with the gas holder. Has the advantages that: this carbon dioxide entrapment device has set up equipment such as filtration, purification, drying to the special environment of cement manufacture for the purity of final carbon dioxide product is higher, through the collection to carbon dioxide, has reduced its emission to in the air.|[0012] CN201820292229.0 discloses carbon dioxide collection device that tail gas was handled among cement manufacture, including cement rotary kiln, gas transmission pipeline, dust remover, absorption tower, cement rotary kiln one end is provided with the smoke chamber, smoke chamber one end is provided with gas transmission pipeline, gas transmission pipeline one end is provided with the dust remover, dust remover one end is provided with the scrubbing tower, scrubbing tower one end is provided with the desulfurizing tower, desulfurizing tower one end is provided with the absorption tower, absorption tower one end is provided with analytic tower, analytic tower one end is provided with the gas holder, gas holder one end is provided with the carbon dioxide and does not have the oil-pressure moulding machine, carbon dioxide does not have oil-pressure moulding machine one end and is provided with first absorption tower. Has the advantages that: the device recovers carbon dioxide gas generated in the cement kiln, does not contain impurities, does not discharge into the air, plays a role in protecting the environment, and improves economic benefits by recycling carbon dioxide in other industries.|[0013] CN201811533699.2 discloses a carbon dioxide desorption method for carbon capture, sequestration and utilization technology, which comprises the desorption steps of: starting and adjusting an electric adjusting valve, reducing the temperature and the pressure of saturated steam in the cement kiln tail waste heat boiler through a temperature and pressure reducer, and heating the saturated steam in an amine liquid reboiler in a desorption tower; heating and desorbing the carbon dioxide passing through the desorption tower; and the saturated steam after heating and desorbing the carbon dioxide in the desorption tower is subjected to liquid change to form saturated water, and the saturated water enters a condensate water recovery device through a water return pipe. The carbon dioxide desorption method for the carbon capture, sequestration and utilization technology does not influence the normal operation of the cement kiln waste heat power generation system, can meet the requirement of the desorption operation of the CCS system, and reduces the economic cost investment.|[0014] CN201010532911.0 discloses a waste treatment facility for introducing a thermal decomposition gas of waste into a cement decomposition furnace, which is provided adjacent to a cement manufacturing facility provided with a cement burning furnace, a clinker cooler for cooling a burned product thereof, and a decomposition furnace into which a high-temperature exhaust gas flows from either one of the burning furnace and the clinker cooler. Wherein, possess: the gasification furnace is provided with a gasification furnace for gasifying the waste to generate thermal decomposition gas, and a gas conveying channel for conveying the generated thermal decomposition gas to the decomposition furnace under the condition of keeping the carbon and the ash unchanged. The pyrolysis gas is introduced into the decomposing furnace in such a manner that the pyrolysis gas does not directly interfere with the main stream of the exhaust gas flow from the burning furnace or the clinker cooler, and is prevented from being scraped, thereby sufficiently burning the pyrolysis gas. Thus, the existing cement manufacturing equipment is effectively utilized, and the sanitary treatment of wastes is realized at low cost.|[0015] 201610704208.0 discloses a method for utilizing carbon dioxide in carbonate calcining flue gas and preparing methanol by collecting carbon dioxide generated in the carbonate calcining process; catalytic pyrolysis of biomass fuel to form H-containing2Introducing the fuel gas into a high-pressure catalytic reaction tower after dust fall treatment; the two are produced into products with methanol as the main component in a high-pressure catalytic reaction tower, and are purified and purified into industrial methanol in a distillation tower. Annual production of ten thousand tons of armorAlcohol calculation, the regeneration method for generating carbon dioxide in the carbonate calcination process disclosed by the invention can absorb and consume about 1.375 ten thousand tons of greenhouse gas carbon dioxide, and absorb and consume about 10 ten thousand tons of biomass waste. The purposes of environmental protection and resource recycling are achieved while economic benefits are generated.|[0016] CN201010229727.9 discloses a production process for removing carbon dioxide from flue gas and preparing ammonium compound fertilizer and light calcium carbonate. The method comprises the steps of using dilute ammonia water as an absorbent, carrying out gas-liquid two-phase high-strength mass transfer absorption reaction on raw flue gas through a super-gravity field absorption tower for decarbonization, discharging the treated flue gas through a chimney, and further carrying out reaction treatment on byproducts of the decarbonization reaction to obtain the ammonium compound fertilizer and the light calcium carbonate with good economic value. The complete set of reaction separation device supporting the process comprises a high-gravity field absorption tower, a static mixer, a deep reaction tank, a cyclone, an ammonium compound fertilizer recovery system, a light calcium carbonate recovery system, various pumps and other equipment, wherein the high-gravity field absorption tower is a chemical reaction absorption section for removing carbon dioxide. The invention is a brand new process, and has the advantages of high efficiency, low investment and low operating cost.|[0017] CN201980083589.7 discloses hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation, to a process for hydromethanating the carbonaceous feedstock in a hydromethanation reactor to a methane-enriched raw product stream, and in particular to processing the solid coke by-product removed from the hydromethanation reactor to improve the carbon utilization and thermal efficiency and economics of the overall process by co-producing power and steam from the by-product coke in addition to the end product pipeline quality substitute natural gas.|[0018] CN202010455978.2 discloses a method and a system for utilizing carbon dioxide, wherein the method comprises the following steps: acquiring carbon dioxide meeting preset conditions; injecting the carbon dioxide into a coal seam and allowing the carbon dioxide to expand and release into the coal seam; and the carbon dioxide is used for expelling the coal bed gas in the coal bed to ensure that the coal bed gas is discharged from the coal bed. In the invention, the relatively single carbon dioxide is used as the displacement gas of the coal bed gas, and after the coal bed gas is displaced out of the coal bed, the carbon dioxide is remained and sealed in the coal bed, so that the carbon dioxide is utilized to obtain a clean gas source, the emission of the carbon dioxide is reduced, and the influence on the greenhouse effect is reduced.|[0019] CN201110176523.8 discloses a method and a device for preparing formic acid by recovering carbon dioxide from flue gas and utilizing electric power at night, a carbon dioxide recovery process for separating and recovering carbon dioxide from flue gas obtained by fuel combustion; sending the separated carbon dioxide into a membrane electrolysis device which is reduced by direct current to reduce the carbon dioxide to obtain formic acid; the formic acid refining process is that the dilute formic acid solution obtained by membrane electrolysis is refined to obtain formic acid product. The membrane electrolysis device is divided into a cathode chamber, a concentration chamber and an anode chamber; or divided into a cathode chamber and an anode chamber; the membrane electrolysis units are combined in any mode of series connection or parallel connection or combination of series connection and parallel connection. The technology adopts an efficient membrane electrolysis device and a gas-liquid mixed feeding mode and a carbon dioxide recovery formic acid refining process, has high electrochemical process efficiency, collects and recovers carbon dioxide and obtains high-concentration formic acid liquid through electrolytic reduction, effectively realizes the recovery and conversion of carbon dioxide, and can also effectively utilize the night power of a power plant.|[0020] The fundamental pain point of the above prior art CCUS is high cost, high energy consumption, low efficiency, low benefit, and is far from large-scale commercial application. World CO2The utilization of CO which is still in the theoretical research stage of the technology2Carbon fiber preparation, acetic acid preparation and the like; already in development stage, there is CO2Preparation of Polymer, CO2Methanation reforming, CO2Preparing methanol by hydrogenation, cultivating seaweed, circulating power and the like; already in the demonstration project phase there is a CO2Chemical fertilizer preparation, oil displacement in oil fields, food-grade application and the like. The negative carbon emission methods being discussed and developed are biomass energy power generation and carbon capture and sequestration (BECCS or BioCCS) technologies, such as BioCCS of the european carbon emission center (CCR), it is theoretically possible to remove CO from the atmosphere while producing fuel or electricity2。|[0021] China actively participates and becomes an important construction force for the world to cope with climate change, and carbon neutralization is realized for realizing carbon peak reachingThe national goal of high-quality development and green transformation, CCUS and biomass in China are still changing along with European and American situations by utilizing the negative carbon emission strategy. The invention creatively replaces fossil energy with biomass energy and CO in the current industrial field2The collection and the Utilization of the prior art are organically combined, and the integrated creation of a biomass energy of a non-power plant can utilize the industrialized commercial negative Carbon emission technologies (NETs) practical technology BECCU or BioCCU (Bioass-energy With Carbon Capture and Utilization).|DISCLOSURE|Disclosure of Invention|[0022] Aiming at the defect that Chinese CCUS and biomass energy use negative carbon emission technology is also and gradually following carbon capture and sequestration (BECCS or biocCS) of European and American biomass power plants, in particular to the industrial pain point that CCUS has high cost, high energy consumption, low efficiency and low benefit, the invention uses CO in the production of light calcium carbonate in the current industrial field2Collecting and utilizing the prior art and the production thereof to CO2The self-demand of raw materials organically integrates the biomass energy source instead of fossil energy with the CCUS technology, the light calcium carbonate production process and the like, creates a biomass energy utilization mode of industrial non-power plant biomass energy utilization negative carbon emission practical technical device BECCU or BioCCU, and realizes the CO energy utilization through industrial production by using the pollution reduction and carbon reduction synergistic effect of high efficiency, high benefit, low cost and low energy consumption2The purpose of negative carbon emission removed from the atmosphere opens up a new field of carbon capture and utilization technology.|[0023] In order to realize the aim, the invention provides a non-power plant industrialized biomass energy utilization negative carbon emission technology, biomass energy is used for completely replacing fire coal to produce light calcium carbonate, and the biomass fuel is directly combusted in the calcium carbonate calcination process and CO produced by biomass gasification combustion in the drying of calcium carbonate cooked pulp2The whole is recycled and used in the carbonation process as the raw material for producing calcium carbonate, and CO absorbed by the biomass from the atmosphere2Permanently fixed and sealed in industrial products and byproducts to realize industrialized removal of atmospheric CO2A fraction of the total amount.|[0024] In the invention, limestone and biomass fuel are added into the stone togetherCalcining in an ash kiln, screening the obtained quick lime, then feeding the quick lime into a digestion mechanism for digestion to obtain lime milk coarse pulp, separating and purifying the coarse pulp to obtain fine pulp, aging the fine pulp in an aging tank, then feeding the fine pulp into a fine pulp concentration-regulating tank, adding clear water to regulate the concentration, then feeding the fine pulp into a carbonization tower, and mixing the fine pulp with purified CO from biomass calcining kiln gas and flue gas of a biomass gas hot-blast stove of a drying process for collection2The generated calcium carbonate cooked slurry is subjected to carbonation reaction, is subjected to standing and aging and then is filtered in a filter, and the obtained filter paste is dehydrated, dried, crushed, separated and dedusted to obtain the final product of light calcium carbonate, so that CO absorbed by the biomass from the atmosphere is realized2Permanently fixed and sealed in light calcium carbonate industrial products and byproducts, and industrially removing atmospheric CO2The purpose of (1).|[0025] In the invention, the calcination process for producing the light calcium carbonate can be directly combusted in an industrial manner by using 3000-4000 kilocalories of wood biomass briquette fuel or high-quality biomass particle briquette fuel, and can also be calcined by using biomass fuel gas produced by pyrolyzing biomass by using a biomass gasification furnace. In fact, the production of the quicklime by directly calcining the limestone by using the wood biofuel firewood is a first generation traditional technology of biomass energy utilization existing before the industrial revolution, and the project adopts a second generation technology of biomass energy utilization and biomass briquette industrialized direct combustion technology to improve the energy utilization efficiency and CO2The recycling rate is improved, and the biomass pyrolysis gasification belongs to the third generation technology of biomass energy utilization, and is more advanced and efficient than the second generation technology. No matter the second generation or the third generation biomass energy utilization technology is adopted, the fuel requirement of limestone calcination can be completely met technically.|[0026] In the invention, the precipitated calcium carbonate cooked pulp drying process adopts a biomass pyrolysis gasification technology to supply heat, and CO in the flue gas of a biomass gas hot blast stove2With CO produced by the calcium carbonate calcination process2And are recycled together.|[0027] In the present invention, CO2The collection and the recycling of the light calcium carbonate can be fully utilized to produce the existing CO2The collection and recovery technology and the device thereof greatly reduce the carbon capture, utilization and sealing of the current CCUS technologyHuge investment and cost are present. Wherein CO produced in the calcination stage2Not only can directly adopt the existing CO2The collection and recycling technology and the device can collect and recycle the existing CO according to the requirement2Collecting CO from a utilization system2Collecting, gas-solid-liquid separating, impurity treating, cooling, recovering and CO2A small amount of adaptive technical transformation is carried out on devices such as compression conveying and the like, so that the CO is further improved2The collection and recycling efficiency of (1); CO produced in the drying process of the calcium carbonate cooked pulp2With CO produced during the calcination process2Can be recycled together to meet the requirement of CO production in industrialized commercial light calcium carbonate2The requirement of raw materials.|[0028] In the invention, the biomass fuel is industrially directly combusted or after gasification, the biomass gas is combusted to form C + O2→CO2Releasing CO2And releases heat; and the calcination of calcium carbonate releases CO2The two processes of producing the calcium oxide CaO and drying the calcium carbonate cooked slurry are heat absorption processes, CaCO3→CaO+CO2The enthalpy change of ↓ΔH is larger than zero when the biomass fuel is used for continuously supplementing and providing energy required by reaction and heating. On the one hand, CO is continuously generated by calcining and combustion heating2On the other hand, CO produced by decomposition of calcium carbonate raw material2And CO produced by the combustion of biomass2CO combined with two sources of feedstock and fuel2Must be removed quickly to reduce CO in the calcination process2Partial pressure increase of calcination released CO2Efficiency, and the normal operation of the biomass gas hot blast stove is maintained.|[0029] In the present invention, CaO + H is digested by quicklime2O→Ca(OH)2Delta H < 0 and calcium hydroxide Ca (OH) carboxylated2+CO2→CaCO3Both ↓ + H2O < delta H > are exothermic reactions. Because of the conservation of energy and conservation of material, those skilled in the art, even scientists, produce CaCO from light calcium carbonate3→CaO+CO2To CaO + H2O→Ca(OH)2To Ca (OH)2+CO2→CaCO3Chemical formula, only the light calcium carbonate raw material is seen to be the same as the chemical formula of the final product, CO2The material is equally fed in and out on the molecular formula in the production of the light calcium carbonate; especially the production of heavy calcium carbonate, has no CO at all2The material enters and exits the production process. Thus, one skilled in the art would even think of the scientist's inertial thinking to be that CO is only2The material is carbon balanced before and after the production of the light calcium carbonate and can not generate CO to the atmosphere2What effect the total amount has. What the average person does not think of is CO2Carbon balance process of equal quantity and one inlet and one outlet in light calcium carbonate production of substances for atmospheric CO2The total emissions may lead to potential negative carbon emission technology utilization scenarios.|[0030] In the invention, if biomass energy is not used for completely replacing fossil energy, the production of light calcium carbonate can generate artificial activities to cause atmospheric CO2Increased total carbon emissions. CO released from fossil fuel in light calcium carbonate production2About 35% of the total carbon emission, which is part of the CO energy2The emission is regulated according to the source category of 'energy' in volume 2 of '2006 IPCC guideline', and the emission needs to be measured and accounted to enter a national greenhouse gas list; and the CO released by calcining the raw calcium carbonate ore accounts for about 44 percent of the mass of the raw calcium carbonate ore2Is recycled for the back end carbonation production process, CO2The material is equally discharged and fed in the industrial process of calcium carbonate production, and the total carbon amount in the industrial process is balanced. Thus, the carbon emissions from light calcium carbonate production are only CO metered and accounted for in fossil fuels2And (4) discharging the amount. This is completely different from the carbon emission mechanism of cement production, which does not have CO in the cement production process2The recycling process and mechanism, therefore, the carbon capture, utilization and sealing can be artificially carried out by human beings by adopting the cement CCUS technology. Volume 3 of the 2006 IPCC guideline "industrial process and product usage" regulations "in certain IPPU categories, especially large point emission sources, can capture emissions for recycling or removal. It is a good practice to consider emissions capture using detailed country-specific or more appropriate enterprise-level data. "," Add Capture to formula by adding other terms to formula representing number of observations captured or efficiency of emission reduction system in conjunction with annual system usage, "" Enterprise isWhether or not to install and use CO2Capture technique, preferably by deducting captured CO in high-level process emission calculations2"" other than on List consider CO2Emission of CO for later use2Amount and short term storage should not be from CO2Deducting the discharge. The default assumption is that carbon dioxide capture and storage (CCS) is not employed. Considering CO2Any method of capture should take into account the CO captured in the process2Emissions may be related to both combustion and process. If combustion and process emissions are reported separately, the inventory maker should ensure that the CO is present2The same number of (a) is not counted twice. In these cases, the captured CO2The total amount should best be reported in the respective fuel combustion and the CO generated in these source classes should be taken into account2The volume ratios are reported in the IPPU source category. "|[0031] In the invention, globally recognized zero-carbon biomass energy is used for completely replacing fossil energy, and the production of light calcium carbonate can generate CO influencing the atmosphere2Reduced total CO2Negative discharge effect. CO released by biomass fuel in light calcium carbonate production2With CO liberated from calcium carbonate ore raw material2Is recycled for the production of carbonation process, is combined into calcium carbonate final industrial product and part of the byproduct thereof, and absorbs CO from the atmosphere in the process of biomass (plant) growth2The CO is permanently fixed and sealed in the final industrial product and by-products of the light calcium carbonate through an industrialized process, so that the CO is obtained2CO removal from the atmosphere2Negative discharge effect.|[0032] In the invention, because the chemical change of the light calcium carbonate industrial production is only in the molecule and atom level, the nuclear polymerization change of the C atomic nucleus is not involved, and the total amount of the C elements of the light calcium carbonate raw material and the final industrial product is not changed, thus the light calcium carbonate is in material balance. The carbon material balance mechanism in the industrial production process of the light calcium carbonate is as follows: the carbon element added by the combustion of the biomass fuel is respectively distributed in byproducts produced by light calcium carbonate such as carbon-containing compounds, mixtures and the like in a gas-solid state and a liquid state in different stages of the industrial production process: such as CaCO3、MgCO3、CaMg(CO3)2、MnCO3And hydrocarbons such as tar, carbohydrates and CO gas (CO)2Reduction reaction of CO2+ C → 2CO product), calcium bicarbonate Ca (HCO) (hard water), H carbonate2CO3(CO2Dissolving in water to generate CO carbonate2+H2O==H2CO3) And other carbon compounds (such as greenhouse gas CO) that escape or are discharged to the atmosphere, surface, and water during production2Emissions and other carbon compounds and mixture emissions, etc.). The carbon balance process is essentially atmospheric CO2Carbon sink absorption due to biomass growth → CO release by biomass energy utilization2→ recovery and utilization of CO by carbon capture in industrial production process of calcium carbonate2→ C element with CO2Or other carbonate and carbon compound mixture forms, and is fixedly sealed in the light calcium carbonate product and other byproducts in the production process thereof in the carbonation process. Therefore, the production process of the biomass energy light calcium carbonate is essentially a negative carbon emission process for industrially fixing the carbon element of the biomass energy (wherein CO dissipated into the atmosphere in the production process2When greenhouse gases are required to be metered and accounted for carbon footprint, and part of negative carbon emission reduction amount generated by the invention is offset and deducted), namely, part of CO in the atmosphere is removed through plant carbon sink and the industrial production process2Removed and permanently fixed in the precipitated calcium carbonate product and other non-greenhouse gas by-products.|[0033] In the present invention, because other non-greenhouse gas byproducts must exist in the production process of light calcium carbonate, the total amount of the byproducts is generally equivalent to 20-30% of the yield of the light calcium carbonate. Among them, some by-products (such as CO, etc.) will form CO in future2Finally discharged into the atmosphere, according to the '2006 IPCC guideline', the CO in the industrial process returning to the atmosphere in the future must be measured and accounted2Carbon footprint emissions, and inclusion in the IPPU Source Category into the national greenhouse gas emissions List, which must be derived from the Biomass energy CO2Deducting the negative discharge amount; most of carbon element contained in by-product is permanently fixed and sealed in inert carbonate, and no CO is formed in future2Nor enter the atmosphere to increase the total greenhouse gas. CO in the industrial production of light calcium carbonate because of the inexhaustible substances2Negative emissions, can never be zero. CO for producing light calcium carbonate by using biomass energy2Negative emission, effect and effect of eliminating greenhouse gases in the atmosphere are absolute, and CO can be generated by different biomass energy and light calcium carbonate production technologies and equipment2The difference between the negative carbon emission and the purge amount.|[0034] In the present invention, CO2The measurement and accounting of negative emissions are very similar to the basic emissions calculations of all carbonate combustion industries, based on molecular weight and CO, which are common, according to the "IPCC guideline 2006, volume 3" Industrial Process and product usage-Chapter 2 mining industry carbon emissions "regulations2Ratio of, wherein, CaCO3(Calcite or aragonite) emission factor (ton CO)2Carbonate per ton) 0.43971, MgCO3Magnesite emission factor 0.52197, CaMg (CO)3)2Dolomite emission factor 0.47732, FeCO3Siderite emission factor 0.37987, Ca (Fe, Mg, Mn) (CO)3)2Iron dolomite emission factor 0.40822-0.47572, MnCO3Rhodochrosite discharge factor 0.38286, Na2CO3Sodium carbonate or soda ash discharge factor 0.41492. "chapter 2 mining industry carbon emissions-2.3 lime production" stipulates that the production of lime involves a series of steps including raw material collection, crushing and sizing and calcining the raw material to produce quicklime and, if necessary, hydrating the lime to calcium hydroxide. Consumption of lime products does not result in CO under certain conditions2Is discharged to the atmosphere. For example, slaked lime used in water softening produces CO2React with lime to reform calcium carbonate without generating CO2Net venting to the atmosphere. Similarly, precipitated calcium carbonates for use in the paper industry and other industrial applications are hydrated high calcium quicklime with CO2Generated by the reaction; in the sugar manufacturing process, lime is used to remove impurities from the raw sugarcane juice, and any excess lime can be removed by carbonation. Only the validated and verified method was used to calculate the CO which reacts with lime to reform calcium carbonate2Volume, any rerun in these particular industriesThe carbonization process can be calculated and reported. When these conditions are met, it can be reported under category 2H "other". Lime Kiln Dust (LKD) is generated during lime production and the emission estimate derived using methods 2 and 3 should take into account LKD related emissions. "|[0035] In the invention, the biomass energy is globally recognized zero-carbon energy, and CO generated by biomass energy utilization and not counted in the total amount of emission of greenhouse gases in the atmosphere2Removed from the atmosphere and permanently fixed in the final industrial product light calcium carbonate and its by-products, BECCU and biomass power plant BECCS or BioCCS on CO2The cleaning effect of (a) is the same. The measurement and accounting of greenhouse gas carbon emission in light calcium carbonate production follows the IPCC guideline of 2006 and related methodology, wherein, in addition to the first range of biomass energy utilization negative carbon emission measurement and accounting, carbon footprints such as outsourcing electric power and other energy sources (second range) and enterprise personnel activity carbon emission (third range) in light calcium carbonate industrial production are not included in the energy boundary range of the first range and the technical field of the CCUS related to the invention, but belong to the other technical field and greenhouse gas emission measurement accounting issues.|[0036] In the present invention, CO2The negative emission is measured and calculated according to '2006 IPCC guideline': 1. volume 2 "energy" 2.3.4 carbon dioxide capture "since this is a new emerging technology, it requires plant specific method 3 reporting. The capture and storage plant will most likely meter the amount of gas removed by the gas stream and diverted to geological storage. "," if biofuel is supplied to the plant, the corresponding CO2Emissions will be zero and therefore, subtracting the amount of gas transferred to long term storage gives negative emissions. As a result, CO2Transport, CO2Subsequent emissions from the injection and storage itself should account for the total emissions of the country, whether the carbon originates from a fossil source or is produced by the recent biomass, and subsequent emissions (CO for later use and short-term storage2) Should not be from CO2Deduction in emissions unless CO2 emissions are counted elsewhere in the list [ e.g. CO in urea production (Vol. 3, section 3.2) and methanol production2Use of (Vol 3, section 3.9), in which consideration should be given to the final productCO of product2Emission later). 2. Volume 4 AFOLU "agroforestry and other land utilization" Chapter 4 "Biomass Combustion generated CO2Emissions are not included in the national total greenhouse gas, but are recorded as items of information for cross-check purposes and to avoid recalculation. "|[0037] In the invention, the estimation of greenhouse gas emission in the production of light calcium carbonate by using biomass energy is carried out by adopting a method 3 of '2006 IPCC guideline' to carry out CO2It is estimated that the present invention utilizes biomass energy to produce light calcium carbonate first range (industrial process and energy use) CO2The negative carbon emission measurement and accounting model is as follows: BECCU CO2DischargingSourceProduction ofSource-capturingSourceNamely, the estimation formula:|[0038] |[0039] in the present invention, FIG. 1 is a schematic illustration of a process diagram of biomass energy utilization with negative carbon emission, which illustrates BECCU CO in detail2DischargingSourceWhy it must be negative (i.e. BECCU CO)2DischargingSourceMust be CO2Negative emissions). The inventor organizes strength development or jointly develops BECCU CO according to the invention and the cooperation of the Chinese environmental science society and the Chinese energy-saving society2The negative emission related methodology applies for the approval of the national climate change department and the approval of IPCC record, and develops or jointly develops the CCUS related group standard such as carbon dioxide capture utilization sealing-BECCU industrialized negative carbon emission standard with the Chinese environmental science society and the Chinese energy-saving society.|DRAWINGS DESCRIPTION|[0040] FIG. 1 is a process diagram of negative carbon emission process for biomass energy utilization|[0041] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate|[0042] FIG. 3 is a view showing a structure of a carbonator in a carbon dioxide utilizing process apparatus|[0043] The reference numbers in the drawings of the specification are as follows:|[0044] 1. a support; 2. a kiln gas inlet; 3. a refined lime milk inlet; 4. an exhaust cap; 5. adding a phosphoric acid port; 6. an overflow port; 7. a gas distribution cover; 8. a withdrawal notch; 9. and (5) discharging the cooked pulp.|INVENTION MODE|Detailed Description|[0045] The concrete description is as follows:|[0046] FIG. 1 is a process diagram of negative carbon emission process for biomass energy utilization|[0047] Production of light calcium carbonate CO by using biomass energy2The negative emission process and principle are illustrated as follows according to the steps shown in FIG. 1:|[0048] 1. the biomass limestone calcining process is that biomass briquette fuel is used to replace anthracite and limestone in a layer combustion mixing mode for industrial direct combustion at about 1000 deg.c, and during calcining, partial biomass gas produced through pyrolysis and gasification may be supplemented as required to regulate and control the temperature, combustion condition and calcining atmosphere in the calcining kiln. The process product for producing quick lime by calcining limestone with biomass comprises the following steps:|[0049] (1)、CO2discharging: c + O2→2CO2、CaCO3→CaO+CO2Releasing CO2Wherein the emission of biomass IPPU source type (fuel) in 2006 IPCC guideline is zero, and the emission of the IPPU source type (raw material) CO in the limestone industrial process2Emission default emission factor (CO per ton lime)2Tonnage) high calcium lime 0.75, dolomitic lime 0.86 or 0.77, hydraulic lime 0.59;|[0050] (2) CaO, which accounts for about 56 percent of the mass of the limestone raw material;|[0051] (3) screening lime ash, wherein carbon-containing compound carbonate or carbon-containing mixture is removed from the lime ash, and a byproduct carbon element needs to be metered and calculated in a biomass energy utilization negative carbon emission process;|[0052] (4) lime kiln gas (CO)2Other impurities in the biomass energy utilization negative carbon emission process, which contain carbon compounds, carbonates or carbon-containing mixtures, and need to measure and account for the removal of the waste gas of the byproduct carbon element;|[0053] (5) the kiln gas dissipates CO and accounts for about 1.69 percent of the total volume fraction of the kiln gas (the mass fraction is about 1.42 percent)) The carbon footprint of the kiln gas dissipation byproduct needs to be measured and accounted for CO2Then discharging the amount;|[0054] (6) dust emission CO of lime kiln2Discharging: the amount of Lime Kiln Dust (LKD) generation from the 2006 IPCC guideline depends on the type of lime kiln used and the carbonate characteristics used, with an average shaft kiln producing 9% to 10% dust loss per 1 ton of lime and a raw material feed loss of 16% to 18%. The chemical composition of LKD varies from raw material feed to raw material feed, typically high calcium lime LKD may contain 75% combined calcium oxide and uncalcined calcium carbonate, the remaining impurities are silica, alumina and iron oxides and sulfur (depending on the fuel used), data is collected regarding the typical ratio of LKD to lime production and typical composition of LKD, and in the absence of data, 2% corrective additions can be assumed to account for LKD (i.e., 1.02 CO2Discharge); the vertical axis furnace produces a relatively small amount of LKD, and the LKD correction factor from the vertical axis furnace is determined to be negligible and not necessarily estimated. Method 3 advantageously collects specific data on the weight proportion of carbonate consumed by lime production and the proportion achieved by calcination in each plant, and also collects data on the amount (dry weight) and composition of LKD produced. Similar to method 3 for cement production, the emissions of LKD should be subtracted from the estimate of method 3.|[0055] 2. A biomass pyrolysis gasification process, wherein a biomass gasification furnace mainly supplies heat for a precipitated calcium carbonate (light calcium carbonate) drying process, and can also supply biomass fuel gas for a lime kiln according to needs, and main products after biomass gasification are as follows:|[0056] (1) biomass combustible gas: 20-25% of CO and H in parts by volume28-10%、CH42-4%、CmHn(C2H6、C2H4、C2H2、C3H6、C3H8Etc.) 0.8, etc. The biomass fuel has different components.|[0057] (2) Carbon dioxide: CO22:8-15%;|[0058] (3) Nitrogen gas: n is a radical of246%-56%;|[0059] (4) Oxygen: o is20.5%-1.5%;|[0060] (5) Ash residue: accounting for 5-8% of the total amount of the biomass fuel, and metering and accounting for ash and slag removal of carbon elements of byproducts such as hydrocarbons and the like in the biomass energy utilization negative carbon emission process.|[0061] 3、CO2Collecting and purifying process, CO in kiln gas for calcining limestone by biomass2And CO in the heat supply flue gas generated by biomass gasification combustion2After being collected and recovered, the kiln gas and the flue gas are purified and can be applied to a subsequent carbonation process, the kiln gas and the flue gas are mixed and are subjected to cyclone dust removal, water washing, tar adsorption and sewage treatment, carbon-containing compound carbonate, other hydrocarbons, carbohydrate or carbon-containing mixture ash, tar, sewage sludge and the like are added, and in the biomass energy utilization negative carbon emission process, the CO is measured and calculated2Removing carbon element as by-product in the purification treatment process.|[0062] 4. Quicklime slaking process, CaO + H2O→Ca(OH)2The intermediate product, namely hydrated lime does not relate to the problem of carbon emission, but about 5 percent of waste residues in the digestion process, the carbonate or the carbon-containing mixture of the waste residues, needs to be metered and counted to remove the waste residues of the carbon element of the byproduct in the biomass energy utilization negative carbon emission process.|[0063] 5、CO2Industrial utilization process of CO from limestone calcination decomposition and biomass energy utilization2After purification treatment, in CO2Industrial utilization device of carbonization tower and slaked lime Ca (OH)2Performing carbonation reaction to generate stable carbonate such as calcium carbonate, wherein CO is derived from biomass energy2Is permanently fixed and sealed in stable carbonate industrial products and byproducts such as light calcium carbonate and the like by industrialization and is permanently eliminated from a biomass plant carbon library (processed in AFOLU department according to AFOLU 4 chapter 4 source category of IPCC guideline 2006, agriculture and forestry and other land utilization, which is incorporated into the total amount of greenhouse gas emission of China). In the process of utilizing biomass energy and discharging negative carbon, the CO of the carbonization tower needs to be metered and accounted2CO in industrial utilization2The carbon element which is a byproduct in the tail gas emission of the dissipation and carbonization tower is removed.|[0064] 6. Drying and processing technology of precipitated calcium carbonate (light calcium carbonate), in drying and processing technology of biomass gasification combustion heat supply precipitated calcium carbonate, biomass gas is combusted to form C + O2→CO2Releasing CO2The flue gas is recycled without metering and accounting carbon footprint emission, but CO is dissipated when the biomass gas hot blast stove is combusted2CO and other carbon-containing substances for drying and processing precipitated calcium carbonate, the process dissipation and processing of impurities, and carbon-containing compound carbonate or carbon-containing mixture, in the biomass energy utilization negative carbon emission process, the removal of by-products, such as the drying process dissipation and processing of impurities, and the like, need to be metered and accounted.|[0065] 7. The negative emission process principle for producing light calcium carbonate by using biomass energy is described as follows by integrating the 6 production process flows:|[0066] (1) the biomass carbon element comes from the absorption of CO from the atmosphere and the soil carbon reservoir in the plant growth process2Water, nitrogen, inorganic and trace elements (ash: Ca, K, P, Mg, Si, Al, Ba, Fe, Ti, Na, Mn, Sr), and forming carbohydrate polymer cellulose, hemicellulose and lignin as main components through photosynthesis, including carbohydrates such as starch, protein, lipid, hydrocarbons, etc., and hydrocarbon organic matters. The carbon element of the biomass adopts a chemical structural formula (C)6H10O5)nGlucose trielement polymer (carbon 44.44% hydrogen 6.17% oxygen 49.39%) is the main carbohydrate form, and is fixedly sealed in the carbon pool and the carbon pool of the earth biomass.|[0067] (2) In the carbon pool and carbon pond of the biomass on the earth, the lignin content of woody plants is 20% -35%, and herbaceous plants are 15% -25%, which are the second major renewable biomass resource next to cellulose, and the biomass generates about 6 multiplied by 10 every year on the world14Tons of native lignin, with an incremental production of 1600 million tons/year. The initial strong thermal decomposition temperature of cellulose is 280-290 ℃, the thermal decomposition temperature of lignin is 350-450 ℃, the carbon content of lignin is 55-65%, the complex aromatic structure and the thermal stability are high, and the effective utilization is not achieved at present. In the last hundred years of 1930, the practice of human research on lignin proves that the high-temperature pyrolysisThe method is the only feasible technical route for large-scale industrialization, and the lignin is separated from air and decomposed at high temperature to obtain charcoal, tar, pyroligneous acid and biogas: CO about 50.9%, CH4About 37.5% CO2About 9.6%, and ethylene and other saturated hydrocarbons about 2.0%. The combustion heat value of the lignin is high, the combustion heat of the ash-free spruce picric lignin is 110kJ/g, and the combustion heat of the lignin sulfate is l09.6kJ/g.|[0068] (3) The human industrialized large-scale exploitation utilizes fossil energy such as underground carbon depot coal, petroleum and natural gas, and the like to cause climate change, and international laws such as climate change frame convention of United nations, Jingdu protocol, Paris convention and the like, and specialized organization IPCC of gasification change of the United nations promote the human energy to utilize renewable energy such as solar energy, wind energy, water energy, biomass energy and the like from underground to ground.|[0069] In order to eliminate the inevitable carbon emission in the industrial production processes of electric power, steel, cement building materials, metallurgy, chemical industry and the like and realize the aim of coping with climate change, IPCC (2005) ' carbon dioxide capture and storage special report ' (SRCCS) and ' 2006 IPCC guideline ' clearly propose the technical route of biomass energy utilization (biomass power plant) negative carbon emission ' for any other types (such as CO, power plant) selected for storage2Marine storage or conversion to inert inorganic carbonates) does not provide an emission estimation method. With the exception of mineral carbonisation of certain waste materials, these techniques are in the research phase, not the demonstration or later stages of development of the IPCC (2005) technique. If they reach late in development, emission inventory guidelines generated by these techniques may be compiled and presented in future revisions of the guidelines. "anthropogenic carbon dioxide emissions originate mainly from the combustion of fossil fuels (and biomass) in the power generation, industrial, construction and transportation sectors. CO22And also in certain industrial processes (such as cement manufacture, natural gas processing, and hydrogen production) non-combustion sources. Power plants and other large industrial facilities are CO2The main candidate for capture, a common deployment of the prior art, can capture about 85% -95% CO (processed by IPCC capture plants)2. ", SRCCS provides in its FIG. 5.2 an overview of the relevant processes for pre-combustion capture, post-combustion capture, capture of oxygenated fuel and capture of industrial processes"It has been mentioned in some industrial processes that chemical reactions cause CO2The formed quantity and concentration can directly capture or separate CO from the flue gas2. If CO generated by biomass combustion is captured2Negative emissions may result from the capture and compression system. The invention utilizes biomass energy to produce light calcium carbonate (precipitated calcium carbonate), and BECCU belongs to the CO of the 2006 IPCC guideline2Technical innovation (CO) under the framework of negative emission overall technical route2Conversion to inert inorganic carbonates), there is currently no established negative emission estimation method for BECCU, the present invention is intended to develop BECCU CO2Negative emission estimation methodology, according to method 3 of the 2006 IPCC guideline, CO (input carbonate based approach), CO2Negative emission estimation model: BECCU CO2DischargingSourceProduction ofSource-capturingSourceThe negative emission process measurement accounting formula is as follows:|[0070] |[0071] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0072] (4) Description of the Process principles for negative carbon emissions|[0073] In the above-mentioned CO2In the negative-emission estimation model, the exhaust gas is,is BECCU CO2And (4) estimating the emission (positive number is positive emission, and negative number is negative emission), wherein a is energy and b is a light calcium carbonate production raw material.Wherein,as a source of energySource classDischarging the waste water, and discharging the waste water,as raw material for industrial processesSource classDischarging the waste water, and discharging the waste water,capture utilization of CO for carbonation processes2Atmospheric CO directly eliminated2The emission amount and CO converted by carbon elements contained in the hydrocarbon, carbohydrate liquid and the like such as the inert inorganic carbonate solid and tar which are byproducts of the whole process of industrial production (greenhouse gas emission is not formed in the future)2Indirectly reducing the displacement.|[0074] Further:|[0075] |[0076] (carbon dioxide capture according to "energy" 2.3.4, volume 2, IPCC guideline 2006).|[0077] |[0078] (emission from 2.3 lime production formula 2.7 method 3: emission based on carbonate feed according to Chapter 2 mining industries, volume 3, guide IPCC 2006).|[0079] Wherein, CO2CO emissions from lime production2Discharge in tons|[0080] Emission factor of EFn carbonate n, ton CO2Carbonate per ton|[0081] Mn-consumed carbonate n weight or mass in tons|[0082] Calcining Fn ═ the ratio obtained in carbonate n, the ratio|[0083] Weight and mass of Md-LKD in tons|[0084] Cd is the weight ratio of original carbonate in LKD|[0085] Fd-calcination ratio achieved for LKD, part|[0086] EFd is the emission factor of uncalcined carbonate in LKD, ton CO2Per ton of carbonate.|[0087] |[0088] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0089] Wherein d represents the subsequent discharge amount of greenhouse gases possibly generated in the future in the industrial production of light calcium carbonate, and in the whole production process of precipitated calcium carbonate, part of the dissipated gases which are not captured and utilized by the carbonation process can form CO in the future2Or non-CO2Greenhouse gases, which are subsequently emitted in this part, must be included in the national greenhouse gas list according to the 2006 IPCC guideline, and cannot be deducted from the emission reduction. The method comprises the following steps:|[0090] d 1: indicating subsequent emission of CO|[0091] d 2: represents CH4Then discharged|[0092] d 3: represents H2CO3And so on for subsequent discharge.|[0093] e represents the byproduct of the whole process of industrial production of precipitated calcium carbonate (i.e. the process waste material shown in figure 1), including inert inorganic carbonate solid (excluding non-calcined carbonate in LKD) and carbon-hydrogen such as tar, and indirect CO converted from carbon element fixed in the industrial byproduct for a long time (which will not naturally form greenhouse gas emission in the future)2Capture utilization reduction (indirect carbon capture) comprising:|[0094] e1 denotes inert inorganic carbonates, CaCO3、MgCO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2Etc. of|[0095] e2 represents indirect CO such as liquid hydrocarbon, carbohydrate tar, wood vinegar, lignin (black liquor), etc2The emission reduction amount of the capture and utilization is not as stable as that of the inert inorganic carbonate solid, and the part can be industrially recycled, but does not naturally form greenhouse gas emission.|[0096] Further:|[0097] |[0098] further:|[0099] for theThe industrial production of the light calcium carbonate only chemically changes on the molecular and atomic level, does not relate to the nuclear polymerization change of C element atomic nucleus, does not change the total amount of C elements of the light calcium carbonate raw material and the final industrial product, and is balanced by C substances; and the total content of the C element of the biomass a, the total content of the C element of the subsequent emission d and the total content of the C element of the industrial byproduct e are also in balance of the C substance, and the total content of the C element is not changed in the industrial production.|[0100] Due to the law of constant substances, as long as industrial production is carried out, an industrial production byproduct e (namely the process waste shown in figure 1) is always present,is also certain to exist and can never be zero; particularly in industrial production, the emission of CO and other greenhouse gases dissipated in the process only accounts for about 1.69 percent (about 1.42 percent by mass) of the total volume of the kiln gas and the flue gas, and the emission proportion is very small and is far smaller than that of CO generated by biomass combustion2The total amount of material, and therefore,|[0101] in conclusion, in the production process for producing light calcium carbonate by comprehensively replacing fossil energy with biomass energy as shown in fig. 1, due to the law of constant substances, in the BECCU process technology,and isThe presence of the (C) is determined,BECCU CO2dischargingSourceMust be negative in emission, and absorb CO from the atmosphere in the process of plant growth2CO fixed in biomass carbon reservoir by carbon sink effect2And is permanently sealed in the final industrial product of the light calcium carbonate through an industrial production process.|[0102] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate|[0103] In the description of the attached figure 1, the processes of calcining, biomass pyrolysis gasification and CO production for producing light calcium carbonate by using biomass energy sources2Collecting and purifying, slaking quicklime, Ca (OH)2Six processes, such as carbonation and calcium carbonate drying, have been described in detail and are not described again.|[0104] FIG. 3 is a view showing a structure of a carbonator in a carbon dioxide utilizing process apparatus|[0105] Ca(OH)2And collecting, purifying and compressing the treated CO2Calcium carbonate is generated in a carbonization tower through reaction, and the carbonization tower is CO2The core equipment of the utilization and carbonation process is that the carbonation reaction equation is Ca (OH)2+CO2→CaCO3. FIG. 3 is a view showing the most simple structure of a carbonization tower in which Ca (OH) from a mature slurry aging tank is used2The fine slurry emulsion enters the carbonization tower from a fine ash emulsion inlet 3 shown in the figure and enters the carbonization tower from CO from a kiln gas inlet 2 shown in the figure2Collecting CO from purification and compression process2Carrying out carbonation reaction to generate calcium carbonate; the main function of the 7-gas-dividing hood shown in the figure is to disperse CO2Realization of CO2Distributing the materials evenly, wherein the generated calcium carbonate product is collected by a boiled slurry tank through a boiled slurry outlet 9 shown in the figure and then is aged in a boiled slurry aging tank; the carbonization tower is provided with 6 overflow ports for controlling the height and pressure of the liquid level, and is also provided with a carbonization reaction impurity 8 extraction notch and a carbonization reaction tail gas outlet 4 exhaust cap for exhausting, and a phosphoric acid adding port 5 shown in the figure is mainly used for adding blending auxiliary materials such as phosphoric acid and the like and used for adjusting performance indexes such as whiteness, activity and the like of a calcium carbonate product.|[0106] It must be noted that the carbonizer is CO2Using the key core apparatus of process importance, carbonic acidThe key process for determining the quality of the final product of the light calcium carbonate, such as particles, crystal forms and the like, is the chemical process, and the core of the invention is to provide CO for producing the light calcium carbonate by utilizing biomass energy2The negative discharge technique and method, fig. 3 is only the simplest and most common carbonator structure selected for the convenience of illustrating the carbonation process, and is not intended to limit the carbonation process and apparatus used in the present invention. In fact, the prior art of the carbonation process has various selectable technical processes, including an intermittent bubbling carbonation method, a continuous spray carbonation method, a hypergravity reaction crystallization method and the like, which can be selected to implement the method, and the CO production by the light calcium carbonate of the method can be realized2The purpose of negative discharge technology. Therefore, the invention can be applied to any carbonation process undoubtedly without enumerating and carbonizing process technology and equipment, and any method adopting the invention to replace fossil energy with biomass energy to produce light calcium carbonate and collect and utilize CO2Realization of CO2The purpose of the negative emission technique is within the scope of the present invention.|[0107] Detailed Description|[0108] The inventor deeply recognizes the high-technology high-added-value clean utilization of biomass energy and gradually replaces fossil energy in scientific and technological innovation and industrial innovation practices of the world biomass energy technology in the field of biomass energy utilization for decades at the forefront, and is one of fundamental countermeasures for solving the climate change crisis caused by the unregulated use of human fossil energy; particularly over a decade ago, the inventors discovered the greenhouse gas CO2Not only from the fields of fossil energy, traditional and novel building materials such as building material cement, calcium carbonate, lithium carbonate and the like, chemical engineering, new materials and the like, but also the used main raw materials such as calcium carbonate and the like are greenhouse gas CO2One of the main sources of (1). Based on the important discovery, the inventor is closely cooperated with domestic authoritative scientific research institutions, industrial design institutions, head enterprises of international and domestic related industries and the like, timely masters the latest international dynamic trend, concentrates all efforts, focuses on the zero-carbon-emission biomass energy efficient clean utilization technology for replacing fossil energy, and carries out original scientific research and development, new technology and new product process technology.|[0109] In recent years, the inventor obtains a plurality of major technical breakthroughs in the new technical fields of developing new materials, such as low-carbon zero-carbon cement building materials, calcium carbonate, lithium carbonate and the like, new technologies, new products coping with climate change, realizing carbon peak-reaching carbon neutralization and the like by replacing fossil energy technologies with biomass energy in an efficient and clean manner, particularly applying the most advanced mature biomass energy technology to the related fields of calcium carbonate to replace fossil energy, and forming one of a series of major original technical achievements.|[0110] The invention relates to industrialized carbon capture and permanent CO sequestration by using carbonate industrial products2The implementation range of the negative carbon emission process technology is not limited to the production of light calcium carbonate, namely a carbonate product, and the technical method can be widely applied to the technical fields of various carbonate industrial negative carbon emission and zero-carbon and low-carbon emission, such as various products of cement, white cement, lithium carbonate and the like, after being subjected to adaptive improvement. Therefore, the following examples of the present invention are not intended to limit the scope of the present invention, and any person skilled in the art can make modifications or variations without departing from the technical scope of the present invention, such as the production of various carbonate products such as calcium carbonate, lithium carbonate and tricalcium silicate and other portland cement products by using the technology of the present invention, i.e. all the biomass energy sources are used to replace fossil energy sources (regardless of the substitution rate or whether biomass gasification technology or biomass fuel industrial direct combustion technology is used) and CO is used in the production of light calcium carbonate according to the present invention2The collection and utilization technology integrates the two technologies (including the carbon capture and utilization technology and the industrialized sequestration technology of the CCUS) into a new technology, so as to achieve the purpose and effect of industrialized negative carbon emission, and the scope of the invention is covered by the invention of the technology.|[0111] The embodiment of the invention comprises the following steps: and 10000t/a light calcium carbonate produced annually by using biomass energy instead of fossil energy is used as an embodiment for negative carbon emission.|[0112] 1. The production process design:|[0113] (1) production capacity: 10000 ton/year, production time: 300 days/year, production safety guarantee coefficient: 1.15, daily productivity: 33.33 tons/day, considering the safety factor of 38.33 tons/day, 1.6 tons/hour;|[0114] (2) the production method comprises the following steps: direct combustion of GaCO by using vertical kiln biomass wood chips3A production process of an intermittent bubble carbonization tower;|[0115] (3) the yield of each process is as follows: calcining limestone: considering the factors of over-burning and under-burning of limestone, the conversion rate of the limestone is 95 percent, and GaCO in the limestone3The content is 97 percent, the loss in the calcining and conveying process is 3 percent, and the total yield in the process is 95 percent multiplied by 97 percent and 89.31 percent;|[0116] the yield of slaked lime and refined hydrated lime is 98 percent;|[0117] and (3) carbonation process: usually CO2Feeding in excess, wherein 99% of lime refined emulsion can be taken as complete reaction;|[0118] and (3) post-treatment procedures such as product dehydration and drying: centrifugally dewatering, and removing about 1-2% of calcium carbonate along with filtrate, wherein the part can be returned to a digester for recycling, and the yield of the part is considered to be 99%; the drying yield is 99%; the operation yield of screening, packaging and the like is 99 percent, and the total yield of the light calcium carbonate is as follows: 89.31% x 93% x 99% x 99% x 99% x 84.08%.|[0119] (4) Consumption of raw materials: limestone ore consumption: 38.33/84.08% ═ 45.59 ton/day, 1.90 ton/hour limestone calcination material measured as 38.33t/d, lime kiln feed: limestone 16 ÷ 0.8263 ÷ 19.36kmol/h ═ 1936kg/h, where: GaCO3Content 97%, 1877.92kg/h MgCO3Content 1.2%, 23.23kg/H, H2The O content is 0.5 percent and 9.68kg/h, and the impurity contents of FE, Mn, Al and the like are 1.3 percent and 25.17 kg/h.|[0120] (5) Biomass fuel consumption: the heat value of the mixed wood biomass briquette fuel or the high-quality biomass particle briquette fuel is 3000-4000 kilocalories, the limestone calcination of the embodiment uses the biomass fuel to be directly combusted (biomass pyrolysis gasification biomass gas can be used for calcination), the drying process uses the biomass pyrolysis gas, the biomass fuel is calculated by 30% of the feeding amount of the limestone, the drying process is equivalent to the biomass consumption of the calcination process, and the two processes are 1936 x 0.30, 580.80kg/h and 2428766208kg/a in total, wherein:|[0121] |[0122] |[0123] (6) and (3) quicklime yield: the CaO amount is 19.36 x 0.97 x 0.95 x 56 ═ 999.05kg/h, the unreacted calcium carbonate ore amount is estimated to be 19.36 x 0.97 x 0.05 x 100 ═ 93.1kg/h, the MgO amount is 23.23 ÷ 84 x 40 ÷ 11.06kg/h, the total impurity by-product amount is 25.17+18.59 ═ 43.76kg/h, and the quick lime discharge amount G is 999.05+93.1+11.06+43.76 ═ 1147.77 kg/h.|[0124] (7)CO2Production amount: CaCO3CO obtained by decomposition2Quantity: 1936/100 x 0.97 x 0.95 x 44 ═ 784.97kg/h, prepared from MgCO3CO obtained by decomposition2Quantity: 23.23/84 x 44 is 12.17kg/h, and according to experience, the CO content is about 1.7% of the kiln gas amount, the CO content is 39kg/h, and the CO is consumed2Amount 39 ÷ (consumption 2 x 28) x 44 x 2 ═ 61.28kg/h, substance C consumption: 39 ÷ (2 x 28) x 12 x 2 ═ 16.72kg/h, 21.90kg/h calculated by biomass ash accounting for 8% of the total carbon content of the biomass, and CO produced by the biomass2Quantity: (273.79-16.72-21.90) ÷ 12 x 44 ═ 862.29kg/h, this example was not metered due to the presence of byproducts of the calcination process, and the biomass CO actually produced was not present in the amount2The amount is slightly less than the data;|[0125] CO-generation of CO2Total amount: sigma CO2At 784.97+12.17+862.29-61.28 at 1598.15kg/h, the present example was not metered due to the presence of byproducts of the calcination process, and actually produced CO2The total amount is slightly less than the data.|[0126] 2. Negative carbon emission estimation of the embodiment:|[0127] to ensure that the carbonation process proceeded smoothly, this example employed an excess of CO2Production Process, CO2Besides reacting with slaked lime fine milk to produce light calcium carbonate target product, it also reacts with water, calcium carbonate and other carbonates to produce various carbon-containing compounds and mixtures.|[0128] In the course of production of light calcium carbonate, the by-products are respectively made up by using solid inert carbonate, liquid hydrocarbon material, carbohydrate tar, wood vinegar, lignin (black liquor) andgaseous CO2、CH4And greenhouse gases such as CO and the like and the form of greenhouse gases discharged later are distributed in various production links and environments: such as CaCO3、H2CO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2And the like.|[0129] The annual negative carbon emission of this example is estimated as follows:|[0130] (1) dissipation was estimated as 2%: sigma CO2=1598.15 x 24 x 300 x 2%=230133.60kg/a|[0131] (2) CO dissipation was estimated at about 1.42% by mass: 230133.60 ÷ 0.35 x 1.42% ═ 9336.84kg/a|[0132] (3)|[0133] (4)|[0134] |[0135] (5)The sum of the carbon elements contained is converted into CO2Equivalent indirectly scavenged CO from the atmosphere2The amount of indirect purging cannot be estimated since the present embodiment does not monitor the associated byproduct data.|[0136] (6)BECCU CO2DischargingSourceProduction ofSource-capturingSourceLess than or equal to-5969017.56 kg/a, i.e. BECCU CO in this example2DischargingSourceThe annual negative carbon emission is not less than 5969017.56 kg. | (CN114380314)|TECHNICAL FIELD|[0001] The invention relates to the technical field of biomass energy source replacement of fossil energy and carbon dioxide capture and utilization of negative carbon emission.|BACKGROUND ART|[0002] Artificially created atmospheric CO2The concentration is increased, and the greenhouse effect threatens the survival and development of human beings. Reduction of anthropogenic CO2The technical route of (1) has two routes: the first is to develop renewable energy sources such as solar energy, wind energy and biomass energy to replace fossil energy sources vigorously or reduce CO from the source by improving the utilization efficiency of the fossil energy sources2Discharging; second, to the CO produced2Atmospheric CO increased by human activity is removed by artificially increasing carbon sequestration and carbon Capture using sequestration techniques CCUS (carbon Capture Utilization and storage)2。|[0003] United nations inter-government climate Change organization (IPCC) on CO in 20052Special reports on capture and storage and 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC guide) indicate that fossil fuels are kept in use throughout the 21 st century, avoiding large amounts of CO, according to the third assessment report on IPCC2Discharge, realize the concentration stability of greenhouse gas in the atmosphere and CO2Capture and Storage (CCS) should be one of the combination options for greenhouse gas concentration stabilization, in particular CO captured from biofuel combustion, injected underground and stored2The amounts are included as negative emissions in the list of greenhouse gases, chapter 5, the CCS System and CO, Chapter 5, volume II (energy source)2Capture, transport, inject into the underground storage and discharge and clear up the estimation method; united nations climate change congress, published 2050 via the coordinated Organisation (OCED) environmental agency in 2011, with the expectation of achieving lower concentration targets (450ppm), largely dependent on carbon capture and sequestration using biomass energy (BECCS or BioCCS); in 2015, climate change of Paris United nations will set a positive target, and the global temperature rise is limited to be below 1.5 ℃ to be restored to the level before industrialization. However, it is possible to use a single-layer,the positive value of carbon emission (positive carbon emission) such as clean power generation technology and energy-saving measures is not enough to solve the problem fundamentally even if CO2Reduced amount and slower rate of emission of CO2The net concentration is still rising; the 20 th group of countries (G20) in 2019, the Ministry of energy and environment, incorporated the CCUS technology for carbon capture, utilization and sequestration. IPCC reports suggest that the CCUS technology is significant for realizing zero carbon emission in 2050 years, and large-scale negative carbon emission application technologies need to be deployed in 2040 years.|[0004] CCUS is essentially an artificial, industrial carbon sequestration approach. Wherein, CO2The trapping method comprises 3 trapping methods including pre-combustion trapping, oxygen-enriched or pure oxygen combustion and post-combustion trapping. Pre-combustion capture is the gasification of fossil fuels to synthesis gas (with H as the major component)2And CO) and then converting the CO to CO by a shift reaction2And then H is absorbed by a solvent or the like2And CO2Separation and collection of CO2The technology is limited to a coal gasification combined power generation device for capturing CO before combustion2The cost is about $ 20/t CO2(ii) a The oxygen-enriched combustion technology adopts pure oxygen or oxygen enrichment to combust fossil fuel, and the main product after combustion is CO2Water and some inert components, because pure oxygen is obtained by air low-temperature separation or membrane separation, the energy consumption is large, and the cost of oxygen-enriched combustion is high; common methods for post-combustion capture technology such as chemical absorption, membrane separation, physical adsorption, etc., and post-combustion capture of CO2The cost of (A) is about $ 40/t CO2。|[0005] The CCUS technical test is carried out firstly, the petrochemical industry enhanced oil recovery is carried out, and CO is passed2Connecting carbon source produced by coal chemical industry or natural gas chemical industry with oil field to obtain CCUS-EOR (enhanced oil recovery), and collecting CO2Injecting into oil field to recover oil from exhausted oil field and CO2Permanently stored underground; thereafter, attempts were made to use CO2Fertilizer and food grade CO2Utilization, etc., and also industrially produced CO2Inputting the green as greenhouse gas to strengthen plant growth, etc.|[0006] The earliest large CCUS project in humans was the U.S. construction in 1972Finished Terrell project, CO2The trapping capacity reaches 40 ten thousand t/a; enid project, Okla, USA, was built in 1982 by CO produced by chemical fertilizer plant2Oil displacement of oil field, CO2The trapping capacity reaches 70 ten thousand t/a; the Norwegian Sleipner project in 1996 was the first CO to be established in the world2Injection into underground (saline aquifer) projects, annual sequestration of CO2The quantity is close to million tons; in the United states, in 2000, in cooperation with Canada, the CO of Great Plant Synfuels plants and Sask Power plants was injected at the Weyburn oil field2Accumulating and storing CO while improving the oil extraction rate of the oil field near exhaustion2Up to 2600 or more tens of thousands t; the project of Boundary Dam Power of Sask Power company of Canada in 2014 is the first successful application of the project to CO Power plant2Capture project, CO generated by 150MW coal-fired generator2After capture, a portion was sequestered underground and a portion was used for U.S. Weyburn oil field flooding, CO2The trapping capacity reaches 100 million t/a, and the project traps CO in 20192Up to 61.6 ten thousand t; 2015 Canadian Quest project CO produced in hydrogen production process of synthetic crude oil2Successfully injected into a saline water layer for sealing and storing, and CO is injected every year2The trapping capacity reaches 100 million/a, the project is the first CCS project in the oil sand industry, the carbon emission can be reduced by 100 million every year, and by 2019, the Quest project can trap CO accumulatively2Up to 400 million t, is the maximum CO capture in the world2And successfully injected into a subterranean project; the Gorgon project in the west of australia in 2016 is a complement to the Gorgon natural gas project, the largest global unit LNG project, which projects CO by liquefaction technology2Separating CO from natural gas2The injection amount can reach 350 ten thousand t/a when the injection is injected into a saline layer of the Balo island.|[0007] China starts to research CCUS technology later, and the government continues to come out of the CCUS technical policy in 2006, and the CCUS technology is one of the key points in China national plan for climate change handling (national scheme for climate change handling science and technology action handling in China), Chinese policy and action for climate change handling in China, and the like. In 2007, the China Petroleum Jilin oil field and the China petrochemical east China division company grass House oil field opened domestic CO2The trapping project firstly realizes the industrialization of the CCUS-EOR technology and establishes five types of CO2Oil displacement and sequestration demonstration area, annual sequestration of CO2The capacity can reach 35 ten thousand t; in the same year, China petrochemical east China division builds CO in the oil field of the grass house2A pilot test project with 4 ten thousand of annual injection amount is built with CO in the later period2The annual treatment capacity of the recovery device can reach 2 ten thousand t. Subsequently, the Zhongpetrochemical Shengli oil field, China Shenhua, prolonged Petroleum and the Zhongpetrochemical Central oil field accelerate the propulsion of CO2Industrialization of the collection item. In 2010, the China petrochemical industry victory oil field is built into the first domestic CCUS demonstration project of a coal-fired power plant, and the flue gas CO of the coal-fired power plant is used2Adopting combustion-trapping technology to trap CO as source2Injecting into oil field for displacing oil and CO2The trapping capacity reaches 3-4 million t/a; in 2011, a CCS demonstration project of Shenhua Ordos 10 ten thousand t/a is completed, and a methanol absorption method is adopted to capture CO in tail gas of a coal gasification hydrogen production project2Injecting CO into saline water layer2The project is the first domestic saline water layer geological sequestration experiment project; in 2012, the oil is prolonged to build 5 ten thousand t/a of CO2A collection and utilization item for utilizing CO generated in coal chemical industry2The crude oil is purified, pressurized and liquefied by a low-temperature methanol washing technology and then injected into an oil field, so that the viscosity of the crude oil is reduced, the recovery ratio of the crude oil is improved, and CO is realized2Permanently sealing and storing; in 2015, CCUS project for tail gas of central oil field refinery in medium petrochemical industry was built, and the project approaches to abandoned oil field through CO2Oil displacement improves the oil field extraction rate by 15 percent, and million tons of CO exist at present2Is injected into the ground.|[0008] In addition to the conventional CO2Trapping technology, China also developed CO2The novel recycling technology is applied to the industries of food, fine chemicals and the like, in 2009, a second power plant carbon capture project at the Shanghai stone cave entrance is built, the capture scale is 10 ten thousand t/a, and the captured CO is2The method is mainly used in the food industry; 2011 CO produced by IGCC in research institute of clean coal energy and power system in Hongyun harbor2Trapping the latter part for urea and sodium carbonate industry, injecting the other part into brine layer for sealing; china electric group CO of Tianjin north pond in 20122The trapping demonstration project adopts a post-combustion trapping technology, the annual trapping amount is 2 ten thousand t, and CO is trapped2For eatingThe product industry; in 2010, the Xinao group in inner Mongolian Dallas utilizes a microalgae carbon sequestration technology to absorb tail gas of a coal-based methanol/dimethyl ether device, wherein one part of tail gas is used as biodiesel and the other part of tail gas is used for producing feed, and the treatment capacity reaches 2 ten thousand t/a; the sea snail cement establishes an industrial CCUS test project of 5 ten thousand tons; qilu petrochemical under construction CCUS-EOR project (2020) CO2The trapping capacity was 4 ten thousand t/a. The utilization direction of the emerging carbon in China is mainly CO2Hydrogenation for preparing methanol and CO2Hydrogenation for preparing isoparaffin and CO2Hydrogenation for preparing aromatic hydrocarbon and CO2Although methanation reforming and the like, such as Shanxi coal chemical institute, Dalian union institute, Shanghai research institute of Chinese academy, university of Dalian union, and the like, have studied these technologies, they are mostly in the theoretical research stage or pilot plant stage of catalyst research, and there is no CCUS practical technology for industrial application.|[0009] The Chinese environmental science society, release the Chinese head CCUS group standard 'carbon dioxide capture utilization and sealing term' T/CSES 41-2021 at 22.12.1.2021, comprises related terms of CCUS, related terms of carbon dioxide, capture and transportation terms of carbon dioxide, related terms of CCUS monitoring and measuring performance, related terms of risk and the like, and regulates related terms of the capture utilization and sealing field of carbon dioxide, and is mainly suitable for scientific research, management, teaching and production activities in related fields of carbon dioxide capture, chemical utilization, geological sealing and the like in high emission industries such as chemical industry, thermal power, steel, cement and the like. The T/CSES 41-2021 has positive significance for scientific research and production activities in the CCUS field, promotes the scientificity and normalization of the use of Chinese CCUS terms, and accelerates the pace of meeting international standards. The community standard does not relate to the related patent technology in the CCUS field. The prior patent technology in the CCUS field is few in China, and the real practical technology is almost none.|[0010] CN201711383170.2 discloses a negative carbon emission system and method thereof, which utilizes photosynthesis of growing plants to absorb carbon dioxide molecules, and properly designs photon wavelength for inducing photosynthesis of plants to increase efficiency of photosynthesis of plants, and selects LED light source with carbon footprint lower than threshold and conversion efficiency higher than threshold, and combines low carbon power source with carbon footprint lower than threshold, such as solar cell panel. The system can be applied to the capture of carbon dioxide.|[0011] CN201810173639.8 discloses carbon dioxide entrapment device in cement manufacture, including gas collecting channel, first intake pipe, air pump, first blast pipe, filter, the gas collecting channel top is provided with first intake pipe, one side of first intake pipe is provided with the air pump, one side of air pump is provided with first blast pipe, one side of first blast pipe is provided with the filter, one side of filter is provided with the dust absorption jar, one side of dust absorption jar is provided with the second blast pipe, one side of second blast pipe is provided with gaseous drying tank, one side of gaseous drying tank is provided with the second intake pipe, one side of second intake pipe is provided with the gas holder. Has the advantages that: this carbon dioxide entrapment device has set up equipment such as filtration, purification, drying to the special environment of cement manufacture for the purity of final carbon dioxide product is higher, through the collection to carbon dioxide, has reduced its emission to in the air.|[0012] CN201820292229.0 discloses carbon dioxide collection device that tail gas was handled among cement manufacture, including cement rotary kiln, gas transmission pipeline, dust remover, absorption tower, cement rotary kiln one end is provided with the smoke chamber, smoke chamber one end is provided with gas transmission pipeline, gas transmission pipeline one end is provided with the dust remover, dust remover one end is provided with the scrubbing tower, scrubbing tower one end is provided with the desulfurizing tower, desulfurizing tower one end is provided with the absorption tower, absorption tower one end is provided with analytic tower, analytic tower one end is provided with the gas holder, gas holder one end is provided with the carbon dioxide and does not have the oil-pressure moulding machine, carbon dioxide does not have oil-pressure moulding machine one end and is provided with first absorption tower. Has the advantages that: the device recovers carbon dioxide gas generated in the cement kiln, does not contain impurities, does not discharge into the air, plays a role in protecting the environment, and improves economic benefits by recycling carbon dioxide in other industries.|[0013] CN201811533699.2 discloses a carbon dioxide desorption method for carbon capture, sequestration and utilization technology, which comprises the desorption steps of: starting and adjusting an electric adjusting valve, reducing the temperature and the pressure of saturated steam in the cement kiln tail waste heat boiler through a temperature and pressure reducer, and heating the saturated steam in an amine liquid reboiler in a desorption tower; heating and desorbing the carbon dioxide passing through the desorption tower; and the saturated steam after heating and desorbing the carbon dioxide in the desorption tower is subjected to liquid change to form saturated water, and the saturated water enters a condensate water recovery device through a water return pipe. The carbon dioxide desorption method for the carbon capture, sequestration and utilization technology does not influence the normal operation of the cement kiln waste heat power generation system, can meet the requirement of the desorption operation of the CCS system, and reduces the economic cost investment.|[0014] CN201010532911.0 discloses a waste treatment facility for introducing a thermal decomposition gas of waste into a cement decomposition furnace, which is provided adjacent to a cement manufacturing facility provided with a cement burning furnace, a clinker cooler for cooling a burned product thereof, and a decomposition furnace into which a high-temperature exhaust gas flows from either one of the burning furnace and the clinker cooler. Wherein, possess: the gasification furnace is provided with a gasification furnace for gasifying the waste to generate thermal decomposition gas, and a gas conveying channel for conveying the generated thermal decomposition gas to the decomposition furnace under the condition of keeping the carbon and the ash unchanged. The pyrolysis gas is introduced into the decomposing furnace in such a manner that the pyrolysis gas does not directly interfere with the main stream of the exhaust gas flow from the burning furnace or the clinker cooler, and is prevented from being scraped, thereby sufficiently burning the pyrolysis gas. Thus, the existing cement manufacturing equipment is effectively utilized, and the sanitary treatment of wastes is realized at low cost.|[0015] 201610704208.0 discloses a method for utilizing carbon dioxide in carbonate calcining flue gas and preparing methanol by collecting carbon dioxide generated in the carbonate calcining process; catalytic pyrolysis of biomass fuel to form H-containing2Introducing the fuel gas into a high-pressure catalytic reaction tower after dust fall treatment; the two are produced into products with methanol as the main component in a high-pressure catalytic reaction tower, and are purified and purified into industrial methanol in a distillation tower. Annual production of ten thousand tons of armorAlcohol calculation, the regeneration method for generating carbon dioxide in the carbonate calcination process disclosed by the invention can absorb and consume about 1.375 ten thousand tons of greenhouse gas carbon dioxide, and absorb and consume about 10 ten thousand tons of biomass waste. The purposes of environmental protection and resource recycling are achieved while economic benefits are generated.|[0016] CN201010229727.9 discloses a production process for removing carbon dioxide from flue gas and preparing ammonium compound fertilizer and light calcium carbonate. The method comprises the steps of using dilute ammonia water as an absorbent, carrying out gas-liquid two-phase high-strength mass transfer absorption reaction on raw flue gas through a super-gravity field absorption tower for decarbonization, discharging the treated flue gas through a chimney, and further carrying out reaction treatment on byproducts of the decarbonization reaction to obtain the ammonium compound fertilizer and the light calcium carbonate with good economic value. The complete set of reaction separation device supporting the process comprises a high-gravity field absorption tower, a static mixer, a deep reaction tank, a cyclone, an ammonium compound fertilizer recovery system, a light calcium carbonate recovery system, various pumps and other equipment, wherein the high-gravity field absorption tower is a chemical reaction absorption section for removing carbon dioxide. The invention is a brand new process, and has the advantages of high efficiency, low investment and low operating cost.|[0017] CN201980083589.7 discloses hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation, to a process for hydromethanating the carbonaceous feedstock in a hydromethanation reactor to a methane-enriched raw product stream, and in particular to processing the solid coke by-product removed from the hydromethanation reactor to improve the carbon utilization and thermal efficiency and economics of the overall process by co-producing power and steam from the by-product coke in addition to the end product pipeline quality substitute natural gas.|[0018] CN202010455978.2 discloses a method and a system for utilizing carbon dioxide, wherein the method comprises the following steps: acquiring carbon dioxide meeting preset conditions; injecting the carbon dioxide into a coal seam and allowing the carbon dioxide to expand and release into the coal seam; and the carbon dioxide is used for expelling the coal bed gas in the coal bed to ensure that the coal bed gas is discharged from the coal bed. In the invention, the relatively single carbon dioxide is used as the displacement gas of the coal bed gas, and after the coal bed gas is displaced out of the coal bed, the carbon dioxide is remained and sealed in the coal bed, so that the carbon dioxide is utilized to obtain a clean gas source, the emission of the carbon dioxide is reduced, and the influence on the greenhouse effect is reduced.|[0019] CN201110176523.8 discloses a method and a device for preparing formic acid by recovering carbon dioxide from flue gas and utilizing electric power at night, a carbon dioxide recovery process for separating and recovering carbon dioxide from flue gas obtained by fuel combustion; sending the separated carbon dioxide into a membrane electrolysis device which is reduced by direct current to reduce the carbon dioxide to obtain formic acid; the formic acid refining process is that the dilute formic acid solution obtained by membrane electrolysis is refined to obtain formic acid product. The membrane electrolysis device is divided into a cathode chamber, a concentration chamber and an anode chamber; or divided into a cathode chamber and an anode chamber; the membrane electrolysis units are combined in any mode of series connection or parallel connection or combination of series connection and parallel connection. The technology adopts an efficient membrane electrolysis device and a gas-liquid mixed feeding mode and a carbon dioxide recovery formic acid refining process, has high electrochemical process efficiency, collects and recovers carbon dioxide and obtains high-concentration formic acid liquid through electrolytic reduction, effectively realizes the recovery and conversion of carbon dioxide, and can also effectively utilize the night power of a power plant.|[0020] The fundamental pain point of the above prior art CCUS is high cost, high energy consumption, low efficiency, low benefit, and is far from large-scale commercial application. World CO2The utilization of CO which is still in the theoretical research stage of the technology2Carbon fiber preparation, acetic acid preparation and the like; already in development stage, there is CO2Preparation of Polymer, CO2Methanation reforming, CO2Preparing methanol by hydrogenation, cultivating seaweed, circulating power and the like; already in the demonstration project phase there is a CO2Chemical fertilizer preparation, oil displacement in oil fields, food-grade application and the like. The negative carbon emission methods being discussed and developed are biomass energy power generation and carbon capture and sequestration (BECCS or BioCCS) technologies, such as BioCCS of the european carbon emission center (CCR), it is theoretically possible to remove CO from the atmosphere while producing fuel or electricity2。|[0021] China actively participates and becomes an important construction force for the world to cope with climate change, and carbon neutralization is realized for realizing carbon peak reachingThe national goal of high-quality development and green transformation, CCUS and biomass in China are still changing along with European and American situations by utilizing the negative carbon emission strategy. The invention creatively replaces fossil energy with biomass energy and CO in the current industrial field2The collection and the Utilization of the prior art are organically combined, and the integrated creation of a biomass energy of a non-power plant can utilize the industrialized commercial negative Carbon emission technologies (NETs) practical technology BECCU or BioCCU (Bioass-energy With Carbon Capture and Utilization).|DISCLOSURE|Disclosure of Invention|[0022] Aiming at the defect that Chinese CCUS and biomass energy use negative carbon emission technology is also and gradually following carbon capture and sequestration (BECCS or biocCS) of European and American biomass power plants, in particular to the industrial pain point that CCUS has high cost, high energy consumption, low efficiency and low benefit, the invention uses CO in the production of light calcium carbonate in the current industrial field2Collecting and utilizing the prior art and the production thereof to CO2The self-demand of raw materials organically integrates the biomass energy source instead of fossil energy with the CCUS technology, the light calcium carbonate production process and the like, creates a biomass energy utilization mode of industrial non-power plant biomass energy utilization negative carbon emission practical technical device BECCU or BioCCU, and realizes the CO energy utilization through industrial production by using the pollution reduction and carbon reduction synergistic effect of high efficiency, high benefit, low cost and low energy consumption2The purpose of negative carbon emission removed from the atmosphere opens up a new field of carbon capture and utilization technology.|[0023] In order to realize the aim, the invention provides a non-power plant industrialized biomass energy utilization negative carbon emission technology, biomass energy is used for completely replacing fire coal to produce light calcium carbonate, and the biomass fuel is directly combusted in the calcium carbonate calcination process and CO produced by biomass gasification combustion in the drying of calcium carbonate cooked pulp2The whole is recycled and used in the carbonation process as the raw material for producing calcium carbonate, and CO absorbed by the biomass from the atmosphere2Permanently fixed and sealed in industrial products and byproducts to realize industrialized removal of atmospheric CO2A fraction of the total amount.|[0024] In the invention, limestone and biomass fuel are added into the stone togetherCalcining in an ash kiln, screening the obtained quick lime, then feeding the quick lime into a digestion mechanism for digestion to obtain lime milk coarse pulp, separating and purifying the coarse pulp to obtain fine pulp, aging the fine pulp in an aging tank, then feeding the fine pulp into a fine pulp concentration-regulating tank, adding clear water to regulate the concentration, then feeding the fine pulp into a carbonization tower, and mixing the fine pulp with purified CO from biomass calcining kiln gas and flue gas of a biomass gas hot-blast stove of a drying process for collection2The generated calcium carbonate cooked slurry is subjected to carbonation reaction, is subjected to standing and aging and then is filtered in a filter, and the obtained filter paste is dehydrated, dried, crushed, separated and dedusted to obtain the final product of light calcium carbonate, so that CO absorbed by the biomass from the atmosphere is realized2Permanently fixed and sealed in light calcium carbonate industrial products and byproducts, and industrially removing atmospheric CO2The purpose of (1).|[0025] In the invention, the calcination process for producing the light calcium carbonate can be directly combusted in an industrial manner by using 3000-4000 kilocalories of wood biomass briquette fuel or high-quality biomass particle briquette fuel, and can also be calcined by using biomass fuel gas produced by pyrolyzing biomass by using a biomass gasification furnace. In fact, the production of the quicklime by directly calcining the limestone by using the wood biofuel firewood is a first generation traditional technology of biomass energy utilization existing before the industrial revolution, and the project adopts a second generation technology of biomass energy utilization and biomass briquette industrialized direct combustion technology to improve the energy utilization efficiency and CO2The recycling rate is improved, and the biomass pyrolysis gasification belongs to the third generation technology of biomass energy utilization, and is more advanced and efficient than the second generation technology. No matter the second generation or the third generation biomass energy utilization technology is adopted, the fuel requirement of limestone calcination can be completely met technically.|[0026] In the invention, the precipitated calcium carbonate cooked pulp drying process adopts a biomass pyrolysis gasification technology to supply heat, and CO in the flue gas of a biomass gas hot blast stove2With CO produced by the calcium carbonate calcination process2And are recycled together.|[0027] In the present invention, CO2The collection and the recycling of the light calcium carbonate can be fully utilized to produce the existing CO2The collection and recovery technology and the device thereof greatly reduce the carbon capture, utilization and sealing of the current CCUS technologyHuge investment and cost are present. Wherein CO produced in the calcination stage2Not only can directly adopt the existing CO2The collection and recycling technology and the device can collect and recycle the existing CO according to the requirement2Collecting CO from a utilization system2Collecting, gas-solid-liquid separating, impurity treating, cooling, recovering and CO2A small amount of adaptive technical transformation is carried out on devices such as compression conveying and the like, so that the CO is further improved2The collection and recycling efficiency of (1); CO produced in the drying process of the calcium carbonate cooked pulp2With CO produced during the calcination process2Can be recycled together to meet the requirement of CO production in industrialized commercial light calcium carbonate2The requirement of raw materials.|[0028] In the invention, the biomass fuel is industrially directly combusted or after gasification, the biomass gas is combusted to form C + O2→CO2Releasing CO2And releases heat; and the calcination of calcium carbonate releases CO2The two processes of producing the calcium oxide CaO and drying the calcium carbonate cooked slurry are heat absorption processes, CaCO3→CaO+CO2The enthalpy change of ↓ΔH is larger than zero when the biomass fuel is used for continuously supplementing and providing energy required by reaction and heating. On the one hand, CO is continuously generated by calcining and combustion heating2On the other hand, CO produced by decomposition of calcium carbonate raw material2And CO produced by the combustion of biomass2CO combined with two sources of feedstock and fuel2Must be removed quickly to reduce CO in the calcination process2Partial pressure increase of calcination released CO2Efficiency, and the normal operation of the biomass gas hot blast stove is maintained.|[0029] In the present invention, CaO + H is digested by quicklime2O→Ca(OH)2Delta H < 0 and calcium hydroxide Ca (OH) carboxylated2+CO2→CaCO3Both ↓ + H2O < delta H > are exothermic reactions. Because of the conservation of energy and conservation of material, those skilled in the art, even scientists, produce CaCO from light calcium carbonate3→CaO+CO2To CaO + H2O→Ca(OH)2To Ca (OH)2+CO2→CaCO3Chemical formula, only the light calcium carbonate raw material is seen to be the same as the chemical formula of the final product, CO2The material is equally fed in and out on the molecular formula in the production of the light calcium carbonate; especially the production of heavy calcium carbonate, has no CO at all2The material enters and exits the production process. Thus, one skilled in the art would even think of the scientist's inertial thinking to be that CO is only2The material is carbon balanced before and after the production of the light calcium carbonate and can not generate CO to the atmosphere2What effect the total amount has. What the average person does not think of is CO2Carbon balance process of equal quantity and one inlet and one outlet in light calcium carbonate production of substances for atmospheric CO2The total emissions may lead to potential negative carbon emission technology utilization scenarios.|[0030] In the invention, if biomass energy is not used for completely replacing fossil energy, the production of light calcium carbonate can generate artificial activities to cause atmospheric CO2Increased total carbon emissions. CO released from fossil fuel in light calcium carbonate production2About 35% of the total carbon emission, which is part of the CO energy2The emission is regulated according to the source category of 'energy' in volume 2 of '2006 IPCC guideline', and the emission needs to be measured and accounted to enter a national greenhouse gas list; and the CO released by calcining the raw calcium carbonate ore accounts for about 44 percent of the mass of the raw calcium carbonate ore2Is recycled for the back end carbonation production process, CO2The material is equally discharged and fed in the industrial process of calcium carbonate production, and the total carbon amount in the industrial process is balanced. Thus, the carbon emissions from light calcium carbonate production are only CO metered and accounted for in fossil fuels2And (4) discharging the amount. This is completely different from the carbon emission mechanism of cement production, which does not have CO in the cement production process2The recycling process and mechanism, therefore, the carbon capture, utilization and sealing can be artificially carried out by human beings by adopting the cement CCUS technology. Volume 3 of the 2006 IPCC guideline "industrial process and product usage" regulations "in certain IPPU categories, especially large point emission sources, can capture emissions for recycling or removal. It is a good practice to consider emissions capture using detailed country-specific or more appropriate enterprise-level data. "," Add Capture to formula by adding other terms to formula representing number of observations captured or efficiency of emission reduction system in conjunction with annual system usage, "" Enterprise isWhether or not to install and use CO2Capture technique, preferably by deducting captured CO in high-level process emission calculations2"" other than on List consider CO2Emission of CO for later use2Amount and short term storage should not be from CO2Deducting the discharge. The default assumption is that carbon dioxide capture and storage (CCS) is not employed. Considering CO2Any method of capture should take into account the CO captured in the process2Emissions may be related to both combustion and process. If combustion and process emissions are reported separately, the inventory maker should ensure that the CO is present2The same number of (a) is not counted twice. In these cases, the captured CO2The total amount should best be reported in the respective fuel combustion and the CO generated in these source classes should be taken into account2The volume ratios are reported in the IPPU source category. "|[0031] In the invention, globally recognized zero-carbon biomass energy is used for completely replacing fossil energy, and the production of light calcium carbonate can generate CO influencing the atmosphere2Reduced total CO2Negative discharge effect. CO released by biomass fuel in light calcium carbonate production2With CO liberated from calcium carbonate ore raw material2Is recycled for the production of carbonation process, is combined into calcium carbonate final industrial product and part of the byproduct thereof, and absorbs CO from the atmosphere in the process of biomass (plant) growth2The CO is permanently fixed and sealed in the final industrial product and by-products of the light calcium carbonate through an industrialized process, so that the CO is obtained2CO removal from the atmosphere2Negative discharge effect.|[0032] In the invention, because the chemical change of the light calcium carbonate industrial production is only in the molecule and atom level, the nuclear polymerization change of the C atomic nucleus is not involved, and the total amount of the C elements of the light calcium carbonate raw material and the final industrial product is not changed, thus the light calcium carbonate is in material balance. The carbon material balance mechanism in the industrial production process of the light calcium carbonate is as follows: the carbon element added by the combustion of the biomass fuel is respectively distributed in byproducts produced by light calcium carbonate such as carbon-containing compounds, mixtures and the like in a gas-solid state and a liquid state in different stages of the industrial production process: such as CaCO3、MgCO3、CaMg(CO3)2、MnCO3And hydrocarbons such as tar, carbohydrates and CO gas (CO)2Reduction reaction of CO2+ C → 2CO product), calcium bicarbonate Ca (HCO) (hard water), H carbonate2CO3(CO2Dissolving in water to generate CO carbonate2+H2O==H2CO3) And other carbon compounds (such as greenhouse gas CO) that escape or are discharged to the atmosphere, surface, and water during production2Emissions and other carbon compounds and mixture emissions, etc.). The carbon balance process is essentially atmospheric CO2Carbon sink absorption due to biomass growth → CO release by biomass energy utilization2→ recovery and utilization of CO by carbon capture in industrial production process of calcium carbonate2→ C element with CO2Or other carbonate and carbon compound mixture forms, and is fixedly sealed in the light calcium carbonate product and other byproducts in the production process thereof in the carbonation process. Therefore, the production process of the biomass energy light calcium carbonate is essentially a negative carbon emission process for industrially fixing the carbon element of the biomass energy (wherein CO dissipated into the atmosphere in the production process2When greenhouse gases are required to be metered and accounted for carbon footprint, and part of negative carbon emission reduction amount generated by the invention is offset and deducted), namely, part of CO in the atmosphere is removed through plant carbon sink and the industrial production process2Removed and permanently fixed in the precipitated calcium carbonate product and other non-greenhouse gas by-products.|[0033] In the present invention, because other non-greenhouse gas byproducts must exist in the production process of light calcium carbonate, the total amount of the byproducts is generally equivalent to 20-30% of the yield of the light calcium carbonate. Among them, some by-products (such as CO, etc.) will form CO in future2Finally discharged into the atmosphere, according to the '2006 IPCC guideline', the CO in the industrial process returning to the atmosphere in the future must be measured and accounted2Carbon footprint emissions, and inclusion in the IPPU Source Category into the national greenhouse gas emissions List, which must be derived from the Biomass energy CO2Deducting the negative discharge amount; most of carbon element contained in by-product is permanently fixed and sealed in inert carbonate, and no CO is formed in future2Nor enter the atmosphere to increase the total greenhouse gas. CO in the industrial production of light calcium carbonate because of the inexhaustible substances2Negative emissions, can never be zero. CO for producing light calcium carbonate by using biomass energy2Negative emission, effect and effect of eliminating greenhouse gases in the atmosphere are absolute, and CO can be generated by different biomass energy and light calcium carbonate production technologies and equipment2The difference between the negative carbon emission and the purge amount.|[0034] In the present invention, CO2The measurement and accounting of negative emissions are very similar to the basic emissions calculations of all carbonate combustion industries, based on molecular weight and CO, which are common, according to the "IPCC guideline 2006, volume 3" Industrial Process and product usage-Chapter 2 mining industry carbon emissions "regulations2Ratio of, wherein, CaCO3(Calcite or aragonite) emission factor (ton CO)2Carbonate per ton) 0.43971, MgCO3Magnesite emission factor 0.52197, CaMg (CO)3)2Dolomite emission factor 0.47732, FeCO3Siderite emission factor 0.37987, Ca (Fe, Mg, Mn) (CO)3)2Iron dolomite emission factor 0.40822-0.47572, MnCO3Rhodochrosite discharge factor 0.38286, Na2CO3Sodium carbonate or soda ash discharge factor 0.41492. "chapter 2 mining industry carbon emissions-2.3 lime production" stipulates that the production of lime involves a series of steps including raw material collection, crushing and sizing and calcining the raw material to produce quicklime and, if necessary, hydrating the lime to calcium hydroxide. Consumption of lime products does not result in CO under certain conditions2Is discharged to the atmosphere. For example, slaked lime used in water softening produces CO2React with lime to reform calcium carbonate without generating CO2Net venting to the atmosphere. Similarly, precipitated calcium carbonates for use in the paper industry and other industrial applications are hydrated high calcium quicklime with CO2Generated by the reaction; in the sugar manufacturing process, lime is used to remove impurities from the raw sugarcane juice, and any excess lime can be removed by carbonation. Only the validated and verified method was used to calculate the CO which reacts with lime to reform calcium carbonate2Volume, any rerun in these particular industriesThe carbonization process can be calculated and reported. When these conditions are met, it can be reported under category 2H "other". Lime Kiln Dust (LKD) is generated during lime production and the emission estimate derived using methods 2 and 3 should take into account LKD related emissions. "|[0035] In the invention, the biomass energy is globally recognized zero-carbon energy, and CO generated by biomass energy utilization and not counted in the total amount of emission of greenhouse gases in the atmosphere2Removed from the atmosphere and permanently fixed in the final industrial product light calcium carbonate and its by-products, BECCU and biomass power plant BECCS or BioCCS on CO2The cleaning effect of (a) is the same. The measurement and accounting of greenhouse gas carbon emission in light calcium carbonate production follows the IPCC guideline of 2006 and related methodology, wherein, in addition to the first range of biomass energy utilization negative carbon emission measurement and accounting, carbon footprints such as outsourcing electric power and other energy sources (second range) and enterprise personnel activity carbon emission (third range) in light calcium carbonate industrial production are not included in the energy boundary range of the first range and the technical field of the CCUS related to the invention, but belong to the other technical field and greenhouse gas emission measurement accounting issues.|[0036] In the present invention, CO2The negative emission is measured and calculated according to '2006 IPCC guideline': 1. volume 2 "energy" 2.3.4 carbon dioxide capture "since this is a new emerging technology, it requires plant specific method 3 reporting. The capture and storage plant will most likely meter the amount of gas removed by the gas stream and diverted to geological storage. "," if biofuel is supplied to the plant, the corresponding CO2Emissions will be zero and therefore, subtracting the amount of gas transferred to long term storage gives negative emissions. As a result, CO2Transport, CO2Subsequent emissions from the injection and storage itself should account for the total emissions of the country, whether the carbon originates from a fossil source or is produced by the recent biomass, and subsequent emissions (CO for later use and short-term storage2) Should not be from CO2Deduction in emissions unless CO2 emissions are counted elsewhere in the list [ e.g. CO in urea production (Vol. 3, section 3.2) and methanol production2Use of (Vol 3, section 3.9), in which consideration should be given to the final productCO of product2Emission later). 2. Volume 4 AFOLU "agroforestry and other land utilization" Chapter 4 "Biomass Combustion generated CO2Emissions are not included in the national total greenhouse gas, but are recorded as items of information for cross-check purposes and to avoid recalculation. "|[0037] In the invention, the estimation of greenhouse gas emission in the production of light calcium carbonate by using biomass energy is carried out by adopting a method 3 of '2006 IPCC guideline' to carry out CO2It is estimated that the present invention utilizes biomass energy to produce light calcium carbonate first range (industrial process and energy use) CO2The negative carbon emission measurement and accounting model is as follows: BECCU CO2DischargingSourceProduction ofSource-capturingSourceNamely, the estimation formula:|[0038] |[0039] in the present invention, FIG. 1 is a schematic illustration of a process diagram of biomass energy utilization with negative carbon emission, which illustrates BECCU CO in detail2DischargingSourceWhy it must be negative (i.e. BECCU CO)2DischargingSourceMust be CO2Negative emissions). The inventor organizes strength development or jointly develops BECCU CO according to the invention and the cooperation of the Chinese environmental science society and the Chinese energy-saving society2The negative emission related methodology applies for the approval of the national climate change department and the approval of IPCC record, and develops or jointly develops the CCUS related group standard such as carbon dioxide capture utilization sealing-BECCU industrialized negative carbon emission standard with the Chinese environmental science society and the Chinese energy-saving society.|DRAWINGS DESCRIPTION|[0040] FIG. 1 is a process diagram of negative carbon emission process for biomass energy utilization|[0041] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate|[0042] FIG. 3 is a view showing a structure of a carbonator in a carbon dioxide utilizing process apparatus|[0043] The reference numbers in the drawings of the specification are as follows:|[0044] 1. a support; 2. a kiln gas inlet; 3. a refined lime milk inlet; 4. an exhaust cap; 5. adding a phosphoric acid port; 6. an overflow port; 7. a gas distribution cover; 8. a withdrawal notch; 9. and (5) discharging the cooked pulp.|INVENTION MODE|Detailed Description|[0045] The concrete description is as follows:|[0046] FIG. 1 is a process diagram of negative carbon emission process for biomass energy utilization|[0047] Production of light calcium carbonate CO by using biomass energy2The negative emission process and principle are illustrated as follows according to the steps shown in FIG. 1:|[0048] 1. the biomass limestone calcining process is that biomass briquette fuel is used to replace anthracite and limestone in a layer combustion mixing mode for industrial direct combustion at about 1000 deg.c, and during calcining, partial biomass gas produced through pyrolysis and gasification may be supplemented as required to regulate and control the temperature, combustion condition and calcining atmosphere in the calcining kiln. The process product for producing quick lime by calcining limestone with biomass comprises the following steps:|[0049] (1)、CO2discharging: c + O2→2CO2、CaCO3→CaO+CO2Releasing CO2Wherein the emission of biomass IPPU source type (fuel) in 2006 IPCC guideline is zero, and the emission of the IPPU source type (raw material) CO in the limestone industrial process2Emission default emission factor (CO per ton lime)2Tonnage) high calcium lime 0.75, dolomitic lime 0.86 or 0.77, hydraulic lime 0.59;|[0050] (2) CaO, which accounts for about 56 percent of the mass of the limestone raw material;|[0051] (3) screening lime ash, wherein carbon-containing compound carbonate or carbon-containing mixture is removed from the lime ash, and a byproduct carbon element needs to be metered and calculated in a biomass energy utilization negative carbon emission process;|[0052] (4) lime kiln gas (CO)2Other impurities in the biomass energy utilization negative carbon emission process, which contain carbon compounds, carbonates or carbon-containing mixtures, and need to measure and account for the removal of the waste gas of the byproduct carbon element;|[0053] (5) the kiln gas dissipates CO and accounts for about 1.69 percent of the total volume fraction of the kiln gas (the mass fraction is about 1.42 percent)) The carbon footprint of the kiln gas dissipation byproduct needs to be measured and accounted for CO2Then discharging the amount;|[0054] (6) dust emission CO of lime kiln2Discharging: the amount of Lime Kiln Dust (LKD) generation from the 2006 IPCC guideline depends on the type of lime kiln used and the carbonate characteristics used, with an average shaft kiln producing 9% to 10% dust loss per 1 ton of lime and a raw material feed loss of 16% to 18%. The chemical composition of LKD varies from raw material feed to raw material feed, typically high calcium lime LKD may contain 75% combined calcium oxide and uncalcined calcium carbonate, the remaining impurities are silica, alumina and iron oxides and sulfur (depending on the fuel used), data is collected regarding the typical ratio of LKD to lime production and typical composition of LKD, and in the absence of data, 2% corrective additions can be assumed to account for LKD (i.e., 1.02 CO2Discharge); the vertical axis furnace produces a relatively small amount of LKD, and the LKD correction factor from the vertical axis furnace is determined to be negligible and not necessarily estimated. Method 3 advantageously collects specific data on the weight proportion of carbonate consumed by lime production and the proportion achieved by calcination in each plant, and also collects data on the amount (dry weight) and composition of LKD produced. Similar to method 3 for cement production, the emissions of LKD should be subtracted from the estimate of method 3.|[0055] 2. A biomass pyrolysis gasification process, wherein a biomass gasification furnace mainly supplies heat for a precipitated calcium carbonate (light calcium carbonate) drying process, and can also supply biomass fuel gas for a lime kiln according to needs, and main products after biomass gasification are as follows:|[0056] (1) biomass combustible gas: 20-25% of CO and H in parts by volume28-10%、CH42-4%、CmHn(C2H6、C2H4、C2H2、C3H6、C3H8Etc.) 0.8, etc. The biomass fuel has different components.|[0057] (2) Carbon dioxide: CO22:8-15%;|[0058] (3) Nitrogen gas: n is a radical of246%-56%;|[0059] (4) Oxygen: o is20.5%-1.5%;|[0060] (5) Ash residue: accounting for 5-8% of the total amount of the biomass fuel, and metering and accounting for ash and slag removal of carbon elements of byproducts such as hydrocarbons and the like in the biomass energy utilization negative carbon emission process.|[0061] 3、CO2Collecting and purifying process, CO in kiln gas for calcining limestone by biomass2And CO in the heat supply flue gas generated by biomass gasification combustion2After being collected and recovered, the kiln gas and the flue gas are purified and can be applied to a subsequent carbonation process, the kiln gas and the flue gas are mixed and are subjected to cyclone dust removal, water washing, tar adsorption and sewage treatment, carbon-containing compound carbonate, other hydrocarbons, carbohydrate or carbon-containing mixture ash, tar, sewage sludge and the like are added, and in the biomass energy utilization negative carbon emission process, the CO is measured and calculated2Removing carbon element as by-product in the purification treatment process.|[0062] 4. Quicklime slaking process, CaO + H2O→Ca(OH)2The intermediate product, namely hydrated lime does not relate to the problem of carbon emission, but about 5 percent of waste residues in the digestion process, the carbonate or the carbon-containing mixture of the waste residues, needs to be metered and counted to remove the waste residues of the carbon element of the byproduct in the biomass energy utilization negative carbon emission process.|[0063] 5、CO2Industrial utilization process of CO from limestone calcination decomposition and biomass energy utilization2After purification treatment, in CO2Industrial utilization device of carbonization tower and slaked lime Ca (OH)2Performing carbonation reaction to generate stable carbonate such as calcium carbonate, wherein CO is derived from biomass energy2Is permanently fixed and sealed in stable carbonate industrial products and byproducts such as light calcium carbonate and the like by industrialization and is permanently eliminated from a biomass plant carbon library (processed in AFOLU department according to AFOLU 4 chapter 4 source category of IPCC guideline 2006, agriculture and forestry and other land utilization, which is incorporated into the total amount of greenhouse gas emission of China). In the process of utilizing biomass energy and discharging negative carbon, the CO of the carbonization tower needs to be metered and accounted2CO in industrial utilization2The carbon element which is a byproduct in the tail gas emission of the dissipation and carbonization tower is removed.|[0064] 6. Drying and processing technology of precipitated calcium carbonate (light calcium carbonate), in drying and processing technology of biomass gasification combustion heat supply precipitated calcium carbonate, biomass gas is combusted to form C + O2→CO2Releasing CO2The flue gas is recycled without metering and accounting carbon footprint emission, but CO is dissipated when the biomass gas hot blast stove is combusted2CO and other carbon-containing substances for drying and processing precipitated calcium carbonate, the process dissipation and processing of impurities, and carbon-containing compound carbonate or carbon-containing mixture, in the biomass energy utilization negative carbon emission process, the removal of by-products, such as the drying process dissipation and processing of impurities, and the like, need to be metered and accounted.|[0065] 7. The negative emission process principle for producing light calcium carbonate by using biomass energy is described as follows by integrating the 6 production process flows:|[0066] (1) the biomass carbon element comes from the absorption of CO from the atmosphere and the soil carbon reservoir in the plant growth process2Water, nitrogen, inorganic and trace elements (ash: Ca, K, P, Mg, Si, Al, Ba, Fe, Ti, Na, Mn, Sr), and forming carbohydrate polymer cellulose, hemicellulose and lignin as main components through photosynthesis, including carbohydrates such as starch, protein, lipid, hydrocarbons, etc., and hydrocarbon organic matters. The carbon element of the biomass adopts a chemical structural formula (C)6H10O5)nGlucose trielement polymer (carbon 44.44% hydrogen 6.17% oxygen 49.39%) is the main carbohydrate form, and is fixedly sealed in the carbon pool and the carbon pool of the earth biomass.|[0067] (2) In the carbon pool and carbon pond of the biomass on the earth, the lignin content of woody plants is 20% -35%, and herbaceous plants are 15% -25%, which are the second major renewable biomass resource next to cellulose, and the biomass generates about 6 multiplied by 10 every year on the world14Tons of native lignin, with an incremental production of 1600 million tons/year. The initial strong thermal decomposition temperature of cellulose is 280-290 ℃, the thermal decomposition temperature of lignin is 350-450 ℃, the carbon content of lignin is 55-65%, the complex aromatic structure and the thermal stability are high, and the effective utilization is not achieved at present. In the last hundred years of 1930, the practice of human research on lignin proves that the high-temperature pyrolysisThe method is the only feasible technical route for large-scale industrialization, and the lignin is separated from air and decomposed at high temperature to obtain charcoal, tar, pyroligneous acid and biogas: CO about 50.9%, CH4About 37.5% CO2About 9.6%, and ethylene and other saturated hydrocarbons about 2.0%. The combustion heat value of the lignin is high, the combustion heat of the ash-free spruce picric lignin is 110kJ/g, and the combustion heat of the lignin sulfate is l09.6kJ/g.|[0068] (3) The human industrialized large-scale exploitation utilizes fossil energy such as underground carbon depot coal, petroleum and natural gas, and the like to cause climate change, and international laws such as climate change frame convention of United nations, Jingdu protocol, Paris convention and the like, and specialized organization IPCC of gasification change of the United nations promote the human energy to utilize renewable energy such as solar energy, wind energy, water energy, biomass energy and the like from underground to ground.|[0069] In order to eliminate the inevitable carbon emission in the industrial production processes of electric power, steel, cement building materials, metallurgy, chemical industry and the like and realize the aim of coping with climate change, IPCC (2005) ' carbon dioxide capture and storage special report ' (SRCCS) and ' 2006 IPCC guideline ' clearly propose the technical route of biomass energy utilization (biomass power plant) negative carbon emission ' for any other types (such as CO, power plant) selected for storage2Marine storage or conversion to inert inorganic carbonates) does not provide an emission estimation method. With the exception of mineral carbonisation of certain waste materials, these techniques are in the research phase, not the demonstration or later stages of development of the IPCC (2005) technique. If they reach late in development, emission inventory guidelines generated by these techniques may be compiled and presented in future revisions of the guidelines. "anthropogenic carbon dioxide emissions originate mainly from the combustion of fossil fuels (and biomass) in the power generation, industrial, construction and transportation sectors. CO22And also in certain industrial processes (such as cement manufacture, natural gas processing, and hydrogen production) non-combustion sources. Power plants and other large industrial facilities are CO2The main candidate for capture, a common deployment of the prior art, can capture about 85% -95% CO (processed by IPCC capture plants)2. ", SRCCS provides in its FIG. 5.2 an overview of the relevant processes for pre-combustion capture, post-combustion capture, capture of oxygenated fuel and capture of industrial processes"It has been mentioned in some industrial processes that chemical reactions cause CO2The formed quantity and concentration can directly capture or separate CO from the flue gas2. If CO generated by biomass combustion is captured2Negative emissions may result from the capture and compression system. The invention utilizes biomass energy to produce light calcium carbonate (precipitated calcium carbonate), and BECCU belongs to the CO of the 2006 IPCC guideline2Technical innovation (CO) under the framework of negative emission overall technical route2Conversion to inert inorganic carbonates), there is currently no established negative emission estimation method for BECCU, the present invention is intended to develop BECCU CO2Negative emission estimation methodology, according to method 3 of the 2006 IPCC guideline, CO (input carbonate based approach), CO2Negative emission estimation model: BECCU CO2DischargingSourceProduction ofSource-capturingSourceThe negative emission process measurement accounting formula is as follows:|[0070] |[0071] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0072] (4) Description of the Process principles for negative carbon emissions|[0073] In the above-mentioned CO2In the negative-emission estimation model, the exhaust gas is,is BECCU CO2And (4) estimating the emission (positive number is positive emission, and negative number is negative emission), wherein a is energy and b is a light calcium carbonate production raw material.Wherein,as a source of energySource classDischarging the waste water, and discharging the waste water,as raw material for industrial processesSource classDischarging the waste water, and discharging the waste water,capture utilization of CO for carbonation processes2Atmospheric CO directly eliminated2The emission amount and CO converted by carbon elements contained in the hydrocarbon, carbohydrate liquid and the like such as the inert inorganic carbonate solid and tar which are byproducts of the whole process of industrial production (greenhouse gas emission is not formed in the future)2Indirectly reducing the displacement.|[0074] Further:|[0075] |[0076] (carbon dioxide capture according to "energy" 2.3.4, volume 2, IPCC guideline 2006).|[0077] |[0078] (emission from 2.3 lime production formula 2.7 method 3: emission based on carbonate feed according to Chapter 2 mining industries, volume 3, guide IPCC 2006).|[0079] Wherein, CO2CO emissions from lime production2Discharge in tons|[0080] Emission factor of EFn carbonate n, ton CO2Carbonate per ton|[0081] Mn-consumed carbonate n weight or mass in tons|[0082] Calcining Fn ═ the ratio obtained in carbonate n, the ratio|[0083] Weight and mass of Md-LKD in tons|[0084] Cd is the weight ratio of original carbonate in LKD|[0085] Fd-calcination ratio achieved for LKD, part|[0086] EFd is the emission factor of uncalcined carbonate in LKD, ton CO2Per ton of carbonate.|[0087] |[0088] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0089] Wherein d represents the subsequent discharge amount of greenhouse gases possibly generated in the future in the industrial production of light calcium carbonate, and in the whole production process of precipitated calcium carbonate, part of the dissipated gases which are not captured and utilized by the carbonation process can form CO in the future2Or non-CO2Greenhouse gases, which are subsequently emitted in this part, must be included in the national greenhouse gas list according to the 2006 IPCC guideline, and cannot be deducted from the emission reduction. The method comprises the following steps:|[0090] d 1: indicating subsequent emission of CO|[0091] d 2: represents CH4Then discharged|[0092] d 3: represents H2CO3And so on for subsequent discharge.|[0093] e represents the byproduct of the whole process of industrial production of precipitated calcium carbonate (i.e. the process waste material shown in figure 1), including inert inorganic carbonate solid (excluding non-calcined carbonate in LKD) and carbon-hydrogen such as tar, and indirect CO converted from carbon element fixed in the industrial byproduct for a long time (which will not naturally form greenhouse gas emission in the future)2Capture utilization reduction (indirect carbon capture) comprising:|[0094] e1 denotes inert inorganic carbonates, CaCO3、MgCO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2Etc. of|[0095] e2 represents indirect CO such as liquid hydrocarbon, carbohydrate tar, wood vinegar, lignin (black liquor), etc2The emission reduction amount of the capture and utilization is not as stable as that of the inert inorganic carbonate solid, and the part can be industrially recycled, but does not naturally form greenhouse gas emission.|[0096] Further:|[0097] |[0098] further:|[0099] for theThe industrial production of the light calcium carbonate only chemically changes on the molecular and atomic level, does not relate to the nuclear polymerization change of C element atomic nucleus, does not change the total amount of C elements of the light calcium carbonate raw material and the final industrial product, and is balanced by C substances; and the total content of the C element of the biomass a, the total content of the C element of the subsequent emission d and the total content of the C element of the industrial byproduct e are also in balance of the C substance, and the total content of the C element is not changed in the industrial production.|[0100] Due to the law of constant substances, as long as industrial production is carried out, an industrial production byproduct e (namely the process waste shown in figure 1) is always present,is also certain to exist and can never be zero; particularly in industrial production, the emission of CO and other greenhouse gases dissipated in the process only accounts for about 1.69 percent (about 1.42 percent by mass) of the total volume of the kiln gas and the flue gas, and the emission proportion is very small and is far smaller than that of CO generated by biomass combustion2The total amount of material, and therefore,|[0101] in conclusion, in the production process for producing light calcium carbonate by comprehensively replacing fossil energy with biomass energy as shown in fig. 1, due to the law of constant substances, in the BECCU process technology,and isThe presence of the (C) is determined,BECCU CO2dischargingSourceMust be negative in emission, and absorb CO from the atmosphere in the process of plant growth2CO fixed in biomass carbon reservoir by carbon sink effect2And is permanently sealed in the final industrial product of the light calcium carbonate through an industrial production process.|[0102] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate|[0103] In the description of the attached figure 1, the processes of calcining, biomass pyrolysis gasification and CO production for producing light calcium carbonate by using biomass energy sources2Collecting and purifying, slaking quicklime, Ca (OH)2Six processes, such as carbonation and calcium carbonate drying, have been described in detail and are not described again.|[0104] FIG. 3 is a view showing a structure of a carbonator in a carbon dioxide utilizing process apparatus|[0105] Ca(OH)2And collecting, purifying and compressing the treated CO2Calcium carbonate is generated in a carbonization tower through reaction, and the carbonization tower is CO2The core equipment of the utilization and carbonation process is that the carbonation reaction equation is Ca (OH)2+CO2→CaCO3. FIG. 3 is a view showing the most simple structure of a carbonization tower in which Ca (OH) from a mature slurry aging tank is used2The fine slurry emulsion enters the carbonization tower from a fine ash emulsion inlet 3 shown in the figure and enters the carbonization tower from CO from a kiln gas inlet 2 shown in the figure2Collecting CO from purification and compression process2Carrying out carbonation reaction to generate calcium carbonate; the main function of the 7-gas-dividing hood shown in the figure is to disperse CO2Realization of CO2Distributing the materials evenly, wherein the generated calcium carbonate product is collected by a boiled slurry tank through a boiled slurry outlet 9 shown in the figure and then is aged in a boiled slurry aging tank; the carbonization tower is provided with 6 overflow ports for controlling the height and pressure of the liquid level, and is also provided with a carbonization reaction impurity 8 extraction notch and a carbonization reaction tail gas outlet 4 exhaust cap for exhausting, and a phosphoric acid adding port 5 shown in the figure is mainly used for adding blending auxiliary materials such as phosphoric acid and the like and used for adjusting performance indexes such as whiteness, activity and the like of a calcium carbonate product.|[0106] It must be noted that the carbonizer is CO2Using the key core apparatus of process importance, carbonic acidThe key process for determining the quality of the final product of the light calcium carbonate, such as particles, crystal forms and the like, is the chemical process, and the core of the invention is to provide CO for producing the light calcium carbonate by utilizing biomass energy2The negative discharge technique and method, fig. 3 is only the simplest and most common carbonator structure selected for the convenience of illustrating the carbonation process, and is not intended to limit the carbonation process and apparatus used in the present invention. In fact, the prior art of the carbonation process has various selectable technical processes, including an intermittent bubbling carbonation method, a continuous spray carbonation method, a hypergravity reaction crystallization method and the like, which can be selected to implement the method, and the CO production by the light calcium carbonate of the method can be realized2The purpose of negative discharge technology. Therefore, the invention can be applied to any carbonation process undoubtedly without enumerating and carbonizing process technology and equipment, and any method adopting the invention to replace fossil energy with biomass energy to produce light calcium carbonate and collect and utilize CO2Realization of CO2The purpose of the negative emission technique is within the scope of the present invention.|[0107] Detailed Description|[0108] The inventor deeply recognizes the high-technology high-added-value clean utilization of biomass energy and gradually replaces fossil energy in scientific and technological innovation and industrial innovation practices of the world biomass energy technology in the field of biomass energy utilization for decades at the forefront, and is one of fundamental countermeasures for solving the climate change crisis caused by the unregulated use of human fossil energy; particularly over a decade ago, the inventors discovered the greenhouse gas CO2Not only from the fields of fossil energy, traditional and novel building materials such as building material cement, calcium carbonate, lithium carbonate and the like, chemical engineering, new materials and the like, but also the used main raw materials such as calcium carbonate and the like are greenhouse gas CO2One of the main sources of (1). Based on the important discovery, the inventor is closely cooperated with domestic authoritative scientific research institutions, industrial design institutions, head enterprises of international and domestic related industries and the like, timely masters the latest international dynamic trend, concentrates all efforts, focuses on the zero-carbon-emission biomass energy efficient clean utilization technology for replacing fossil energy, and carries out original scientific research and development, new technology and new product process technology.|[0109] In recent years, the inventor obtains a plurality of major technical breakthroughs in the new technical fields of developing new materials, such as low-carbon zero-carbon cement building materials, calcium carbonate, lithium carbonate and the like, new technologies, new products coping with climate change, realizing carbon peak-reaching carbon neutralization and the like by replacing fossil energy technologies with biomass energy in an efficient and clean manner, particularly applying the most advanced mature biomass energy technology to the related fields of calcium carbonate to replace fossil energy, and forming one of a series of major original technical achievements.|[0110] The invention relates to industrialized carbon capture and permanent CO sequestration by using carbonate industrial products2The implementation range of the negative carbon emission process technology is not limited to the production of light calcium carbonate, namely a carbonate product, and the technical method can be widely applied to the technical fields of various carbonate industrial negative carbon emission and zero-carbon and low-carbon emission, such as various products of cement, white cement, lithium carbonate and the like, after being subjected to adaptive improvement. Therefore, the following examples of the present invention are not intended to limit the scope of the present invention, and any person skilled in the art can make modifications or variations without departing from the technical scope of the present invention, such as the production of various carbonate products such as calcium carbonate, lithium carbonate and tricalcium silicate and other portland cement products by using the technology of the present invention, i.e. all the biomass energy sources are used to replace fossil energy sources (regardless of the substitution rate or whether biomass gasification technology or biomass fuel industrial direct combustion technology is used) and CO is used in the production of light calcium carbonate according to the present invention2The collection and utilization technology integrates the two technologies (including the carbon capture and utilization technology and the industrialized sequestration technology of the CCUS) into a new technology, so as to achieve the purpose and effect of industrialized negative carbon emission, and the scope of the invention is covered by the invention of the technology.|[0111] The embodiment of the invention comprises the following steps: and 10000t/a light calcium carbonate produced annually by using biomass energy instead of fossil energy is used as an embodiment for negative carbon emission.|[0112] 1. The production process design:|[0113] (1) production capacity: 10000 ton/year, production time: 300 days/year, production safety guarantee coefficient: 1.15, daily productivity: 33.33 tons/day, considering the safety factor of 38.33 tons/day, 1.6 tons/hour;|[0114] (2) the production method comprises the following steps: direct combustion of GaCO by using vertical kiln biomass wood chips3A production process of an intermittent bubble carbonization tower;|[0115] (3) the yield of each process is as follows: calcining limestone: considering the factors of over-burning and under-burning of limestone, the conversion rate of the limestone is 95 percent, and GaCO in the limestone3The content is 97 percent, the loss in the calcining and conveying process is 3 percent, and the total yield in the process is 95 percent multiplied by 97 percent and 89.31 percent;|[0116] the yield of slaked lime and refined hydrated lime is 98 percent;|[0117] and (3) carbonation process: usually CO2Feeding in excess, wherein 99% of lime refined emulsion can be taken as complete reaction;|[0118] and (3) post-treatment procedures such as product dehydration and drying: centrifugally dewatering, and removing about 1-2% of calcium carbonate along with filtrate, wherein the part can be returned to a digester for recycling, and the yield of the part is considered to be 99%; the drying yield is 99%; the operation yield of screening, packaging and the like is 99 percent, and the total yield of the light calcium carbonate is as follows: 89.31% x 93% x 99% x 99% x 99% x 84.08%.|[0119] (4) Consumption of raw materials: limestone ore consumption: 38.33/84.08% ═ 45.59 ton/day, 1.90 ton/hour limestone calcination material measured as 38.33t/d, lime kiln feed: limestone 16 ÷ 0.8263 ÷ 19.36kmol/h ═ 1936kg/h, where: GaCO3Content 97%, 1877.92kg/h MgCO3Content 1.2%, 23.23kg/H, H2The O content is 0.5 percent and 9.68kg/h, and the impurity contents of FE, Mn, Al and the like are 1.3 percent and 25.17 kg/h.|[0120] (5) Biomass fuel consumption: the heat value of the mixed wood biomass briquette fuel or the high-quality biomass particle briquette fuel is 3000-4000 kilocalories, the limestone calcination of the embodiment uses the biomass fuel to be directly combusted (biomass pyrolysis gasification biomass gas can be used for calcination), the drying process uses the biomass pyrolysis gas, the biomass fuel is calculated by 30% of the feeding amount of the limestone, the drying process is equivalent to the biomass consumption of the calcination process, and the two processes are 1936 x 0.30, 580.80kg/h and 2428766208kg/a in total, wherein:|[0121] |[0122] |[0123] (6) and (3) quicklime yield: the CaO amount is 19.36 x 0.97 x 0.95 x 56 ═ 999.05kg/h, the unreacted calcium carbonate ore amount is estimated to be 19.36 x 0.97 x 0.05 x 100 ═ 93.1kg/h, the MgO amount is 23.23 ÷ 84 x 40 ÷ 11.06kg/h, the total impurity by-product amount is 25.17+18.59 ═ 43.76kg/h, and the quick lime discharge amount G is 999.05+93.1+11.06+43.76 ═ 1147.77 kg/h.|[0124] (7)CO2Production amount: CaCO3CO obtained by decomposition2Quantity: 1936/100 x 0.97 x 0.95 x 44 ═ 784.97kg/h, prepared from MgCO3CO obtained by decomposition2Quantity: 23.23/84 x 44 is 12.17kg/h, and according to experience, the CO content is about 1.7% of the kiln gas amount, the CO content is 39kg/h, and the CO is consumed2Amount 39 ÷ (consumption 2 x 28) x 44 x 2 ═ 61.28kg/h, substance C consumption: 39 ÷ (2 x 28) x 12 x 2 ═ 16.72kg/h, 21.90kg/h calculated by biomass ash accounting for 8% of the total carbon content of the biomass, and CO produced by the biomass2Quantity: (273.79-16.72-21.90) ÷ 12 x 44 ═ 862.29kg/h, this example was not metered due to the presence of byproducts of the calcination process, and the biomass CO actually produced was not present in the amount2The amount is slightly less than the data;|[0125] CO-generation of CO2Total amount: sigma CO2At 784.97+12.17+862.29-61.28 at 1598.15kg/h, the present example was not metered due to the presence of byproducts of the calcination process, and actually produced CO2The total amount is slightly less than the data.|[0126] 2. Negative carbon emission estimation of the embodiment:|[0127] to ensure that the carbonation process proceeded smoothly, this example employed an excess of CO2Production Process, CO2Besides reacting with slaked lime fine milk to produce light calcium carbonate target product, it also reacts with water, calcium carbonate and other carbonates to produce various carbon-containing compounds and mixtures.|[0128] In the course of production of light calcium carbonate, the by-products are respectively made up by using solid inert carbonate, liquid hydrocarbon material, carbohydrate tar, wood vinegar, lignin (black liquor) andgaseous CO2、CH4And greenhouse gases such as CO and the like and the form of greenhouse gases discharged later are distributed in various production links and environments: such as CaCO3、H2CO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2And the like.|[0129] The annual negative carbon emission of this example is estimated as follows:|[0130] (1) dissipation was estimated as 2%: sigma CO2=1598.15 x 24 x 300 x 2%=230133.60kg/a|[0131] (2) CO dissipation was estimated at about 1.42% by mass: 230133.60 ÷ 0.35 x 1.42% ═ 9336.84kg/a|[0132] (3)|[0133] (4)|[0134] |[0135] (5)The sum of the carbon elements contained is converted into CO2Equivalent indirectly scavenged CO from the atmosphere2The amount of indirect purging cannot be estimated since the present embodiment does not monitor the associated byproduct data.|[0136] (6)BECCU CO2DischargingSourceProduction ofSource-capturingSourceLess than or equal to-5969017.56 kg/a, i.e. BECCU CO in this example2DischargingSourceThe annual negative carbon emission is not less than 5969017.56 kg. | Family Number|(99735170)|99735170|Abstract|(CN114380314 A)|Biomass energy is used for replacing fossil energy and a light calcium carbonate CO2 collection and utilization process , a biomass energy utilization negative carbon emission technology BECCU is created , and the method is more economical , practical and effective compared with a power plant carbon capture and storage BECCS . In light calcium carbonate production , lime calcination and calcium carbonate drying need to consume energy , and a carbonation process needs to consume a CO2 raw material . In the prior art , fossil energy produced from calcium carbonate is used as fuel , and CO2 is recycled as carbonation raw material . The world - recognized zero - carbon - emission biomass energy is used for replacing fossil energy , CO2 produced by the biomass energy is converted into a light calcium carbonate industrial raw material , and the recycled CO2 is from CO2 absorbed from the atmosphere and soil during plant photosynthesis and is not from crustal fossil energy , so that the energy consumption is reduced , and the environmental pollution is reduced . The part of CO2 is combined into a component of a calcium carbonate final product and a byproduct thereof in a carbonation process and each production link , and is removed from the atmosphere to realize a negative emission effect , and a negative carbon emission estimation model BECCU is that CO2 emission source = production source - capture source . |Advantages / Prev. Drawbacks|(CN114380314 A)|( . . . ) congress , published 2050 via the coordinated Organisation ( OCED ) environmental agency in 2011, with the expectation of achieving lower concentration targets ( 450 ppm ) , largely dependent on carbon capture and sequestration using biomass energy ( BECCS or BioCCS ) ; in 2015, climate change of Paris United nations will set a positive target , and the global temperature rise is limited to be below 1.5 ℃to be restored to the level before industrialization . | | Chemical engineering|Materials, metallurgy | B01J-004/00/1|B01J-019/00|B01J-2204/002|C01F-011/18 | B01J-004/00/1|B01J-019/00|B01J-2204/002|C01F-011/18 | B01J-004/00|B01J-019/00|C01F-011/18 | B01J-004/00|B01J-019/00|C01F-011/18 | WO2024170007|CN115532054|GB2643483 | WO2024170007 106298091 WHO=Examiner SELF=Y CAT=A|CN115532054 103251148 WHO=Examiner SELF=N CAT=A|GB2643483 111695430 WHO=Examiner SELF=N | LAPSED | (CN114380314)|LAPSED | DEAD | (CN114380314)|DEAD | (CN114380314)|LEGAL DETAILS FOR CN114380314|Actual or expected expiration date=2023-10-17|Legal state=DEAD|Status=LAPSED|Event publication date=2022-01-27|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202210102805|Application date=2022-01-27|Standardized application number=2022CN-0102805|Event publication date=2022-04-22|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN114380314|Publication stage code=A|Publication date=2022-04-22|Standardized publication number=CN114380314|Event publication date=2022-04-22|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2022-05-10|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|Event publication date=2023-10-17|Event code=CN/WD01|Event indicator=Neg|Event group=Event indicating Not In Force|Patent application deemed withdrawn after publication | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoR0Qagxb2vGhVfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000062591916&ekey=2116&xpn=CN114380314&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=%252Ft7WZ8o529lIb7ahtihdn5NXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN114380314)|NAME=HUANG DA;SHENZHEN SHUOFA INTELLECTUAL PROPERTY AGENCY (GENERAL PARTNERSHIP) , REG=44321 | (CN114380314)|NAME=ZHANG WENBIN | (CN114380314)|4 | 1 | 1 | (CN114380314)|Number of Claims: NCL=10|Gazette date: GAZDATE=2022-04-22|Gazette number: GAZNUM=38-1602|Number of Pages: NPAGES=21| | (CN114380314)|CHINESE (CHI) | (CN114380314)|Patent | Titre: (CN114380314)|Industrial negative carbon emission biomass energy utilization technology device BECCU Résumé: (CN114380314)|Biomass energy is used for replacing fossil energy and a light calcium carbonate CO2 collection and utilization process, a biomass energy utilization negative carbon emission technology BECCU is created, and the method is more economical, practical and effective compared with a power plant carbon capture and storage BECCS. In light calcium carbonate production, lime calcination and calcium carbonate drying need to consume energy, and a carbonation process needs to consume a CO2 raw material. In the prior art, fossil energy produced from calcium carbonate is used as fuel, and CO2 is recycled as carbonation raw material. The world-recognized zero-carbon-emission biomass energy is used for replacing fossil energy, CO2 produced by the biomass energy is converted into a light calcium carbonate industrial raw material, and the recycled CO2 is from CO2 absorbed from the atmosphere and soil during plant photosynthesis and is not from crustal fossil energy, so that the energy consumption is reduced, and the environmental pollution is reduced. The part of CO2 is combined into a component of a calcium carbonate final product and a byproduct thereof in a carbonation process and each production link, and is removed from the atmosphere to realize a negative emission effect, and a negative carbon emission estimation model BECCU is that CO2 emission source = production source-capture source. Autre: (CN114380314)|1. An industrial negative carbon emission biomass energy utilization technical device BECCU is technically characterized in that biomass energy is used for replacing fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, namely precipitated calcium carbonate.|2. The technical device is technically characterized in that biomass energy is used for replacing fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide is collected in the light calcium carbonate production process, the prior art is utilized to collect and utilize biomass energy Carbon, and the negative Carbon emission of zero-Carbon biomass energy Utilization is realized through the industrial Carbon dioxide collection and Utilization process.|3. A technical device BECCU for utilizing industrial negative Carbon emission biomass energy is technically characterized in that biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide in light calcium carbonate production is collected and utilized by the prior art to Capture and utilize Carbon, Carbon dioxide generated in light calcium carbonate industrial production is sealed in light calcium carbonate industrial products and byproducts thereof, Carbon Capture and long-term or permanent industrial product sealing of Carbon dioxide sealed in CCUS Carbon Capture Utilization and Storage are realized, namely, Carbon dioxide is sealed by industrial products and byproducts permanently or long-term Carbon, and negative Carbon emission of zero-Carbon biomass energy Utilization is realized.|4. The industrial negative-carbon-emission biomass energy utilization device BECCU according to claim 1, wherein the calcium carbonate calcination process replaces fossil energy coal, fuel oil, fuel gas and derived energy with internationally recognized zero-carbon biomass energy and biomass briquette to achieve zero-carbon emission of the energy source category of the calcination process.|5. The BECCU according to claim 1, wherein the precipitated calcium carbonate drying and heating process uses internationally recognized zero-carbon biomass energy secondary energy biomass pyrolysis gas to replace fossil energy coal, fuel oil, fuel gas and derived energy for heating, or uses biomass briquette fuel to directly burn to replace fossil energy for heating, thereby realizing zero-carbon emission in the energy source category of the drying and heating process.|6. The industrial negative carbon emission biomass energy utilization device BECCU according to claim 2, which is technically characterized in that the existing technology and device are fully utilized for collecting and utilizing carbon dioxide in the production of light calcium carbonate, the existing technology and device are adaptively modified, and carbon dioxide generated by two production processes, namely a limestone calcining process and a precipitated calcium carbonate drying process, is collected and utilized for recycling.|7. The BECCU according to claim 6, wherein the collected carbon dioxide used in the production of precipitated calcium carbonate includes not only carbon dioxide generated by the calcination and drying of biomass energy source type, but also carbon dioxide decomposed by the calcination of limestone, which is a raw material source type in the calcination process, and carbon dioxide generated by the energy source type and the raw material source type in the industrial production process.|8. The BECCU according to claim 3, wherein the industrial products and by-products produced by precipitated calcium carbonate industry are used for long-term and permanent sequestration of carbon dioxide, and the by-products include all the by-product process wastes produced by the precipitated calcium carbonate industry from limestone ore to the full-flow industrial production of the final product, including inert carbonates such as calcium carbonate, magnesium carbonate and tar, pyroligneous liquor, solid, liquid and gaseous non-greenhouse gas precursor stable substances which will not naturally form greenhouse gas emissions for a long time in the future, but not CO unstable gases and methane greenhouse gases emitted by the light calcium carbonate industry, and which may form subsequent greenhouse gas emissions or greenhouse gases emitted in the future and in the short-term, must be deducted from the carbon dioxide inventory.|9. The device BECCU according to claim 2 and claim 3, wherein the negative carbon emission of zero-carbon biomass energy utilization is realized by a carbon dioxide sequestration process using industrial processes and industrial products and byproducts, and the estimation model of the negative carbon emission is BECCU CO2DischargingSourceProduction ofSource-capturingSource。|10. The device BECCU as claimed in claim 9, wherein the method and related technical standards for developing the device BECCU as an industrial negative carbon emission biomass energy utilization device according to the model for estimating the amount of carbon emission of the device BECCU as a zero-carbon biomass energy utilization device according to the present invention are not limited to the applicant, and any person other than the applicant must have written the consent of the applicant or be developed together with the applicant for developing the method and related technical standards for developing the device BECCU as an industrial negative carbon emission biomass energy utilization device according to the present invention. | 4 | Abstract | gpt-4o-mini | no | The article focuses on a process that utilizes CO₂ absorbed from the atmosphere and soil, rather than CO₂ generated from biomass energy production, which does not align with the BECCS definition. | |||||||||||||||||||||||||||
| 5 | CN202110319100 | CN202110319100 | CN113095637 | 95124595 | CN113095637 A 2021-07-09 [CN113095637] | 2021-03-25 | 2021-03-25 | 2021-07-09 | (CN113095637)|2041-03-25 | (CN113095637)|Evaluation method and system for economic feasibility of biological energy and carbon capture and storage technology | (CN113095637)|A method and a system for evaluating economic feasibility of bioenergy and carbon dioxide capture and storage technology are characterized in that patent application documents and policy documents related to bioenergy and carbon dioxide capture and storage are acquired, a patent database is obtained according to questions, abstracts and keywords of the patent application documents, and according to full texts of the policy documents, a policy database is obtained; theme distribution and word distribution of a database are recognized through machine learning according to a patent database and a policy database, a BECCS technology with an invention prospect is recognized according to the theme distribution and word distribution of the database, and an energy conservation and emission reduction benefit evaluation framework is constructed through an energy conservation supply curve. The energy conservation and emission reduction benefits of the BECCS technology are evaluated through the energy conservation and emission reduction benefit evaluation framework, and the method has the advantages of being comprehensive, accurate, high in perspectiveness and the like. | BEIJING UNIVERSITY OF TECHNOLOGY | (CN113095637)|BEIJING INSTITUTE OF TECHNOLOGY ([CN]) | WEI YIMING|ZHU NANNAN|YU BIYING|WANG JINWEI|KANG JIANING|LIAO HUA | (CN113095637)|WEI YIMING|ZHU NANNAN|YU BIYING|WANG JINWEI|KANG JIANING|LIAO HUA | (CN113095637)|LIU XIYUN;PATENT CENTER OF BEIJING UNIVERSITY OF TECHNOLOGY|Reg. Nb: 11120|LI WEIWEI;PATENT CENTER OF BEIJING UNIVERSITY OF TECHNOLOGY|Reg. Nb: 11120 | (CN113095637)|A system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module; acquiring patent application files and policy files related to capture and sealing of bioenergy and carbon dioxide by a file acquisition module, acquiring a patent database by a database acquisition module according to titles, abstracts and keywords of the patent application files, and acquiring a policy database according to the full text of the policy files; the machine learning module is adopted to recognize the topic distribution and the word distribution of the database through machine learning according to the patent database and the policy database, the technology recognition module and the judgment module recognize the BECCS technology with development prospect according to the topic distribution and the word distribution of the database, finally, an energy-saving and emission-reducing benefit evaluation frame is constructed through the two evaluation modules according to an energy-saving supply curve, and the energy-saving and emission-reducing benefit evaluation frame evaluates the energy-saving and emission-reducing benefits of the BECCS technology, so that the machine learning system has the advantages of being comprehensive, accurate, strong in prospect and the like.| | (CN113095637)|1. A method for assessing the economic viability of bioenergy and carbon capture and sequestration technologies, comprising the steps of: s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies; s2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file; s3: obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode; s4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution; s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology; s6: according to the biological energy and carbon capture and sequestration technology with the development prospect, the energy-saving emission-reduction cost and the energy-saving emission-reduction potential of the biological energy and carbon capture and sequestration technology with the development prospect are evaluated through an energy-saving supply curve; s7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|6. A system for evaluating economic feasibility of biological energy and carbon capture and sequestration technologies is characterized by comprising a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module; the file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology; the database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file; the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode; the technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution; the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect; the first evaluation module is used for evaluating the energy-saving emission-reducing cost and the energy-saving emission-reducing potential of the biological energy and carbon capture and sequestration technology with the development prospect through an energy-saving supply curve according to the biological energy and carbon capture and sequestration technology with the development prospect; and the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.| | (CN113095637)|Based on the above embodiments, the invention provides an evaluation system for economic feasibility of biological energy and carbon capture and sequestration technologies, which comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module.|In order to solve the problems, the invention provides a method and a system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies, and overcomes the defects of weak prospect, strong one-sidedness and the like of the traditional method.|In summary, the invention discloses a method and a system for evaluating economic feasibility of bioenergy and Carbon dioxide Capture and sequestration technology (Bio-Energy with Carbon Capture and Storage, BECCS), wherein the method comprises the following steps: acquiring patent application documents and policy documents related to capture and sequestration of bioenergy and carbon dioxide; obtaining the title, abstract and key words of the patent application file according to the patent application file to obtain a patent database; identifying theme distribution and word distribution thereof through machine learning according to the patent database; identifying an energy-saving technology with a negative emission effect in a patent database according to the theme distribution and the word distribution thereof; according to the policy file, obtaining the title and the content of the policy file to obtain a policy database; identifying subject distribution and word distribution thereof through machine learning according to the policy database; identifying an energy-saving technology with a negative emission effect in a policy database according to the theme distribution and the word distribution thereof; according to the energy-saving technology with the negative emission effect in the patent database and the policy database, identifying the biological energy and carbon dioxide trapping and sealing technology with development prospect; according to the biological energy and carbon dioxide trapping and sealing technology with development prospect, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the technology are calculated through an energy-saving supply curve; according to the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the energy-saving supply curve calculation technology, outputting an energy-saving and emission-reducing benefit analysis chart of the biological energy and carbon dioxide capture and sequestration technology; therefore, the method can overcome the defects of strong one-sidedness, weak foresight and the like of the traditional method.| | (CN113095637)|CARBON CAPTURE(100,87)|SEQUESTRATION(100,83)|BIOLOGICAL ENERGY(100,38)|BIOENERGY ECONOMIC VIABILITY(100,6)|ECONOMIC VIABILITY(100,6)|ECONOMIC FEASIBILITY EVALUATION(100,5)|BIOENERGY EVALUATING ECONOMIC FEASIBILITY(100,3)|POLICY DATABASE(98,36)|DATABASE ACQUISITION MODULE(73,8)|DEVELOPMENT PROSPECT(70,34)|FILE ACQUISITION MODULE(68,8)|EVALUATION MODULE(66,17)|POLICY FILE(66,14)|BIOENERGY ECONOMIC FEASIBILITY(64,7)|WORD DISTRIBUTION(59,30)|CERVUS ELAPHUS CHI DATABASE(55,2)|METHANEDIONE CAPTURE(54,9)|JUDGEMENT MODULE(54,8)|METHANEDIONE TRAPPING(54,2)|THEME DISTRIBUTION(53,13)|BIOENERGY WORD DISTRIBUTION(52,14)|POLICY DOCUMENT(48,18)|ENERGY SAVING(46,49)|TECHNOLOGY IDENTIFICATION MODULE(45,7)|BIOENERGY SEQUESTRATION(44,1)|BIOENERGY(43,31)|WEAK PROSPECT DEFECT(43,1)|EVALUATION FRAMEWORK(42,22)|NEGATIVE EMISSION(42,15)|INHALABLE PARTICLE(34,12)|MACHINE LEARNING MODULE(34,11)|TOPIC DISTRIBUTION(33,8)|MACHINE LEARNING(32,25)|CORE DERMAN DATABASE(32,5)|SCIENCE DATABASE WEB(28,5)|ECONOMIC FEASIBILITY(27,13)|TITLE(27,11)|TECHNOLOGY RECOGNITION MODULE(27,1)|WEAK PROSPECT(27,1)|METHANEDIONE(26,16)|GOVERNMENT SUBSIDY(25,27)|BECCS EMISSION REDUCING BENEFIT(24,3)|SUBJECT DISTRIBUTION(23,9)|WEAK FORESIGHT(23,2)|BECCS(22,8)|FILE CONTENT(21,6)|JUDGEMENT STANDARD(21,6)|PROSPECT(21,5)|EMISSION REDUCTION COST(20,38)|KEYWORD(20,17)|EMISSION REDUCING BENEFIT(20,11)|DIRICHLET DISTRIBUTION TOPIC(20,6)|MATRIX ACQUISITION(20,6)|SYNERGISTIC BENEFIT ANALYSIS(20,6)|POLICY FILE FULL TEXT(20,2)|EMISSION REDUCTION(19,60)|ASSESSMENT MODULE(19,1)|CARBON CAPTURE SYNERGISTIC BENEFIT(18,6)|COMPREHENSIVE(17,3)|BIOLOGICAL ENERGY ECONOMIC FEASIBILITY(17,1)|EVALUATION FRAME(17,1)|EMISSION REDUCING BENEFIT EVALUATION(15,1)|FRAMEWORK CONSTRUCTION(14,6)|MACHINE LEARNING MODE(14,6)|IDENTIFYING ENERGY SAVING(14,3)|ENERGY SAVING EMISSION REDUCTION(13,14)|WORD SEGMENTATION OPERATION(13,12)|ENERGY SAVING SUPPLY CURVE(13,9)|EMISSION REDUCTION POTENTIAL(13,6)|PROFIT LOSS BALANCE ANALYSIS(13,6)|DISTRIBUTION ACQUISITION(13,3)|DEFECT(13,1)|SUPPLY CURVE CALCULATION(13,1)|BIOFUEL(12,5)|EMISSION REDUCING BENEFIT ANALYSIS(12,1)|SULFUR DIOXIDE(11,13)|CERVUS ELAPHUS CHING DATABASE(11,2)|SENSITIVITY ANALYSIS(10,14)|SUPPLY CURVE(10,10)|EMISSION REDUCING COST(10,6)|EMISSION REDUCTION COST CALCULATION(9,6)|DISCOUNT RATE CHANGE(8,6)|BIOMASS POWER GENERATION(8,5)|ECONOMIC LOSS(7,6)|CERVUS ELAPHUS CHINENSIS DATABASE(7,1)|GOVERNMENT PATCH(6,3)|EMISSION REDUCTION POTENTIAL ANALYSIS(5,6)|FULL TEXT(5,3)|BECCS ECONOMIC FEASIBILITY(5,1)|EQUILIBRIUM COAL PRICE(5,1)|BIOMASS POWER PLANT(4,6)|YUAN TON(4,6)| | (CN113095637)|1. A method for assessing the economic viability of bioenergy and carbon capture and sequestration technologies, comprising the steps of:|s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies;|s2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|s3: obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode;|s4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution;|s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology;|s6: according to the biological energy and carbon capture and sequestration technology with the development prospect, the energy-saving emission-reduction cost and the energy-saving emission-reduction potential of the biological energy and carbon capture and sequestration technology with the development prospect are evaluated through an energy-saving supply curve;|s7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|2. The method of claim 1, wherein the patent application and policy documents related to bioenergy and carbon capture and sequestration are specifically:|keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|3. The method for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies as claimed in claim 1, wherein the patent application documents are obtained from the Derman database of the core set of the Web of Science database, and the policy documents are obtained from the Chi database of Cervus elaphus L.|4. The method of claim 1, wherein the step S3 of obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and policy database by machine learning comprises:|creating a DT matrix according to the patent database and the policy database;|and constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|5. The method for evaluating the economic feasibility of the bioenergy and carbon capture and sequestration technology according to claim 1, wherein the method for evaluating the energy saving and emission reduction cost and the energy saving and emission reduction potential of the bioenergy and carbon capture and sequestration technology with a development prospect comprises the following steps:|s61: constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|s62: according to the energy-saving and emission-reducing benefit evaluation framework, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospects are evaluated, and the method specifically comprises the following steps:|obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|6. A system for evaluating economic feasibility of biological energy and carbon capture and sequestration technologies is characterized by comprising a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module;|the file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology;|the database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode;|the technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution;|the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect;|the first evaluation module is used for evaluating the energy-saving emission-reducing cost and the energy-saving emission-reducing potential of the biological energy and carbon capture and sequestration technology with the development prospect through an energy-saving supply curve according to the biological energy and carbon capture and sequestration technology with the development prospect;|and the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|7. The system for assessing the economic viability of bioenergy and carbon capture and sequestration technologies as claimed in claim 6, wherein said patent application documents and policy documents relating to bioenergy and carbon capture and sequestration technologies are in particular:|keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|8. The system for assessing the economic viability of a bioenergy and carbon capture and sequestration technology according to claim 6 wherein the patent application is obtained by the Derman database of the core set of the Web of Science database and the policy is obtained by the Chi database of Cervus elaphus L.|9. The system for assessing the economic viability of a bioenergy and carbon capture and sequestration technology according to claim 6, wherein said machine learning module comprises a matrix acquisition unit and a distribution acquisition unit;|the matrix acquisition unit is used for creating a DT matrix according to the patent database and the policy database;|the distribution obtaining unit is used for constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|10. The system for assessing the economic viability of a bioenergy and carbon capture and sequestration technology according to claim 6, wherein said first assessment module comprises a framework construction unit and an assessment unit;|the framework construction unit is used for constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|the evaluation unit is used for evaluating the energy saving and emission reducing cost and the energy saving and emission reducing potential of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reducing benefit evaluation framework, and specifically comprises the following steps:|obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy. | (CN113095637)|TECHNICAL FIELD|[0001] The invention belongs to the technical field of technical and economic evaluation, and particularly relates to a method and a system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies.|BACKGROUND ART|[0002] The traditional method for evaluating the economic feasibility of the technology mainly aims at the prior art, lacks consideration on the development trend of the technology, has weak foresight and strong one-sidedness, and cannot meet the planning and deployment requirements of emerging technologies under the background of big data. Biological Energy and Carbon Capture and Storage technology (Bio-Energy with Carbon Capture and Storage, BECCS) is an important green technology, can reduce Carbon dioxide in the atmosphere, and is vital to coping with climate change and realizing sustainable development. As a negative emission approach which is most likely to realize commercial deployment, at present, there is no intelligent technical scheme for evaluating the energy saving and emission reduction benefit of the BECCS technology based on a future perspective, so that research and development of a method and a system for evaluating the economic feasibility of the BECCS technology to realize energy saving and emission reduction benefit evaluation of the BECCS technology become a technical problem to be solved urgently by researchers in the field.|DISCLOSURE|Disclosure of Invention|[0003] In order to solve the problems, the invention provides a method and a system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies, and overcomes the defects of weak prospect, strong one-sidedness and the like of the traditional method.|[0004] A method for assessing the economic viability of bioenergy and carbon capture and sequestration technologies comprising the steps of:|[0005] s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies;|[0006] s2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0007] s3: obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode;|[0008] s4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution;|[0009] s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology;|[0010] s6: according to the biological energy and carbon capture and sequestration technology with the development prospect, the energy-saving emission-reduction cost and the energy-saving emission-reduction potential of the biological energy and carbon capture and sequestration technology with the development prospect are evaluated through an energy-saving supply curve;|[0011] s7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0012] Further, the patent application documents and policy documents related to bioenergy and carbon capture and sequestration technologies are specifically:|[0013] keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|[0014] Further, the patent application document is obtained through a Derman database of a core set of Web of Science database, and the policy document is obtained through a Cervus elaphus Chinensis database.|[0015] Further, the step S3 of obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by machine learning specifically includes:|[0016] creating a DT matrix according to the patent database and the policy database;|[0017] and constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0018] Further, the evaluation method of the energy saving and emission reduction cost and the energy saving and emission reduction potential of the biological energy and carbon capture and sequestration technology with development prospects specifically comprises the following steps:|[0019] s61: constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0020] s62: according to the energy-saving and emission-reducing benefit evaluation framework, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospects are evaluated, and the method specifically comprises the following steps:|[0021] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0022] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0023] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0024] A system for evaluating economic feasibility of biological energy and carbon capture and sequestration technologies comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module;|[0025] the file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology;|[0026] the database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0027] the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode;|[0028] the technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution;|[0029] the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect;|[0030] the first evaluation module is used for evaluating the energy-saving emission-reducing cost and the energy-saving emission-reducing potential of the biological energy and carbon capture and sequestration technology with the development prospect through an energy-saving supply curve according to the biological energy and carbon capture and sequestration technology with the development prospect;|[0031] and the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0032] Further, the machine learning module comprises a matrix acquisition unit and a distribution acquisition unit;|[0033] the matrix acquisition unit is used for creating a DT matrix according to the patent database and the policy database;|[0034] the distribution obtaining unit is used for constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0035] Further, the first evaluation module comprises a framework construction unit and an evaluation unit;|[0036] the framework construction unit is used for constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0037] the evaluation unit is used for evaluating the energy saving and emission reducing cost and the energy saving and emission reducing potential of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reducing benefit evaluation framework, and specifically comprises the following steps:|[0038] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0039] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0040] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0041] Has the advantages that:|[0042] 1. a method for evaluating economic feasibility of a bioenergy and carbon capture and sequestration technology comprises the steps of obtaining patent application documents and policy documents related to bioenergy and carbon dioxide capture and sequestration, obtaining a patent database according to titles, abstracts and keywords of the patent application documents, and obtaining a policy database according to full texts of the policy documents; the method comprises the steps of identifying theme distribution and word distribution of a database through machine learning according to a patent database and a policy database, identifying the BECCS technology with the inventive prospect according to the theme distribution and the word distribution of the database, constructing an energy-saving and emission-reducing benefit evaluation framework through an energy-saving supply curve, evaluating the energy-saving and emission-reducing benefits of the BECCS technology through the energy-saving and emission-reducing benefit evaluation framework, and having the advantages of being comprehensive, accurate, strong in prospect and the like.|[0043] 2. A system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module; acquiring patent application files and policy files related to capture and sealing of bioenergy and carbon dioxide by a file acquisition module, acquiring a patent database by a database acquisition module according to titles, abstracts and keywords of the patent application files, and acquiring a policy database according to the full text of the policy files; the machine learning module is adopted to recognize the topic distribution and the word distribution of the database through machine learning according to the patent database and the policy database, the technology recognition module and the judgment module recognize the BECCS technology with development prospect according to the topic distribution and the word distribution of the database, finally, an energy-saving and emission-reducing benefit evaluation frame is constructed through the two evaluation modules according to an energy-saving supply curve, and the energy-saving and emission-reducing benefit evaluation frame evaluates the energy-saving and emission-reducing benefits of the BECCS technology, so that the machine learning system has the advantages of being comprehensive, accurate, strong in prospect and the like.|DRAWINGS DESCRIPTION|[0044] FIG. 1 is a flow chart of a method for evaluating the economic feasibility of the BECCS technology of the present invention;|[0045] FIG. 2 is a block diagram of the BECCS technical economic feasibility assessment system of the present invention;|[0046] FIG. 3 is a frame diagram of the BECCS technology energy conservation and emission reduction benefit evaluation of the present invention;|[0047] FIG. 4 is a graph of emission reduction cost and emission reduction potential output for the BECCS technique of the present invention;|[0048] FIG. 5 is a diagram of the analysis of the profit-loss equilibrium coal price and the profit-loss equilibrium carbon price of the BECCS technology of the present invention;|[0049] FIG. 6 is a diagram of a BECCS technology synergy analysis of the present invention;|[0050] FIG. 7(a) is a graph of a sensitivity analysis of emission reduction cost versus current exposure for the BECCS technique of the present invention;|[0051] FIG. 7(b) is a graph of sensitivity of emission reduction cost to carbon price for the present invention BECCS technology;|[0052] FIG. 7(c) is a graph of a sensitivity of emission reduction costs to government subsidies for the BECCS technology of the present invention.|INVENTION MODE|Detailed Description|[0053] In order to make the technical solutions better understood by those skilled in the art, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application.|[0054] Example one|[0055] As shown in fig. 1, a method for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies, comprising the following steps:|[0056] s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies; optionally, the patent application document and the policy document specifically include: keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|[0057] It should be noted that the patent application document is obtained through a Derman database of the core set of Web of Science database, and the policy document is obtained through a Cervus elaphus Ching database.|[0058] S2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0059] s3: obtaining the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode, and specifically comprises the following steps:|[0060] creating a DT matrix according to the patent database and the policy database;|[0061] and constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0062] S4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution;|[0063] s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology;|[0064] s6: according to the biological energy and carbon capture and sequestration technology with development prospect, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospect are evaluated through an energy-saving supply curve, and specifically the method comprises the following steps:|[0065] s61: constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0066] s62: according to the energy-saving and emission-reducing benefit evaluation framework, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospects are evaluated, and the method specifically comprises the following steps:|[0067] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0068] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0069] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0070] S7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0071] Example two|[0072] Based on the above embodiments, the invention provides an evaluation system for economic feasibility of biological energy and carbon capture and sequestration technologies, which comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module.|[0073] The file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology; optionally, the patent application document and the policy document specifically include: keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|[0074] It should be noted that the patent application document is obtained through a Derman database of the core set of Web of Science database, and the policy document is obtained through a Cervus elaphus Ching database.|[0075] The database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0076] the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode; the machine learning module comprises a matrix acquisition unit and a distribution acquisition unit; the matrix acquisition unit is used for creating a DT matrix according to the patent database and the policy database; the distribution obtaining unit is used for constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0077] The technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution;|[0078] the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect;|[0079] as shown in fig. 3, the first evaluation module is configured to evaluate the energy saving and emission reduction cost and the energy saving and emission reduction potential of the biological energy and carbon capture and sequestration technology with a development prospect through an energy saving supply curve according to the biological energy and carbon capture and sequestration technology with a development prospect; the first evaluation module comprises a framework construction unit and an evaluation unit;|[0080] the framework construction unit is used for constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0081] the evaluation unit is used for evaluating the energy saving and emission reducing cost and the energy saving and emission reducing potential of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reducing benefit evaluation framework, and specifically comprises the following steps:|[0082] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0083] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0084] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0085] And the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0086] Fig. 4 is a diagram of output of emission reduction cost and emission reduction potential of the BECCS technology in an embodiment of the present invention, as shown in fig. 4, a column width in the diagram represents a technology emission reduction potential, a column height represents a technology emission reduction cost, and a technology with an emission reduction cost lower than a critical carbon value represents that the current stage has emission reduction economic feasibility, otherwise, the current stage does not have emission reduction economic feasibility.|[0087] Fig. 5 is an analysis diagram of profit-loss balance coal price and profit-loss balance carbon price of BECCS technology according to an embodiment of the present invention, as shown in fig. 5, the shape in fig. 5 represents a combination of coal price, carbon price, and critical carbon price, different shapes represent different carbon dioxide price levels, and black triangles, black squares, black diamonds, and black circles represent combination points when carbon dioxide prices are 30 yuan/ton, 43 yuan/ton, 116 yuan/ton, and 186 yuan/ton, respectively.|[0088] Fig. 6 is a diagram of a BECCS technology synergistic benefit analysis in an embodiment of the present invention, and as shown in fig. 6, 3 lines in the diagram respectively represent critical price lines for three cases where only energy saving benefits, energy saving and carbon dioxide emission reduction benefits, and energy saving and carbon dioxide and sulfur dioxide emission reduction synergistic benefits are considered, where an area above the critical price lines is a cost effective area, and the cost effective area is expanded as the synergistic benefits are brought into a cost calculation range.|[0089] Fig. 7(a), 7(b), and 7(c) are graphs of sensitivity analysis of emission reduction cost of BECCS technology to discount rate, carbon price, and government subsidy, respectively, according to an embodiment of the present invention, as shown in fig. 7(a), 7(b), and 7(c), where different lines indicate emission reduction cost of technology at different levels of depreciation rate, carbon price, and government subsidy;|[0090] specifically, the carbon dioxide price level when the depreciation rate changes to take a value in fig. 7(a) is 30 yuan/ton, the government patch is 0, the depreciation rate when the carbon price changes to take a value in fig. 7(b) is 5%, the government patch is 0, the depreciation rate when the government patch changes to take a value in fig. 7(c) is 5%, and the carbon dioxide price level is 30 yuan/ton.|[0091] In summary, the invention discloses a method and a system for evaluating economic feasibility of bioenergy and Carbon dioxide Capture and sequestration technology (Bio-Energy with Carbon Capture and Storage, BECCS), wherein the method comprises the following steps: acquiring patent application documents and policy documents related to capture and sequestration of bioenergy and carbon dioxide; obtaining the title, abstract and key words of the patent application file according to the patent application file to obtain a patent database; identifying theme distribution and word distribution thereof through machine learning according to the patent database; identifying an energy-saving technology with a negative emission effect in a patent database according to the theme distribution and the word distribution thereof; according to the policy file, obtaining the title and the content of the policy file to obtain a policy database; identifying subject distribution and word distribution thereof through machine learning according to the policy database; identifying an energy-saving technology with a negative emission effect in a policy database according to the theme distribution and the word distribution thereof; according to the energy-saving technology with the negative emission effect in the patent database and the policy database, identifying the biological energy and carbon dioxide trapping and sealing technology with development prospect; according to the biological energy and carbon dioxide trapping and sealing technology with development prospect, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the technology are calculated through an energy-saving supply curve; according to the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the energy-saving supply curve calculation technology, outputting an energy-saving and emission-reducing benefit analysis chart of the biological energy and carbon dioxide capture and sequestration technology; therefore, the method can overcome the defects of strong one-sidedness, weak foresight and the like of the traditional method.|[0092] The present invention may be embodied in other specific forms without departing from the spirit or essential attributes thereof, and it will be understood by those skilled in the art that various changes and modifications may be made herein without departing from the spirit and scope of the invention as defined in the appended claims. | (CN113095637)|TECHNICAL FIELD|[0001] The invention belongs to the technical field of technical and economic evaluation, and particularly relates to a method and a system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies.|BACKGROUND ART|[0002] The traditional method for evaluating the economic feasibility of the technology mainly aims at the prior art, lacks consideration on the development trend of the technology, has weak foresight and strong one-sidedness, and cannot meet the planning and deployment requirements of emerging technologies under the background of big data. Biological Energy and Carbon Capture and Storage technology (Bio-Energy with Carbon Capture and Storage, BECCS) is an important green technology, can reduce Carbon dioxide in the atmosphere, and is vital to coping with climate change and realizing sustainable development. As a negative emission approach which is most likely to realize commercial deployment, at present, there is no intelligent technical scheme for evaluating the energy saving and emission reduction benefit of the BECCS technology based on a future perspective, so that research and development of a method and a system for evaluating the economic feasibility of the BECCS technology to realize energy saving and emission reduction benefit evaluation of the BECCS technology become a technical problem to be solved urgently by researchers in the field.|DISCLOSURE|Disclosure of Invention|[0003] In order to solve the problems, the invention provides a method and a system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies, and overcomes the defects of weak prospect, strong one-sidedness and the like of the traditional method.|[0004] A method for assessing the economic viability of bioenergy and carbon capture and sequestration technologies comprising the steps of:|[0005] s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies;|[0006] s2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0007] s3: obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode;|[0008] s4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution;|[0009] s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology;|[0010] s6: according to the biological energy and carbon capture and sequestration technology with the development prospect, the energy-saving emission-reduction cost and the energy-saving emission-reduction potential of the biological energy and carbon capture and sequestration technology with the development prospect are evaluated through an energy-saving supply curve;|[0011] s7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0012] Further, the patent application documents and policy documents related to bioenergy and carbon capture and sequestration technologies are specifically:|[0013] keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|[0014] Further, the patent application document is obtained through a Derman database of a core set of Web of Science database, and the policy document is obtained through a Cervus elaphus Chinensis database.|[0015] Further, the step S3 of obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by machine learning specifically includes:|[0016] creating a DT matrix according to the patent database and the policy database;|[0017] and constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0018] Further, the evaluation method of the energy saving and emission reduction cost and the energy saving and emission reduction potential of the biological energy and carbon capture and sequestration technology with development prospects specifically comprises the following steps:|[0019] s61: constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0020] s62: according to the energy-saving and emission-reducing benefit evaluation framework, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospects are evaluated, and the method specifically comprises the following steps:|[0021] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0022] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0023] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0024] A system for evaluating economic feasibility of biological energy and carbon capture and sequestration technologies comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module;|[0025] the file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology;|[0026] the database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0027] the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode;|[0028] the technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution;|[0029] the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect;|[0030] the first evaluation module is used for evaluating the energy-saving emission-reducing cost and the energy-saving emission-reducing potential of the biological energy and carbon capture and sequestration technology with the development prospect through an energy-saving supply curve according to the biological energy and carbon capture and sequestration technology with the development prospect;|[0031] and the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0032] Further, the machine learning module comprises a matrix acquisition unit and a distribution acquisition unit;|[0033] the matrix acquisition unit is used for creating a DT matrix according to the patent database and the policy database;|[0034] the distribution obtaining unit is used for constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0035] Further, the first evaluation module comprises a framework construction unit and an evaluation unit;|[0036] the framework construction unit is used for constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0037] the evaluation unit is used for evaluating the energy saving and emission reducing cost and the energy saving and emission reducing potential of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reducing benefit evaluation framework, and specifically comprises the following steps:|[0038] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0039] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0040] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0041] Has the advantages that:|[0042] 1. a method for evaluating economic feasibility of a bioenergy and carbon capture and sequestration technology comprises the steps of obtaining patent application documents and policy documents related to bioenergy and carbon dioxide capture and sequestration, obtaining a patent database according to titles, abstracts and keywords of the patent application documents, and obtaining a policy database according to full texts of the policy documents; the method comprises the steps of identifying theme distribution and word distribution of a database through machine learning according to a patent database and a policy database, identifying the BECCS technology with the inventive prospect according to the theme distribution and the word distribution of the database, constructing an energy-saving and emission-reducing benefit evaluation framework through an energy-saving supply curve, evaluating the energy-saving and emission-reducing benefits of the BECCS technology through the energy-saving and emission-reducing benefit evaluation framework, and having the advantages of being comprehensive, accurate, strong in prospect and the like.|[0043] 2. A system for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module; acquiring patent application files and policy files related to capture and sealing of bioenergy and carbon dioxide by a file acquisition module, acquiring a patent database by a database acquisition module according to titles, abstracts and keywords of the patent application files, and acquiring a policy database according to the full text of the policy files; the machine learning module is adopted to recognize the topic distribution and the word distribution of the database through machine learning according to the patent database and the policy database, the technology recognition module and the judgment module recognize the BECCS technology with development prospect according to the topic distribution and the word distribution of the database, finally, an energy-saving and emission-reducing benefit evaluation frame is constructed through the two evaluation modules according to an energy-saving supply curve, and the energy-saving and emission-reducing benefit evaluation frame evaluates the energy-saving and emission-reducing benefits of the BECCS technology, so that the machine learning system has the advantages of being comprehensive, accurate, strong in prospect and the like.|DRAWINGS DESCRIPTION|[0044] FIG. 1 is a flow chart of a method for evaluating the economic feasibility of the BECCS technology of the present invention;|[0045] FIG. 2 is a block diagram of the BECCS technical economic feasibility assessment system of the present invention;|[0046] FIG. 3 is a frame diagram of the BECCS technology energy conservation and emission reduction benefit evaluation of the present invention;|[0047] FIG. 4 is a graph of emission reduction cost and emission reduction potential output for the BECCS technique of the present invention;|[0048] FIG. 5 is a diagram of the analysis of the profit-loss equilibrium coal price and the profit-loss equilibrium carbon price of the BECCS technology of the present invention;|[0049] FIG. 6 is a diagram of a BECCS technology synergy analysis of the present invention;|[0050] FIG. 7(a) is a graph of a sensitivity analysis of emission reduction cost versus current exposure for the BECCS technique of the present invention;|[0051] FIG. 7(b) is a graph of sensitivity of emission reduction cost to carbon price for the present invention BECCS technology;|[0052] FIG. 7(c) is a graph of a sensitivity of emission reduction costs to government subsidies for the BECCS technology of the present invention.|INVENTION MODE|Detailed Description|[0053] In order to make the technical solutions better understood by those skilled in the art, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the drawings in the embodiments of the present application.|[0054] Example one|[0055] As shown in fig. 1, a method for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies, comprising the following steps:|[0056] s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies; optionally, the patent application document and the policy document specifically include: keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|[0057] It should be noted that the patent application document is obtained through a Derman database of the core set of Web of Science database, and the policy document is obtained through a Cervus elaphus Ching database.|[0058] S2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0059] s3: obtaining the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode, and specifically comprises the following steps:|[0060] creating a DT matrix according to the patent database and the policy database;|[0061] and constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0062] S4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution;|[0063] s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology;|[0064] s6: according to the biological energy and carbon capture and sequestration technology with development prospect, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospect are evaluated through an energy-saving supply curve, and specifically the method comprises the following steps:|[0065] s61: constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0066] s62: according to the energy-saving and emission-reducing benefit evaluation framework, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospects are evaluated, and the method specifically comprises the following steps:|[0067] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0068] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0069] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0070] S7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0071] Example two|[0072] Based on the above embodiments, the invention provides an evaluation system for economic feasibility of biological energy and carbon capture and sequestration technologies, which comprises a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module.|[0073] The file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology; optionally, the patent application document and the policy document specifically include: keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|[0074] It should be noted that the patent application document is obtained through a Derman database of the core set of Web of Science database, and the policy document is obtained through a Cervus elaphus Ching database.|[0075] The database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|[0076] the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode; the machine learning module comprises a matrix acquisition unit and a distribution acquisition unit; the matrix acquisition unit is used for creating a DT matrix according to the patent database and the policy database; the distribution obtaining unit is used for constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|[0077] The technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution;|[0078] the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect;|[0079] as shown in fig. 3, the first evaluation module is configured to evaluate the energy saving and emission reduction cost and the energy saving and emission reduction potential of the biological energy and carbon capture and sequestration technology with a development prospect through an energy saving supply curve according to the biological energy and carbon capture and sequestration technology with a development prospect; the first evaluation module comprises a framework construction unit and an evaluation unit;|[0080] the framework construction unit is used for constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|[0081] the evaluation unit is used for evaluating the energy saving and emission reducing cost and the energy saving and emission reducing potential of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reducing benefit evaluation framework, and specifically comprises the following steps:|[0082] obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|[0083] estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|[0084] and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|[0085] And the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|[0086] Fig. 4 is a diagram of output of emission reduction cost and emission reduction potential of the BECCS technology in an embodiment of the present invention, as shown in fig. 4, a column width in the diagram represents a technology emission reduction potential, a column height represents a technology emission reduction cost, and a technology with an emission reduction cost lower than a critical carbon value represents that the current stage has emission reduction economic feasibility, otherwise, the current stage does not have emission reduction economic feasibility.|[0087] Fig. 5 is an analysis diagram of profit-loss balance coal price and profit-loss balance carbon price of BECCS technology according to an embodiment of the present invention, as shown in fig. 5, the shape in fig. 5 represents a combination of coal price, carbon price, and critical carbon price, different shapes represent different carbon dioxide price levels, and black triangles, black squares, black diamonds, and black circles represent combination points when carbon dioxide prices are 30 yuan/ton, 43 yuan/ton, 116 yuan/ton, and 186 yuan/ton, respectively.|[0088] Fig. 6 is a diagram of a BECCS technology synergistic benefit analysis in an embodiment of the present invention, and as shown in fig. 6, 3 lines in the diagram respectively represent critical price lines for three cases where only energy saving benefits, energy saving and carbon dioxide emission reduction benefits, and energy saving and carbon dioxide and sulfur dioxide emission reduction synergistic benefits are considered, where an area above the critical price lines is a cost effective area, and the cost effective area is expanded as the synergistic benefits are brought into a cost calculation range.|[0089] Fig. 7(a), 7(b), and 7(c) are graphs of sensitivity analysis of emission reduction cost of BECCS technology to discount rate, carbon price, and government subsidy, respectively, according to an embodiment of the present invention, as shown in fig. 7(a), 7(b), and 7(c), where different lines indicate emission reduction cost of technology at different levels of depreciation rate, carbon price, and government subsidy;|[0090] specifically, the carbon dioxide price level when the depreciation rate changes to take a value in fig. 7(a) is 30 yuan/ton, the government patch is 0, the depreciation rate when the carbon price changes to take a value in fig. 7(b) is 5%, the government patch is 0, the depreciation rate when the government patch changes to take a value in fig. 7(c) is 5%, and the carbon dioxide price level is 30 yuan/ton.|[0091] In summary, the invention discloses a method and a system for evaluating economic feasibility of bioenergy and Carbon dioxide Capture and sequestration technology (Bio-Energy with Carbon Capture and Storage, BECCS), wherein the method comprises the following steps: acquiring patent application documents and policy documents related to capture and sequestration of bioenergy and carbon dioxide; obtaining the title, abstract and key words of the patent application file according to the patent application file to obtain a patent database; identifying theme distribution and word distribution thereof through machine learning according to the patent database; identifying an energy-saving technology with a negative emission effect in a patent database according to the theme distribution and the word distribution thereof; according to the policy file, obtaining the title and the content of the policy file to obtain a policy database; identifying subject distribution and word distribution thereof through machine learning according to the policy database; identifying an energy-saving technology with a negative emission effect in a policy database according to the theme distribution and the word distribution thereof; according to the energy-saving technology with the negative emission effect in the patent database and the policy database, identifying the biological energy and carbon dioxide trapping and sealing technology with development prospect; according to the biological energy and carbon dioxide trapping and sealing technology with development prospect, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the technology are calculated through an energy-saving supply curve; according to the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the energy-saving supply curve calculation technology, outputting an energy-saving and emission-reducing benefit analysis chart of the biological energy and carbon dioxide capture and sequestration technology; therefore, the method can overcome the defects of strong one-sidedness, weak foresight and the like of the traditional method.|[0092] The present invention may be embodied in other specific forms without departing from the spirit or essential attributes thereof, and it will be understood by those skilled in the art that various changes and modifications may be made herein without departing from the spirit and scope of the invention as defined in the appended claims. | Family Number|(95124595)|95124595|Object of Invention|(CN113095637 A)|In summary , the invention discloses a method and a system for evaluating economic feasibility of bioenergy and Carbon dioxide Capture and sequestration technology ( Bio - Energy with Carbon Capture and Storage , BECCS ) , wherein the method comprises the following steps : acquiring patent application documents and policy documents related to capture and sequestration of bioenergy and carbon dioxide ; obtaining the title , abstract and key words of the patent ( . . . ) |Abstract|(CN113095637 A)|A method and a system for evaluating economic feasibility of bioenergy and carbon dioxide capture and storage technology are characterized in that patent application documents and policy documents related to bioenergy and carbon dioxide capture and storage are acquired , a patent database is obtained according to questions , abstracts and keywords of the patent application documents , and according to full texts of the policy documents , a policy database is obtained ; theme distribution and word distribution of a database are recognized through machine learning according to a patent database and a policy database , a BECCS technology with an invention prospect is recognized according to the theme distribution and word distribution of the database , and an energy conservation and emission reduction benefit evaluation framework is constructed through an energy conservation supply curve . The energy conservation and emission reduction benefits of the BECCS technology are evaluated through the energy conservation and emission reduction benefit evaluation framework , and the method has the advantages of being comprehensive , accurate , high in perspectiveness and the like . |Advantages / Prev. Drawbacks|(CN113095637 A)|( . . . ) adopted to recognize the topic distribution and the word distribution of the database through machine learning according to the patent database and the policy database , the technology recognition module and the judgment module recognize the BECCS technology with development prospect according to the topic distribution and the word distribution of the database , finally , ( . . . ) energy - saving and emission - reducing benefit evaluation frame evaluates the energy - saving and emission - reducing benefits of the BECCS technology , so that the machine learning system has the advantages of being comprehensive , accurate , strong in prospect and the like . | | IT methods for management | G06N-020/00|G06Q-010/06/39|G06Q-050/26|Y02P-090/82 | G06N-020/00|G06Q-010/06/39|G06Q-050/26|Y02P-090/82 | G06N-020/00|G06Q-010/06|G06Q-050/26 | G06N-020/00|G06Q-010/06|G06Q-050/26 | CN111078852|AU2020102603|CN109829158|CN109493265|CN108932351|CN108399314|CN105677907 | CN111078852 88485471 WHO=Examiner SELF=N CAT=Y CAT=A|AU2020102603 91845192 WHO=Examiner SELF=Y CAT=A|CN109829158 84698119 WHO=Examiner SELF=N CAT=A|CN109493265 83767291 WHO=Examiner SELF=N CAT=A|CN108932351 82327842 WHO=Examiner SELF=Y CAT=A|CN108399314 80897496 WHO=Examiner SELF=N CAT=A|CN105677907 73329309 WHO=Examiner SELF=N CAT=A | 张雷 等: "中国结构节能减排的潜力分析", 《中国软科学》 (Cat. A)|马丁 等: "中国钢铁行业技术减排的协同效益分析", 《中国环境科学》, vol. 35, no. 01, pages 298 - 303 (Cat. Y)|张雷 等: "中国结构节能减排的潜力分析", 《中国软科学》, no. 2, 28 February 2011 (2011-02-28) (Cat. A)|任明 等: "京津冀地区钢铁行业节能潜力及成本分析", 生态经济, vol. 34, no. 10, pages 91 - 97 (Cat. Y)|朱容辉 等: "基于专利统计的绿色技术创新文献分析及趋势探究", 科技管理研究, vol. 38, no. 04, pages 260 - 265 (Cat. Y) | CN105677907; CN108932351; CN109493265; CN109829158; AU2020102603; CN111078852; CN108399314 | PENDING | (CN113095637)|PENDING | ALIVE | (CN113095637)|ALIVE | (CN113095637)|LEGAL DETAILS FOR CN113095637|Actual or expected expiration date=2041-03-25|Legal state=ALIVE|Status=PENDING|Event publication date=2021-03-25|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202110319100|Application date=2021-03-25|Standardized application number=2021CN-0319100|Event publication date=2021-07-09|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN113095637|Publication stage code=A|Publication date=2021-07-09|Standardized publication number=CN113095637|Event publication date=2021-07-09|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2021-07-27|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination | (CN113095637)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoSGIPN1WKGxb1fn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000058032345&ekey=2230&xpn=CN113095637&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=V7Cyc0RfqX1h0rWOT02oA5NXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN113095637)|CN | (CN113095637)|NAME=BEIJING INSTITUTE OF TECHNOLOGY , COUNTRY=CN | (CN113095637)|NAME=LIU XIYUN;PATENT CENTER OF BEIJING UNIVERSITY OF TECHNOLOGY , REG=11120NAME=LI WEIWEI;PATENT CENTER OF BEIJING UNIVERSITY OF TECHNOLOGY , REG=11120 | (CN113095637)|NAME=WEI YIMING|NAME=ZHU NANNAN|NAME=YU BIYING|NAME=WANG JINWEI|NAME=KANG JIANING|NAME=LIAO HUA | (CN113095637)|7 | 1 | 1 | (CN113095637)|Number of Claims: NCL=10|Gazette date: GAZDATE=2021-07-09|Gazette number: GAZNUM=37-2802|Number of Pages: NPAGES=16| | (CN113095637)|CHINESE (CHI) | (CN113095637)|Patent | Titre: (CN113095637)|Evaluation method and system for economic feasibility of biological energy and carbon capture and storage technology Résumé: (CN113095637)|A method and a system for evaluating economic feasibility of bioenergy and carbon dioxide capture and storage technology are characterized in that patent application documents and policy documents related to bioenergy and carbon dioxide capture and storage are acquired, a patent database is obtained according to questions, abstracts and keywords of the patent application documents, and according to full texts of the policy documents, a policy database is obtained; theme distribution and word distribution of a database are recognized through machine learning according to a patent database and a policy database, a BECCS technology with an invention prospect is recognized according to the theme distribution and word distribution of the database, and an energy conservation and emission reduction benefit evaluation framework is constructed through an energy conservation supply curve. The energy conservation and emission reduction benefits of the BECCS technology are evaluated through the energy conservation and emission reduction benefit evaluation framework, and the method has the advantages of being comprehensive, accurate, high in perspectiveness and the like. Autre: (CN113095637)|1. A method for assessing the economic viability of bioenergy and carbon capture and sequestration technologies, comprising the steps of:|s1: obtaining patent application documents and policy documents related to the bioenergy and carbon capture and sequestration technologies;|s2: obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|s3: obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database by adopting a machine learning mode;|s4: identifying an energy-saving technology with a negative emission effect in a patent database and a policy database according to the theme distribution and the word distribution;|s5: taking at least 3 related patents as judgment standards with development prospects, and acquiring bioenergy with development prospects and a carbon capture and sequestration technology from the energy-saving technology;|s6: according to the biological energy and carbon capture and sequestration technology with the development prospect, the energy-saving emission-reduction cost and the energy-saving emission-reduction potential of the biological energy and carbon capture and sequestration technology with the development prospect are evaluated through an energy-saving supply curve;|s7: and evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|2. The method of claim 1, wherein the patent application and policy documents related to bioenergy and carbon capture and sequestration are specifically:|keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|3. The method for evaluating the economic feasibility of bioenergy and carbon capture and sequestration technologies as claimed in claim 1, wherein the patent application documents are obtained from the Derman database of the core set of the Web of Science database, and the policy documents are obtained from the Chi database of Cervus elaphus L.|4. The method of claim 1, wherein the step S3 of obtaining the subject distribution and word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and policy database by machine learning comprises:|creating a DT matrix according to the patent database and the policy database;|and constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|5. The method for evaluating the economic feasibility of the bioenergy and carbon capture and sequestration technology according to claim 1, wherein the method for evaluating the energy saving and emission reduction cost and the energy saving and emission reduction potential of the bioenergy and carbon capture and sequestration technology with a development prospect comprises the following steps:|s61: constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|s62: according to the energy-saving and emission-reducing benefit evaluation framework, the energy-saving and emission-reducing cost and the energy-saving and emission-reducing potential of the biological energy and carbon capture and sequestration technology with development prospects are evaluated, and the method specifically comprises the following steps:|obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy.|6. A system for evaluating economic feasibility of biological energy and carbon capture and sequestration technologies is characterized by comprising a file acquisition module, a database acquisition module, a machine learning module, a technology identification module, a judgment module, a first evaluation module and a second evaluation module;|the file acquisition module is used for acquiring patent application files and policy files related to the bioenergy and carbon capture and sequestration technology;|the database acquisition module is used for obtaining a patent database through word segmentation operation based on the title, abstract and key words of the patent application file; meanwhile, a policy database is obtained through word segmentation operation based on the file content of the policy file;|the machine learning module is used for acquiring the subject distribution and the word distribution of the bioenergy and carbon capture and sequestration technology from the patent database and the policy database in a machine learning mode;|the technology identification module is used for identifying energy-saving technologies with negative emission effects in a patent database and a policy database according to the theme distribution and the word distribution;|the judgment module is used for acquiring bioenergy with development prospect and a carbon capture and sequestration technology from the energy-saving technology by taking not less than 3 related patents as judgment standards with development prospect;|the first evaluation module is used for evaluating the energy-saving emission-reducing cost and the energy-saving emission-reducing potential of the biological energy and carbon capture and sequestration technology with the development prospect through an energy-saving supply curve according to the biological energy and carbon capture and sequestration technology with the development prospect;|and the second evaluation module is used for evaluating the energy saving and emission reduction benefits of the biological energy and carbon capture and sequestration technology with development prospects according to the energy saving and emission reduction cost and the energy saving and emission reduction potential.|7. The system for assessing the economic viability of bioenergy and carbon capture and sequestration technologies as claimed in claim 6, wherein said patent application documents and policy documents relating to bioenergy and carbon capture and sequestration technologies are in particular:|keywords include bioenergy and carbon dioxide capture and storage, bioenergy, biofuel, negative emissions or carbon capture and storage patent applications, keywords include policy documents for biomass power generation.|8. The system for assessing the economic viability of a bioenergy and carbon capture and sequestration technology according to claim 6 wherein the patent application is obtained by the Derman database of the core set of the Web of Science database and the policy is obtained by the Chi database of Cervus elaphus L.|9. The system for assessing the economic viability of a bioenergy and carbon capture and sequestration technology according to claim 6, wherein said machine learning module comprises a matrix acquisition unit and a distribution acquisition unit;|the matrix acquisition unit is used for creating a DT matrix according to the patent database and the policy database;|the distribution obtaining unit is used for constructing a Dirichlet distribution topic model according to the DT matrix to obtain topic distribution and word distribution of the bioenergy and carbon capture and sequestration technology.|10. The system for assessing the economic viability of a bioenergy and carbon capture and sequestration technology according to claim 6, wherein said first assessment module comprises a framework construction unit and an assessment unit;|the framework construction unit is used for constructing an energy-saving emission-reduction benefit evaluation framework, wherein the energy-saving emission-reduction benefit evaluation framework comprises emission-reduction cost and emission-reduction potential analysis, profit-loss balance analysis, synergistic benefit analysis and sensitivity analysis;|the evaluation unit is used for evaluating the energy saving and emission reducing cost and the energy saving and emission reducing potential of the biological energy and carbon capture and sequestration technology with development prospect according to the energy saving and emission reducing benefit evaluation framework, and specifically comprises the following steps:|obtaining the carbon value of the newly-built biomass power plant during profit-loss balance according to an emission reduction cost calculation formula;|estimating the biological energy with development prospect and the synergistic benefit of the carbon capture and sequestration technology according to the economic loss of the energy-saving and coal price, the emission reduction and carbon price, the carbon dioxide, the sulfur dioxide, the nitrogen oxide, the inhalable particles, the carbon dioxide, the sulfur dioxide, the nitrogen oxide and the inhalable particles to the environment;|and changing the discount rate, the carbon price and the government subsidy, respectively substituting the changed discount rate, the carbon price and the government subsidy into the emission reduction cost calculation formula, judging whether the discount rate, the carbon price and the government subsidy can cause the increase or decrease of the emission reduction cost or not, and obtaining the corresponding increase and decrease so as to realize the sensitivity analysis of the emission reduction cost on the discount rate, the carbon price and the government subsidy. | 3 | Abstract | gpt-4o-mini | uncertain | The article discusses evaluating the economic feasibility of BECCS technology but does not directly describe a system that combines biomass energy production with CO₂ capture and storage. | ||||||||||||||||||||||
| 6 | CN202210102926 | CN202210102926 | CN114229879 | 99292568 | CN114229879 A 2022-03-25 [CN114229879] | 2022-01-27 | 2022-01-27 | 2022-03-25 | (CN114229879)|2026-03-13 | (CN114229879)|Industrial negative carbon emission biomass energy utilization technology BECCU method | (CN114229879)|Biomass energy is used for replacing fossil energy and a light calcium carbonate CO2 collection and utilization process, a biomass energy utilization negative carbon emission technology BECCU is created, and the method is more economical, practical and effective compared with a power plant carbon capture and storage BECCS. In light calcium carbonate production, lime calcination and calcium carbonate drying need to consume energy, and a carbonation process needs to consume a CO2 raw material. In the prior art, fossil energy produced from calcium carbonate is used as fuel, and CO2 is recycled as carbonation raw material. The world-recognized zero-carbon-emission biomass energy is used for replacing fossil energy, CO2 produced by the biomass energy is converted into a light calcium carbonate industrial raw material, and the recycled CO2 is from CO2 absorbed from the atmosphere and soil during plant photosynthesis and is not from crustal fossil energy, so that the energy consumption is reduced, and the environmental pollution is reduced. The part of CO2 is combined into a component of a calcium carbonate final product and a byproduct thereof in a carbonation process and each production link, and is removed from the atmosphere to realize a negative emission effect, and a negative carbon emission estimation model BECCU is that CO2 emission source = production source-capture source. | SHENZHEN CARBONNEUTRAL BIO GAS|SHENZHEN QIANHAI CARBONNEUTRAL LITHIUM INDUSTRY | (CN114229879)|SHENZHEN CARBONNEUTRAL BIO-GAS CO., LTD.|SHENZHEN QIANHAI CARBONNEUTRAL LITHIUM INDUSTRY CO., LTD. | ZHANG WENBIN | (CN114229879)|ZHANG WENBIN | (CN114229879)|HUANG DA;SHENZHEN SHUOFA INTELLECTUAL PROPERTY AGENCY (GENERAL PARTNERSHIP)|Reg. Nb: 44321 | (CN114229879)|"chapter 2 mining industry carbon emissions-2.3 lime production" stipulates that the production of lime involves a series of steps including raw material collection, crushing and sizing and calcining the raw material to produce quicklime and, if necessary, hydrating the lime to calcium hydroxide.|It is a good practice to consider emissions capture using detailed country-specific or more appropriate enterprise-level data. "," Add Capture to formula by adding other terms in formula representing observed quantity of Capture or efficiency of emission reduction System in conjunction with annual System usage "" "whether CO should be installed and deployed in Enterprise2Capture technique, preferably by deducting captured CO in high-level process emission calculations2"" other than on List consider CO2Emission of CO for later use2Amount and short term storage should not be from CO2Deducting the discharge.|The invention is a brand new process, and has the advantages of high efficiency, low investment and low operating cost.|Pre-combustion capture is the gasification of fossil fuels to synthesis gas (with H as the major component)2And CO) and then converting the CO to CO by a shift reaction2And then H is absorbed by a solvent or the like2And CO2Separation and collection of CO2The technology is limited to a coal gasification combined power generation device for capturing CO before combustion2The cost is about $ 20/t CO2(ii) a The oxygen-enriched combustion technology adopts pure oxygen or oxygen enrichment to combust fossil fuel, and the main product after combustion is CO2Water and some inert components, because pure oxygen is obtained by air low-temperature separation or membrane separation, the energy consumption is large, and the cost of oxygen-enriched combustion is high; common methods for post-combustion capture technology such as chemical absorption, membrane separation, physical adsorption, etc., and post-combustion capture of CO2The cost of (A) is about $ 40/t CO2.|The initial strong thermal decomposition temperature of cellulose is 280-290 ℃, the thermal decomposition temperature of lignin is 350-450 ℃, the carbon content of lignin is 55-65%, the complex aromatic structure and the thermal stability are high, and the effective utilization is not achieved at present.|United nations inter-government climate Change organization (IPCC) on CO in 20052Special reports on capture and storage and 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC guide) indicate that fossil fuels are kept in use throughout the 21 st century, avoiding large amounts of CO, according to the third assessment report on IPCC2Discharge, realize the concentration stability of greenhouse gas in the atmosphere and CO2Capture and Storage (CCS) should be one of the combination options for greenhouse gas concentration stabilization, in particular CO captured from biofuel combustion, injected underground and stored2The amounts are included as negative emissions in the list of greenhouse gases, chapter 5, the CCS System and CO, Chapter 5, volume II (energy source)2Capture, transport, inject into the underground storage and discharge and clear up the estimation method; united nations climate change congress, published 2050 via the coordinated Organisation (OCED) environmental agency in 2011, with the expectation of achieving lower concentration targets (450ppm), largely dependent on carbon capture and sequestration using biomass energy (BECCS or BioCCS); in 2015, climate change of Paris United nations will set a positive target, and the global temperature rise is limited to be below 1.5 ℃ to be restored to the level before industrialization.| | (CN114229879)|1. A process for utilizing industrial negative-carbon-emission biomass energy by BECCU technique features that the biomass energy is used to replace fossil energy such as coal, fuel oil, gas and their derivatives to produce light calcium carbonate (precipitated calcium carbonate).|2. A technical BECCU method for utilizing industrial negative Carbon emission biomass energy is technically characterized in that biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide in light calcium carbonate production is collected and utilized by the prior art to Capture biomass energy Carbon, and negative Carbon emission of zero-Carbon biomass energy Utilization is realized by utilizing BECCU or BioCCU Bioass-energy With Carbon Capture and Utilization.|3. A technical BECCU method for utilizing industrial negative Carbon emission biomass energy is technically characterized in that the biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide generated in the light calcium carbonate industrial production is collected and utilized by utilizing the prior art, Carbon Capture and Utilization are carried out, Carbon dioxide generated in the light calcium carbonate industrial production is sealed in precipitated calcium carbonate industrial products and byproducts thereof, the Carbon Capture and the long-term or permanent industrial product sealing of the Carbon dioxide sealed in the CCUS Carbon Capture Utilization and Storage are realized, namely, the Carbon dioxide is sealed by the industrial products and the byproducts permanently or the long-term Carbon, and the negative Carbon emission of zero-Carbon biomass energy Utilization is realized.| | (CN114229879)|In order to realize the aim, the invention provides a non-power plant industrialized biomass energy utilization negative carbon emission technology, biomass energy is used for completely replacing fire coal to produce light calcium carbonate, and the biomass fuel is directly combusted in the calcium carbonate calcination process and CO produced by biomass gasification combustion in the drying of calcium carbonate cooked pulp2The CO absorbed by the biomass energy from the atmosphere is completely recycled and used as the calcium carbonate production raw material in the carbonation process2Permanently fixed and sealed in industrial products to realize industrialized removal of atmospheric CO2A fraction of the total amount.|The invention relates to the technical field of biomass energy source replacement of fossil energy and carbon dioxide capture and utilization of negative carbon emission.|in the present invention, FIG. 1 is a schematic illustration of a process diagram of biomass energy utilization with negative carbon emission, which illustrates BECCU CO in detail2DischargingSourceWhy it must be negative (i.e.| | (CN114229879)|CALCIUM CARBONATE(100,119)|BIOMASS ENERGY(100,46)|LIGHT CALCIUM CARBONATE(100,42)|NEGATIVE CARBON EMISSION(100,33)|BIOMASS ENERGY UTILIZATION(100,26)|FOSSIL ENERGY(100,15)|CARBON EMISSION(100,12)|BECCU(100,9)|PRECIPITATED CALCIUM CARBONATE(100,9)|GAS(100,6)|FUEL OIL(100,5)|FOSSIL ENERGY COAL(100,4)|COAL(100,3)|CARBON EMISSION BIOMASS ENERGY(100,2)|INDUSTRIALIZED NEGATIVE CARBON EMISSION(100,2)|TECHNICAL BECCU(100,2)|DERIVATIVE(100,1)|CARBONATION PROCESS2PERMANENTLY(85,1)|LIKE2AND CO2SEPARATION(79,1)|SYSTEM COORDINATION(71,1)|ATMOSPHERIC CO2A FRACTION(65,1)|CALCIUM CARBONATE COOKED PULP2THE(65,1)|COOKED PULP2THE(63,1)|REPLACING FIRE COAL(63,1)|UNITED NATIONS INTERGOVERNMENT(63,1)|CO2THE COLLECTION(60,4)|ASSESSMENT REPORT(59,1)|LATE USE2AMOUNT(59,1)|BIOMASS GASIFICATION COMBUSTION(58,1)|OXYGEN ENRICHED COMBUSTION(55,2)|BIO FUEL COMBUSTION(55,1)|CCUS CARBON CAPTURE UTILIZATION(55,1)|BIOMASS BRIQUETTE FUEL COMBUSTION(54,1)|INDUSTRIALIZED BIOMASS ENERGY UTILIZATION(54,1)|UTILIZATION TECHNIQUE BECCU(50,2)|INJECTED UNDERGROUND(50,1)|PRECOMBUSTION CAPTURE(49,2)|IPCC GUIDELINE(48,17)|PLANT PHOTOSYNTHESIS2NOT(47,1)|LIME CALCINATION(46,1)|DERIVING ENERGY(45,4)|GASEOUS NONGREENHOUSE GAS PRECURSOR(45,1)|OXYGEN ENRICHMENT(45,1)|PYROLIGNEOUS LIQUOR(45,1)|CALCIUM CARBONATE CO2THE COLLECTION(42,1)|LIMESTONE DECOMPOSITION(42,1)|REMOVAL INDUSTRIALIZATION(42,1)|BYPRODUCT(40,8)|ENTERPRISE2CAPTURE(40,1)|LIGNIN CARBON CONTENT(40,1)|NONPOWER PLANT(39,3)|CALCIUM CARBONATE INDUSTRY(37,3)|FOSSIL FUEL COMBUSTION(36,2)|IPCC GUIDE(36,1)|GREENHOUSE GAS CONCENTRATION STABILIZATION(35,1)|POWER PLANT SEQUESTRATION BECCS(35,1)|CENTURY(33,1)|CONCENTRATION TARGET(33,1)|IPCC2DISCHARGE(33,1)|CHAPTER(32,6)|EXPECTATION(32,1)|NATIONAL GREENHOUSE GAS INVENTORY(32,1)|OXYGEN ENRICHED COMBUSTION COST(32,1)|CARBON DIOXIDE(31,67)|NEGATIVE EMISSION(31,8)|NEGATIVE CARBON EMISSION ESTIMATION(31,3)|CARBON DIOXIDE PERMANENT SEQUESTRATION(30,1)|CLIMATE CHANGE CONGRESS(30,1)|CONCENTRATION STABILITY(30,1)|INVESTMENT(29,1)|ZERO CARBON BIOMASS ENERGY(28,7)|NEGATIVE CARBON EMISSION UTILIZATION(28,1)|POSITIVE TARGET(28,1)|INDUSTRIALIZATION(27,2)|UTILIZING CARBON CAPTURE(27,2)|CARBONATION PROCESS2RAW MATERIAL(27,1)|GREENHOUSE GAS CONCENTRATION STABILITY(27,1)|CALCINING(26,12)|LIGNIN THERMAL DECOMPOSITION TEMPERATURE(26,1)|PERMANENT INDUSTRIAL PRODUCT(26,1)|SITUTHE PRODUCT(26,1)|CARBON CAPTURE(25,17)|CALCIUM CARBONATE INDUSTRIAL PRODUCTION(25,4)|FOSSIL FUEL(25,4)|MEMBRANE SEPARATION(25,2)|THERMAL DECOMPOSITION TEMPERATURE(25,2)|CARBON CONTENT(25,1)|CRUSHING(25,1)|ENVIRONMENTAL AGENCY(25,1)|FRACTION2IN(25,1)|INERT COMPONENT(25,1)|INDUSTRIAL PRODUCT(24,7)|CALCIUM CARBONATE CALCINATION(24,2)|CARBON DIOXIDE CAPTURE(23,9)|CALCIUM CARBONATE PRODUCTION(23,7)|BIOMASS ENERGY SOURCE(23,4)|BIOMASS ENERGY CARBON(23,2)|COAL GASIFICATION(23,2)|CARBON EMISSION TECHNIQUE BECCU(23,1)|METHANE GREENHOUSE GAS(23,1)|PRECIPITATED CALCIUM CARBONATE PRODUCTION(23,1)|UTILIZATION NEGATIVE(23,1)|GREENHOUSE GAS(22,15)|BYPRODUCT CARBON DIOXIDE(22,1)|SIZING(22,1)|LIME PRODUCTION(21,7)|BIOMASS GASIFICATION(21,5)|ANNUAL SYSTEM USAGE(21,1)|CARBON DIOXIDE INVENTORY(21,1)|CELLULOSE THERMAL DECOMPOSITION TEMPERATURE(21,1)|LIMESTONE CALCINING(21,1)|PROCESS EMISSION CALCULATION(21,1)|UNSTABLE GAS(21,1)|SEQUESTRATION(20,8)|FUEL GAS(20,5)|THERMAL DECOMPOSITION(20,5)|QUICKLIME(20,4)|INERT CARBONATE(20,3)|POST COMBUSTION CAPTURE(20,3)|MINING INDUSTRY CARBON EMISSION(20,2)|PURE OXYGEN(20,2)|ZERO CARBON EMISSION(20,2)|GLOBAL TEMPERATURE RISE(19,1)|SECONDARY ENERGY BIOMASS(19,1)|UNDERGROUND STORAGE(19,1)|ZERO CARBON(18,9)|BIOMASS FUEL(17,11)|MEMBRANE ELECTROLYSIS(17,5)|BIOCCS(17,4)|BECCU CO2NEGATIVE EMISSION ESTIMATION(17,1)|GREENHOUSE GAS INVENTORY(17,1)|IMMEDIATE PERIOD(17,1)|PHYSICAL ADSORPTION(17,1)|CO2THE TRAPPING CAPACITY(16,4)|BECCS(16,3)|BIOMASS PARTICLE BRIQUETTE FUEL(16,2)|CARBONIZATION TOWER CO2INDUSTRIAL UTILIZATION(16,1)|CO2(16,1)|CO2ALTHOUGH METHANATION REFORMING(16,1)|CO2THE ANNUAL SEQUESTRATION(16,1)|COLLECTED CARBON DIOXIDE(16,1)|COMPLEX AROMATIC STRUCTURE(16,1)|IPCC GUIDELINE2TECHNICAL INNOVATION(16,1)|INDUSTRIAL PRODUCTION(15,17)|CLIMATE CHANGE(15,13)|COMBUSTION(15,6)|LIME(15,6)|MINING INDUSTRY(15,3)|CALCIUM CARBONATE INDUSTRIAL PRODUCT(15,2)|CALCIUM HYDROXIDE(15,2)|CARBONACEOUS FEEDSTOCK HYDROMETHANATION(15,1)|GRASS HOUSE2ANNUAL INJECTION OILFIELD(15,1)|HYDROMETHANATING CARBONACEOUS FEEDSTOCK(15,1)|INEXHAUSTIBLE SUBSTANCES2NEGATIVE EMISSION(15,1)|INTERMITTENT BUBBLE CARBONIZATION TOWER(15,1)|SEQUESTRATION(15,1)|WEYBURN OILFIELD FLOODING(15,1)|LIGHT CALCIUM CARBONATE PRODUCTION(14,8)|ABSORPTION TOWER(14,6)|CHINESE ENVIRONMENTAL SCIENCE SOCIETY(14,3)|CLINKER COOLER(14,3)|DESORPTION TOWER(14,3)|CARBONATE TON CO2PER TON(14,1)|DOMESTIC CCUS DEMONSTRATION(14,1)|ENERGY CONSUMPTION(14,1)|ENTERPRISE LEVEL DATA(14,1)|GEOLOGICAL SEQUESTRATION EXPERIMENT PROJECT(14,1)|INTERMITTENT BUBBLING CARBONATION(14,1)|MAGNESIUM CARBONATE(14,1)|NATIVE LIGNIN WORLD14TONS(14,1)|THERMAL STABILITY(14,1)|INTAKE PIPE(13,5)|TECHNICAL STANDARD(13,2)|ACCOUNTED2CARBON FOOTPRINT EMISSION(13,1)|CARBONATION RAW MATERIAL(13,1)|CO2THE CAPACITY ANNUAL SEQUESTRATION(13,1)|DOMESTIC CO2THE TRAPPING(13,1)|LONG TERM SEQUESTRATION(13,1)|METHANOLTHE WASTE TON(13,1)|SHORT PERIOD(13,1)|SYNTHESIS GAS(13,1)|UTILIZATION(13,1)|REPLACING FOSSIL ENERGY(11,4)|CALCINING LIMESTONE(11,2)|DUST ABSORPTION JAR(11,2)|HYDROMETHANATION REACTOR(11,2)|ANTHROPOGENIC CO2THE TECHNICAL ROUTE(11,1)|ATMOSPHERIC CO2CARBON SINK ABSORPTION(11,1)|BIOMASS ASH ACCOUNTING(11,1)|CCUS INDUSTRIALIZATION(11,1)|CCUS SEQUESTRATION(11,1)|CO2TOTAL COGENERATION(11,1)|DALIAN UNION INSTITUTE(11,1)|DALIAN UNION UNIVERSITY(11,1)|ENERGY SOURCE CATEGORY(11,1)|GUIDELINE FUTURE REVISION(11,1)|IPCC RECORD APPROVAL(11,1)|LIMESTONE CALCINATION DECOMPOSITION(11,1)|LIMESTONE CALCINATION FUEL REQUIREMENT(11,1)|LONG TERM CARBON(11,1)|PROCESSESSOURCE CLASSDISCHARGING(11,1)|RAW MATERIAL COLLECTION(11,1)|SUBSTANCES2NEGATIVE EMISSION COMBUSTION(11,1)|ZHONGPETROCHEMICAL SHENGLI OILFIELD(11,1)|ENERGY SOURCE(10,4)|COAL BED(10,3)|DUST REMOVER(10,3)|EMISSION REDUCTION(10,3)|ANALYTICAL TOWER(10,2)|CALCIUM CARBONATE COOKED SLURRY(10,2)|CARBOHYDRATE TAR(10,2)|CO2OIL DISPLACEMENT(10,2)|FOSSIL ENERGY SOURCE(10,2)|NUCLEAR POLYMERIZATION(10,2)|SCRUBBING TOWER(10,2)|TECHNOLOGY BECCU(10,2)|BIOMASS GASIFICATION COMBUSTION2AFTER(10,1)|BOILED SLURRY AGING TANK(10,1)|BRAND NEW(10,1)|CALCINATION PROCESS2PARTIAL(10,1)|CANADIAN QUEST PROJECT(10,1)|CO2CHEMICAL FERTILIZER(10,1)|CO2NEGATIVE EMISSION ESTIMATION MODEL(10,1)|COAL FIRED GENERATOR2AFTER CAPTURE(10,1)|KILN BIOMASS WOOD(10,1)|LIMESTONE ORE CONSUMPTION(10,1)|MAJOR RENEWABLE BIOMASS RESOURCE(10,1)|METHODSTHE EMISSION ESTIMATE(10,1)|NGLUCOSE TRIELEMENT POLYMER(10,1)|ORE RAW MATERIAL2IS(10,1)|PLANT INDUCING PHOTOSYNTHESIS(10,1)|TRAPPING DEMONSTRATION PROJECT(10,1)|UNDERGROUND CARBON DEPOT COAL(10,1)|AGING TANKTHE(9,1)|BIOMASS CALCINING KILN GAS(9,1)|CALCINATION PROCESS2CAN(9,1)|CALCIUM CARBONATE CALCINATION PROCESS2AND(9,1)|CARBONATE PRODUCTS2THE(9,1)|CEMENT BURNING FURNACE(9,1)|CEMENT CCUS(9,1)|CEMENT DECOMPOSITION FURNACE(9,1)|CHINESE ACADEMY RESEARCH INSTITUTE(9,1)|CO2METHANATION REFORMING(9,1)|CULTIVATING SEAWEED(9,1)|DESULFURIZE TOWER(9,1)|GASIFYING BIOMASS(9,1)|LATE INTERNATIONAL DYNAMIC TREND(9,1)|LIME MILK COARSE PULP(9,1)|LIME REFINED EMULSION(9,1)|MATURE SLURRY AGING TANK(9,1)|PRECOMBUSTION TRAPPING(9,1)|PYROLYZING BIOMASS(9,1)|QILU PETROCHEMICAL(9,1)|SCREENING LIME ASH(9,1)|USED2THE FINE SLURRY EMULSION(9,1)|VICTORY OILFIELD(9,1)|WOODY PLANT LIGNIN CONTENT(9,1)|YEAR2THE TRAPPING CAPACITY(9,1)|GAS TRANSMISSION PIPELINE(8,3)|WASTE RESIDUE(8,3)|CEMENT ROTARY KILN(8,2)|GASEOUS DRYING TANK(8,2)|IPPU SOURCE CATEGORY(8,2)|LAND UTILIZATION(8,2)|SHORT TERM STORAGE(8,2)|ADAPTIVE TECHNICAL TRANSFORMATION(8,1)|AFOLU DEPARTMENT(8,1)|ANNUAL TRAPPING(8,1)|ATMOSPHERE2NEGATIVE DISCHARGE(8,1)|ATMOSPHERE2REDUCED TOTAL CO2NEGATIVE DISCHARGE(8,1)|ATMOSPHERIC CO2INCREASED(8,1)|AUSTRALIA WEST(8,1)|BALO ISLAND SALINE LAYER(8,1)|BIOMASS CARBON POND(8,1)|BIOMASS ENERGYCO PRODUCTION(8,1)|BIOMASS GASIFICATION FURNACE(8,1)|BIOMASS LIMESTONE(8,1)|BIOMASS PLANT CARBON LIBRARY(8,1)|BIOMASS2CO COMBUSTION(8,1)|CALCIUM CARBONATE COOKED PULP2WITH(8,1)|CALCIUM CARBONATE2THE(8,1)|CAPTURE CO2ANY(8,1)|CARBONIZATION REACTION IMPURITY(8,1)|CEMENT PRODUCTION PROCESS2THE(8,1)|CO2SUBSEQUENT EMISSION(8,1)|EUROPEAN BIOCCS(8,1)|FINE PULP THICKENING TANK(8,1)|FUNDAMENTAL COUNTERMEASURE(8,1)|GACO COMBUSTION(8,1)|HUGE INVESTMENT(8,1)|HYPERGRAVITY REACTION CRYSTALIZATION(8,1)|IMPROVED2THE COLLECTION(8,1)|INVENTORY MAKER(8,1)|IPCC GUIDELINE SOURCE CATEGORY(8,1)|IPPU CATEGORY(8,1)|LIMESTONE BURNING(8,1)|LIVING ORGANISMSCO(8,1)|MASS ENERGY2NEGATIVE EMISSION(8,1)|NONGREENHOUSE GAS ADJUNCT(8,1)|OILFIELD EXHAUSTION(8,1)|OILFIELD EXTRACTION(8,1)|PROCESS2EMISSION DEFAULT EMISSION FACTOR(8,1)|SLAKED LIME FINE MILK(8,1)|SPRAY CARBONATION(8,1)|TECHNOLOGY2CARBON FIBER(8,1)|TON CO2CARBONATE(8,1)|UTILIZATION2AFTER PURIFICATION TREATMENT(8,1)|ZHONGPETROCHEMICAL CENTRAL OILFIELD(8,1)|WASTEWATER(7,4)|CALCIUM CARBONATE FINAL PRODUCT(7,2)|POST COMBUSTION TRAPPING(7,2)|AMMONIUM COMPOUND FERTILIZER(7,1)|ASH EMULSION INLET(7,1)|ASH FINE EMULSION INLET(7,1)|AUTHORITATIVE SCIENTIFIC RESEARCH INSTITUTION(7,1)|BIOMASS CARBON RESERVOIR(7,1)|BIOMASS COMBUSTION2THE TOTAL(7,1)|BIOMASS IPPU SOURCE EMISSION(7,1)|BIOMASSGA COMBUSTION(7,1)|BOILED SLURRY OUTLET(7,1)|CALCINING FN(7,1)|CALCIUM CARBONATE RAW MATERIAL2AND(7,1)|CARBOHYDRATE POLYMER CELLULOSE(7,1)|CARBONATE COMBUSTION INDUSTRY(7,1)|CATALYTIC PYROLYSIS(7,1)|CCUS MONITORING TERM(7,1)|CENTRAL OILFIELD REFINERY(7,1)|CHINESE CCUS TERM(7,1)|CO2A COLLECTION(7,1)|CO2CO EMISSION(7,1)|CO2RELEASING CO2AND RELEASE HEAT(7,1)|CO2THE CLEANING(7,1)|CO2THE MAIN CANDIDATE(7,1)|CO2THE NEGATIVE EMISSION(7,1)|DAILY PRODUCTIVITY(7,1)|DEFAULT ASSUMPTION(7,1)|DISSIPATION TAIL GAS EMISSION(7,1)|DRYING PROCESS2THE(7,1)|EMISSION INVENTORY GUIDELINE(7,1)|ENERGY2THE EMISSION(7,1)|ENTERPRISE PERSONNEL CARBON EMISSION(7,1)|ESTABLISHED NEGATIVE EMISSION ESTIMATION(7,1)|FIELD2THE COLLECTION(7,1)|FIELDOIL DISPLACEMENT(7,1)|FUEL FORMATION(7,1)|FUNDAMENTAL PAIN(7,1)|GORGON PROJECT(7,1)|GROUND BIOMASS(7,1)|INTERNATIONAL ENTERPRISE(7,1)|IPCC CAPTURE(7,1)|IPCC REPORT(7,1)|MAJOR TECHNICAL BREAKTHROUGH(7,1)|MICROALGAE CARBON SEQUESTRATION(7,1)|MNCO3AND HYDROCARBON(7,1)|MNCO3RHODOCHROSITE DISCHARGE(7,1)|NA2CO3SODIUM CARBONATE(7,1)|NATURAL GAS2THE INJECTION(7,1)|NEGATIVE EMISSION FRAMEWORK(7,1)|NONCALCINED CARBONATE(7,1)|NONPOWER PLANT BIOMASS ENERGY(7,1)|OPERATING COST(7,1)|PLANT SYNFUEL(7,1)|QUICKLIME DISCHARGE(7,1)|RAW MEATCO(7,1)|RAW SUGARCANE JUICE(7,1)|REFINED LIME MILK INLET(7,1)|RESOURCE RECYCLING(7,1)|SALINE AQUIFER(7,1)|SEA SNAIL CEMENT(7,1)|SIGMA CO2AT(7,1)|SPECIALIZED SYSTEM(7,1)|SUBTERRANEAN PROJECT(7,1)|TECHNICAL ROUTE2CONVERSION(7,1)|TECHNOLOGY UTILIZATION SCENARIO(7,1)|TERRELL PROJECT(7,1)|TRANSPORTATION SECTOR(7,1)|TREATED CO2CALCIUM CARBONATE(7,1)|UNCALCINED CARBONATE EMISSION FACTOR(7,1)|WOOD BIOFUEL(7,1)|LIME KILN DUST(6,17)|COMPOUND CARBONATE(6,3)|INERT INORGANIC CARBONATE SOLID(6,3)|PROCESS DIAGRAM(6,3)|WOOD VINEGAR(6,3)|ANODE CHAMBER(6,2)|BIOMASS ENERGY UTILIZATION GENERATION(6,2)|CARBON DIOXIDE DESORPTION(6,2)|CARBON DIOXIDE ENTRAPMENT(6,2)|CARBON POOL(6,2)|CARBON UTILIZATION(6,2)|CATHODE CHAMBER(6,2)|CO2HYDROGENATION(6,2)|CONSTANT SUBSTANCE LAW(6,2)|ECONOMIC BENEFIT(6,2)|EXHAUST CAP(6,2)|KILN GAS INLET(6,2)|MAIN PRODUCT(6,2)|OVERFLOW PORT(6,2)|PRODUCTION RAW MATERIAL(6,2)|RAW MATERIAL SOURCE(6,2)|BLAST PIPE(5,5)|PRODUCING LIGHT CALCIUM CARBONATE(5,5)|BIOMASS GAS HOT BLAST(5,4)|ANNUAL NEGATIVE CARBON EMISSION(5,2)|BIOCCU(5,2)|BIOMASS FUEL GAS(5,2)|CARBONATOR STRUCTURE(5,2)|CATALYTIC REACTION TOWER(5,2)|CO2COLLECTING(5,2)|CO2EMISSIONS(5,2)|HYDRATED LIME(5,2)|KILOCALORIE(5,2)|ABANDONED OILFIELD(5,1)|ATMOSPHERIC CO2THE TOTAL EMISSION(5,1)|BIOMASS ENERGY SOURCES2COLLECTING(5,1)|BIOMASS FUEL CONSUMPTION(5,1)|BIOMASS GROWTH(5,1)|BIOMASS PYROLYSIS GASIFICATION(5,1)|BOUNDARY PROJECT(5,1)|CALCINING ATMOSPHERE(5,1)|CALCIUM CARBONATE ORE ACCOUNT(5,1)|CALCIUM CARBONATE PRODUCTION2WITH(5,1)|CAPTURE UTILIZATION TERM(5,1)|CAPTURED CO2THE TOTAL(5,1)|CAPTURING BENEFIT(5,1)|CARBONATION PRODUCTION(5,1)|CARBONATION REACTION EQUATION(5,1)|CCUS TECHNICAL TEST(5,1)|CCUS TEST(5,1)|CEMENT MANUFACTURE ENVIRONMENT(5,1)|CHEMICAL FERTILIZER PLANT2PERFORMING(5,1)|CHINESE ENERGY SAVING SOCIETY(5,1)|CLEAN UTILIZATION(5,1)|CO2 EMISSION(5,1)|CO2CO REMOVAL SEPARATION(5,1)|CO2THE KEY CORE EQUIPMENT(5,1)|CO2THE MEASUREMENT(5,1)|CO2TRAPPING(5,1)|COAL METHANOL(5,1)|COUNTRY TOTAL EMISSION(5,1)|DECARBONIZATION REACTION(5,1)|DEMONSTRATION PROJECT PHASE(5,1)|DIVIDING HOOD(5,1)|EFN CARBONATE EMISSION FACTOR(5,1)|EMISSION CALCULATION BASIS(5,1)|EMISSION INDUSTRY(5,1)|EMISSION PROPORTION(5,1)|ENERGY MINISTRY(5,1)|ENID PROJECT(5,1)|EXTRACTION NOTCH(5,1)|GEOLOGICAL SEALING(5,1)|GREEN TRANSFORMATION(5,1)|INDUSTRY2THE CRUDE OIL(5,1)|IPCC DEVELOPMENT(5,1)|LIMESTONE3THE CONTENT(5,1)|LOW TEMPERATURE SEPARATION(5,1)|METHANOL ABSORPTION(5,1)|MGCO3MAGNESITE EMISSION FACTOR(5,1)|PHOTON WAVELENGTH(5,1)|PROJECT TRAP(5,1)|PROLONGED PETROLEUM(5,1)|QUICKLIME YIELD(5,1)|RECOVERY ANNUAL TREATMENT CAPACITY(5,1)|SEQUESTRATION DEMONSTRATION AREA(5,1)|SLAKED LIME CA(5,1)|SLAKED LIME YIELD(5,1)|SYNTHETIC CRUDE OIL2SUCCESSFULLY(5,1)|TIMELY MASTER(5,1)|TON LIME(5,1)|UNCALCINED CALCIUM CARBONATE(5,1)|UTILIZATION2THE CARBON(5,1)|WITHDRAWAL NOTCH(5,1)|WOOD CHIP BIOMASS BRIQUETTE(5,1)|SRCCS(4,4)|TOTAL CONTENT(4,4)|LITHIUM CARBONATE(4,3)|POWER GENERATION(4,3)|SATURATED STEAM(4,3)|THERMAL DECOMPOSITION GAS(4,3)|TON DAY(4,3)|COAL SEAM(4,2)|DECADE(4,2)|NIGHT(4,2)|ACCOUNTING CARBON FOOTPRINT(4,1)|ACCUMULATIVELY2UP(4,1)|AIR LOW TEMPERATURE SEPARATION(4,1)|AMOUNT2THE(4,1)|ANNUAL PRODUCTION(4,1)|ARTIFICIALLY INCREASING CARBON SEQUESTRATION(4,1)|ASH RESIDUE(4,1)|ATMOSPHERE2REMOVED(4,1)|BIOASS ENERGY(4,1)|BIOMASS2QUANTITY(4,1)|BOILED SLURRY TANK(4,1)|CALCINATION PROCESS BIOMASS CONSUMPTION(4,1)|CAPTURE SCALE(4,1)|CARBON CAPTURE INDUSTRIALIZATION(4,1)|CARBON EMISSION STRATEGY UTILIZATION(4,1)|CARBON PEAK CARBON NEUTRALIZATION(4,1)|CARBON SINK EFFECT2AND(4,1)|CARBONIZATION TOWER STRUCTURE(4,1)|CATALYST RESEARCH(4,1)|CEMENT MANUFACTURING FACILITY(4,1)|CHINA ELECTRIC(4,1)|CO2THE NOVEL RECYCLING TECHNOLOGY(4,1)|CONDENSATE WATER RECOVERY(4,1)|CONDITIONS2IS(4,1)|CORRECTION FACTOR(4,1)|COUNTRYTHE TOTAL(4,1)|CROSSCHECK(4,1)|DIRECTLY ELIMINATED2THE EMISSION(4,1)|DISPLACING OIL(4,1)|DOLOMITE EMISSION FACTOR(4,1)|DUST EMISSION(4,1)|EMISSION BASIS(4,1)|EMITTING NEGATIVE(4,1)|EQUIPMENT2THE DIFFERENCE(4,1)|EXCESS LIME(4,1)|EXPELLING COALBED GAS(4,1)|FECO3SIDERITE EMISSION FACTOR(4,1)|FIELD2ACCUMULATING(4,1)|FIELD2COLLECTING(4,1)|FILTER PASTE(4,1)|FULL FLOW INDUSTRIAL PRODUCTION(4,1)|GAS DISSIPATION(4,1)|GENERATION BIOMASS ENERGY UTILIZATION(4,1)|GEOLOGICAL STORAGE(4,1)|GUIDE IPCC(4,1)|IMPURITY CONTENT(4,1)|INCREMENTAL PRODUCTION(4,1)|INDUSTRIAL PRODUCTION PROCESS2REMOVED(4,1)|INDUSTRIALIZED COMMERCIAL LIGHT CALCIUM(4,1)|INEVITABLE CARBON EMISSION(4,1)|INTEGRATED CREATION(4,1)|JINGDU(4,1)|KILN GAS CARBON FOOTPRINT(4,1)|LIGNIN SULFATE COMBUSTION HEAT(4,1)|LIME KILN FEED(4,1)|MATURE BIOMASS ENERGY(4,1)|MEETING INTERNATIONAL STANDARD PACE(4,1)|MIXED WOOD BIOMASS BRIQUETTE(4,1)|NATIONAL GREENHOUSE GAS LIST(4,1)|PEAK REACHING CARBON NEUTRALIZATION(4,1)|POLLUTION REDUCTION(4,1)|POSITIVE CARBON REJECTION(4,1)|POSITIVE SIGNIFICANCE(4,1)|POWER PLANT2CAPTURE PROJECT(4,1)|PROCESS2EMISSIONS(4,1)|PRODUCED CO2INPUTTING(4,1)|PRODUCTION PROCESS2EQUAL GREENHOUSE GAS(4,1)|QUICKLIME PRODUCTION(4,1)|QUICKLIME SLAKING(4,1)|RAW CALCIUM CARBONATE MASS(4,1)|REACTION TANK DEPTH(4,1)|REMAINING IMPURITY(4,1)|SALINE WATER LAYER2THE PROJECT(4,1)|SANITARY TREATMENT(4,1)|SCIENTIFICITY(4,1)|SMOKE CHAMBER(4,1)|SODA ASH DISCHARGE(4,1)|STORAGE2MARINE STORAGE(4,1)|TON HOUR LIMESTONE(4,1)|UTILIZATION ITEM(4,1)|WHITE CEMENT(4,1)|WORLD BIOMASS ENERGY(4,1)|WORLD2INJECTION(4,1)|RAW MATERIAL(3,12)|NEGATIVE CARBON EMISSION(3,9)|ABSORB CARBON DIOXIDE(3,1)|ABSORBENT(3,1)|ABSORPTION REACTION(3,1)|ACCESSORY PRODUCT(3,1)|AGRICULTURE(3,1)|AGROFORESTRY(3,1)|ANTHRACITE(3,1)|ARAGONITE(3,1)|AVERAGE PERSON(3,1)|AVERAGE SHAFT KILN(3,1)|BIODIESEL(3,1)|BIOGAS(3,1)|BIOMASS ENERGY UTILIZATION MODE(3,1)|BIOMASS POWER PLANT BECCS(3,1)|BIOMASS TOTAL CARBON CONTENT(3,1)|BIOMASS2AND(3,1)|BRINE LAYER(3,1)|BURNED PRODUCT COOLING(3,1)|CACO3BOTH(3,1)|CALCINATION RATIO(3,1)|CALCITE(3,1)|CALCIUM CARBONATE DRYING PROCESSING(3,1)|CALCIUM OXIDE CAO(3,1)|CARBOHYDRATE LIQUID(3,1)|CARBON DIOXIDE COLLECTION(3,1)|CARBON DIOXIDE EMISSION(3,1)|CARBON EMISSION ESTIMATION(3,1)|CARBONATE CALCINING(3,1)|CARBONATE WEIGHT PROPORTION(3,1)|CARBONATE2CO(3,1)|CARBONIZER(3,1)|CEMENT KILN WASTE HEAT(3,1)| | (CN114229879)|1. A process for utilizing industrial negative-carbon-emission biomass energy by BECCU technique features that the biomass energy is used to replace fossil energy such as coal, fuel oil, gas and their derivatives to produce light calcium carbonate (precipitated calcium carbonate).|2. A technical BECCU method for utilizing industrial negative Carbon emission biomass energy is technically characterized in that biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide in light calcium carbonate production is collected and utilized by the prior art to Capture biomass energy Carbon, and negative Carbon emission of zero-Carbon biomass energy Utilization is realized by utilizing BECCU or BioCCU Bioass-energy With Carbon Capture and Utilization.|3. A technical BECCU method for utilizing industrial negative Carbon emission biomass energy is technically characterized in that the biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide generated in the light calcium carbonate industrial production is collected and utilized by utilizing the prior art, Carbon Capture and Utilization are carried out, Carbon dioxide generated in the light calcium carbonate industrial production is sealed in precipitated calcium carbonate industrial products and byproducts thereof, the Carbon Capture and the long-term or permanent industrial product sealing of the Carbon dioxide sealed in the CCUS Carbon Capture Utilization and Storage are realized, namely, the Carbon dioxide is sealed by the industrial products and the byproducts permanently or the long-term Carbon, and the negative Carbon emission of zero-Carbon biomass energy Utilization is realized.|4. The industrial negative carbon emission biomass energy utilization technology BECCU method as claimed in claim 1, wherein the calcium carbonate calcination process replaces fossil energy coal, fuel oil, fuel gas and derived energy with internationally recognized zero-carbon biomass energy and formed fuel to realize zero-carbon emission of the energy source category of the calcination process.|5. The BECCU method for the industrialized negative carbon emission biomass energy utilization technology according to claim 1, wherein the precipitated calcium carbonate drying and heating technology replaces fossil energy coal, fuel oil, fuel gas and derived energy to supply heat by internationally recognized zero-carbon biomass energy secondary energy biomass pyrolysis gas, or replaces fossil energy to supply heat by direct combustion of biomass briquette fuel, so as to realize zero-carbon emission of the energy source type of the drying and heating technology.|6. The method for utilizing the industrial negative carbon emission biomass energy source BECCU according to claim 2, is characterized in that the existing technology and device are fully utilized for collecting and utilizing the carbon dioxide in the production of the light calcium carbonate, the existing technology and device are adaptively modified, and the carbon dioxide generated by the two production processes, namely the limestone calcining process and the precipitated calcium carbonate drying process, is collected and utilized together for recycling.|7. The BECCU method as claimed in claim 6, wherein the collected carbon dioxide used in the production of precipitated calcium carbonate includes not only carbon dioxide generated by the calcination and drying of biomass energy source type, but also carbon dioxide generated by the calcination and decomposition of limestone in the raw material source type of the calcination process, and carbon dioxide generated by the energy source type and the raw material source type in the industrial production process are recycled.|8. The BECCU method as claimed in claim 3, wherein the industrial products and by-products produced by precipitated calcium carbonate industry are used for long-term and permanent sequestration of carbon dioxide, and the by-products include all the by-product process wastes produced by the precipitated calcium carbonate industry from limestone ore to the full-flow industrial production of the final product, including inert carbonates such as calcium carbonate, magnesium carbonate and tar, pyroligneous liquor, solid, liquid and gaseous non-greenhouse gas precursor stable substances which will not naturally form greenhouse gas emissions in a long term, but not CO unstable gases and methane greenhouse gases emitted by the light calcium carbonate industry, and which are likely to form subsequent greenhouse gas emissions or greenhouse gases emitted in a short and immediate period, must be deducted from the carbon dioxide inventory.|9. The industrial negative carbon emission biomass energy utilization technology BECCU method as claimed in claim 2 and claim 3, wherein the negative carbon emission of zero carbon biomass energy utilization is realized by the carbon dioxide capture and utilization of industrial processes and industrial product and byproduct carbon dioxide sequestration process, and the estimation model of the negative carbon emission is BECCU CO2DischargingSourceProduction ofSource-capturingSource。|10. The method for the industrial negative carbon emission biomass energy utilization technique BECCU according to claim 9, wherein the method for developing the industrial negative carbon emission biomass energy utilization technique BECCU and the related technical standards according to the zero carbon biomass energy utilization negative carbon emission technique BECCU and the model for estimating the amount of negative carbon emission thereof is developed, and any person other than the applicant must be informed by the applicant or developed together with the applicant based on or using the method for developing the industrial negative carbon emission biomass energy utilization technique BECCU and the related technical standards of the present invention. | (CN114229879)|TECHNICAL FIELD|[0001] The invention relates to the technical field of biomass energy source replacement of fossil energy and carbon dioxide capture and utilization of negative carbon emission.|BACKGROUND ART|[0002] Artificially created atmospheric CO2The concentration is increased, and the greenhouse effect threatens the survival and development of human beings. Reduction of anthropogenic CO2The technical route of (1) has two routes: the first is to develop renewable energy sources such as solar energy, wind energy and biomass energy to replace fossil energy sources vigorously or reduce CO from the source by improving the utilization efficiency of the fossil energy sources2Discharging; second, to the CO produced2Atmospheric CO increased by human activity is removed by artificially increasing carbon sequestration and carbon Capture using sequestration techniques CCUS (carbon Capture Utilization and storage)2。|[0003] United nations inter-government climate Change organization (IPCC) on CO in 20052Special reports on capture and storage and 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC guide) indicate that fossil fuels are kept in use throughout the 21 st century, avoiding large amounts of CO, according to the third assessment report on IPCC2Discharge, realize the concentration stability of greenhouse gas in the atmosphere and CO2Capture and Storage (CCS) should be one of the combination options for greenhouse gas concentration stabilization, in particular CO captured from biofuel combustion, injected underground and stored2The amounts are included as negative emissions in the list of greenhouse gases, chapter 5, the CCS System and CO, Chapter 5, volume II (energy source)2Capture, transport, inject into the underground storage and discharge and clear up the estimation method; united nations climate change congress, published 2050 via the coordinated Organisation (OCED) environmental agency in 2011, with the expectation of achieving lower concentration targets (450ppm), largely dependent on carbon capture and sequestration using biomass energy (BECCS or BioCCS); in 2015, climate change of Paris United nations will set a positive target, and the global temperature rise is limited to be below 1.5 ℃ to be restored to the level before industrialization. However, positive carbon rejection (positive carbon emissions) of clean power generation technologies and energy conservation measures are not sufficient to solve the problem by themselves, even if CO2The amount is reduced and discharged at a slower rate,CO2the net concentration is still rising; the 20 th group of countries (G20) in 2019, the Ministry of energy and environment, incorporated the CCUS technology for carbon capture, utilization and sequestration. IPCC reports suggest that the CCUS technology is significant for realizing zero carbon emission in 2050 years, and large-scale negative carbon emission application technologies need to be deployed in 2040 years.|[0004] CCUS is essentially an artificial, industrial carbon sequestration approach. Wherein, CO2The trapping method comprises 3 trapping methods including pre-combustion trapping, oxygen-enriched or pure oxygen combustion and post-combustion trapping. Pre-combustion capture is the gasification of fossil fuels to synthesis gas (with H as the major component)2And CO) and then converting the CO to CO by a shift reaction2And then H is absorbed by a solvent or the like2And CO2Separation and collection of CO2The technology is limited to a coal gasification combined power generation device for capturing CO before combustion2The cost is about $ 20/t CO2(ii) a The oxygen-enriched combustion technology adopts pure oxygen or oxygen enrichment to combust fossil fuel, and the main product after combustion is CO2Water and some inert components, because pure oxygen is obtained by air low-temperature separation or membrane separation, the energy consumption is large, and the cost of oxygen-enriched combustion is high; common methods for post-combustion capture technology such as chemical absorption, membrane separation, physical adsorption, etc., and post-combustion capture of CO2The cost of (A) is about $ 40/t CO2。|[0005] The CCUS technical test is carried out firstly, the petrochemical industry enhanced oil recovery is carried out, and CO is passed2Connecting carbon source produced by coal chemical industry or natural gas chemical industry with oil field to obtain CCUS-EOR (enhanced oil recovery), and collecting CO2Injecting into oil field to recover oil from exhausted oil field and CO2Permanently stored underground; thereafter, attempts were made to use CO2Fertilizer and food grade CO2Utilization, etc., and also industrially produced CO2Inputting the green as greenhouse gas to strengthen plant growth, etc.|[0006] The earliest large CCUS project in humans was the Terrell project, CO, built in the United states in 19722The trapping capacity reaches 40 ten thousand t/a; enid project, Okla, USA, was built in 1982 by CO produced by chemical fertilizer plant2Performing oil fieldOil displacement, CO2The trapping capacity reaches 70 ten thousand t/a; the Norwegian Sleipner project in 1996 was the first CO to be established in the world2Injection into underground (saline aquifer) projects, annual sequestration of CO2The quantity is close to million tons; in the United states, in 2000, in cooperation with Canada, the CO of Great Plant Synfuels plants and Sask Power plants was injected at the Weyburn oil field2Accumulating and storing CO while improving the oil extraction rate of the oil field near exhaustion2Up to 2600 or more tens of thousands t; the project of Boundary Dam Power of Sask Power company of Canada in 2014 is the first successful application of the project to CO Power plant2Capture project, CO generated by 150MW coal-fired generator2After capture, a portion was sequestered underground and a portion was used for U.S. Weyburn oil field flooding, CO2The trapping capacity reaches 100 million t/a, and the project traps CO in 20192Up to 61.6 ten thousand t; 2015 Canadian Quest project CO produced in hydrogen production process of synthetic crude oil2Successfully injected into a saline water layer for sealing and storing, and CO is injected every year2The trapping capacity reaches 100 million/a, the project is the first CCS project in the oil sand industry, the carbon emission can be reduced by 100 million every year, and by 2019, the Quest project can trap CO accumulatively2Up to 400 million t, is the maximum CO capture in the world2And successfully injected into a subterranean project; the Gorgon project in the west of australia in 2016 is a complement to the Gorgon natural gas project, the largest global unit LNG project, which projects CO by liquefaction technology2Separating CO from natural gas2The injection amount can reach 350 ten thousand t/a when the injection is injected into a saline layer of the Balo island.|[0007] China starts to research CCUS technology later, and the government continues to come out of the CCUS technical policy in 2006, and the CCUS technology is one of the key points in China national plan for climate change handling (national scheme for climate change handling science and technology action handling in China), Chinese policy and action for climate change handling in China, and the like. In 2007, the China Petroleum Jilin oil field and the China petrochemical east China division company grass House oil field opened domestic CO2The trapping project firstly realizes the industrialization of the CCUS-EOR technology and establishes five types of CO2Oil displacement and sequestration demonstration area, annual sequestration of CO2The capacity can reach 35 ten thousand t; in the same year, China petrochemical east China division builds CO in the oil field of the grass house2Annual injection amount4 ten thousand t of pilot test items, and CO is built in the later period2The annual treatment capacity of the recovery device can reach 2 ten thousand t. Subsequently, the Zhongpetrochemical Shengli oil field, China Shenhua, prolonged Petroleum and the Zhongpetrochemical Central oil field accelerate the propulsion of CO2Industrialization of the collection item. In 2010, the China petrochemical industry victory oil field is built into the first domestic CCUS demonstration project of a coal-fired power plant, and the flue gas CO of the coal-fired power plant is used2Adopting combustion-trapping technology to trap CO as source2Injecting into oil field for displacing oil and CO2The trapping capacity reaches 3-4 million t/a; in 2011, a CCS demonstration project of Shenhua Ordos 10 ten thousand t/a is completed, and a methanol absorption method is adopted to capture CO in tail gas of a coal gasification hydrogen production project2Injecting CO into saline water layer2The project is the first domestic saline water layer geological sequestration experiment project; in 2012, the oil is prolonged to build 5 ten thousand t/a of CO2A collection and utilization item for utilizing CO generated in coal chemical industry2The crude oil is purified, pressurized and liquefied by a low-temperature methanol washing technology and then injected into an oil field, so that the viscosity of the crude oil is reduced, the recovery ratio of the crude oil is improved, and CO is realized2Permanently sealing and storing; in 2015, CCUS project for tail gas of central oil field refinery in medium petrochemical industry was built, and the project approaches to abandoned oil field through CO2Oil displacement improves the oil field extraction rate by 15 percent, and million tons of CO exist at present2Is injected into the ground.|[0008] In addition to the conventional CO2Trapping technology, China also developed CO2The novel recycling technology is applied to the industries of food, fine chemicals and the like, in 2009, a second power plant carbon capture project at the Shanghai stone cave entrance is built, the capture scale is 10 ten thousand t/a, and the captured CO is2The method is mainly used in the food industry; 2011 CO produced by IGCC in research institute of clean coal energy and power system in Hongyun harbor2Trapping the latter part for urea and sodium carbonate industry, injecting the other part into brine layer for sealing; china electric group CO of Tianjin north pond in 20122The trapping demonstration project adopts a post-combustion trapping technology, the annual trapping amount is 2 ten thousand t, and CO is trapped2Used in the food industry; in 2010, the Xinao group in inner Mongolian Dallas absorbed tail gas of a coal-based methanol/dimethyl ether device by using a microalgae carbon sequestration technology, and a part of the tail gas is used as biodiesel,one part is used for producing feed, and the treatment capacity reaches 2 ten thousand t/a; the sea snail cement establishes an industrial CCUS test project of 5 ten thousand tons; qilu petrochemical under construction CCUS-EOR project (2020) CO2The trapping capacity was 4 ten thousand t/a. The utilization direction of the emerging carbon in China is mainly CO2Hydrogenation for preparing methanol and CO2Hydrogenation for preparing isoparaffin and CO2Hydrogenation for preparing aromatic hydrocarbon and CO2Although methanation reforming and the like, such as Shanxi coal chemical institute, Dalian union institute, Shanghai research institute of Chinese academy, university of Dalian union, and the like, have studied these technologies, they are mostly in the theoretical research stage or pilot plant stage of catalyst research, and there is no CCUS practical technology for industrial application.|[0009] The Chinese environmental science society, release the Chinese head CCUS group standard 'carbon dioxide capture utilization and sealing term' T/CSES 41-2021 at 22.12.1.2021, comprises related terms of CCUS, related terms of carbon dioxide, capture and transportation terms of carbon dioxide, related terms of CCUS monitoring and measuring performance, related terms of risk and the like, and regulates related terms of the capture utilization and sealing field of carbon dioxide, and is mainly suitable for scientific research, management, teaching and production activities in related fields of carbon dioxide capture, chemical utilization, geological sealing and the like in high emission industries such as chemical industry, thermal power, steel, cement and the like. The T/CSES 41-2021 has positive significance for scientific research and production activities in the CCUS field, promotes the scientificity and normalization of the use of Chinese CCUS terms, and accelerates the pace of meeting international standards. The community standard does not relate to the related patent technology in the CCUS field. The prior patent technology in the CCUS field is few in China, and the real practical technology is almost none.|[0010] CN201711383170.2 discloses a negative carbon emission system and method thereof, which utilizes photosynthesis of growing plants to absorb carbon dioxide molecules, and properly designs photon wavelength for inducing photosynthesis of plants to increase efficiency of photosynthesis of plants, and selects LED light source with carbon footprint lower than threshold and conversion efficiency higher than threshold, and combines low carbon power source with carbon footprint lower than threshold, such as solar cell panel. The system can be applied to the capture of carbon dioxide.|[0011] CN201810173639.8 discloses carbon dioxide entrapment device in cement manufacture, including gas collecting channel, first intake pipe, air pump, first blast pipe, filter, the gas collecting channel top is provided with first intake pipe, one side of first intake pipe is provided with the air pump, one side of air pump is provided with first blast pipe, one side of first blast pipe is provided with the filter, one side of filter is provided with the dust absorption jar, one side of dust absorption jar is provided with the second blast pipe, one side of second blast pipe is provided with gaseous drying tank, one side of gaseous drying tank is provided with the second intake pipe, one side of second intake pipe is provided with the gas holder. Has the advantages that: this carbon dioxide entrapment device has set up equipment such as filtration, purification, drying to the special environment of cement manufacture for the purity of final carbon dioxide product is higher, through the collection to carbon dioxide, has reduced its emission to in the air.|[0012] CN201820292229.0 discloses carbon dioxide collection device that tail gas was handled among cement manufacture, including cement rotary kiln, gas transmission pipeline, dust remover, absorption tower, cement rotary kiln one end is provided with the smoke chamber, smoke chamber one end is provided with gas transmission pipeline, gas transmission pipeline one end is provided with the dust remover, dust remover one end is provided with the scrubbing tower, scrubbing tower one end is provided with the desulfurizing tower, desulfurizing tower one end is provided with the absorption tower, absorption tower one end is provided with analytic tower, analytic tower one end is provided with the gas holder, gas holder one end is provided with the carbon dioxide and does not have the oil-pressure moulding machine, carbon dioxide does not have oil-pressure moulding machine one end and is provided with first absorption tower. Has the advantages that: the device recovers carbon dioxide gas generated in the cement kiln, does not contain impurities, does not discharge into the air, plays a role in protecting the environment, and improves economic benefits by recycling carbon dioxide in other industries.|[0013] CN201811533699.2 discloses a carbon dioxide desorption method for carbon capture, sequestration and utilization technology, which comprises the desorption steps of: starting and adjusting an electric adjusting valve, reducing the temperature and the pressure of saturated steam in the cement kiln tail waste heat boiler through a temperature and pressure reducer, and heating the saturated steam in an amine liquid reboiler in a desorption tower; heating and desorbing the carbon dioxide passing through the desorption tower; and the saturated steam after heating and desorbing the carbon dioxide in the desorption tower is subjected to liquid change to form saturated water, and the saturated water enters a condensate water recovery device through a water return pipe. The carbon dioxide desorption method for the carbon capture, sequestration and utilization technology does not influence the normal operation of the cement kiln waste heat power generation system, can meet the requirement of the desorption operation of the CCS system, and reduces the economic cost investment.|[0014] CN201010532911.0 discloses a waste treatment facility for introducing a thermal decomposition gas of waste into a cement decomposition furnace, which is provided adjacent to a cement manufacturing facility provided with a cement burning furnace, a clinker cooler for cooling a burned product thereof, and a decomposition furnace into which a high-temperature exhaust gas flows from either one of the burning furnace and the clinker cooler. Wherein, possess: the gasification furnace is provided with a gasification furnace for gasifying the waste to generate thermal decomposition gas, and a gas conveying channel for conveying the generated thermal decomposition gas to the decomposition furnace under the condition of keeping the carbon and the ash unchanged. The pyrolysis gas is introduced into the decomposing furnace in such a manner that the pyrolysis gas does not directly interfere with the main stream of the exhaust gas flow from the burning furnace or the clinker cooler, and is prevented from being scraped, thereby sufficiently burning the pyrolysis gas. Thus, the existing cement manufacturing equipment is effectively utilized, and the sanitary treatment of wastes is realized at low cost.|[0015] 201610704208.0 discloses a method for utilizing carbon dioxide in carbonate calcining flue gas and preparing methanol by collecting carbon dioxide generated in the carbonate calcining process; catalytic pyrolysis of biomass fuel to form H-containing2Introducing the fuel gas into a high-pressure catalytic reaction tower after dust fall treatment; the two are produced into products with methanol as the main component in a high-pressure catalytic reaction tower, and are purified and purified into industrial methanol in a distillation tower. The method for regenerating carbon dioxide generated in the carbonate calcination process disclosed by the invention can absorb and consume about 1.375 million tons of greenhouse gas carbon dioxide and absorb and consume biomass according to the annual production of ten thousand tons of methanolThe waste is approximately 10 ten thousand tons. The purposes of environmental protection and resource recycling are achieved while economic benefits are generated.|[0016] CN201010229727.9 discloses a production process for removing carbon dioxide from flue gas and preparing ammonium compound fertilizer and light calcium carbonate. The method comprises the steps of using dilute ammonia water as an absorbent, carrying out gas-liquid two-phase high-strength mass transfer absorption reaction on raw flue gas through a super-gravity field absorption tower for decarbonization, discharging the treated flue gas through a chimney, and further carrying out reaction treatment on byproducts of the decarbonization reaction to obtain the ammonium compound fertilizer and the light calcium carbonate with good economic value. The complete set of reaction separation device supporting the process comprises a high-gravity field absorption tower, a static mixer, a deep reaction tank, a cyclone, an ammonium compound fertilizer recovery system, a light calcium carbonate recovery system, various pumps and other equipment, wherein the high-gravity field absorption tower is a chemical reaction absorption section for removing carbon dioxide. The invention is a brand new process, and has the advantages of high efficiency, low investment and low operating cost.|[0017] CN201980083589.7 discloses hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation, to a process for hydromethanating the carbonaceous feedstock in a hydromethanation reactor to a methane-enriched raw product stream, and in particular to processing the solid coke by-product removed from the hydromethanation reactor to improve the carbon utilization and thermal efficiency and economics of the overall process by co-producing power and steam from the by-product coke in addition to the end product pipeline quality substitute natural gas.|[0018] CN202010455978.2 discloses a method and a system for utilizing carbon dioxide, wherein the method comprises the following steps: acquiring carbon dioxide meeting preset conditions; injecting the carbon dioxide into a coal seam and allowing the carbon dioxide to expand and release into the coal seam; and the carbon dioxide is used for expelling the coal bed gas in the coal bed to ensure that the coal bed gas is discharged from the coal bed. In the invention, the relatively single carbon dioxide is used as the displacement gas of the coal bed gas, and after the coal bed gas is displaced out of the coal bed, the carbon dioxide is remained and sealed in the coal bed, so that the carbon dioxide is utilized to obtain a clean gas source, the emission of the carbon dioxide is reduced, and the influence on the greenhouse effect is reduced.|[0019] CN201110176523.8 discloses a method and a device for preparing formic acid by recovering carbon dioxide from flue gas and utilizing electric power at night, a carbon dioxide recovery process for separating and recovering carbon dioxide from flue gas obtained by fuel combustion; sending the separated carbon dioxide into a membrane electrolysis device which is reduced by direct current to reduce the carbon dioxide to obtain formic acid; the formic acid refining process is that the dilute formic acid solution obtained by membrane electrolysis is refined to obtain formic acid product. The membrane electrolysis device is divided into a cathode chamber, a concentration chamber and an anode chamber; or divided into a cathode chamber and an anode chamber; the membrane electrolysis units are combined in any mode of series connection or parallel connection or combination of series connection and parallel connection. The technology adopts an efficient membrane electrolysis device and a gas-liquid mixed feeding mode and a carbon dioxide recovery formic acid refining process, has high electrochemical process efficiency, collects and recovers carbon dioxide and obtains high-concentration formic acid liquid through electrolytic reduction, effectively realizes the recovery and conversion of carbon dioxide, and can also effectively utilize the night power of a power plant.|[0020] The fundamental pain point of the above prior art CCUS is high cost, high energy consumption, low efficiency, low benefit, and is far from large-scale commercial application. World CO2The utilization of CO which is still in the theoretical research stage of the technology2Carbon fiber preparation, acetic acid preparation and the like; already in development stage, there is CO2Preparation of Polymer, CO2Methanation reforming, CO2Preparing methanol by hydrogenation, cultivating seaweed, circulating power and the like; already in the demonstration project phase there is a CO2Chemical fertilizer preparation, oil displacement in oil fields, food-grade application and the like. The negative carbon emission methods being discussed and developed are biomass energy power generation and carbon capture and sequestration (BECCS or BioCCS) technologies, such as BioCCS of the european carbon emission center (CCR), it is theoretically possible to remove CO from the atmosphere while producing fuel or electricity2。|[0021] China actively participates and becomes an important construction force for coping with climate change in the world, and in order to achieve the green transformation target of carbon peak carbon neutralization and high-quality development in China, the technical field of carbon emission strategy utilization by CCUS and biomass in China has to be changed thoroughly. Book (I)Creatively replaces fossil energy with biomass energy and CO in the current industrial field2The collection and the Utilization of the prior art are organically combined, and the integrated creation of a biomass energy of a non-power plant can utilize the industrialized commercial negative Carbon emission technologies (NETs) practical technology BECCU or BioCCU (Bioass-energy With Carbon Capture and Utilization).|DISCLOSURE|Disclosure of Invention|[0022] Aiming at the defect that Chinese CCUS and biomass energy use negative carbon emission technology is also and gradually following carbon capture and sequestration (BECCS or biocCS) of European and American biomass power plants, in particular to the industrial pain point that CCUS has high cost, high energy consumption, low efficiency and low benefit, the invention uses CO in the production of light calcium carbonate in the current industrial field2Collecting and utilizing the prior art and the production thereof to CO2The self-demand of raw materials organically integrates the biomass energy source instead of fossil energy with the CCUS technology, the light calcium carbonate production process and the like, creates a biomass energy utilization mode of industrial non-power plant biomass energy utilization negative carbon emission practical technology BECCU or BioCCU, and realizes the CO energy utilization mode through industrial production by using the pollution reduction and carbon reduction synergistic effect of high efficiency, high benefit, low cost and low energy consumption2The purpose of negative carbon emission removed from the atmosphere opens up a new field of carbon capture and utilization technology.|[0023] In order to realize the aim, the invention provides a non-power plant industrialized biomass energy utilization negative carbon emission technology, biomass energy is used for completely replacing fire coal to produce light calcium carbonate, and the biomass fuel is directly combusted in the calcium carbonate calcination process and CO produced by biomass gasification combustion in the drying of calcium carbonate cooked pulp2The CO absorbed by the biomass energy from the atmosphere is completely recycled and used as the calcium carbonate production raw material in the carbonation process2Permanently fixed and sealed in industrial products to realize industrialized removal of atmospheric CO2A fraction of the total amount.|[0024] In the invention, limestone and biomass fuel are added into a lime kiln together for calcination, the obtained quick lime is screened and then enters a digestion mechanism for digestion to obtain lime milk coarse pulp, the coarse pulp is separated and purified to obtain fine pulp, and the fine pulp is aged in an aging tankThe mixture enters a fine pulp thickening tank after being dissolved, and then enters a carbonization tower after being added with clear water to adjust the concentration, and the CO is mixed and collected with purified flue gas from a biomass calcining kiln gas and a biomass gas hot blast stove in a drying process2The generated calcium carbonate cooked slurry is subjected to carbonation reaction, is subjected to standing and aging and then is filtered in a filter, and the obtained filter paste is dehydrated, dried, crushed, separated and dedusted to obtain the light calcium carbonate final product, so that the CO absorbed by the biomass energy from the atmosphere is realized2Permanently fixed and sealed in light calcium carbonate industrial products for industrially removing atmospheric CO2The purpose of (1).|[0025] In the invention, the calcination process for producing the light calcium carbonate can be directly combusted in an industrial manner by using 3000 to 4000 kilocalories of wood chip biomass briquette fuel or high-quality biomass particle briquette fuel, and can also be calcined by using biomass fuel gas produced by pyrolyzing biomass by using a biomass gasifier. In fact, the production of the quicklime by directly calcining the limestone by using the wood biofuel firewood is a first generation traditional technology of biomass energy utilization existing before the industrial revolution, and the project adopts a second generation technology of biomass energy utilization and biomass briquette industrialized direct combustion technology to improve the energy utilization efficiency and CO2The recycling rate is improved, and the biomass pyrolysis gasification belongs to the third generation technology of biomass energy utilization, and is more advanced and efficient than the second generation technology. No matter the second generation or the third generation biomass energy utilization technology is adopted, the fuel requirement of limestone calcination can be completely met technically.|[0026] In the invention, the precipitated calcium carbonate cooked pulp drying process adopts a biomass pyrolysis gasification technology to supply heat, and CO in the flue gas of a biomass gas hot blast stove2With CO produced by the calcium carbonate calcination process2And are recycled together.|[0027] In the present invention, CO2The collection and the recycling of the light calcium carbonate can be fully utilized to produce the existing CO2The collection and recovery technology and the device greatly reduce the huge investment and cost of the carbon capture, utilization and sequestration of the CCUS technology at present. Wherein CO produced in the calcination stage2Not only can directly adopt the existing CO2Collecting and recycling technology and device for collecting and recyclingOr, if necessary, to the existing CO2Collecting CO from a utilization system2Collecting, gas-solid-liquid separating, impurity treating, cooling, recovering and CO2A small amount of adaptive technical transformation is carried out on devices such as compression conveying and the like, so that the CO is further improved2The collection and recycling efficiency of (1); CO produced in the drying process of the calcium carbonate cooked pulp2With CO produced during the calcination process2Can be recycled together to meet the requirement of CO production in industrialized commercial light calcium carbonate2The requirement of raw materials.|[0028] In the invention, the biomass fuel is industrially directly combusted or after gasification, the biomass gas is combusted to form C + O2→CO2Releasing CO2And releases heat; and the calcination of calcium carbonate releases CO2The two processes of producing the calcium oxide CaO and drying the calcium carbonate cooked slurry are heat absorption processes, CaCO3→CaO+CO2The enthalpy change of ↓ΔH is larger than zero when the biomass fuel is used for continuously supplementing and providing energy required by reaction and heating. On the one hand, CO is continuously generated by calcining and combustion heating2On the other hand, CO produced by decomposition of calcium carbonate raw material2And CO produced by the combustion of biomass2CO combined with two sources of feedstock and fuel2Must be removed quickly to reduce CO in the calcination process2Partial pressure increase of calcination released CO2Efficiency, and the normal operation of the biomass gas hot blast stove is maintained.|[0029] In the present invention, CaO + H is digested by quicklime2O→Ca(OH)2Delta H < 0 and calcium hydroxide Ca (OH) carboxylated2+CO2→CaCO3Both ↓ + H2O < delta H > are exothermic reactions. Because of the conservation of energy and conservation of material, those skilled in the art, even scientists, produce CaCO from light calcium carbonate3→CaO+CO2To CaO + H2O→Ca(OH)2To Ca (OH)2+CO2→CaCO3Chemical formula, only the light calcium carbonate raw material is seen to be the same as the chemical formula of the final product, CO2The material is equally fed in and out on the molecular formula in the production of the light calcium carbonate; especially the production of heavy calcium carbonate, has no CO at all2The material enters and exits the production process. Therefore, the temperature of the molten metal is controlled,those skilled in the art will recognize, even scientists, that inertial thinking only holds, CO2The material is carbon balanced before and after the production of the light calcium carbonate and can not generate CO to the atmosphere2What effect the total amount has. What the average person does not think of is CO2Carbon balance process of equal quantity and one inlet and one outlet in light calcium carbonate production of substances for atmospheric CO2The total emissions may lead to potential negative carbon emission technology utilization scenarios.|[0030] In the invention, if biomass energy is not used for completely replacing fossil energy, the production of light calcium carbonate can generate artificial activities to cause atmospheric CO2Increased total carbon emissions. CO released from fossil fuel in light calcium carbonate production2About 35% of the total carbon emission, which is part of the CO energy2The emission is regulated according to the source category of 'energy' in volume 2 of '2006 IPCC guideline', and the emission needs to be measured and accounted to enter a national greenhouse gas list; and the CO released by calcining the raw calcium carbonate ore accounts for about 44 percent of the mass of the raw calcium carbonate ore2Is recycled for the back end carbonation production process, CO2The material is equally discharged and fed in the industrial process of calcium carbonate production, and the total carbon amount in the industrial process is balanced. Thus, the carbon emissions from light calcium carbonate production are only CO metered and accounted for in fossil fuels2And (4) discharging the amount. This is completely different from the carbon emission mechanism of cement production, which does not have CO in the cement production process2The recycling process and mechanism, therefore, the carbon capture, utilization and sealing can be artificially carried out by human beings by adopting the cement CCUS technology. Volume 3 of the 2006 IPCC guideline "industrial process and product usage" regulations "in certain IPPU categories, especially large point emission sources, can capture emissions for recycling or removal. It is a good practice to consider emissions capture using detailed country-specific or more appropriate enterprise-level data. "," Add Capture to formula by adding other terms in formula representing observed quantity of Capture or efficiency of emission reduction System in conjunction with annual System usage "" "whether CO should be installed and deployed in Enterprise2Capture technique, preferably by deducting captured CO in high-level process emission calculations2"" other than on List consider CO2Emission of CO for later use2Amount and short term storage should not be from CO2Deducting the discharge. The default assumption is that carbon dioxide capture and storage (CCS) is not employed. Considering CO2Any method of capture should take into account the CO captured in the process2Emissions may be related to both combustion and process. If combustion and process emissions are reported separately, the inventory maker should ensure that the CO is present2The same number of (a) is not counted twice. In these cases, the captured CO2The total amount should best be reported in the respective fuel combustion and the CO generated in these source classes should be taken into account2The volume ratios are reported in the IPPU source category. "|[0031] In the invention, globally recognized zero-carbon biomass energy is used for completely replacing fossil energy, and the production of light calcium carbonate can generate CO influencing the atmosphere2Reduced total CO2Negative discharge effect. CO released by biomass fuel in light calcium carbonate production2With CO liberated from calcium carbonate ore raw material2Is recycled for the production of carbonation, is combined into a part of calcium carbonate final industrial product, and absorbs CO from the atmosphere in the process of biomass (plant) growth2The CO is permanently fixed and sealed in the final industrial product of the light calcium carbonate through an industrialized process to realize the separation of CO2CO removal from the atmosphere2Negative discharge effect.|[0032] In the invention, because the chemical change of the light calcium carbonate industrial production is only in the molecule and atom level, the nuclear polymerization change of the C atomic nucleus is not involved, and the total amount of the C elements of the light calcium carbonate raw material and the final industrial product is not changed, thus the light calcium carbonate is in material balance. The carbon material balance mechanism in the industrial production process of the light calcium carbonate is as follows: the carbon element added by the combustion of the biomass fuel is respectively distributed in accessory products produced by light calcium carbonate such as carbon-containing compounds, mixtures and the like in a gas-solid state and a liquid state at different stages of the industrial production process: such as CaCO3、MgCO3、CaMg(CO3)2、MnCO3And hydrocarbons such as tar, carbohydrates and CO gas (CO)2Reduction reaction of CO2+ C → 2CO product), calcium bicarbonate Ca (HCO) (hard water), H carbonate2CO3(CO2Dissolving in water to generate CO carbonate2+H2O==H2CO3) And other carbon compounds (such as greenhouse gas CO) that escape or are discharged to the atmosphere, surface, and water during production2Emissions and other carbon compounds and mixture emissions, etc.). The carbon balance process is essentially atmospheric CO2Carbon sink absorption due to biomass growth → CO release by biomass energy utilization2→ recovery and utilization of CO by carbon capture in industrial production process of calcium carbonate2→ C element with CO2Or other carbonate and carbon compound mixture forms, and is fixedly sealed in the light calcium carbonate product and other by-product products in the production process thereof in the carbonation process. Therefore, the production process of the biomass energy light calcium carbonate is essentially a negative carbon emission process for industrially fixing the carbon element of the biomass energy (wherein CO dissipated into the atmosphere in the production process2Equal greenhouse gases, carbon footprint must be metered and accounted, and part of the negative carbon emission reduction amount generated by the invention is offset and deducted), namely, part of CO in the atmosphere is removed through plant carbon sink and the industrial production process2Removed and permanently fixed in the precipitated calcium carbonate product and other non-greenhouse gas adjuncts.|[0033] In the invention, because other non-greenhouse gas by-product products must exist in the production process of the light calcium carbonate, the total amount of the by-product products is generally equivalent to 20-30% of the yield of the light calcium carbonate. Among them, some by-product products (such as CO, etc.) will form CO in future2Finally discharged into the atmosphere, according to the '2006 IPCC guideline', the CO in the industrial process returning to the atmosphere in the future must be measured and accounted2Carbon footprint emissions, and inclusion in the IPPU Source Category into the national greenhouse gas emissions List, which must be derived from the Biomass energy CO2Deducting the negative discharge amount; most of carbon element contained in by-product is permanently fixed and sealed in inert carbonate, and no CO is formed in future2Nor enter the atmosphere to increase the total greenhouse gas. CO in the industrial production of light calcium carbonate because of the inexhaustible substances2Negative emissions, can never be zero. Using living organismsCO for producing light calcium carbonate by using mass energy2Negative emission, effect and effect of eliminating greenhouse gases in the atmosphere are absolute, and CO can be generated by different biomass energy and light calcium carbonate production technologies and equipment2The difference between the negative carbon emission and the purge amount.|[0034] In the present invention, CO2The measurement and accounting of negative emissions are very similar to the basic emissions calculations of all carbonate combustion industries, based on molecular weight and CO, which are common, according to the "IPCC guideline 2006, volume 3" Industrial Process and product usage-Chapter 2 mining industry carbon emissions "regulations2Ratio of, wherein, CaCO3(Calcite or aragonite) emission factor (ton CO)2Carbonate per ton) 0.43971, MgCO3Magnesite emission factor 0.52197, CaMg (CO)3)2Dolomite emission factor 0.47732, FeCO3Siderite emission factor 0.37987, Ca (Fe, Mg, Mn) (CO)3)2Iron dolomite emission factor 0.40822-0.47572, MnCO3Rhodochrosite discharge factor 0.38286, Na2CO3Sodium carbonate or soda ash discharge factor 0.41492. "chapter 2 mining industry carbon emissions-2.3 lime production" stipulates that the production of lime involves a series of steps including raw material collection, crushing and sizing and calcining the raw material to produce quicklime and, if necessary, hydrating the lime to calcium hydroxide. Consumption of lime products does not result in CO under certain conditions2Is discharged to the atmosphere. For example, slaked lime used in water softening produces CO2React with lime to reform calcium carbonate without generating CO2Net venting to the atmosphere. Similarly, precipitated calcium carbonates for use in the paper industry and other industrial applications are hydrated high calcium quicklime with CO2Generated by the reaction; in the sugar manufacturing process, lime is used to remove impurities from the raw sugarcane juice, and any excess lime can be removed by carbonation. Only the validated and verified method was used to calculate the CO which reacts with lime to reform calcium carbonate2The amount, any recarbonization process in these particular industries can be calculated and reported. When these conditions are met, it can be reported under category 2H "other". Lime Kiln Dust (LKD) generation during lime production, methods of use 2 and methodsThe emissions estimate from method 3 should take into account the emissions associated with LKD. "|[0035] In the invention, the biomass energy is globally recognized zero-carbon energy, and CO generated by biomass energy utilization and not counted in the total amount of emission of greenhouse gases in the atmosphere2Removed from the atmosphere and permanently fixed in the final industrial product light calcium carbonate and its by-products, BECCU and biomass power plant BECCS or BioCCS on CO2The cleaning effect of (a) is the same. The measurement and accounting of greenhouse gas carbon emission in light calcium carbonate production follows the IPCC guideline of 2006 and related methodology, wherein, in addition to the first range of biomass energy utilization negative carbon emission measurement and accounting, carbon footprints such as outsourcing electric power and other energy sources (second range) and enterprise personnel activity carbon emission (third range) in light calcium carbonate industrial production are not included in the energy boundary range of the first range and the CCUS technical field involved in the invention, but belong to another technical field and the greenhouse gas emission measurement accounting subject matter.|[0036] In the present invention, CO2The negative emission is measured and calculated according to '2006 IPCC guideline': 1. volume 2 "energy" 2.3.4 carbon dioxide capture "since this is a new emerging technology, it requires plant specific method 3 reporting. The capture and storage plant will most likely meter the amount of gas removed by the gas stream and diverted to geological storage. "," if biofuel is supplied to the plant, the corresponding CO2Emissions will be zero and therefore, subtracting the amount of gas transferred to long term storage gives negative emissions. As a result, CO2Transport, CO2Subsequent emissions from the injection and storage itself should account for the total emissions of the country, whether the carbon originates from a fossil source or is produced by the recent biomass, and subsequent emissions (CO for later use and short-term storage2) Should not be from CO2Deduction in emissions unless CO2 emissions are counted elsewhere in the list [ e.g. CO in urea production (Vol. 3, section 3.2) and methanol production2Volume 3, section 3.9, in which the CO due to the final product should be taken into account2Emission later). 2. Volume 4 AFOLU "agroforestry and other land utilization" Chapter 4 "Biomass Combustion generated CO2Emissions are not included in the countryThe total amount of greenhouse gases, but is recorded as an item of information for cross-check purposes and to avoid recalculation. "|[0037] In the invention, the estimation of greenhouse gas emission in the production of light calcium carbonate by using biomass energy is carried out by adopting a method 3 of '2006 IPCC guideline' to carry out CO2It is estimated that the present invention utilizes biomass energy to produce light calcium carbonate first range (industrial process and energy use) CO2The negative carbon emission measurement and accounting model is as follows: BECCU CO2DischargingSourceProduction ofSource-capturingSourceNamely, the estimation formula:|[0038] |[0039] in the present invention, FIG. 1 is a schematic illustration of a process diagram of biomass energy utilization with negative carbon emission, which illustrates BECCU CO in detail2DischargingSourceWhy it must be negative (i.e. BECCU CO)2DischargingSourceMust be CO2Negative emissions). The inventor organizes strength development or jointly develops BECCU CO according to the invention and the cooperation of the Chinese environmental science society and the Chinese energy-saving society2The negative emission related methodology applies for the approval of the national climate change department and the approval of IPCC record, and develops or jointly develops the CCUS related group standard such as carbon dioxide capture utilization sealing-BECCU industrialized negative carbon emission standard with the Chinese environmental science society and the Chinese energy-saving society.|DRAWINGS DESCRIPTION|[0040] FIG. 1 is a process diagram of a biomass energy utilization negative carbon emission process;|[0041] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate;|[0042] FIG. 3 is a view showing the structure of a carbonator in a carbon dioxide utilizing process apparatus.|[0043] The reference numbers in the drawings of the specification are as follows:|[0044] 1. a support; 2. a kiln gas inlet; 3. a refined lime milk inlet; 4. an exhaust cap; 5. adding a phosphoric acid port; 6. an overflow port; 7. a gas distribution cover; 8. a withdrawal notch; 9. and (5) discharging the cooked pulp.|INVENTION MODE|Detailed Description|[0045] The concrete description is as follows:|[0046] FIG. 1 is a process diagram of negative carbon emission process for biomass energy utilization|[0047] Production of light calcium carbonate CO by using biomass energy2The negative emission process and principle are illustrated as follows according to the steps shown in FIG. 1:|[0048] 1. the biomass limestone calcining process is that biomass briquette fuel is used to replace anthracite and limestone in a layer combustion mixing mode for industrial direct combustion at about 1000 deg.c, and during calcining, partial biomass gas produced through pyrolysis and gasification may be supplemented as required to regulate and control the temperature, combustion condition and calcining atmosphere in the calcining kiln. The process product for producing quick lime by calcining limestone with biomass comprises the following steps:|[0049] (1)、CO2discharging: c + O2→2CO2、CaCO3→CaO+CO2Releasing CO2Wherein the emission of biomass IPPU source type (fuel) in 2006 IPCC guideline is zero, and the emission of the IPPU source type (raw material) CO in the limestone industrial process2Emission default emission factor (CO per ton lime)2Tonnage) high calcium lime 0.75, dolomitic lime 0.86 or 0.77, hydraulic lime 0.59;|[0050] (2) CaO, which accounts for about 56 percent of the mass of the limestone raw material;|[0051] (3) screening lime ash, wherein carbon-containing compound carbonate or carbon-containing mixture is removed from the lime ash, and a byproduct carbon element needs to be metered and calculated in a biomass energy utilization negative carbon emission process;|[0052] (4) lime kiln gas (CO)2Other impurities in the biomass energy utilization negative carbon emission process, which contain carbon compounds, carbonates or carbon-containing mixtures, and need to measure and account for the removal of the waste gas of the byproduct carbon element;|[0053] (5) the kiln gas dissipated CO accounts for about 1.69 percent (about 1.42 percent) of the total volume fraction of the kiln gas, and the carbon footprint of the kiln gas dissipated by-product is measured and calculated to calculate CO2Then discharging the amount;|[0054] (6) dust emission CO of lime kiln2Discharging: the amount of Lime Kiln Dust (LKD) generation from the 2006 IPCC guideline depends on the type of lime kiln used and the carbonate characteristics used, with an average shaft kiln producing 9% to 10% dust loss per 1 ton of lime and a raw material feed loss of 16% to 18%. The chemical composition of LKD varies from raw material feed to raw material feed, typically high calcium lime LKD may contain 75% combined calcium oxide and uncalcined calcium carbonate, the remaining impurities are silica, alumina and iron oxides and sulfur (depending on the fuel used), data is collected regarding the typical ratio of LKD to lime production and typical composition of LKD, and in the absence of data, 2% corrective additions can be assumed to account for LKD (i.e., 1.02 CO2Discharge); the vertical axis furnace produces a relatively small amount of LKD, and the LKD correction factor from the vertical axis furnace is determined to be negligible and not necessarily estimated. Method 3 advantageously collects specific data on the weight proportion of carbonate consumed by lime production and the proportion achieved by calcination in each plant, and also collects data on the amount (dry weight) and composition of LKD produced. Similar to method 3 for cement production, the emissions of LKD should be subtracted from the estimate of method 3.|[0055] 2. A biomass pyrolysis gasification process, wherein a biomass gasification furnace mainly supplies heat for a precipitated calcium carbonate (light calcium carbonate) drying process, and can also supply biomass fuel gas for a lime kiln according to needs, and main products after biomass gasification are as follows:|[0056] (1) biomass combustible gas: 20-25% of CO and H in parts by volume28-10%、CH42-4%、CmHn(C2H6、C2H4、C2H2、C3H6、C3H8Etc.) 0.8, etc. The biomass fuel has different components.|[0057] (2) Carbon dioxide: CO22:8-15%;|[0058] (3) Nitrogen gas: n is a radical of246%-56%;|[0059] (4) Oxygen: o is20.5%-1.5%;|[0060] (5) Ash residue: accounting for 5-8% of the total amount of the biomass fuel, and metering and accounting for ash and slag removal of carbon elements of byproducts such as hydrocarbons and the like in the biomass energy utilization negative carbon emission process.|[0061] 3、CO2Collecting and purifying process, CO in kiln gas for calcining limestone by biomass2And CO in the heat supply flue gas generated by biomass gasification combustion2After being collected and recovered, the kiln gas and the flue gas are purified and can be applied to a subsequent carbonation process, the kiln gas and the flue gas are mixed and are subjected to cyclone dust removal, water washing, tar adsorption and sewage treatment, carbon-containing compound carbonate, other hydrocarbons, carbohydrate or carbon-containing mixture ash, tar, sewage sludge and the like are added, and in the biomass energy utilization negative carbon emission process, the CO is measured and calculated2Removing carbon element as by-product in the purification treatment process.|[0062] 4. Quicklime slaking process, CaO + H2O→Ca(OH)2The intermediate product, namely hydrated lime does not relate to the problem of carbon emission, but about 5 percent of waste residues in the digestion process, the carbonate or the carbon-containing mixture of the waste residues, needs to be metered and counted to remove the waste residues of the carbon element of the byproduct in the biomass energy utilization negative carbon emission process.|[0063] 5、CO2Industrial utilization process of CO from limestone calcination decomposition and biomass energy utilization2After purification treatment, in CO2Industrial utilization device of carbonization tower and slaked lime Ca (OH)2Performing carbonation reaction to generate stable carbonate such as calcium carbonate, wherein CO is derived from biomass energy2Is permanently fixed and sealed in stable carbonate industrial products and byproducts such as light calcium carbonate and the like by industrialization and is permanently eliminated from a biomass plant carbon library (processed in AFOLU department according to AFOLU 4 chapter 4 source category of IPCC guideline 2006, agriculture and forestry and other land utilization, which is incorporated into the total amount of greenhouse gas emission of China). In the process of utilizing biomass energy and discharging negative carbon, the CO of the carbonization tower needs to be metered and accounted2CO in industrial utilization2The carbon element which is a byproduct in the tail gas emission of the dissipation and carbonization tower is removed.|[0064] 6. Drying and processing technology of precipitated calcium carbonate (light calcium carbonate), biomass gasification combustion heat supply precipitated calcium carbonate drying processing technology, biomassGas combustion of C + O2→CO2Releasing CO2The flue gas is recycled without metering and accounting carbon footprint emission, but CO is dissipated when the biomass gas hot blast stove is combusted2CO and other carbon-containing substances for drying and processing precipitated calcium carbonate, the process dissipation and processing of impurities, and carbon-containing compound carbonate or carbon-containing mixture, in the biomass energy utilization negative carbon emission process, the removal of by-products, such as the drying process dissipation and processing of impurities, and the like, need to be metered and accounted.|[0065] 7. The negative emission process principle for producing light calcium carbonate by using biomass energy is described as follows by integrating the 6 production process flows:|[0066] (1) the biomass carbon element comes from the absorption of CO from the atmosphere and the soil carbon reservoir in the plant growth process2Water, nitrogen, inorganic and trace elements (ash: Ca, K, P, Mg, Si, Al, Ba, Fe, Ti, Na, Mn, Sr), and forming carbohydrate polymer cellulose, hemicellulose and lignin as main components through photosynthesis, including carbohydrates such as starch, protein, lipid, hydrocarbons, etc., and hydrocarbon organic matters. The carbon element of the biomass adopts a chemical structural formula (C)6H10O5)nGlucose trielement polymer (carbon 44.44% hydrogen 6.17% oxygen 49.39%) is the main carbohydrate form, and is fixedly sealed in the carbon pool and the carbon pool of the earth biomass.|[0067] (2) In the carbon pool and carbon pond of the biomass on the earth, the lignin content of woody plants is 20% -35%, and herbaceous plants are 15% -25%, which are the second major renewable biomass resource next to cellulose, and the biomass generates about 6 multiplied by 10 every year on the world14Tons of native lignin, with an incremental production of 1600 million tons/year. The initial strong thermal decomposition temperature of cellulose is 280-290 ℃, the thermal decomposition temperature of lignin is 350-450 ℃, the carbon content of lignin is 55-65%, the complex aromatic structure and the thermal stability are high, and the effective utilization is not achieved at present. In the last hundred years of 1930, the practice of human research on lignin proves that pyrolysis is the only feasible technical route for large-scale industrialization, and the lignin is decomposed at high temperature by insulating air to obtain charcoal, tar, wood vinegar and biogas: about 50.9% of CO,CH4about 37.5% CO2About 9.6%, and ethylene and other saturated hydrocarbons about 2.0%. The combustion heat value of the lignin is high, the combustion heat of the ash-free spruce picric lignin is 110kJ/g, and the combustion heat of the lignin sulfate is l09.6kJ/g.|[0068] (3) The human industrialized large-scale exploitation utilizes fossil energy such as underground carbon depot coal, petroleum and natural gas, and the like to cause climate change, and international laws such as climate change frame convention of United nations, Jingdu protocol, Paris convention and the like, and specialized organization IPCC of gasification change of the United nations promote the human energy to utilize renewable energy such as solar energy, wind energy, water energy, biomass energy and the like from underground to ground.|[0069] In order to eliminate the inevitable carbon emission in the industrial production processes of electric power, steel, cement building materials, metallurgy, chemical industry and the like and realize the aim of coping with climate change, IPCC (2005) ' carbon dioxide capture and storage special report ' (SRCCS) and ' 2006 IPCC guideline ' clearly propose the technical route of biomass energy utilization (biomass power plant) negative carbon emission ' for any other types (such as CO, power plant) selected for storage2Marine storage or conversion to inert inorganic carbonates) does not provide an emission estimation method. With the exception of mineral carbonisation of certain waste materials, these techniques are in the research phase, not the demonstration or later stages of development of the IPCC (2005) technique. If they reach late in development, emission inventory guidelines generated by these techniques may be compiled and presented in future revisions of the guidelines. "anthropogenic carbon dioxide emissions originate mainly from the combustion of fossil fuels (and biomass) in the power generation, industrial, construction and transportation sectors. CO22And also in certain industrial processes (such as cement manufacture, natural gas processing, and hydrogen production) non-combustion sources. Power plants and other large industrial facilities are CO2The main candidate for capture, a common deployment of the prior art, can capture about 85% -95% CO (processed by IPCC capture plants)2. ", SRCCS provides in its FIG. 5.2 an overview of the relevant processes for pre-combustion capture, post-combustion capture, capture of oxygenated fuel and capture of industrial processes". As already mentioned in some industrial processes, the chemical reaction causes CO2The formed quantity and concentration can directly capture or separate CO from the flue gas2. If it captures the raw meatCO produced by combustion of substances2Negative emissions may result from the capture and compression system. The invention utilizes biomass energy to produce light calcium carbonate (precipitated calcium carbonate), and BECCU belongs to the CO of the 2006 IPCC guideline2Technical innovation (CO) under the framework of negative emission overall technical route2Conversion to inert inorganic carbonates), there is currently no established negative emission estimation method for BECCU, the present invention is intended to develop BECCU CO2Negative emission estimation methodology, according to method 3 of the 2006 IPCC guideline, CO (input carbonate based approach), CO2Negative emission estimation model: BECCU CO2DischargingSourceProduction ofSource-capturingSourceThe negative emission process measurement accounting formula is as follows:|[0070] |[0071] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0072] (4) Description of the Process principles for negative carbon emissions|[0073] In the above-mentioned CO2In the negative-emission estimation model, the exhaust gas is,is BECCU CO2And (4) estimating the emission (positive number is positive emission, and negative number is negative emission), wherein a is energy and b is a light calcium carbonate production raw material.Wherein,as a source of energySource classDischarging the waste water, and discharging the waste water,as raw material for industrial processesSource classDischarging the waste water, and discharging the waste water,capturing benefits for carbonation processesWith CO2Atmospheric CO directly eliminated2The emission amount and CO converted by carbon elements contained in the hydrocarbon, carbohydrate liquid and the like such as the inert inorganic carbonate solid and tar which are byproducts of the whole process of industrial production (greenhouse gas emission is not formed in the future)2Indirectly reducing the displacement.|[0074] Further:|[0075] |[0076] (carbon dioxide capture according to "energy" 2.3.4, volume 2, IPCC guideline 2006).|[0077] |[0078] (emission from 2.3 lime production formula 2.7 method 3: emission based on carbonate feed according to Chapter 2 mining industries, volume 3, guide IPCC 2006).|[0079] Wherein, CO2CO emissions from lime production2Discharge in tons|[0080] Emission factor of EFn carbonate n, ton CO2Carbonate per ton|[0081] Mn-consumed carbonate n weight or mass in tons|[0082] Calcining Fn ═ the ratio obtained in carbonate n, the ratio|[0083] Weight and mass of Md-LKD in tons|[0084] Cd is the weight ratio of original carbonate in LKD|[0085] Fd-calcination ratio achieved for LKD, part|[0086] EFd is the emission factor of uncalcined carbonate in LKD, ton CO2Per ton of carbonate.|[0087] |[0088] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0089] Wherein d represents the subsequent discharge amount of greenhouse gases possibly generated in the future in the industrial production of light calcium carbonate, and in the whole production process of precipitated calcium carbonate, part of the dissipated gases which are not captured and utilized by the carbonation process can form CO in the future2Or non-CO2Greenhouse gases, which are subsequently emitted in this part, must be included in the national greenhouse gas list according to the 2006 IPCC guideline, and cannot be deducted from the emission reduction. The method comprises the following steps:|[0090] d 1: indicating subsequent emission of CO|[0091] d 2: represents CH4Then discharged|[0092] d 3: represents H2CO3And so on for subsequent discharge.|[0093] e represents the byproduct of the whole process of industrial production of precipitated calcium carbonate (i.e. the process waste material shown in figure 1), including inert inorganic carbonate solid (excluding non-calcined carbonate in LKD) and carbon-hydrogen such as tar, and indirect CO converted from carbon element fixed in the industrial byproduct for a long time (which will not naturally form greenhouse gas emission in the future)2Capture utilization reduction (indirect carbon capture) comprising:|[0094] e1 denotes inert inorganic carbonates, CaCO3、MgCO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2Etc. of|[0095] e2 represents indirect CO such as liquid hydrocarbon, carbohydrate tar, wood vinegar, lignin (black liquor), etc2The emission reduction amount of the capture and utilization is not as stable as that of the inert inorganic carbonate solid, and the part can be industrially recycled, but does not naturally form greenhouse gas emission.|[0096] Further:|[0097] |[0098] further:|[0099] the industrial production of the light calcium carbonate only chemically changes on the molecular and atomic level, does not relate to the nuclear polymerization change of C element atomic nucleus, does not change the total amount of C elements of the light calcium carbonate raw material and the final industrial product, and is balanced by C substances; and the total content of the C element of the biomass a, the total content of the C element of the subsequent emission d and the total content of the C element of the industrial byproduct e are also in balance of the C substance, and the total content of the C element is not changed in the industrial production.|[0100] Due to the law of constant substances, as long as industrial production is carried out, an industrial production byproduct e (namely the process waste shown in figure 1) is always present,is also certain to exist and can never be zero; particularly in industrial production, the emission of CO and other greenhouse gases dissipated in the process only accounts for about 1.69 percent (about 1.42 percent by mass) of the total volume of the kiln gas and the flue gas, and the emission proportion is very small and is far smaller than that of CO generated by biomass combustion2The total amount of material, and therefore,|[0101] in conclusion, in the production process for producing light calcium carbonate by comprehensively replacing fossil energy with biomass energy as shown in fig. 1, due to the law of constant substances, in the BECCU process technology,and isThe presence of the (C) is determined,BECCU CO2dischargingSourceMust be negative in emission, and absorb CO from the atmosphere in the process of plant growth2CO fixed in biomass carbon reservoir by carbon sink effect2And is permanently sealed in the final industrial product of the light calcium carbonate through an industrial production process.|[0102] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate|[0103] In the description of the attached figure 1, the processes of calcining, biomass pyrolysis gasification and CO production for producing light calcium carbonate by using biomass energy sources2Collecting and purifying, slaking quicklime, Ca (OH)2Six processes, such as carbonation and calcium carbonate drying, have been described in detail and are not described again.|[0104] FIG. 3 is a view showing a structure of a carbonator in a carbon dioxide utilizing process apparatus|[0105] Ca(OH)2And collecting, purifying and compressing the treated CO2Calcium carbonate is generated in a carbonization tower through reaction, and the carbonization tower is CO2The core equipment of the utilization and carbonation process is that the carbonation reaction equation is Ca (OH)2+CO2→CaCO3. FIG. 3 is a view showing the most simple structure of a carbonization tower in which Ca (OH) from a mature slurry aging tank is used2The fine slurry emulsion enters the carbonization tower from a fine ash emulsion inlet 3 shown in the figure and enters the carbonization tower from CO from a kiln gas inlet 2 shown in the figure2Collecting CO from purification and compression process2Carrying out carbonation reaction to generate calcium carbonate; the main function of the 7-gas-dividing hood shown in the figure is to disperse CO2Realization of CO2Distributing the materials evenly, wherein the generated calcium carbonate product is collected by a boiled slurry tank through a boiled slurry outlet 9 shown in the figure and then is aged in a boiled slurry aging tank; the carbonization tower is provided with 6 overflow ports for controlling the height and pressure of the liquid level, and is also provided with a carbonization reaction impurity 8 extraction notch and a carbonization reaction tail gas outlet 4 exhaust cap for exhausting, and a phosphoric acid adding port 5 shown in the figure is mainly used for adding blending auxiliary materials such as phosphoric acid and the like and used for adjusting performance indexes such as whiteness, activity and the like of a calcium carbonate product.|[0106] It must be noted that the carbonizer is CO2The key core equipment of the process is utilized, the carbonation process is one of the key processes for determining the quality of the final product of the light calcium carbonate, such as the granule, the crystal form and the like, the core of the invention is to provide the method for utilizing the biomass energyCO production of light calcium carbonate2The negative discharge technique and method, fig. 3 is only the simplest and most common carbonator structure selected for the convenience of illustrating the carbonation process, and is not intended to limit the carbonation process and apparatus used in the present invention. In fact, the prior art of the carbonation process has various selectable technical processes, including an intermittent bubbling carbonation method, a continuous spray carbonation method, a hypergravity reaction crystallization method and the like, which can be selected to implement the method, and the CO production by the light calcium carbonate of the method can be realized2The purpose of negative discharge technology. Therefore, the invention can be applied to any carbonation process undoubtedly without enumerating and carbonizing process technology and equipment, and any method adopting the invention to replace fossil energy with biomass energy to produce light calcium carbonate and collect and utilize CO2Realization of CO2The purpose of the negative emission technique is within the scope of the present invention.|[0107] Detailed Description|[0108] The inventor deeply recognizes the high-technology high-added-value clean utilization of biomass energy and gradually replaces fossil energy in scientific and technological innovation and industrial innovation practices of the world biomass energy technology in the field of biomass energy utilization for decades at the forefront, and is one of fundamental countermeasures for solving the climate change crisis caused by the unregulated use of human fossil energy; particularly over a decade ago, the inventors discovered the greenhouse gas CO2Not only from the fields of fossil energy, traditional and novel building materials such as building material cement, calcium carbonate, lithium carbonate and the like, chemical engineering, new materials and the like, but also the used main raw materials such as calcium carbonate and the like are greenhouse gas CO2One of the main sources of (1). Based on the important discovery, the inventor is closely cooperated with domestic authoritative scientific research institutions, industrial design institutions, head enterprises of international and domestic related industries and the like, timely masters the latest international dynamic trend, concentrates all efforts, focuses on the zero-carbon-emission biomass energy efficient clean utilization technology for replacing fossil energy, and carries out original scientific research and development, new technology and new product process technology.|[0109] In recent years, the inventor obtains a plurality of major technical breakthroughs in the new technical fields of developing new materials, such as low-carbon zero-carbon cement building materials, calcium carbonate, lithium carbonate and the like, new technologies, new products coping with climate change, realizing carbon peak-reaching carbon neutralization and the like by replacing fossil energy technologies with biomass energy in an efficient and clean manner, particularly applying the most advanced mature biomass energy technology to the related fields of calcium carbonate to replace fossil energy, and forming one of a series of major original technical achievements.|[0110] The invention relates to industrialized carbon capture and permanent CO sequestration by using carbonate industrial products2The implementation range of the negative carbon emission process technology is not limited to the production of light calcium carbonate, namely a carbonate product, and the technical method can be widely applied to the technical fields of various carbonate industrial negative carbon emission and zero-carbon and low-carbon emission, such as various products of cement, white cement, lithium carbonate and the like, after being subjected to adaptive improvement. Therefore, the following examples of the present invention are not intended to limit the scope of the present invention, and any person skilled in the art can make modifications or variations without departing from the technical scope of the present invention, such as the production of various carbonate products such as calcium carbonate, lithium carbonate and tricalcium silicate and other portland cement products by using the technology of the present invention, i.e. all the biomass energy sources are used to replace fossil energy sources (regardless of the substitution rate or whether biomass gasification technology or biomass fuel industrial direct combustion technology is used) and CO is used in the production of light calcium carbonate according to the present invention2The collection and utilization technology integrates the two technologies (including the carbon capture and utilization technology and the industrialized sequestration technology of the CCUS) into a new technology, so as to achieve the purpose and effect of industrialized negative carbon emission, and the scope of the invention is covered by the invention of the technology.|[0111] The embodiment of the invention comprises the following steps: and 10000t/a light calcium carbonate produced annually by using biomass energy instead of fossil energy is used as an embodiment for negative carbon emission.|[0112] 1. The production process design:|[0113] (1) production capacity: 10000 ton/year, production time: 300 days/year, production safety guarantee coefficient: 1.15, daily productivity: 33.33 tons/day, considering the safety factor of 38.33 tons/day, 1.6 tons/hour;|[0114] (2) the production method comprises the following steps: direct combustion of GaCO by using vertical kiln biomass wood chips3A production process of an intermittent bubble carbonization tower;|[0115] (3) each workerThe process yield is as follows: calcining limestone: considering the factors of over-burning and under-burning of limestone, the conversion rate of the limestone is 95 percent, and GaCO in the limestone3The content is 97 percent, the loss in the calcining and conveying process is 3 percent, and the total yield in the process is 95 percent multiplied by 97 percent and 89.31 percent;|[0116] the yield of slaked lime and refined hydrated lime is 98 percent;|[0117] and (3) carbonation process: usually CO2Feeding in excess, wherein 99% of lime refined emulsion can be taken as complete reaction;|[0118] and (3) post-treatment procedures such as product dehydration and drying: centrifugally dewatering, and removing about 1-2% of calcium carbonate along with filtrate, wherein the part can be returned to a digester for recycling, and the yield of the part is considered to be 99%; the drying yield is 99%; the operation yield of screening, packaging and the like is 99 percent, and the total yield of the light calcium carbonate is as follows: 89.31% x 93% x 99% x 99% x 99% x 84.08%.|[0119] (4) Consumption of raw materials: limestone ore consumption: 38.33/84.08% ═ 45.59 ton/day, 1.90 ton/hour limestone calcination material measured as 38.33t/d, lime kiln feed: limestone 16 ÷ 0.8263 ÷ 19.36kmol/h ═ 1936kg/h, where: GaCO3Content 97%, 1877.92kg/h MgCO3Content 1.2%, 23.23kg/H, H2The O content is 0.5 percent and 9.68kg/h, and the impurity contents of FE, Mn, Al and the like are 1.3 percent and 25.17 kg/h.|[0120] (5) Biomass fuel consumption: the heat value of the mixed wood biomass briquette fuel or the high-quality biomass particle briquette fuel is 3000-4000 kilocalories, the limestone calcination of the embodiment uses the biomass fuel to be directly combusted (biomass pyrolysis gasification biomass gas can be used for calcination), the drying process uses the biomass pyrolysis gas, the biomass fuel is calculated by 30% of the feeding amount of the limestone, the drying process is equivalent to the biomass consumption of the calcination process, and the two processes are 1936 x 0.30, 580.80kg/h and 2428766208kg/a in total, wherein:|[0121] |[0122] |[0123] low calorific value 16302KJ/Kg|[0124] (6) And (3) quicklime yield: the CaO amount is 19.36 x 0.97 x 0.95 x 56 ═ 999.05kg/h, the unreacted calcium carbonate ore amount is estimated to be 19.36 x 0.97 x 0.05 x 100 ═ 93.1kg/h, the MgO amount is 23.23 ÷ 84 x 40 ÷ 11.06kg/h, the total impurity by-product amount is 25.17+18.59 ═ 43.76kg/h, and the quick lime discharge amount G is 999.05+93.1+11.06+43.76 ═ 1147.77 kg/h.|[0125] (7)CO2Production amount: CaCO3CO obtained by decomposition2Quantity: 1936/100 x 0.97 x 0.95 x 44 ═ 784.97kg/h, prepared from MgCO3CO obtained by decomposition2Quantity: 23.23/84 x 44 is 12.17kg/h, and according to experience, the CO content is about 1.7% of the kiln gas amount, the CO content is 39kg/h, and the CO is consumed2Amount 39 ÷ (consumption 2 x 28) x 44 x 2 ═ 61.28kg/h, substance C consumption: 39 ÷ (2 x 28) x 12 x 2 ═ 16.72kg/h, 21.90kg/h calculated by biomass ash accounting for 8% of the total carbon content of the biomass, and CO produced by the biomass2Quantity: (273.79-16.72-21.90) ÷ 12 x 44 ═ 862.29kg/h, this example was not metered due to the presence of byproducts of the calcination process, and the biomass CO actually produced was not present in the amount2The amount is slightly less than the data;|[0126] CO-generation of CO2Total amount: sigma CO2At 784.97+12.17+862.29-61.28 at 1598.15kg/h, the present example was not metered due to the presence of byproducts of the calcination process, and actually produced CO2The total amount is slightly less than the data.|[0127] 2. Negative carbon emission estimation of the embodiment:|[0128] to ensure that the carbonation process proceeded smoothly, this example employed an excess of CO2Production Process, CO2Besides reacting with slaked lime fine milk to produce light calcium carbonate target product, it also reacts with water, calcium carbonate and other carbonates to produce various carbon-containing compounds and mixtures.|[0129] In the course of producing light calcium carbonate, the by-products are respectively made up by using solid inert carbonate, liquid hydrocarbon material, carbohydrate tar, wood vinegar, lignin (black liquor) and gas CO2、CH4And CO and the like and the subsequent emission form of greenhouse gases are distributed in each productionIn links and environments: such as CaCO3、H2CO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2And the like.|[0130] The annual negative carbon emission of this example is estimated as follows:|[0131] (1) dissipation was estimated as 2%: sigma CO2=1598.15 x 24 x 300 x 2%=230133.60kg/a|[0132] (2) CO dissipation was estimated at about 1.42% by mass: 230133.60 ÷ 0.35 x 1.42% ═ 9336.84kg/a|[0133] |[0134] |[0135] |[0136] The sum of the carbon elements contained is converted into CO2Equivalent indirectly scavenged CO from the atmosphere2The amount of indirect purging cannot be estimated since the present embodiment does not monitor the associated byproduct data.|[0137] (6)BECCU CO2DischargingSourceProduction ofSource-capturingSourceLess than or equal to-5969017.56 kg/a, i.e. BECCU CO in this example2DischargingSourceThe annual negative carbon emission is not less than 5969017.56 kg. | (CN114229879)|TECHNICAL FIELD|[0001] The invention relates to the technical field of biomass energy source replacement of fossil energy and carbon dioxide capture and utilization of negative carbon emission.|BACKGROUND ART|[0002] Artificially created atmospheric CO2The concentration is increased, and the greenhouse effect threatens the survival and development of human beings. Reduction of anthropogenic CO2The technical route of (1) has two routes: the first is to develop renewable energy sources such as solar energy, wind energy and biomass energy to replace fossil energy sources vigorously or reduce CO from the source by improving the utilization efficiency of the fossil energy sources2Discharging; second, to the CO produced2Atmospheric CO increased by human activity is removed by artificially increasing carbon sequestration and carbon Capture using sequestration techniques CCUS (carbon Capture Utilization and storage)2。|[0003] United nations inter-government climate Change organization (IPCC) on CO in 20052Special reports on capture and storage and 2006 IPCC Guidelines for National Greenhouse Gas Inventories (the 2006 IPCC guide) indicate that fossil fuels are kept in use throughout the 21 st century, avoiding large amounts of CO, according to the third assessment report on IPCC2Discharge, realize the concentration stability of greenhouse gas in the atmosphere and CO2Capture and Storage (CCS) should be one of the combination options for greenhouse gas concentration stabilization, in particular CO captured from biofuel combustion, injected underground and stored2The amounts are included as negative emissions in the list of greenhouse gases, chapter 5, the CCS System and CO, Chapter 5, volume II (energy source)2Capture, transport, inject into the underground storage and discharge and clear up the estimation method; united nations climate change congress, published 2050 via the coordinated Organisation (OCED) environmental agency in 2011, with the expectation of achieving lower concentration targets (450ppm), largely dependent on carbon capture and sequestration using biomass energy (BECCS or BioCCS); in 2015, climate change of Paris United nations will set a positive target, and the global temperature rise is limited to be below 1.5 ℃ to be restored to the level before industrialization. However, positive carbon rejection (positive carbon emissions) of clean power generation technologies and energy conservation measures are not sufficient to solve the problem by themselves, even if CO2The amount is reduced and discharged at a slower rate,CO2the net concentration is still rising; the 20 th group of countries (G20) in 2019, the Ministry of energy and environment, incorporated the CCUS technology for carbon capture, utilization and sequestration. IPCC reports suggest that the CCUS technology is significant for realizing zero carbon emission in 2050 years, and large-scale negative carbon emission application technologies need to be deployed in 2040 years.|[0004] CCUS is essentially an artificial, industrial carbon sequestration approach. Wherein, CO2The trapping method comprises 3 trapping methods including pre-combustion trapping, oxygen-enriched or pure oxygen combustion and post-combustion trapping. Pre-combustion capture is the gasification of fossil fuels to synthesis gas (with H as the major component)2And CO) and then converting the CO to CO by a shift reaction2And then H is absorbed by a solvent or the like2And CO2Separation and collection of CO2The technology is limited to a coal gasification combined power generation device for capturing CO before combustion2The cost is about $ 20/t CO2(ii) a The oxygen-enriched combustion technology adopts pure oxygen or oxygen enrichment to combust fossil fuel, and the main product after combustion is CO2Water and some inert components, because pure oxygen is obtained by air low-temperature separation or membrane separation, the energy consumption is large, and the cost of oxygen-enriched combustion is high; common methods for post-combustion capture technology such as chemical absorption, membrane separation, physical adsorption, etc., and post-combustion capture of CO2The cost of (A) is about $ 40/t CO2。|[0005] The CCUS technical test is carried out firstly, the petrochemical industry enhanced oil recovery is carried out, and CO is passed2Connecting carbon source produced by coal chemical industry or natural gas chemical industry with oil field to obtain CCUS-EOR (enhanced oil recovery), and collecting CO2Injecting into oil field to recover oil from exhausted oil field and CO2Permanently stored underground; thereafter, attempts were made to use CO2Fertilizer and food grade CO2Utilization, etc., and also industrially produced CO2Inputting the green as greenhouse gas to strengthen plant growth, etc.|[0006] The earliest large CCUS project in humans was the Terrell project, CO, built in the United states in 19722The trapping capacity reaches 40 ten thousand t/a; enid project, Okla, USA, was built in 1982 by CO produced by chemical fertilizer plant2Performing oil fieldOil displacement, CO2The trapping capacity reaches 70 ten thousand t/a; the Norwegian Sleipner project in 1996 was the first CO to be established in the world2Injection into underground (saline aquifer) projects, annual sequestration of CO2The quantity is close to million tons; in the United states, in 2000, in cooperation with Canada, the CO of Great Plant Synfuels plants and Sask Power plants was injected at the Weyburn oil field2Accumulating and storing CO while improving the oil extraction rate of the oil field near exhaustion2Up to 2600 or more tens of thousands t; the project of Boundary Dam Power of Sask Power company of Canada in 2014 is the first successful application of the project to CO Power plant2Capture project, CO generated by 150MW coal-fired generator2After capture, a portion was sequestered underground and a portion was used for U.S. Weyburn oil field flooding, CO2The trapping capacity reaches 100 million t/a, and the project traps CO in 20192Up to 61.6 ten thousand t; 2015 Canadian Quest project CO produced in hydrogen production process of synthetic crude oil2Successfully injected into a saline water layer for sealing and storing, and CO is injected every year2The trapping capacity reaches 100 million/a, the project is the first CCS project in the oil sand industry, the carbon emission can be reduced by 100 million every year, and by 2019, the Quest project can trap CO accumulatively2Up to 400 million t, is the maximum CO capture in the world2And successfully injected into a subterranean project; the Gorgon project in the west of australia in 2016 is a complement to the Gorgon natural gas project, the largest global unit LNG project, which projects CO by liquefaction technology2Separating CO from natural gas2The injection amount can reach 350 ten thousand t/a when the injection is injected into a saline layer of the Balo island.|[0007] China starts to research CCUS technology later, and the government continues to come out of the CCUS technical policy in 2006, and the CCUS technology is one of the key points in China national plan for climate change handling (national scheme for climate change handling science and technology action handling in China), Chinese policy and action for climate change handling in China, and the like. In 2007, the China Petroleum Jilin oil field and the China petrochemical east China division company grass House oil field opened domestic CO2The trapping project firstly realizes the industrialization of the CCUS-EOR technology and establishes five types of CO2Oil displacement and sequestration demonstration area, annual sequestration of CO2The capacity can reach 35 ten thousand t; in the same year, China petrochemical east China division builds CO in the oil field of the grass house2Annual injection amount4 ten thousand t of pilot test items, and CO is built in the later period2The annual treatment capacity of the recovery device can reach 2 ten thousand t. Subsequently, the Zhongpetrochemical Shengli oil field, China Shenhua, prolonged Petroleum and the Zhongpetrochemical Central oil field accelerate the propulsion of CO2Industrialization of the collection item. In 2010, the China petrochemical industry victory oil field is built into the first domestic CCUS demonstration project of a coal-fired power plant, and the flue gas CO of the coal-fired power plant is used2Adopting combustion-trapping technology to trap CO as source2Injecting into oil field for displacing oil and CO2The trapping capacity reaches 3-4 million t/a; in 2011, a CCS demonstration project of Shenhua Ordos 10 ten thousand t/a is completed, and a methanol absorption method is adopted to capture CO in tail gas of a coal gasification hydrogen production project2Injecting CO into saline water layer2The project is the first domestic saline water layer geological sequestration experiment project; in 2012, the oil is prolonged to build 5 ten thousand t/a of CO2A collection and utilization item for utilizing CO generated in coal chemical industry2The crude oil is purified, pressurized and liquefied by a low-temperature methanol washing technology and then injected into an oil field, so that the viscosity of the crude oil is reduced, the recovery ratio of the crude oil is improved, and CO is realized2Permanently sealing and storing; in 2015, CCUS project for tail gas of central oil field refinery in medium petrochemical industry was built, and the project approaches to abandoned oil field through CO2Oil displacement improves the oil field extraction rate by 15 percent, and million tons of CO exist at present2Is injected into the ground.|[0008] In addition to the conventional CO2Trapping technology, China also developed CO2The novel recycling technology is applied to the industries of food, fine chemicals and the like, in 2009, a second power plant carbon capture project at the Shanghai stone cave entrance is built, the capture scale is 10 ten thousand t/a, and the captured CO is2The method is mainly used in the food industry; 2011 CO produced by IGCC in research institute of clean coal energy and power system in Hongyun harbor2Trapping the latter part for urea and sodium carbonate industry, injecting the other part into brine layer for sealing; china electric group CO of Tianjin north pond in 20122The trapping demonstration project adopts a post-combustion trapping technology, the annual trapping amount is 2 ten thousand t, and CO is trapped2Used in the food industry; in 2010, the Xinao group in inner Mongolian Dallas absorbed tail gas of a coal-based methanol/dimethyl ether device by using a microalgae carbon sequestration technology, and a part of the tail gas is used as biodiesel,one part is used for producing feed, and the treatment capacity reaches 2 ten thousand t/a; the sea snail cement establishes an industrial CCUS test project of 5 ten thousand tons; qilu petrochemical under construction CCUS-EOR project (2020) CO2The trapping capacity was 4 ten thousand t/a. The utilization direction of the emerging carbon in China is mainly CO2Hydrogenation for preparing methanol and CO2Hydrogenation for preparing isoparaffin and CO2Hydrogenation for preparing aromatic hydrocarbon and CO2Although methanation reforming and the like, such as Shanxi coal chemical institute, Dalian union institute, Shanghai research institute of Chinese academy, university of Dalian union, and the like, have studied these technologies, they are mostly in the theoretical research stage or pilot plant stage of catalyst research, and there is no CCUS practical technology for industrial application.|[0009] The Chinese environmental science society, release the Chinese head CCUS group standard 'carbon dioxide capture utilization and sealing term' T/CSES 41-2021 at 22.12.1.2021, comprises related terms of CCUS, related terms of carbon dioxide, capture and transportation terms of carbon dioxide, related terms of CCUS monitoring and measuring performance, related terms of risk and the like, and regulates related terms of the capture utilization and sealing field of carbon dioxide, and is mainly suitable for scientific research, management, teaching and production activities in related fields of carbon dioxide capture, chemical utilization, geological sealing and the like in high emission industries such as chemical industry, thermal power, steel, cement and the like. The T/CSES 41-2021 has positive significance for scientific research and production activities in the CCUS field, promotes the scientificity and normalization of the use of Chinese CCUS terms, and accelerates the pace of meeting international standards. The community standard does not relate to the related patent technology in the CCUS field. The prior patent technology in the CCUS field is few in China, and the real practical technology is almost none.|[0010] CN201711383170.2 discloses a negative carbon emission system and method thereof, which utilizes photosynthesis of growing plants to absorb carbon dioxide molecules, and properly designs photon wavelength for inducing photosynthesis of plants to increase efficiency of photosynthesis of plants, and selects LED light source with carbon footprint lower than threshold and conversion efficiency higher than threshold, and combines low carbon power source with carbon footprint lower than threshold, such as solar cell panel. The system can be applied to the capture of carbon dioxide.|[0011] CN201810173639.8 discloses carbon dioxide entrapment device in cement manufacture, including gas collecting channel, first intake pipe, air pump, first blast pipe, filter, the gas collecting channel top is provided with first intake pipe, one side of first intake pipe is provided with the air pump, one side of air pump is provided with first blast pipe, one side of first blast pipe is provided with the filter, one side of filter is provided with the dust absorption jar, one side of dust absorption jar is provided with the second blast pipe, one side of second blast pipe is provided with gaseous drying tank, one side of gaseous drying tank is provided with the second intake pipe, one side of second intake pipe is provided with the gas holder. Has the advantages that: this carbon dioxide entrapment device has set up equipment such as filtration, purification, drying to the special environment of cement manufacture for the purity of final carbon dioxide product is higher, through the collection to carbon dioxide, has reduced its emission to in the air.|[0012] CN201820292229.0 discloses carbon dioxide collection device that tail gas was handled among cement manufacture, including cement rotary kiln, gas transmission pipeline, dust remover, absorption tower, cement rotary kiln one end is provided with the smoke chamber, smoke chamber one end is provided with gas transmission pipeline, gas transmission pipeline one end is provided with the dust remover, dust remover one end is provided with the scrubbing tower, scrubbing tower one end is provided with the desulfurizing tower, desulfurizing tower one end is provided with the absorption tower, absorption tower one end is provided with analytic tower, analytic tower one end is provided with the gas holder, gas holder one end is provided with the carbon dioxide and does not have the oil-pressure moulding machine, carbon dioxide does not have oil-pressure moulding machine one end and is provided with first absorption tower. Has the advantages that: the device recovers carbon dioxide gas generated in the cement kiln, does not contain impurities, does not discharge into the air, plays a role in protecting the environment, and improves economic benefits by recycling carbon dioxide in other industries.|[0013] CN201811533699.2 discloses a carbon dioxide desorption method for carbon capture, sequestration and utilization technology, which comprises the desorption steps of: starting and adjusting an electric adjusting valve, reducing the temperature and the pressure of saturated steam in the cement kiln tail waste heat boiler through a temperature and pressure reducer, and heating the saturated steam in an amine liquid reboiler in a desorption tower; heating and desorbing the carbon dioxide passing through the desorption tower; and the saturated steam after heating and desorbing the carbon dioxide in the desorption tower is subjected to liquid change to form saturated water, and the saturated water enters a condensate water recovery device through a water return pipe. The carbon dioxide desorption method for the carbon capture, sequestration and utilization technology does not influence the normal operation of the cement kiln waste heat power generation system, can meet the requirement of the desorption operation of the CCS system, and reduces the economic cost investment.|[0014] CN201010532911.0 discloses a waste treatment facility for introducing a thermal decomposition gas of waste into a cement decomposition furnace, which is provided adjacent to a cement manufacturing facility provided with a cement burning furnace, a clinker cooler for cooling a burned product thereof, and a decomposition furnace into which a high-temperature exhaust gas flows from either one of the burning furnace and the clinker cooler. Wherein, possess: the gasification furnace is provided with a gasification furnace for gasifying the waste to generate thermal decomposition gas, and a gas conveying channel for conveying the generated thermal decomposition gas to the decomposition furnace under the condition of keeping the carbon and the ash unchanged. The pyrolysis gas is introduced into the decomposing furnace in such a manner that the pyrolysis gas does not directly interfere with the main stream of the exhaust gas flow from the burning furnace or the clinker cooler, and is prevented from being scraped, thereby sufficiently burning the pyrolysis gas. Thus, the existing cement manufacturing equipment is effectively utilized, and the sanitary treatment of wastes is realized at low cost.|[0015] 201610704208.0 discloses a method for utilizing carbon dioxide in carbonate calcining flue gas and preparing methanol by collecting carbon dioxide generated in the carbonate calcining process; catalytic pyrolysis of biomass fuel to form H-containing2Introducing the fuel gas into a high-pressure catalytic reaction tower after dust fall treatment; the two are produced into products with methanol as the main component in a high-pressure catalytic reaction tower, and are purified and purified into industrial methanol in a distillation tower. The method for regenerating carbon dioxide generated in the carbonate calcination process disclosed by the invention can absorb and consume about 1.375 million tons of greenhouse gas carbon dioxide and absorb and consume biomass according to the annual production of ten thousand tons of methanolThe waste is approximately 10 ten thousand tons. The purposes of environmental protection and resource recycling are achieved while economic benefits are generated.|[0016] CN201010229727.9 discloses a production process for removing carbon dioxide from flue gas and preparing ammonium compound fertilizer and light calcium carbonate. The method comprises the steps of using dilute ammonia water as an absorbent, carrying out gas-liquid two-phase high-strength mass transfer absorption reaction on raw flue gas through a super-gravity field absorption tower for decarbonization, discharging the treated flue gas through a chimney, and further carrying out reaction treatment on byproducts of the decarbonization reaction to obtain the ammonium compound fertilizer and the light calcium carbonate with good economic value. The complete set of reaction separation device supporting the process comprises a high-gravity field absorption tower, a static mixer, a deep reaction tank, a cyclone, an ammonium compound fertilizer recovery system, a light calcium carbonate recovery system, various pumps and other equipment, wherein the high-gravity field absorption tower is a chemical reaction absorption section for removing carbon dioxide. The invention is a brand new process, and has the advantages of high efficiency, low investment and low operating cost.|[0017] CN201980083589.7 discloses hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation, to a process for hydromethanating the carbonaceous feedstock in a hydromethanation reactor to a methane-enriched raw product stream, and in particular to processing the solid coke by-product removed from the hydromethanation reactor to improve the carbon utilization and thermal efficiency and economics of the overall process by co-producing power and steam from the by-product coke in addition to the end product pipeline quality substitute natural gas.|[0018] CN202010455978.2 discloses a method and a system for utilizing carbon dioxide, wherein the method comprises the following steps: acquiring carbon dioxide meeting preset conditions; injecting the carbon dioxide into a coal seam and allowing the carbon dioxide to expand and release into the coal seam; and the carbon dioxide is used for expelling the coal bed gas in the coal bed to ensure that the coal bed gas is discharged from the coal bed. In the invention, the relatively single carbon dioxide is used as the displacement gas of the coal bed gas, and after the coal bed gas is displaced out of the coal bed, the carbon dioxide is remained and sealed in the coal bed, so that the carbon dioxide is utilized to obtain a clean gas source, the emission of the carbon dioxide is reduced, and the influence on the greenhouse effect is reduced.|[0019] CN201110176523.8 discloses a method and a device for preparing formic acid by recovering carbon dioxide from flue gas and utilizing electric power at night, a carbon dioxide recovery process for separating and recovering carbon dioxide from flue gas obtained by fuel combustion; sending the separated carbon dioxide into a membrane electrolysis device which is reduced by direct current to reduce the carbon dioxide to obtain formic acid; the formic acid refining process is that the dilute formic acid solution obtained by membrane electrolysis is refined to obtain formic acid product. The membrane electrolysis device is divided into a cathode chamber, a concentration chamber and an anode chamber; or divided into a cathode chamber and an anode chamber; the membrane electrolysis units are combined in any mode of series connection or parallel connection or combination of series connection and parallel connection. The technology adopts an efficient membrane electrolysis device and a gas-liquid mixed feeding mode and a carbon dioxide recovery formic acid refining process, has high electrochemical process efficiency, collects and recovers carbon dioxide and obtains high-concentration formic acid liquid through electrolytic reduction, effectively realizes the recovery and conversion of carbon dioxide, and can also effectively utilize the night power of a power plant.|[0020] The fundamental pain point of the above prior art CCUS is high cost, high energy consumption, low efficiency, low benefit, and is far from large-scale commercial application. World CO2The utilization of CO which is still in the theoretical research stage of the technology2Carbon fiber preparation, acetic acid preparation and the like; already in development stage, there is CO2Preparation of Polymer, CO2Methanation reforming, CO2Preparing methanol by hydrogenation, cultivating seaweed, circulating power and the like; already in the demonstration project phase there is a CO2Chemical fertilizer preparation, oil displacement in oil fields, food-grade application and the like. The negative carbon emission methods being discussed and developed are biomass energy power generation and carbon capture and sequestration (BECCS or BioCCS) technologies, such as BioCCS of the european carbon emission center (CCR), it is theoretically possible to remove CO from the atmosphere while producing fuel or electricity2。|[0021] China actively participates and becomes an important construction force for coping with climate change in the world, and in order to achieve the green transformation target of carbon peak carbon neutralization and high-quality development in China, the technical field of carbon emission strategy utilization by CCUS and biomass in China has to be changed thoroughly. Book (I)Creatively replaces fossil energy with biomass energy and CO in the current industrial field2The collection and the Utilization of the prior art are organically combined, and the integrated creation of a biomass energy of a non-power plant can utilize the industrialized commercial negative Carbon emission technologies (NETs) practical technology BECCU or BioCCU (Bioass-energy With Carbon Capture and Utilization).|DISCLOSURE|Disclosure of Invention|[0022] Aiming at the defect that Chinese CCUS and biomass energy use negative carbon emission technology is also and gradually following carbon capture and sequestration (BECCS or biocCS) of European and American biomass power plants, in particular to the industrial pain point that CCUS has high cost, high energy consumption, low efficiency and low benefit, the invention uses CO in the production of light calcium carbonate in the current industrial field2Collecting and utilizing the prior art and the production thereof to CO2The self-demand of raw materials organically integrates the biomass energy source instead of fossil energy with the CCUS technology, the light calcium carbonate production process and the like, creates a biomass energy utilization mode of industrial non-power plant biomass energy utilization negative carbon emission practical technology BECCU or BioCCU, and realizes the CO energy utilization mode through industrial production by using the pollution reduction and carbon reduction synergistic effect of high efficiency, high benefit, low cost and low energy consumption2The purpose of negative carbon emission removed from the atmosphere opens up a new field of carbon capture and utilization technology.|[0023] In order to realize the aim, the invention provides a non-power plant industrialized biomass energy utilization negative carbon emission technology, biomass energy is used for completely replacing fire coal to produce light calcium carbonate, and the biomass fuel is directly combusted in the calcium carbonate calcination process and CO produced by biomass gasification combustion in the drying of calcium carbonate cooked pulp2The CO absorbed by the biomass energy from the atmosphere is completely recycled and used as the calcium carbonate production raw material in the carbonation process2Permanently fixed and sealed in industrial products to realize industrialized removal of atmospheric CO2A fraction of the total amount.|[0024] In the invention, limestone and biomass fuel are added into a lime kiln together for calcination, the obtained quick lime is screened and then enters a digestion mechanism for digestion to obtain lime milk coarse pulp, the coarse pulp is separated and purified to obtain fine pulp, and the fine pulp is aged in an aging tankThe mixture enters a fine pulp thickening tank after being dissolved, and then enters a carbonization tower after being added with clear water to adjust the concentration, and the CO is mixed and collected with purified flue gas from a biomass calcining kiln gas and a biomass gas hot blast stove in a drying process2The generated calcium carbonate cooked slurry is subjected to carbonation reaction, is subjected to standing and aging and then is filtered in a filter, and the obtained filter paste is dehydrated, dried, crushed, separated and dedusted to obtain the light calcium carbonate final product, so that the CO absorbed by the biomass energy from the atmosphere is realized2Permanently fixed and sealed in light calcium carbonate industrial products for industrially removing atmospheric CO2The purpose of (1).|[0025] In the invention, the calcination process for producing the light calcium carbonate can be directly combusted in an industrial manner by using 3000 to 4000 kilocalories of wood chip biomass briquette fuel or high-quality biomass particle briquette fuel, and can also be calcined by using biomass fuel gas produced by pyrolyzing biomass by using a biomass gasifier. In fact, the production of the quicklime by directly calcining the limestone by using the wood biofuel firewood is a first generation traditional technology of biomass energy utilization existing before the industrial revolution, and the project adopts a second generation technology of biomass energy utilization and biomass briquette industrialized direct combustion technology to improve the energy utilization efficiency and CO2The recycling rate is improved, and the biomass pyrolysis gasification belongs to the third generation technology of biomass energy utilization, and is more advanced and efficient than the second generation technology. No matter the second generation or the third generation biomass energy utilization technology is adopted, the fuel requirement of limestone calcination can be completely met technically.|[0026] In the invention, the precipitated calcium carbonate cooked pulp drying process adopts a biomass pyrolysis gasification technology to supply heat, and CO in the flue gas of a biomass gas hot blast stove2With CO produced by the calcium carbonate calcination process2And are recycled together.|[0027] In the present invention, CO2The collection and the recycling of the light calcium carbonate can be fully utilized to produce the existing CO2The collection and recovery technology and the device greatly reduce the huge investment and cost of the carbon capture, utilization and sequestration of the CCUS technology at present. Wherein CO produced in the calcination stage2Not only can directly adopt the existing CO2Collecting and recycling technology and device for collecting and recyclingOr, if necessary, to the existing CO2Collecting CO from a utilization system2Collecting, gas-solid-liquid separating, impurity treating, cooling, recovering and CO2A small amount of adaptive technical transformation is carried out on devices such as compression conveying and the like, so that the CO is further improved2The collection and recycling efficiency of (1); CO produced in the drying process of the calcium carbonate cooked pulp2With CO produced during the calcination process2Can be recycled together to meet the requirement of CO production in industrialized commercial light calcium carbonate2The requirement of raw materials.|[0028] In the invention, the biomass fuel is industrially directly combusted or after gasification, the biomass gas is combusted to form C + O2→CO2Releasing CO2And releases heat; and the calcination of calcium carbonate releases CO2The two processes of producing the calcium oxide CaO and drying the calcium carbonate cooked slurry are heat absorption processes, CaCO3→CaO+CO2The enthalpy change of ↓ΔH is larger than zero when the biomass fuel is used for continuously supplementing and providing energy required by reaction and heating. On the one hand, CO is continuously generated by calcining and combustion heating2On the other hand, CO produced by decomposition of calcium carbonate raw material2And CO produced by the combustion of biomass2CO combined with two sources of feedstock and fuel2Must be removed quickly to reduce CO in the calcination process2Partial pressure increase of calcination released CO2Efficiency, and the normal operation of the biomass gas hot blast stove is maintained.|[0029] In the present invention, CaO + H is digested by quicklime2O→Ca(OH)2Delta H < 0 and calcium hydroxide Ca (OH) carboxylated2+CO2→CaCO3Both ↓ + H2O < delta H > are exothermic reactions. Because of the conservation of energy and conservation of material, those skilled in the art, even scientists, produce CaCO from light calcium carbonate3→CaO+CO2To CaO + H2O→Ca(OH)2To Ca (OH)2+CO2→CaCO3Chemical formula, only the light calcium carbonate raw material is seen to be the same as the chemical formula of the final product, CO2The material is equally fed in and out on the molecular formula in the production of the light calcium carbonate; especially the production of heavy calcium carbonate, has no CO at all2The material enters and exits the production process. Therefore, the temperature of the molten metal is controlled,those skilled in the art will recognize, even scientists, that inertial thinking only holds, CO2The material is carbon balanced before and after the production of the light calcium carbonate and can not generate CO to the atmosphere2What effect the total amount has. What the average person does not think of is CO2Carbon balance process of equal quantity and one inlet and one outlet in light calcium carbonate production of substances for atmospheric CO2The total emissions may lead to potential negative carbon emission technology utilization scenarios.|[0030] In the invention, if biomass energy is not used for completely replacing fossil energy, the production of light calcium carbonate can generate artificial activities to cause atmospheric CO2Increased total carbon emissions. CO released from fossil fuel in light calcium carbonate production2About 35% of the total carbon emission, which is part of the CO energy2The emission is regulated according to the source category of 'energy' in volume 2 of '2006 IPCC guideline', and the emission needs to be measured and accounted to enter a national greenhouse gas list; and the CO released by calcining the raw calcium carbonate ore accounts for about 44 percent of the mass of the raw calcium carbonate ore2Is recycled for the back end carbonation production process, CO2The material is equally discharged and fed in the industrial process of calcium carbonate production, and the total carbon amount in the industrial process is balanced. Thus, the carbon emissions from light calcium carbonate production are only CO metered and accounted for in fossil fuels2And (4) discharging the amount. This is completely different from the carbon emission mechanism of cement production, which does not have CO in the cement production process2The recycling process and mechanism, therefore, the carbon capture, utilization and sealing can be artificially carried out by human beings by adopting the cement CCUS technology. Volume 3 of the 2006 IPCC guideline "industrial process and product usage" regulations "in certain IPPU categories, especially large point emission sources, can capture emissions for recycling or removal. It is a good practice to consider emissions capture using detailed country-specific or more appropriate enterprise-level data. "," Add Capture to formula by adding other terms in formula representing observed quantity of Capture or efficiency of emission reduction System in conjunction with annual System usage "" "whether CO should be installed and deployed in Enterprise2Capture technique, preferably by deducting captured CO in high-level process emission calculations2"" other than on List consider CO2Emission of CO for later use2Amount and short term storage should not be from CO2Deducting the discharge. The default assumption is that carbon dioxide capture and storage (CCS) is not employed. Considering CO2Any method of capture should take into account the CO captured in the process2Emissions may be related to both combustion and process. If combustion and process emissions are reported separately, the inventory maker should ensure that the CO is present2The same number of (a) is not counted twice. In these cases, the captured CO2The total amount should best be reported in the respective fuel combustion and the CO generated in these source classes should be taken into account2The volume ratios are reported in the IPPU source category. "|[0031] In the invention, globally recognized zero-carbon biomass energy is used for completely replacing fossil energy, and the production of light calcium carbonate can generate CO influencing the atmosphere2Reduced total CO2Negative discharge effect. CO released by biomass fuel in light calcium carbonate production2With CO liberated from calcium carbonate ore raw material2Is recycled for the production of carbonation, is combined into a part of calcium carbonate final industrial product, and absorbs CO from the atmosphere in the process of biomass (plant) growth2The CO is permanently fixed and sealed in the final industrial product of the light calcium carbonate through an industrialized process to realize the separation of CO2CO removal from the atmosphere2Negative discharge effect.|[0032] In the invention, because the chemical change of the light calcium carbonate industrial production is only in the molecule and atom level, the nuclear polymerization change of the C atomic nucleus is not involved, and the total amount of the C elements of the light calcium carbonate raw material and the final industrial product is not changed, thus the light calcium carbonate is in material balance. The carbon material balance mechanism in the industrial production process of the light calcium carbonate is as follows: the carbon element added by the combustion of the biomass fuel is respectively distributed in accessory products produced by light calcium carbonate such as carbon-containing compounds, mixtures and the like in a gas-solid state and a liquid state at different stages of the industrial production process: such as CaCO3、MgCO3、CaMg(CO3)2、MnCO3And hydrocarbons such as tar, carbohydrates and CO gas (CO)2Reduction reaction of CO2+ C → 2CO product), calcium bicarbonate Ca (HCO) (hard water), H carbonate2CO3(CO2Dissolving in water to generate CO carbonate2+H2O==H2CO3) And other carbon compounds (such as greenhouse gas CO) that escape or are discharged to the atmosphere, surface, and water during production2Emissions and other carbon compounds and mixture emissions, etc.). The carbon balance process is essentially atmospheric CO2Carbon sink absorption due to biomass growth → CO release by biomass energy utilization2→ recovery and utilization of CO by carbon capture in industrial production process of calcium carbonate2→ C element with CO2Or other carbonate and carbon compound mixture forms, and is fixedly sealed in the light calcium carbonate product and other by-product products in the production process thereof in the carbonation process. Therefore, the production process of the biomass energy light calcium carbonate is essentially a negative carbon emission process for industrially fixing the carbon element of the biomass energy (wherein CO dissipated into the atmosphere in the production process2Equal greenhouse gases, carbon footprint must be metered and accounted, and part of the negative carbon emission reduction amount generated by the invention is offset and deducted), namely, part of CO in the atmosphere is removed through plant carbon sink and the industrial production process2Removed and permanently fixed in the precipitated calcium carbonate product and other non-greenhouse gas adjuncts.|[0033] In the invention, because other non-greenhouse gas by-product products must exist in the production process of the light calcium carbonate, the total amount of the by-product products is generally equivalent to 20-30% of the yield of the light calcium carbonate. Among them, some by-product products (such as CO, etc.) will form CO in future2Finally discharged into the atmosphere, according to the '2006 IPCC guideline', the CO in the industrial process returning to the atmosphere in the future must be measured and accounted2Carbon footprint emissions, and inclusion in the IPPU Source Category into the national greenhouse gas emissions List, which must be derived from the Biomass energy CO2Deducting the negative discharge amount; most of carbon element contained in by-product is permanently fixed and sealed in inert carbonate, and no CO is formed in future2Nor enter the atmosphere to increase the total greenhouse gas. CO in the industrial production of light calcium carbonate because of the inexhaustible substances2Negative emissions, can never be zero. Using living organismsCO for producing light calcium carbonate by using mass energy2Negative emission, effect and effect of eliminating greenhouse gases in the atmosphere are absolute, and CO can be generated by different biomass energy and light calcium carbonate production technologies and equipment2The difference between the negative carbon emission and the purge amount.|[0034] In the present invention, CO2The measurement and accounting of negative emissions are very similar to the basic emissions calculations of all carbonate combustion industries, based on molecular weight and CO, which are common, according to the "IPCC guideline 2006, volume 3" Industrial Process and product usage-Chapter 2 mining industry carbon emissions "regulations2Ratio of, wherein, CaCO3(Calcite or aragonite) emission factor (ton CO)2Carbonate per ton) 0.43971, MgCO3Magnesite emission factor 0.52197, CaMg (CO)3)2Dolomite emission factor 0.47732, FeCO3Siderite emission factor 0.37987, Ca (Fe, Mg, Mn) (CO)3)2Iron dolomite emission factor 0.40822-0.47572, MnCO3Rhodochrosite discharge factor 0.38286, Na2CO3Sodium carbonate or soda ash discharge factor 0.41492. "chapter 2 mining industry carbon emissions-2.3 lime production" stipulates that the production of lime involves a series of steps including raw material collection, crushing and sizing and calcining the raw material to produce quicklime and, if necessary, hydrating the lime to calcium hydroxide. Consumption of lime products does not result in CO under certain conditions2Is discharged to the atmosphere. For example, slaked lime used in water softening produces CO2React with lime to reform calcium carbonate without generating CO2Net venting to the atmosphere. Similarly, precipitated calcium carbonates for use in the paper industry and other industrial applications are hydrated high calcium quicklime with CO2Generated by the reaction; in the sugar manufacturing process, lime is used to remove impurities from the raw sugarcane juice, and any excess lime can be removed by carbonation. Only the validated and verified method was used to calculate the CO which reacts with lime to reform calcium carbonate2The amount, any recarbonization process in these particular industries can be calculated and reported. When these conditions are met, it can be reported under category 2H "other". Lime Kiln Dust (LKD) generation during lime production, methods of use 2 and methodsThe emissions estimate from method 3 should take into account the emissions associated with LKD. "|[0035] In the invention, the biomass energy is globally recognized zero-carbon energy, and CO generated by biomass energy utilization and not counted in the total amount of emission of greenhouse gases in the atmosphere2Removed from the atmosphere and permanently fixed in the final industrial product light calcium carbonate and its by-products, BECCU and biomass power plant BECCS or BioCCS on CO2The cleaning effect of (a) is the same. The measurement and accounting of greenhouse gas carbon emission in light calcium carbonate production follows the IPCC guideline of 2006 and related methodology, wherein, in addition to the first range of biomass energy utilization negative carbon emission measurement and accounting, carbon footprints such as outsourcing electric power and other energy sources (second range) and enterprise personnel activity carbon emission (third range) in light calcium carbonate industrial production are not included in the energy boundary range of the first range and the CCUS technical field involved in the invention, but belong to another technical field and the greenhouse gas emission measurement accounting subject matter.|[0036] In the present invention, CO2The negative emission is measured and calculated according to '2006 IPCC guideline': 1. volume 2 "energy" 2.3.4 carbon dioxide capture "since this is a new emerging technology, it requires plant specific method 3 reporting. The capture and storage plant will most likely meter the amount of gas removed by the gas stream and diverted to geological storage. "," if biofuel is supplied to the plant, the corresponding CO2Emissions will be zero and therefore, subtracting the amount of gas transferred to long term storage gives negative emissions. As a result, CO2Transport, CO2Subsequent emissions from the injection and storage itself should account for the total emissions of the country, whether the carbon originates from a fossil source or is produced by the recent biomass, and subsequent emissions (CO for later use and short-term storage2) Should not be from CO2Deduction in emissions unless CO2 emissions are counted elsewhere in the list [ e.g. CO in urea production (Vol. 3, section 3.2) and methanol production2Volume 3, section 3.9, in which the CO due to the final product should be taken into account2Emission later). 2. Volume 4 AFOLU "agroforestry and other land utilization" Chapter 4 "Biomass Combustion generated CO2Emissions are not included in the countryThe total amount of greenhouse gases, but is recorded as an item of information for cross-check purposes and to avoid recalculation. "|[0037] In the invention, the estimation of greenhouse gas emission in the production of light calcium carbonate by using biomass energy is carried out by adopting a method 3 of '2006 IPCC guideline' to carry out CO2It is estimated that the present invention utilizes biomass energy to produce light calcium carbonate first range (industrial process and energy use) CO2The negative carbon emission measurement and accounting model is as follows: BECCU CO2DischargingSourceProduction ofSource-capturingSourceNamely, the estimation formula:|[0038] |[0039] in the present invention, FIG. 1 is a schematic illustration of a process diagram of biomass energy utilization with negative carbon emission, which illustrates BECCU CO in detail2DischargingSourceWhy it must be negative (i.e. BECCU CO)2DischargingSourceMust be CO2Negative emissions). The inventor organizes strength development or jointly develops BECCU CO according to the invention and the cooperation of the Chinese environmental science society and the Chinese energy-saving society2The negative emission related methodology applies for the approval of the national climate change department and the approval of IPCC record, and develops or jointly develops the CCUS related group standard such as carbon dioxide capture utilization sealing-BECCU industrialized negative carbon emission standard with the Chinese environmental science society and the Chinese energy-saving society.|DRAWINGS DESCRIPTION|[0040] FIG. 1 is a process diagram of a biomass energy utilization negative carbon emission process;|[0041] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate;|[0042] FIG. 3 is a view showing the structure of a carbonator in a carbon dioxide utilizing process apparatus.|[0043] The reference numbers in the drawings of the specification are as follows:|[0044] 1. a support; 2. a kiln gas inlet; 3. a refined lime milk inlet; 4. an exhaust cap; 5. adding a phosphoric acid port; 6. an overflow port; 7. a gas distribution cover; 8. a withdrawal notch; 9. and (5) discharging the cooked pulp.|INVENTION MODE|Detailed Description|[0045] The concrete description is as follows:|[0046] FIG. 1 is a process diagram of negative carbon emission process for biomass energy utilization|[0047] Production of light calcium carbonate CO by using biomass energy2The negative emission process and principle are illustrated as follows according to the steps shown in FIG. 1:|[0048] 1. the biomass limestone calcining process is that biomass briquette fuel is used to replace anthracite and limestone in a layer combustion mixing mode for industrial direct combustion at about 1000 deg.c, and during calcining, partial biomass gas produced through pyrolysis and gasification may be supplemented as required to regulate and control the temperature, combustion condition and calcining atmosphere in the calcining kiln. The process product for producing quick lime by calcining limestone with biomass comprises the following steps:|[0049] (1)、CO2discharging: c + O2→2CO2、CaCO3→CaO+CO2Releasing CO2Wherein the emission of biomass IPPU source type (fuel) in 2006 IPCC guideline is zero, and the emission of the IPPU source type (raw material) CO in the limestone industrial process2Emission default emission factor (CO per ton lime)2Tonnage) high calcium lime 0.75, dolomitic lime 0.86 or 0.77, hydraulic lime 0.59;|[0050] (2) CaO, which accounts for about 56 percent of the mass of the limestone raw material;|[0051] (3) screening lime ash, wherein carbon-containing compound carbonate or carbon-containing mixture is removed from the lime ash, and a byproduct carbon element needs to be metered and calculated in a biomass energy utilization negative carbon emission process;|[0052] (4) lime kiln gas (CO)2Other impurities in the biomass energy utilization negative carbon emission process, which contain carbon compounds, carbonates or carbon-containing mixtures, and need to measure and account for the removal of the waste gas of the byproduct carbon element;|[0053] (5) the kiln gas dissipated CO accounts for about 1.69 percent (about 1.42 percent) of the total volume fraction of the kiln gas, and the carbon footprint of the kiln gas dissipated by-product is measured and calculated to calculate CO2Then discharging the amount;|[0054] (6) dust emission CO of lime kiln2Discharging: the amount of Lime Kiln Dust (LKD) generation from the 2006 IPCC guideline depends on the type of lime kiln used and the carbonate characteristics used, with an average shaft kiln producing 9% to 10% dust loss per 1 ton of lime and a raw material feed loss of 16% to 18%. The chemical composition of LKD varies from raw material feed to raw material feed, typically high calcium lime LKD may contain 75% combined calcium oxide and uncalcined calcium carbonate, the remaining impurities are silica, alumina and iron oxides and sulfur (depending on the fuel used), data is collected regarding the typical ratio of LKD to lime production and typical composition of LKD, and in the absence of data, 2% corrective additions can be assumed to account for LKD (i.e., 1.02 CO2Discharge); the vertical axis furnace produces a relatively small amount of LKD, and the LKD correction factor from the vertical axis furnace is determined to be negligible and not necessarily estimated. Method 3 advantageously collects specific data on the weight proportion of carbonate consumed by lime production and the proportion achieved by calcination in each plant, and also collects data on the amount (dry weight) and composition of LKD produced. Similar to method 3 for cement production, the emissions of LKD should be subtracted from the estimate of method 3.|[0055] 2. A biomass pyrolysis gasification process, wherein a biomass gasification furnace mainly supplies heat for a precipitated calcium carbonate (light calcium carbonate) drying process, and can also supply biomass fuel gas for a lime kiln according to needs, and main products after biomass gasification are as follows:|[0056] (1) biomass combustible gas: 20-25% of CO and H in parts by volume28-10%、CH42-4%、CmHn(C2H6、C2H4、C2H2、C3H6、C3H8Etc.) 0.8, etc. The biomass fuel has different components.|[0057] (2) Carbon dioxide: CO22:8-15%;|[0058] (3) Nitrogen gas: n is a radical of246%-56%;|[0059] (4) Oxygen: o is20.5%-1.5%;|[0060] (5) Ash residue: accounting for 5-8% of the total amount of the biomass fuel, and metering and accounting for ash and slag removal of carbon elements of byproducts such as hydrocarbons and the like in the biomass energy utilization negative carbon emission process.|[0061] 3、CO2Collecting and purifying process, CO in kiln gas for calcining limestone by biomass2And CO in the heat supply flue gas generated by biomass gasification combustion2After being collected and recovered, the kiln gas and the flue gas are purified and can be applied to a subsequent carbonation process, the kiln gas and the flue gas are mixed and are subjected to cyclone dust removal, water washing, tar adsorption and sewage treatment, carbon-containing compound carbonate, other hydrocarbons, carbohydrate or carbon-containing mixture ash, tar, sewage sludge and the like are added, and in the biomass energy utilization negative carbon emission process, the CO is measured and calculated2Removing carbon element as by-product in the purification treatment process.|[0062] 4. Quicklime slaking process, CaO + H2O→Ca(OH)2The intermediate product, namely hydrated lime does not relate to the problem of carbon emission, but about 5 percent of waste residues in the digestion process, the carbonate or the carbon-containing mixture of the waste residues, needs to be metered and counted to remove the waste residues of the carbon element of the byproduct in the biomass energy utilization negative carbon emission process.|[0063] 5、CO2Industrial utilization process of CO from limestone calcination decomposition and biomass energy utilization2After purification treatment, in CO2Industrial utilization device of carbonization tower and slaked lime Ca (OH)2Performing carbonation reaction to generate stable carbonate such as calcium carbonate, wherein CO is derived from biomass energy2Is permanently fixed and sealed in stable carbonate industrial products and byproducts such as light calcium carbonate and the like by industrialization and is permanently eliminated from a biomass plant carbon library (processed in AFOLU department according to AFOLU 4 chapter 4 source category of IPCC guideline 2006, agriculture and forestry and other land utilization, which is incorporated into the total amount of greenhouse gas emission of China). In the process of utilizing biomass energy and discharging negative carbon, the CO of the carbonization tower needs to be metered and accounted2CO in industrial utilization2The carbon element which is a byproduct in the tail gas emission of the dissipation and carbonization tower is removed.|[0064] 6. Drying and processing technology of precipitated calcium carbonate (light calcium carbonate), biomass gasification combustion heat supply precipitated calcium carbonate drying processing technology, biomassGas combustion of C + O2→CO2Releasing CO2The flue gas is recycled without metering and accounting carbon footprint emission, but CO is dissipated when the biomass gas hot blast stove is combusted2CO and other carbon-containing substances for drying and processing precipitated calcium carbonate, the process dissipation and processing of impurities, and carbon-containing compound carbonate or carbon-containing mixture, in the biomass energy utilization negative carbon emission process, the removal of by-products, such as the drying process dissipation and processing of impurities, and the like, need to be metered and accounted.|[0065] 7. The negative emission process principle for producing light calcium carbonate by using biomass energy is described as follows by integrating the 6 production process flows:|[0066] (1) the biomass carbon element comes from the absorption of CO from the atmosphere and the soil carbon reservoir in the plant growth process2Water, nitrogen, inorganic and trace elements (ash: Ca, K, P, Mg, Si, Al, Ba, Fe, Ti, Na, Mn, Sr), and forming carbohydrate polymer cellulose, hemicellulose and lignin as main components through photosynthesis, including carbohydrates such as starch, protein, lipid, hydrocarbons, etc., and hydrocarbon organic matters. The carbon element of the biomass adopts a chemical structural formula (C)6H10O5)nGlucose trielement polymer (carbon 44.44% hydrogen 6.17% oxygen 49.39%) is the main carbohydrate form, and is fixedly sealed in the carbon pool and the carbon pool of the earth biomass.|[0067] (2) In the carbon pool and carbon pond of the biomass on the earth, the lignin content of woody plants is 20% -35%, and herbaceous plants are 15% -25%, which are the second major renewable biomass resource next to cellulose, and the biomass generates about 6 multiplied by 10 every year on the world14Tons of native lignin, with an incremental production of 1600 million tons/year. The initial strong thermal decomposition temperature of cellulose is 280-290 ℃, the thermal decomposition temperature of lignin is 350-450 ℃, the carbon content of lignin is 55-65%, the complex aromatic structure and the thermal stability are high, and the effective utilization is not achieved at present. In the last hundred years of 1930, the practice of human research on lignin proves that pyrolysis is the only feasible technical route for large-scale industrialization, and the lignin is decomposed at high temperature by insulating air to obtain charcoal, tar, wood vinegar and biogas: about 50.9% of CO,CH4about 37.5% CO2About 9.6%, and ethylene and other saturated hydrocarbons about 2.0%. The combustion heat value of the lignin is high, the combustion heat of the ash-free spruce picric lignin is 110kJ/g, and the combustion heat of the lignin sulfate is l09.6kJ/g.|[0068] (3) The human industrialized large-scale exploitation utilizes fossil energy such as underground carbon depot coal, petroleum and natural gas, and the like to cause climate change, and international laws such as climate change frame convention of United nations, Jingdu protocol, Paris convention and the like, and specialized organization IPCC of gasification change of the United nations promote the human energy to utilize renewable energy such as solar energy, wind energy, water energy, biomass energy and the like from underground to ground.|[0069] In order to eliminate the inevitable carbon emission in the industrial production processes of electric power, steel, cement building materials, metallurgy, chemical industry and the like and realize the aim of coping with climate change, IPCC (2005) ' carbon dioxide capture and storage special report ' (SRCCS) and ' 2006 IPCC guideline ' clearly propose the technical route of biomass energy utilization (biomass power plant) negative carbon emission ' for any other types (such as CO, power plant) selected for storage2Marine storage or conversion to inert inorganic carbonates) does not provide an emission estimation method. With the exception of mineral carbonisation of certain waste materials, these techniques are in the research phase, not the demonstration or later stages of development of the IPCC (2005) technique. If they reach late in development, emission inventory guidelines generated by these techniques may be compiled and presented in future revisions of the guidelines. "anthropogenic carbon dioxide emissions originate mainly from the combustion of fossil fuels (and biomass) in the power generation, industrial, construction and transportation sectors. CO22And also in certain industrial processes (such as cement manufacture, natural gas processing, and hydrogen production) non-combustion sources. Power plants and other large industrial facilities are CO2The main candidate for capture, a common deployment of the prior art, can capture about 85% -95% CO (processed by IPCC capture plants)2. ", SRCCS provides in its FIG. 5.2 an overview of the relevant processes for pre-combustion capture, post-combustion capture, capture of oxygenated fuel and capture of industrial processes". As already mentioned in some industrial processes, the chemical reaction causes CO2The formed quantity and concentration can directly capture or separate CO from the flue gas2. If it captures the raw meatCO produced by combustion of substances2Negative emissions may result from the capture and compression system. The invention utilizes biomass energy to produce light calcium carbonate (precipitated calcium carbonate), and BECCU belongs to the CO of the 2006 IPCC guideline2Technical innovation (CO) under the framework of negative emission overall technical route2Conversion to inert inorganic carbonates), there is currently no established negative emission estimation method for BECCU, the present invention is intended to develop BECCU CO2Negative emission estimation methodology, according to method 3 of the 2006 IPCC guideline, CO (input carbonate based approach), CO2Negative emission estimation model: BECCU CO2DischargingSourceProduction ofSource-capturingSourceThe negative emission process measurement accounting formula is as follows:|[0070] |[0071] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0072] (4) Description of the Process principles for negative carbon emissions|[0073] In the above-mentioned CO2In the negative-emission estimation model, the exhaust gas is,is BECCU CO2And (4) estimating the emission (positive number is positive emission, and negative number is negative emission), wherein a is energy and b is a light calcium carbonate production raw material.Wherein,as a source of energySource classDischarging the waste water, and discharging the waste water,as raw material for industrial processesSource classDischarging the waste water, and discharging the waste water,capturing benefits for carbonation processesWith CO2Atmospheric CO directly eliminated2The emission amount and CO converted by carbon elements contained in the hydrocarbon, carbohydrate liquid and the like such as the inert inorganic carbonate solid and tar which are byproducts of the whole process of industrial production (greenhouse gas emission is not formed in the future)2Indirectly reducing the displacement.|[0074] Further:|[0075] |[0076] (carbon dioxide capture according to "energy" 2.3.4, volume 2, IPCC guideline 2006).|[0077] |[0078] (emission from 2.3 lime production formula 2.7 method 3: emission based on carbonate feed according to Chapter 2 mining industries, volume 3, guide IPCC 2006).|[0079] Wherein, CO2CO emissions from lime production2Discharge in tons|[0080] Emission factor of EFn carbonate n, ton CO2Carbonate per ton|[0081] Mn-consumed carbonate n weight or mass in tons|[0082] Calcining Fn ═ the ratio obtained in carbonate n, the ratio|[0083] Weight and mass of Md-LKD in tons|[0084] Cd is the weight ratio of original carbonate in LKD|[0085] Fd-calcination ratio achieved for LKD, part|[0086] EFd is the emission factor of uncalcined carbonate in LKD, ton CO2Per ton of carbonate.|[0087] |[0088] (according to the '2006 IPCC guideline' and IPCC 2005 'Special report on carbon dioxide Capture and storage' SRCCS)|[0089] Wherein d represents the subsequent discharge amount of greenhouse gases possibly generated in the future in the industrial production of light calcium carbonate, and in the whole production process of precipitated calcium carbonate, part of the dissipated gases which are not captured and utilized by the carbonation process can form CO in the future2Or non-CO2Greenhouse gases, which are subsequently emitted in this part, must be included in the national greenhouse gas list according to the 2006 IPCC guideline, and cannot be deducted from the emission reduction. The method comprises the following steps:|[0090] d 1: indicating subsequent emission of CO|[0091] d 2: represents CH4Then discharged|[0092] d 3: represents H2CO3And so on for subsequent discharge.|[0093] e represents the byproduct of the whole process of industrial production of precipitated calcium carbonate (i.e. the process waste material shown in figure 1), including inert inorganic carbonate solid (excluding non-calcined carbonate in LKD) and carbon-hydrogen such as tar, and indirect CO converted from carbon element fixed in the industrial byproduct for a long time (which will not naturally form greenhouse gas emission in the future)2Capture utilization reduction (indirect carbon capture) comprising:|[0094] e1 denotes inert inorganic carbonates, CaCO3、MgCO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2Etc. of|[0095] e2 represents indirect CO such as liquid hydrocarbon, carbohydrate tar, wood vinegar, lignin (black liquor), etc2The emission reduction amount of the capture and utilization is not as stable as that of the inert inorganic carbonate solid, and the part can be industrially recycled, but does not naturally form greenhouse gas emission.|[0096] Further:|[0097] |[0098] further:|[0099] the industrial production of the light calcium carbonate only chemically changes on the molecular and atomic level, does not relate to the nuclear polymerization change of C element atomic nucleus, does not change the total amount of C elements of the light calcium carbonate raw material and the final industrial product, and is balanced by C substances; and the total content of the C element of the biomass a, the total content of the C element of the subsequent emission d and the total content of the C element of the industrial byproduct e are also in balance of the C substance, and the total content of the C element is not changed in the industrial production.|[0100] Due to the law of constant substances, as long as industrial production is carried out, an industrial production byproduct e (namely the process waste shown in figure 1) is always present,is also certain to exist and can never be zero; particularly in industrial production, the emission of CO and other greenhouse gases dissipated in the process only accounts for about 1.69 percent (about 1.42 percent by mass) of the total volume of the kiln gas and the flue gas, and the emission proportion is very small and is far smaller than that of CO generated by biomass combustion2The total amount of material, and therefore,|[0101] in conclusion, in the production process for producing light calcium carbonate by comprehensively replacing fossil energy with biomass energy as shown in fig. 1, due to the law of constant substances, in the BECCU process technology,and isThe presence of the (C) is determined,BECCU CO2dischargingSourceMust be negative in emission, and absorb CO from the atmosphere in the process of plant growth2CO fixed in biomass carbon reservoir by carbon sink effect2And is permanently sealed in the final industrial product of the light calcium carbonate through an industrial production process.|[0102] FIG. 2 is a flow chart of a production process of biomass energy light calcium carbonate|[0103] In the description of the attached figure 1, the processes of calcining, biomass pyrolysis gasification and CO production for producing light calcium carbonate by using biomass energy sources2Collecting and purifying, slaking quicklime, Ca (OH)2Six processes, such as carbonation and calcium carbonate drying, have been described in detail and are not described again.|[0104] FIG. 3 is a view showing a structure of a carbonator in a carbon dioxide utilizing process apparatus|[0105] Ca(OH)2And collecting, purifying and compressing the treated CO2Calcium carbonate is generated in a carbonization tower through reaction, and the carbonization tower is CO2The core equipment of the utilization and carbonation process is that the carbonation reaction equation is Ca (OH)2+CO2→CaCO3. FIG. 3 is a view showing the most simple structure of a carbonization tower in which Ca (OH) from a mature slurry aging tank is used2The fine slurry emulsion enters the carbonization tower from a fine ash emulsion inlet 3 shown in the figure and enters the carbonization tower from CO from a kiln gas inlet 2 shown in the figure2Collecting CO from purification and compression process2Carrying out carbonation reaction to generate calcium carbonate; the main function of the 7-gas-dividing hood shown in the figure is to disperse CO2Realization of CO2Distributing the materials evenly, wherein the generated calcium carbonate product is collected by a boiled slurry tank through a boiled slurry outlet 9 shown in the figure and then is aged in a boiled slurry aging tank; the carbonization tower is provided with 6 overflow ports for controlling the height and pressure of the liquid level, and is also provided with a carbonization reaction impurity 8 extraction notch and a carbonization reaction tail gas outlet 4 exhaust cap for exhausting, and a phosphoric acid adding port 5 shown in the figure is mainly used for adding blending auxiliary materials such as phosphoric acid and the like and used for adjusting performance indexes such as whiteness, activity and the like of a calcium carbonate product.|[0106] It must be noted that the carbonizer is CO2The key core equipment of the process is utilized, the carbonation process is one of the key processes for determining the quality of the final product of the light calcium carbonate, such as the granule, the crystal form and the like, the core of the invention is to provide the method for utilizing the biomass energyCO production of light calcium carbonate2The negative discharge technique and method, fig. 3 is only the simplest and most common carbonator structure selected for the convenience of illustrating the carbonation process, and is not intended to limit the carbonation process and apparatus used in the present invention. In fact, the prior art of the carbonation process has various selectable technical processes, including an intermittent bubbling carbonation method, a continuous spray carbonation method, a hypergravity reaction crystallization method and the like, which can be selected to implement the method, and the CO production by the light calcium carbonate of the method can be realized2The purpose of negative discharge technology. Therefore, the invention can be applied to any carbonation process undoubtedly without enumerating and carbonizing process technology and equipment, and any method adopting the invention to replace fossil energy with biomass energy to produce light calcium carbonate and collect and utilize CO2Realization of CO2The purpose of the negative emission technique is within the scope of the present invention.|[0107] Detailed Description|[0108] The inventor deeply recognizes the high-technology high-added-value clean utilization of biomass energy and gradually replaces fossil energy in scientific and technological innovation and industrial innovation practices of the world biomass energy technology in the field of biomass energy utilization for decades at the forefront, and is one of fundamental countermeasures for solving the climate change crisis caused by the unregulated use of human fossil energy; particularly over a decade ago, the inventors discovered the greenhouse gas CO2Not only from the fields of fossil energy, traditional and novel building materials such as building material cement, calcium carbonate, lithium carbonate and the like, chemical engineering, new materials and the like, but also the used main raw materials such as calcium carbonate and the like are greenhouse gas CO2One of the main sources of (1). Based on the important discovery, the inventor is closely cooperated with domestic authoritative scientific research institutions, industrial design institutions, head enterprises of international and domestic related industries and the like, timely masters the latest international dynamic trend, concentrates all efforts, focuses on the zero-carbon-emission biomass energy efficient clean utilization technology for replacing fossil energy, and carries out original scientific research and development, new technology and new product process technology.|[0109] In recent years, the inventor obtains a plurality of major technical breakthroughs in the new technical fields of developing new materials, such as low-carbon zero-carbon cement building materials, calcium carbonate, lithium carbonate and the like, new technologies, new products coping with climate change, realizing carbon peak-reaching carbon neutralization and the like by replacing fossil energy technologies with biomass energy in an efficient and clean manner, particularly applying the most advanced mature biomass energy technology to the related fields of calcium carbonate to replace fossil energy, and forming one of a series of major original technical achievements.|[0110] The invention relates to industrialized carbon capture and permanent CO sequestration by using carbonate industrial products2The implementation range of the negative carbon emission process technology is not limited to the production of light calcium carbonate, namely a carbonate product, and the technical method can be widely applied to the technical fields of various carbonate industrial negative carbon emission and zero-carbon and low-carbon emission, such as various products of cement, white cement, lithium carbonate and the like, after being subjected to adaptive improvement. Therefore, the following examples of the present invention are not intended to limit the scope of the present invention, and any person skilled in the art can make modifications or variations without departing from the technical scope of the present invention, such as the production of various carbonate products such as calcium carbonate, lithium carbonate and tricalcium silicate and other portland cement products by using the technology of the present invention, i.e. all the biomass energy sources are used to replace fossil energy sources (regardless of the substitution rate or whether biomass gasification technology or biomass fuel industrial direct combustion technology is used) and CO is used in the production of light calcium carbonate according to the present invention2The collection and utilization technology integrates the two technologies (including the carbon capture and utilization technology and the industrialized sequestration technology of the CCUS) into a new technology, so as to achieve the purpose and effect of industrialized negative carbon emission, and the scope of the invention is covered by the invention of the technology.|[0111] The embodiment of the invention comprises the following steps: and 10000t/a light calcium carbonate produced annually by using biomass energy instead of fossil energy is used as an embodiment for negative carbon emission.|[0112] 1. The production process design:|[0113] (1) production capacity: 10000 ton/year, production time: 300 days/year, production safety guarantee coefficient: 1.15, daily productivity: 33.33 tons/day, considering the safety factor of 38.33 tons/day, 1.6 tons/hour;|[0114] (2) the production method comprises the following steps: direct combustion of GaCO by using vertical kiln biomass wood chips3A production process of an intermittent bubble carbonization tower;|[0115] (3) each workerThe process yield is as follows: calcining limestone: considering the factors of over-burning and under-burning of limestone, the conversion rate of the limestone is 95 percent, and GaCO in the limestone3The content is 97 percent, the loss in the calcining and conveying process is 3 percent, and the total yield in the process is 95 percent multiplied by 97 percent and 89.31 percent;|[0116] the yield of slaked lime and refined hydrated lime is 98 percent;|[0117] and (3) carbonation process: usually CO2Feeding in excess, wherein 99% of lime refined emulsion can be taken as complete reaction;|[0118] and (3) post-treatment procedures such as product dehydration and drying: centrifugally dewatering, and removing about 1-2% of calcium carbonate along with filtrate, wherein the part can be returned to a digester for recycling, and the yield of the part is considered to be 99%; the drying yield is 99%; the operation yield of screening, packaging and the like is 99 percent, and the total yield of the light calcium carbonate is as follows: 89.31% x 93% x 99% x 99% x 99% x 84.08%.|[0119] (4) Consumption of raw materials: limestone ore consumption: 38.33/84.08% ═ 45.59 ton/day, 1.90 ton/hour limestone calcination material measured as 38.33t/d, lime kiln feed: limestone 16 ÷ 0.8263 ÷ 19.36kmol/h ═ 1936kg/h, where: GaCO3Content 97%, 1877.92kg/h MgCO3Content 1.2%, 23.23kg/H, H2The O content is 0.5 percent and 9.68kg/h, and the impurity contents of FE, Mn, Al and the like are 1.3 percent and 25.17 kg/h.|[0120] (5) Biomass fuel consumption: the heat value of the mixed wood biomass briquette fuel or the high-quality biomass particle briquette fuel is 3000-4000 kilocalories, the limestone calcination of the embodiment uses the biomass fuel to be directly combusted (biomass pyrolysis gasification biomass gas can be used for calcination), the drying process uses the biomass pyrolysis gas, the biomass fuel is calculated by 30% of the feeding amount of the limestone, the drying process is equivalent to the biomass consumption of the calcination process, and the two processes are 1936 x 0.30, 580.80kg/h and 2428766208kg/a in total, wherein:|[0121] |[0122] |[0123] low calorific value 16302KJ/Kg|[0124] (6) And (3) quicklime yield: the CaO amount is 19.36 x 0.97 x 0.95 x 56 ═ 999.05kg/h, the unreacted calcium carbonate ore amount is estimated to be 19.36 x 0.97 x 0.05 x 100 ═ 93.1kg/h, the MgO amount is 23.23 ÷ 84 x 40 ÷ 11.06kg/h, the total impurity by-product amount is 25.17+18.59 ═ 43.76kg/h, and the quick lime discharge amount G is 999.05+93.1+11.06+43.76 ═ 1147.77 kg/h.|[0125] (7)CO2Production amount: CaCO3CO obtained by decomposition2Quantity: 1936/100 x 0.97 x 0.95 x 44 ═ 784.97kg/h, prepared from MgCO3CO obtained by decomposition2Quantity: 23.23/84 x 44 is 12.17kg/h, and according to experience, the CO content is about 1.7% of the kiln gas amount, the CO content is 39kg/h, and the CO is consumed2Amount 39 ÷ (consumption 2 x 28) x 44 x 2 ═ 61.28kg/h, substance C consumption: 39 ÷ (2 x 28) x 12 x 2 ═ 16.72kg/h, 21.90kg/h calculated by biomass ash accounting for 8% of the total carbon content of the biomass, and CO produced by the biomass2Quantity: (273.79-16.72-21.90) ÷ 12 x 44 ═ 862.29kg/h, this example was not metered due to the presence of byproducts of the calcination process, and the biomass CO actually produced was not present in the amount2The amount is slightly less than the data;|[0126] CO-generation of CO2Total amount: sigma CO2At 784.97+12.17+862.29-61.28 at 1598.15kg/h, the present example was not metered due to the presence of byproducts of the calcination process, and actually produced CO2The total amount is slightly less than the data.|[0127] 2. Negative carbon emission estimation of the embodiment:|[0128] to ensure that the carbonation process proceeded smoothly, this example employed an excess of CO2Production Process, CO2Besides reacting with slaked lime fine milk to produce light calcium carbonate target product, it also reacts with water, calcium carbonate and other carbonates to produce various carbon-containing compounds and mixtures.|[0129] In the course of producing light calcium carbonate, the by-products are respectively made up by using solid inert carbonate, liquid hydrocarbon material, carbohydrate tar, wood vinegar, lignin (black liquor) and gas CO2、CH4And CO and the like and the subsequent emission form of greenhouse gases are distributed in each productionIn links and environments: such as CaCO3、H2CO3、CaMg(CO3)2、FeCO3、MnCO3、Na2CO3、Ca(HCO)、Ca(Fe,Mg,Mn)(CO3)2And the like.|[0130] The annual negative carbon emission of this example is estimated as follows:|[0131] (1) dissipation was estimated as 2%: sigma CO2=1598.15 x 24 x 300 x 2%=230133.60kg/a|[0132] (2) CO dissipation was estimated at about 1.42% by mass: 230133.60 ÷ 0.35 x 1.42% ═ 9336.84kg/a|[0133] |[0134] |[0135] |[0136] The sum of the carbon elements contained is converted into CO2Equivalent indirectly scavenged CO from the atmosphere2The amount of indirect purging cannot be estimated since the present embodiment does not monitor the associated byproduct data.|[0137] (6)BECCU CO2DischargingSourceProduction ofSource-capturingSourceLess than or equal to-5969017.56 kg/a, i.e. BECCU CO in this example2DischargingSourceThe annual negative carbon emission is not less than 5969017.56 kg. | Family Number|(99292568)|99292568|Abstract|(CN114229879 A)|Biomass energy is used for replacing fossil energy and a light calcium carbonate CO2 collection and utilization process , a biomass energy utilization negative carbon emission technology BECCU is created , and the method is more economical , practical and effective compared with a power plant carbon capture and storage BECCS . In light calcium carbonate production , lime calcination and calcium carbonate drying need to consume energy , and a carbonation process needs to consume a CO2 raw material . In the prior art , fossil energy produced from calcium carbonate is used as fuel , and CO2 is recycled as carbonation raw material . The world - recognized zero - carbon - emission biomass energy is used for replacing fossil energy , CO2 produced by the biomass energy is converted into a light calcium carbonate industrial raw material , and the recycled CO2 is from CO2 absorbed from the atmosphere and soil during plant photosynthesis and is not from crustal fossil energy , so that the energy consumption is reduced , and the environmental pollution is reduced . The part of CO2 is combined into a component of a calcium carbonate final product and a byproduct thereof in a carbonation process and each production link , and is removed from the atmosphere to realize a negative emission effect , and a negative carbon emission estimation model BECCU is that CO2 emission source = production source - capture source . |Advantages / Prev. Drawbacks|(CN114229879 A)|( . . . ) congress , published 2050 via the coordinated Organisation ( OCED ) environmental agency in 2011, with the expectation of achieving lower concentration targets ( 450 ppm ) , largely dependent on carbon capture and sequestration using biomass energy ( BECCS or BioCCS ) ; in 2015, climate change of Paris United nations will set a positive target , and the global temperature rise is limited to be below 1.5 ℃to be restored to the level before industrialization . | | Chemical engineering|Materials, metallurgy | B01J-004/00/1|B01J-019/00|B01J-2204/002|C01F-011/18 | B01J-004/00/1|B01J-019/00|B01J-2204/002|C01F-011/18 | B01J-004/00|B01J-019/00|C01F-011/18 | B01J-004/00|B01J-019/00|C01F-011/18 | CN116395722|CN120289124B|GB2643483|CN117473208B|CN116656384B | CN116395722 105655582 WHO=Examiner SELF=Y CAT=Y|CN120289124B 115244754 WHO=Examiner SELF=N|GB2643483 111695430 WHO=Examiner SELF=N|CN117473208B 108338308 WHO=Examiner SELF=N|CN116656384B 106298091 WHO=Examiner SELF=Y | CN103911197|CN102220150|CN113582214|CN103449437|CN102773006|CN103382400|CN101797470|CA2405635 | CN103911197 66612321 WHO=Examiner SELF=N CAT=X|CN102220150 7432772 WHO=Examiner SELF=N CAT=X|CN113582214 96800210 WHO=Examiner SELF=N CAT=A|CN103449437 59453650 WHO=Examiner SELF=N CAT=A|CN102773006 7978193 WHO=Examiner SELF=N CAT=A|CN103382400 59307013 WHO=Examiner SELF=N CAT=A|CN101797470 7083752 WHO=Examiner SELF=N CAT=A|CA2405635 1739675 WHO=Examiner SELF=N CAT=A | 何建坤等: "《能源革命与低碳发展》", 30 June 2018, 中国环境科学出版社 (Cat. A) | CA2405635; CN101797470; CN102220150; CN102773006; CN103382400; CN103449437; CN103911197; CN113582214 | REVOKED | (CN114229879)|REVOKED | DEAD | (CN114229879)|DEAD | (CN114229879)|LEGAL DETAILS FOR CN114229879|Actual or expected expiration date=2026-03-13|Legal state=DEAD|Status=REVOKED|Event publication date=2022-01-27|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202210102926|Application date=2022-01-27|Standardized application number=2022CN-0102926|Event publication date=2022-03-25|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN114229879|Publication stage code=A|Publication date=2022-03-25|Standardized publication number=CN114229879|Event publication date=2022-03-25|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2022-04-12|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|Event publication date=2026-03-13|Event code=CN/RJ01|Event indicator=Neg|Event group=Event indicating Not In Force|Rejection of an application after its publication | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoRQtpKEfk84TFfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000062132406&ekey=2154&xpn=CN114229879&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=g48V6lKZdHnKubq7EFSolZNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN114229879)|NAME=HUANG DA;SHENZHEN SHUOFA INTELLECTUAL PROPERTY AGENCY (GENERAL PARTNERSHIP) , REG=44321 | (CN114229879)|NAME=ZHANG WENBIN | (CN114229879)|4 | 1 | 1 | (CN114229879)|Number of Claims: NCL=10|Gazette date: GAZDATE=2022-03-25|Gazette number: GAZNUM=38-1202|Number of Pages: NPAGES=21| | (CN114229879)|CHINESE (CHI) | (CN114229879)|Patent | Titre: (CN114229879)|Industrial negative carbon emission biomass energy utilization technology BECCU method Résumé: (CN114229879)|Biomass energy is used for replacing fossil energy and a light calcium carbonate CO2 collection and utilization process, a biomass energy utilization negative carbon emission technology BECCU is created, and the method is more economical, practical and effective compared with a power plant carbon capture and storage BECCS. In light calcium carbonate production, lime calcination and calcium carbonate drying need to consume energy, and a carbonation process needs to consume a CO2 raw material. In the prior art, fossil energy produced from calcium carbonate is used as fuel, and CO2 is recycled as carbonation raw material. The world-recognized zero-carbon-emission biomass energy is used for replacing fossil energy, CO2 produced by the biomass energy is converted into a light calcium carbonate industrial raw material, and the recycled CO2 is from CO2 absorbed from the atmosphere and soil during plant photosynthesis and is not from crustal fossil energy, so that the energy consumption is reduced, and the environmental pollution is reduced. The part of CO2 is combined into a component of a calcium carbonate final product and a byproduct thereof in a carbonation process and each production link, and is removed from the atmosphere to realize a negative emission effect, and a negative carbon emission estimation model BECCU is that CO2 emission source = production source-capture source. Autre: (CN114229879)|1. A process for utilizing industrial negative-carbon-emission biomass energy by BECCU technique features that the biomass energy is used to replace fossil energy such as coal, fuel oil, gas and their derivatives to produce light calcium carbonate (precipitated calcium carbonate).|2. A technical BECCU method for utilizing industrial negative Carbon emission biomass energy is technically characterized in that biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide in light calcium carbonate production is collected and utilized by the prior art to Capture biomass energy Carbon, and negative Carbon emission of zero-Carbon biomass energy Utilization is realized by utilizing BECCU or BioCCU Bioass-energy With Carbon Capture and Utilization.|3. A technical BECCU method for utilizing industrial negative Carbon emission biomass energy is technically characterized in that the biomass energy replaces fossil energy coal, fuel oil, fuel gas and derived energy to produce light calcium carbonate, Carbon dioxide generated in the light calcium carbonate industrial production is collected and utilized by utilizing the prior art, Carbon Capture and Utilization are carried out, Carbon dioxide generated in the light calcium carbonate industrial production is sealed in precipitated calcium carbonate industrial products and byproducts thereof, the Carbon Capture and the long-term or permanent industrial product sealing of the Carbon dioxide sealed in the CCUS Carbon Capture Utilization and Storage are realized, namely, the Carbon dioxide is sealed by the industrial products and the byproducts permanently or the long-term Carbon, and the negative Carbon emission of zero-Carbon biomass energy Utilization is realized.|4. The industrial negative carbon emission biomass energy utilization technology BECCU method as claimed in claim 1, wherein the calcium carbonate calcination process replaces fossil energy coal, fuel oil, fuel gas and derived energy with internationally recognized zero-carbon biomass energy and formed fuel to realize zero-carbon emission of the energy source category of the calcination process.|5. The BECCU method for the industrialized negative carbon emission biomass energy utilization technology according to claim 1, wherein the precipitated calcium carbonate drying and heating technology replaces fossil energy coal, fuel oil, fuel gas and derived energy to supply heat by internationally recognized zero-carbon biomass energy secondary energy biomass pyrolysis gas, or replaces fossil energy to supply heat by direct combustion of biomass briquette fuel, so as to realize zero-carbon emission of the energy source type of the drying and heating technology.|6. The method for utilizing the industrial negative carbon emission biomass energy source BECCU according to claim 2, is characterized in that the existing technology and device are fully utilized for collecting and utilizing the carbon dioxide in the production of the light calcium carbonate, the existing technology and device are adaptively modified, and the carbon dioxide generated by the two production processes, namely the limestone calcining process and the precipitated calcium carbonate drying process, is collected and utilized together for recycling.|7. The BECCU method as claimed in claim 6, wherein the collected carbon dioxide used in the production of precipitated calcium carbonate includes not only carbon dioxide generated by the calcination and drying of biomass energy source type, but also carbon dioxide generated by the calcination and decomposition of limestone in the raw material source type of the calcination process, and carbon dioxide generated by the energy source type and the raw material source type in the industrial production process are recycled.|8. The BECCU method as claimed in claim 3, wherein the industrial products and by-products produced by precipitated calcium carbonate industry are used for long-term and permanent sequestration of carbon dioxide, and the by-products include all the by-product process wastes produced by the precipitated calcium carbonate industry from limestone ore to the full-flow industrial production of the final product, including inert carbonates such as calcium carbonate, magnesium carbonate and tar, pyroligneous liquor, solid, liquid and gaseous non-greenhouse gas precursor stable substances which will not naturally form greenhouse gas emissions in a long term, but not CO unstable gases and methane greenhouse gases emitted by the light calcium carbonate industry, and which are likely to form subsequent greenhouse gas emissions or greenhouse gases emitted in a short and immediate period, must be deducted from the carbon dioxide inventory.|9. The industrial negative carbon emission biomass energy utilization technology BECCU method as claimed in claim 2 and claim 3, wherein the negative carbon emission of zero carbon biomass energy utilization is realized by the carbon dioxide capture and utilization of industrial processes and industrial product and byproduct carbon dioxide sequestration process, and the estimation model of the negative carbon emission is BECCU CO2DischargingSourceProduction ofSource-capturingSource。|10. The method for the industrial negative carbon emission biomass energy utilization technique BECCU according to claim 9, wherein the method for developing the industrial negative carbon emission biomass energy utilization technique BECCU and the related technical standards according to the zero carbon biomass energy utilization negative carbon emission technique BECCU and the model for estimating the amount of negative carbon emission thereof is developed, and any person other than the applicant must be informed by the applicant or developed together with the applicant based on or using the method for developing the industrial negative carbon emission biomass energy utilization technique BECCU and the related technical standards of the present invention. | 5 | Abstract | gpt-4o-mini | no | The article focuses on a process that utilizes CO2 absorbed from the atmosphere and soil, rather than CO2 generated from biomass energy production, which does not align with the BECCS definition. | |||||||||||||||||||||||
| 7 | CN201911050763 | CN201911050763 | CN110777091 | 87566585 | CN110777091 A 2020-02-11 [CN110777091] | 2019-10-31 | 2019-10-31 | 2020-02-11 | (CN110777091)|2022-07-15 | (CN110777091)|Method for developing high-efficiency BECCS system taking bicarbonate radical as link | (CN110777091)|The invention discloses a method for developing a high-efficiency BECCS system taking bicarbonate radical as a link. The method comprises the following main steps: selecting Na2(subscript)CO3(subscript) and K2(subscript)CO3(subscript) as chemical absorbents, and fully absorbing CO2(subscript) to form corresponding bicarbonates, NaHCO3(subscript) and KHCO3(subscript), to be used as carbon sources in the mutagenized spirulina culture process. Culture conditions in experiments: light intensity | TIANJING UNIVERSITY | (CN110777091)|TIANJING UNIV ([CN]) | SONG CHUNFENG|LI MEIDI|WEI YANLING|SUN CHENLU|WANG YU|HUANG DI | (CN110777091)|SONG CHUNFENG|LI MEIDI|WEI YANLING|SUN CHENLU|WANG YU|HUANG DI | (CN110777091)|CHENG XIAOYAN;TIANJIN BEIYANG PATENT AGENCY|Reg. Nb: 12201 | (CN110777091)|Compared with the prior art, the invention has the advantages that:|It is statistically estimated that there are about 33.4 million tons of CO per year 2Discharge to the atmosphere of these CO 2From power plants, oil refineries, biogas desulfurization and ethylene oxide, cement and steel production, with 40% CO 2Produced by coal-fired power plants [3,4]A series of environmental problems such as global warming and sea level increase are caused.| | (CN110777091)|1. A method for developing a bicarbonate-based efficient BECCS system, comprising the steps of:1) selection of chemical absorbent: selection of Na2CO3And K2CO3To fully absorb CO2After generation of NaHCO3And KHCO3Three different concentrations of 0.1mol/L, 0.2mol/L and 0.3mol/L are respectively set;2) and mutagenizing spirulina and spirulina:the spirulina was pre-cultured in a common zarrouk medium at 30 deg.C under 4000luxs light intensity, and 5% CO was introduced at 0.1vvm2Mixed gas (5% CO)2+95%N2) Or air, the microalgae enters a pre-culture stage;inducing the growth of the spirulina to logarithmic growth phase after ventilation, ending the pre-culture stage, and taking the cultured algae seeds as inoculation mother liquor of a formal experiment;controlling the inoculation amount to OD in formal inoculation experiment560=0.2;3) And formal culture experiment:using a zarrouk culture medium without a carbon source as a basal medium, and respectively adding NaHCO with different concentrations3And KHCO3(0.1mol/L, 0.2mol/L and 0.3mol/L) as a carbon source;the culture medium has a volume of 200ml, and is sterilized at 121 deg.C for 30min with NaHCO3And KHCO3Filtering with 0.45 μm filter membrane for sterilization, and inoculating algae with OD5600.2 of induced Spirulina platensis;culturing under the conditions of light intensity of 4000luxs and temperature of 30 +/-1 deg.C for 18 days.| | (CN110777091)|The invention discloses a method for developing a high-efficiency BECCS system taking bicarbonate radical as a link, which mainly comprises the following steps: chemical absorbent is Na 2CO 3And K 2CO 3To fully absorb CO 2NaHCO to form the corresponding bicarbonate 3And KHCO 3Used for mutagenizing a carbon source in the culture process of spirulina.|the invention relates to the technical field of microalgae biological carbon sequestration, and relates to a method for trapping CO by chemical absorption 2The carbon capture resource utilization combined with microalgae biological carbon sequestration is a method for developing a high-efficiency BECCS system taking bicarbonate radical as a link.| | (CN110777091)|BICARBONATE RADICAL(100,6)|BECCS(100,3)|LIGAMENT(100,2)|BICARBONATE EFFICIENT BECCS(100,1)|INDUCED SPIRULINA PLATENSIS(99,6)|FORMAL EXPERIMENT LIQUOR(86,2)|MUTAGENIZING SPIRULINA(82,2)|CULTURED ALGAE(82,1)|SPIRULINA GROWTH(79,1)|FORMAL CULTURE EXPERIMENT(77,2)|FORMAL INOCULATION(66,2)|PRECULTURE(55,4)|MICROALGAE CARBON UTILIZATION(53,1)|FORMAL EXPERIMENT(51,3)|MICROALGAE CONVERSION(47,1)|SPIRULINA(45,14)|INOCULATION(45,4)|CARBON CAPTURE RESOURCE UTILIZATION(45,1)|KHCO(44,5)|ABSORBENT SELECTION(44,3)|MICROALGAE(43,12)|NA SELECTION(38,2)|KHCO CONTENT(37,1)|LOGARITHMIC GROWTH PHASE(37,1)|STEP INDUCED SPIRULINA PLATENSIS(37,1)|VENTILATION(37,1)|BASAL MEDIUM(36,2)|ZARROUK CULTURE MEDIUM(34,3)|STERILIZATION(31,2)|CULTURE(30,5)|MUTAGENIZING CARBON SOURCE(29,1)|ZARROUK(28,2)|ABSORBENT(25,8)|M FILTER MEMBRANE(25,2)|BICARBONATE(24,14)|CARBON SEQUESTRATION(23,7)|SOLID CARBON CONTENT EXPERIMENTATION(21,1)|ALGAE(20,4)|MUTAGENIZED SPIRULINA BIOMASS(18,1)|LIGHT INTENSITY(17,7)|CULTURE MEDIUM(17,2)|NAHCO(17,2)|SPIRULINA PHOTOSYNTHESIS(17,2)|HIGH EFFICIENCY BECCS(16,5)|DESORPTION TOWER(16,3)|INDUCING SPIRULINA PLATENSIS(16,1)|MAXIMUM SOLID CARBON(16,1)|MUTAGENIZED SPIRULINA CHLOROPHYL CONTENT(16,1)|SPIRULINA ORGANISM CARBON SEQUESTRATION(15,2)|ABSORPTION TOWER(13,4)|CHINA OCEAN UNIVERSITY(13,1)|CULTURED SPIRULINA SEED(13,1)|MUTAGENIZED BLUNT TIPPED HELIX(13,1)|PHOTOSYNTHETIC PHOSPHORYLATIONPROCESS(13,1)|SPIRULINA PHOTOSYNTHETIC(13,1)|MICROALGAE BIOMASS YIELD(12,1)|SUPERNATANT COLLECTION(11,2)|CARBON SOURCE(10,9)|AUTOCLAVED ZARROUK(10,1)|BIOMASS SPIRULINA BIOMASS YIELD(10,1)|GREEN TRANSFORMATION PROMOTION(10,1)|INDUCED BLUNT TIPPED SPIRULINA(10,1)|ORDINARY MICROALGAE ORGANISM(10,1)|RESOURCE DEPARTMENT STATE(10,1)|BIOMASS ACCUMULATION(9,1)|CHINA MINISTRY(9,1)|CIVIL REPUBLIC(9,1)|CULTURE MICROALGAE(9,1)|FLUORESCENCE EXCITATION DETECTION WAVELENGTH(9,1)|HYDROXYLAMINE ABSORBENT(9,1)|INDUCED BLUNT ENDED SPIRULINA(9,1)|INTERNATIONAL ENERGY REVOLUTION FORUM(9,1)|METHANEDIONE CAPTURE(9,1)|MICROALGAE FILTRATION(9,1)|MUTAGENIZED SPIRULINA OIL CONTENT(9,1)|RICH COAL SITUATION(9,1)|SPIRULINA BIOMASS SCHEMATIC REPRESENTATION(9,1)|SPIRULINA TOLERANCE(9,1)|SPIRULINA UTILIZATION(9,1)|RICH ABSORBENT SOLUTION(8,2)|ABUNDANT CARBON RESOURCE(8,1)|ASSET REPORT(8,1)|BICARBONATE UTILIZATION(8,1)|CHINESE FINISH(8,1)|ECONOMIC ABSORBENT(8,1)|INORGANIC CARBON MICROALGAE(8,1)|INORGANIC SALT NUTRIENT SUBSTANCE(8,1)|SPIRULINA GROWTH RETARDATION(8,1)|AMMONIA NITROGEN(7,2)|NUTRIENT SALT COST(7,2)|ALGAE LIQUID(6,3)|BIOETHANOL(6,3)|ALGAE POWDER(6,1)|ALGAE SUSPENSION(6,1)|AQUATIC ENVIRONMENT(6,1)|BIODIESEL PRODUCTION(6,1)|BIOMASS DETECTION(6,1)|BIOTECHNOLOGY ADVANCE(6,1)|DECARBONIZATION(6,1)|GREEN RENEWABLE FUEL(6,1)|HUNDRED MILLION TON(6,1)|INORGANIC CARBON UTILIZATION(6,1)|MICROALGAE CARBON FIXATION(6,1)|MICROALGAE PHOTOSYNTHETIC CARBON FIXATION(6,1)|PEOPLE ATTENTION(6,1)|POLLUTION DISCHARGE(6,1)|RESOURCE STATE(6,1)|SPRAYED CHEMICAL ABSORBENT(6,1)|SUPERVISOBLE CARBON EMISSION(6,1)|VENTILATION DAY(6,1)|CARBON EMISSION REDUCTION(5,4)|BIOFUEL(5,2)|PLANNING(5,2)|SPECTROPHOTOMETRIC VALUE(5,2)|AMMONIUM HYDROXIDE ABSORBENT(5,1)|BIOSOLID CARBON FIXATION(5,1)|CARBON EMITTING COUNTRY(5,1)|CARBONIC ANHYDRASE(5,1)|CHINESE ENERGY(5,1)|COAL STORAGE(5,1)|CONCENTRATION SPIRULINA SOLUTION(5,1)|CULTURING MICROALGAE(5,1)|DAY TODAY ILLUMINATION(5,1)|DENITRIFICATION(5,1)|ENVIRONMENTAL DEGRADATION SITUATION(5,1)|FACTORSUBSTITUTION(5,1)|FEEDSTOCK(5,1)|FILTER FILTRATION MEMBRANE(5,1)|GREEN RESIDUE(5,1)|INORGANIC CARBON DETECTION(5,1)|INVESTMENT COST(5,1)|LOGARITHMIC PHASE(5,1)|METHANESULFINYLMETHANE(5,1)|NUTRIENT CONTENT(5,1)|PAST FEW YEAR(5,1)|PHOTOBIOREACTOR(5,1)|PHOTOREACTION COURSE(5,1)|POTASSIUM CARBONATE ABSORBENT(5,1)|PRODUCING BIOBUTANOL(5,1)|RECYCLING CARBON(5,1)|REDUCELESS CARBON EMISSION(5,1)|SPIRULINA PRODUCTION COST(5,1)|TRADESMAN(5,1)|TRANSESTERIFICATION(5,1)|ZARROUK MEDIUM(5,1)|FOSSIL FUEL COMBUSTION(4,2)|GREASE(4,2)|ABSORPTION CARBON FIXATION(4,1)|ABSORPTION RATE(4,1)|AERATION(4,1)|ALGAE SOLUTION(4,1)|ALGAL SOLUTION(4,1)|AMMONIUM HYDROXIDE MARKET PRICE(4,1)|ANALYZING ELEMENT(4,1)|BIOENERGY(4,1)|BIOGAS(4,1)|BIOMETHANOL(4,1)|CARBOHYDRATE(4,1)|CHINESE GOVERNMENT(4,1)|CHLORELLA(4,1)|CHLOROPHYL CONTENT DETERMINATION(4,1)|CHLOROPHYL VALUE(4,1)|COAL FIRED FLUE GAS(4,1)|CORROSIVE(4,1)|COUPLING CHEMICAL ABSORPTION(4,1)|CULTURE CONDITION(4,1)|CULTURE PERIOD(4,1)|DARK CONDITION(4,1)|DARKROOM(4,1)|DESULFURIZATION(4,1)|ELECTRON TRANSMISSION(4,1)| | (CN110777091)|1. A method for developing a bicarbonate-based efficient BECCS system, comprising the steps of:|1) selection of chemical absorbent: selection of Na2CO3And K2CO3To fully absorb CO2After generation of NaHCO3And KHCO3Three different concentrations of 0.1mol/L, 0.2mol/L and 0.3mol/L are respectively set;|2) and mutagenizing spirulina and spirulina:|the spirulina was pre-cultured in a common zarrouk medium at 30 deg.C under 4000luxs light intensity, and 5% CO was introduced at 0.1vvm2Mixed gas (5% CO)2+95%N2) Or air, the microalgae enters a pre-culture stage;|inducing the growth of the spirulina to logarithmic growth phase after ventilation, ending the pre-culture stage, and taking the cultured algae seeds as inoculation mother liquor of a formal experiment;|controlling the inoculation amount to OD in formal inoculation experiment560=0.2;|3) And formal culture experiment:|using a zarrouk culture medium without a carbon source as a basal medium, and respectively adding NaHCO with different concentrations3And KHCO3(0.1mol/L, 0.2mol/L and 0.3mol/L) as a carbon source;|the culture medium has a volume of 200ml, and is sterilized at 121 deg.C for 30min with NaHCO3And KHCO3Filtering with 0.45 μm filter membrane for sterilization, and inoculating algae with OD5600.2 of induced Spirulina platensis;|culturing under the conditions of light intensity of 4000luxs and temperature of 30 +/-1 deg.C for 18 days.|2. The method for developing a bicarbonate-bound high-efficiency BECCS system according to claim 1, wherein the induced spirulina platensis of step 2) is nuclear-irradiated induced spirulina platensis. | (CN110777091)|TECHNICAL FIELD|[0001] The technical field is as follows:|[0002] the invention relates to the technical field of microalgae biological carbon sequestration, and relates to a method for trapping CO by chemical absorption2The carbon capture resource utilization combined with microalgae biological carbon sequestration is a method for developing a high-efficiency BECCS system taking bicarbonate radical as a link.|[0003] Background field:|[0004] by 2017, the energy storage in China has proved that the coal storage amount is up to 1.27 hundred million tons, which accounts for 13.4 percent of the total coal amount all over the world. The reserves of petroleum and natural gas respectively account for 1.5 percent and 2.8 percent of the reserves of the world and are far lower than the reserves of coal[1]. The current situations of rich coal, lack of oil and little gas determine that the energy structure in China mainly uses coal and uses petroleum and natural gas as auxiliary materials. Although the national government strives to adjust and optimize the energy system and expand the use of renewable and sustainable new energy, the consumption of new energy such as nuclear energy, wind energy, solar energy, biomass energy and the like only accounts for 11.7 percent due to the technical limit[2]. On the other hand, China is in a rapid development stage, and the demand for energy is increasing day by day, so that fossil fuel is always in the leading position of Chinese energy in a short period of time, and the combustion of the fossil fuel can generate CO2And the carbon emission in China is far higher than that in developed countries using novel energy sources. It is statistically estimated that there are about 33.4 million tons of CO per year2Discharge to the atmosphere of these CO2From power plants, oil refineries, biogas desulfurization and ethylene oxide, cement and steel production, with 40% CO2Produced by coal-fired power plants[3,4]A series of environmental problems such as global warming and sea level increase are caused.|[0005] Various tradesmen have been striving to alleviate the current situation of environmental degradation due to excessive carbon emissions, and in the past few years, the Chinese government has taken many policies and measures to reduceLess carbon emission and promotion of green transformation in various industries. Among them, carbon taxes are considered to be an effective prospective economic means of reducing carbon emissions in China[5]. The Chinese finishes the 'twelve-five' planning in 2015, and the 'thirteen-five' planning is compiled in order to achieve the carbon emission reduction target. The concept of establishing energy use right, carbon emission right, pollution discharge right trading market and promoting marketable energy-saving carbon emission reduction is provided, and ten specific, measurable, realizable, supervisoble and practical carbon emission reduction measures such as carbon recycling, scientific development of renewable energy sources, clean energy source substitution and the like are provided. In addition to controlling carbon emissions, fossil fuel combustion produces CO2Should also be the focus of the study.|[0006] Chemical absorption is most widely used in a plurality of post-combustion capture technologies, and the chemical absorption method has mature technical support and is promising CO2The method of (1). The typical decarbonization system consists of two parts, namely an absorption tower and a desorption tower, and is generally positioned after dust removal, desulfurization and denitrification, flue gas enters the absorption tower from the bottom of the absorption tower after being cooled and is in reverse contact with a sprayed chemical absorbent, and at the moment, the chemical absorbent and CO are in reverse contact2A reversible chemical reaction occurs. Absorb CO2The rich absorbent solution is pumped out of the absorption tower and exchanges heat with the poor absorbent solution in the heat exchanger, the rich absorbent solution enters the desorption tower after being heated at high temperature, the high-temperature regeneration of the chemical absorbent is realized in the desorption tower, and pure CO is separated2Condensing, drying and compressing CO2Sealed or recycled[6]. Chemical absorption is widely used due to the advantages of high reaction rate, good absorption effect, high recovery degree and the like, and has the defects of high energy consumption, high investment cost and easy occurrence of bubbles and entrainment in solution.|[0007] 1.83t of CO can be utilized in the course of carbon sequestration of spirulina organisms2To produce 1t dry weight of biomass[7]. The principle of carbon sequestration of spirulina organisms is divided into two parts, one part is a light reaction, and the other part is a dark reaction. In the course of photoreaction, the spirulina undergoes light energy absorption, light transmission, photochemical reaction, electron transmission, and photosynthetic phosphorylationProcess for decomposing H while generating ATP and reduced coenzyme (NADPH)2O to O2. The dark reaction stage mainly utilizes ATP and NADPH generated in the light reaction stage to further complete the carbon metabolism process, and finally generates organic matters[8]. Spirulina living in aquatic environment, and inorganic carbon in water has CO2(aq)、CO32-、HCO3-、H2CO3Etc. not every kind of inorganic carbon microalgae can be absorbed and utilized, but two kinds of inorganic carbon that spirulina can utilize are CO2And HCO3-Spirulina Carbonic Anhydrase (CA) activity was very strong and bicarbonate utilization efficiency was higher compared to green algae. But the efficiency of carbon sequestration by spirulina organisms is low.|[0008] Active products such as saturated fatty acid and unsaturated fatty acid can be extracted from biomass of spirulina, and can be used as raw materials for industrially producing biodiesel, biogas, biological hydrogen production, bioethanol and biobutanol. Biodiesel is a green renewable fuel, usually produced from biological feedstocks, and spirulina biomass contains lipids that can be converted to FAME (fatty acid methyl esters) by transesterification to produce biodiesel. Carbohydrates (mainly glucose, starch, cellulose, hemicellulose) can be converted into bioethanol by fermentation. The green residue after the extraction of spirulina oil can be used for producing biobutanol which is more suitable for biofuel than biomethanol or bioethanol because of its higher energy density, and can be used as a solvent in addition to biofuel. Carbon sequestration and emission reduction coal-fired flue gas CO of spirulina organisms2Has important significance for alleviating greenhouse effect, developing pollution control of low-carbon economy and environmental protection industries. The spirulina contains high nutrient content, but the spirulina culture process consumes a large amount of water and inorganic salt nutrient substances. There is a need to provide a method for reducing the cost of spirulina production and promoting the commercial utilization of spirulina on a large scale.|[0009] Due to combustion of fossil fuels, large amounts of CO2The amount of emissions is discharged into the air, and the amount of emissions tends to increase year by year. China is one of the carbon-emitting countries and emits to the atmosphere every yearCO in2Up to 33.4 million tons. CO 22Is a main greenhouse gas, and the environmental hazard brought by the emission into the atmosphere draws attention of people, and simultaneously CO2Is also the most abundant carbon resource, and how to effectively capture carbon and utilize the carbon resource becomes the key point. In the traditional carbon capture process, chemical absorption is the most common, but the problem of high energy consumption exists. The biological carbon fixation is most environment-friendly, and the microalgae uses CO under the photosynthesis2Is a carbon source, synthesizes biomass and other high-value additional products, but has large consumption of nutritive salt in the process of culturing microalgae. In order to solve the problems of high energy consumption in the chemical absorption process and the cost of nutrient salts in the microalgae culture process, a high-efficiency BECCS (bioenergy spent with carbon dioxide capture and storage) system taking bicarbonate radical as a link is developed, namely, chemical absorption carbon fixation and microalgae biosolid carbon fixation are connected together through bicarbonate, the yield of microalgae biomass is improved on the basis of reducing the cost of nutrient salts, and the photosynthetic carbon fixation of microalgae is promoted.|DISCLOSURE|[0010] Disclosure of Invention|[0011] The invention aims to overcome the defects in the prior art and provide a method for carbon fixation by coupling chemical absorption with microalgae carbon fixation.|[0012] The technical scheme of the invention is that the method for developing the high-efficiency BECCS system taking the bicarbonate radical as the ligament comprises the following steps:|[0013] 1) selection of chemical absorbent: the traditional typical chemical absorbent is divided into ammonia water absorbent, alcohol amine absorbent, amino acid salt absorbent and potassium carbonate absorbent. However, some chemical absorbents absorb CO2The substances generated later are corrosive or toxic, and are not beneficial to the culture of the subsequent spirulina. Selection of Na2CO3And K2CO3To fully absorb CO2After generation of NaHCO3And KHCO3And three different concentrations of 0.1mol/L, 0.2mol/L and 0.3mol/L are respectively set.|[0014] 2) And mutagenizing spirulina and spirulina: the spirulina was pre-cultured in a common zarrouk medium at 30 deg.C under 4000luxs light intensity, and 5% CO was introduced at 0.1vvm2Mixed gas (5% CO)2+95%N2) Or air, the microalgae enters the pre-culture stage. After 5 days of ventilation, the mutagenized spirulina grows to the logarithmic phase, the pre-culture stage is finished, and the cultured spirulina seeds are used as the inoculation mother liquor of the formal experiment. Controlling the inoculation amount to OD in formal inoculation experiment560=0.2|[0015] 3) And formal culture experiment: using a zarrouk culture medium without a carbon source as a basal medium, and respectively adding NaHCO with different concentrations3And KHCO3(0.1mol/L, 0.2mol/L and 0.3mol/L) as a carbon source. The culture medium has a volume of 200ml, and is sterilized at 121 deg.C for 30min with NaHCO3And KHCO3Filtering with 0.45 μm filter membrane for sterilization, and inoculating algae with OD5600.2 of induced Spirulina platensis.|[0016] Culturing under the conditions of light intensity of 4000luxs and temperature of 30 +/-1 deg.C for 18 days.|[0017] The induced blunt-ended spirulina in the step 2) is induced blunt-ended spirulina subjected to nuclear radiation.|[0018] Compared with the prior art, the invention has the advantages that:|[0019] 1) the invention researches a BECCS system taking bicarbonate radical as a link, and induces the spirulina platensis to be NaHCO of 0.3mol/L through 18 days of culture3The highest biomass dry weight obtained in the system is 2.29g/L, KHCO at 0.3mol/L32.00g/L of microalgae biomass dry weight is obtained in the system. In NaHCO3The utilization efficiency of carbon in the system is higher than KHCO3Systematic, highest carbon utilization efficiency is 0.3mol/L NaHCO326.71% was obtained in the system. The maximum carbon fixing amount of the induced blunt-top spirulina is 23036mg/L/d, which is higher than the carbon fixing amount of the ordinary microalgae organisms.|[0020] 2) The invention fixes CO by chemical absorption2Coupled with microalgae biological carbon sequestration, the problem of high energy consumption in the desorption process of a chemical absorbent is avoided, and simultaneously, carbonate absorbs CO2The generated bicarbonate is used as a carbon source in the process of culturing the spirulina, so that the cost problem in the process of culturing the microalgae is reduced, and the microalgae can extract high-value added-value products such as grease, polysaccharide, protein and the like.|DRAWINGS DESCRIPTION|[0021] Description of the drawings:|[0022] FIG. 1 is a schematic representation of biomass dry weight of induced Spirulina platensis in bicarbonate system|[0023] FIG. 2 is a schematic diagram showing the variation of inorganic carbon content and carbon utilization efficiency of a solution in a bicarbonate system|[0024] FIG. 3 is a graph showing the carbon fixation of mutagenized blunt-tipped helices in a bicarbonate system|[0025] FIG. 4 shows the change in chlorophyll content of mutagenized spirulina in bicarbonate system|[0026] FIG. 5 is a graph showing the oil content of mutagenized spirulina in a bicarbonate system|INVENTION MODE|[0027] The specific implementation mode is as follows:|[0028] the invention is further illustrated by the following specific examples and the accompanying drawings. The examples are intended to better enable those skilled in the art to better understand the present invention and are not intended to limit the present invention in any way.|[0029] The invention develops a BECCS system taking bicarbonate as a bond, which comprises the following steps:|[0030] 1) selection of chemical absorbent: the economic absorbent is selected, the market price of ammonia water is the cheapest, but the tolerance of the spirulina to ammonia nitrogen is not good, and the high-concentration ammonia nitrogen can generate toxic action on the photosynthetic system of the spirulina. And the carbon source form which the spirulina can utilize is HCO3-And CO2Based on the method, the chemical absorbent adopts carbonate to absorb CO2The bicarbonate produced is then used to culture microalgae. Na having a high absorption rate is preferable2CO3And K2CO3。|[0031] 2) Pre-culturing induced spirulina platensis: the induced blunt-tipped spirulina was inoculated under aseptic conditions and cultured in 200mL autoclaved zarrouk medium in a 250mL Erlenmeyer flask while passing air at a flow rate of 0.1 vvm.|[0032] The composition of SE medium is given in the following table:|[0033] TABLE 1 nutrient component ratios in Zarrouk medium|[0034] |[0035] TABLE 2 A5、B6Composition of solution|[0036] |[0037] Culture conditions for inducing Spirulina platensis: the light intensity is 4000luxs, the illumination is carried out all day long, the temperature is 30 +/-1 ℃, and the culture period is intermittently shaken;|[0038] 3) in the formal experiment, in the experimental process, a Zarrouk culture medium without adding a carbon source is adopted to inoculate OD560The two types of bicarbonate were used as carbon sources at concentrations of 0.1mol/L, 0.2mol/L, and 0.3mol/L, respectively, with no aeration during the main culture.|[0039] The culture conditions include day-to-day illumination, light intensity of 6000luxs, and temperature of 30 + -1 deg.C|[0040] A. Biomass detection:|[0041] collecting 2mL of algae suspension, measuring the biomass of the mutagenized spirulina, measuring a spectrophotometric value at a wavelength of 560nm, and substituting the spectrophotometric value into a dry weight standard curve to convert the dry weight of the biomass. Each sample was run in triplicate, and blank samples were also treated in the same manner, with samples containing no algae as controls.|[0042] The biomass dry weight standard curve of the spirulina is measured by a drying method. Diluting high concentration Spirulina solution with deionized water to OD560100ml of algal solution was measured out when the concentration was 0.2, 0.4, 0.6, 0.8 and 1.0, respectively. Before filtering the algae liquid, drying the filter membrane with the aperture of 0.45 mu m in an oven at 150 ℃ for 2h to remove the interference of water, weighing the filter membrane after the filter membrane is dried to constant weight and cooled down, and recording the weight of the filter membrane before filtering. And then 100ml of the algae liquid is filtered by a membrane, the filtered filter membrane is put into an oven at 150 ℃ again to be dried to constant weight, and the filter membrane after the microalgae filtration is weighed after cooling. The difference value of the two previous filter membrane weighing processes is the biomass dry weight of the spirulina.|[0043] A schematic representation of the spirulina biomass after 18 days of culture is shown in FIG. 1.|[0044] Analysis of FIG. 1, induced Spirulina platensis grow differently in two different species, different bicarbonate concentration systemsThe highest dry weight of biomass was obtained in the system with a concentration of 0.3 mol/L. NaHCO 232.29g/L of KHCO is obtained in the system3The dry weight of biomass in the system was 2.00 g/L. The three concentrations of bicarbonate did not produce a toxic effect on spirulina, but spirulina growth retardation occurred in the high concentration bicarbonate system.|[0045] B. Detection of inorganic carbon|[0046] Taking a certain amount of solution in the system, filtering the solution by a filter membrane of 0.45 mu m, collecting supernatant, and determining the inorganic carbon value in the solution in a liquid-phase TOC detector.|[0047] As shown in the second figure, the Spirulina platensis was induced to have NaHCO content of 0.3mol/L3The inorganic carbon utilization efficiency in the system is highest, mainly because the high-concentration bicarbonate system has higher buffer capacity, the carbon utilization efficiency is improved.|[0048] C. Calculation of the amount of solid carbon|[0049] After the experiment period is finished, taking out all algae liquid, drying the algae, then taking 20mg of microalgae for element analysis in an element analyzer to obtain the C element ratio, multiplying the dry weight of the biomass of the spirulina by the C element in the algae powder, and converting the amount of the spirulina into the fixed carbon dioxide according to the following calculation formula:|[0050] |[0051] -the amount of carbon fixed by the spirulina organisms, mg/L/d;|[0052] Pbiomass-spirulina biomass yield, g/L/d;|[0053] Calgae-spirulina powder C content in% >;|[0054] ----CO2relative molecular mass;|[0055] MC- -C relative to atomic mass.|[0056] D. Chlorophyll content determination|[0057] Centrifuging 5ml of Spirulina solution at 5000rpm for 20min, pouring out supernatant, adding 5ml of methanol into the precipitate, ultrasonically oscillating for 15min in dark condition, placing in a refrigerator at 4 deg.C, extracting for 12 hr, centrifuging again, collecting supernatant, measuring absorbance values at wavelengths of 666nm, 653nm and 470nm, and adjusting to zero with methanol as blank.|[0058] Chlorophyll can be used as an index for evaluating the photosynthesis of spirulina, the higher the chlorophyll concentration is, the stronger the photosynthesis of the spirulina is, the higher the biomass accumulation is, and the highest chlorophyll value can be seen in the culture day 9, 0.3mol/L NaHCO3And (4) obtaining in the system.|[0059] E. Determination of oil content|[0060] Measuring the oil content by adopting a Nile red fluorescent staining method, taking 2.55ml of algae solution, and adding 450 mu L of dimethyl sulfoxide and 24 mu L of Nile red solution; standing in a dark room at 30 deg.C for 10min, and selecting 580nm as fluorescence excitation detection wavelength for determination.|[0061] The grease can be used as an added-value product in the later stage of spirulina culture, can be further used for producing and preparing biodiesel, and is applied to the aspect of energy.|[0062] It should be understood that the embodiments and examples discussed herein are illustrative only and that various modifications or changes in light thereof will be suggested to persons skilled in the art and are to be included within the spirit and purview of this application and scope of the appended claims.|[0063] The related documents are:|[0064] [1] china Ministry of civil republic of China, national resources department, China mining assets report 2018[ C ]. Beijing, 2018.|[0065] [2] China renewable energy development report 2017[ C ].2018, International energy revolution forum.|[0066] [3]Cheng J,Zhu Y,Zhang Z,et al.Modification and improvement ofmicroalgae strains for strengthening CO2fixation from coal-fired flue gas inpower plants[J].Bioresource Technology,2019,291:121850.|[0067] [4]Singh H M,Kothari R,Gupta R,et al.Bio-fixation of flue gas fromthermal power plants with algal biomass:Overview and research perspectives[J].Journal of Environmental Management,2019,245:519–539.dioxide,nitrogenoxide and sulfur dioxide from flue gas using Chlorella sp.cultures.Bioresour.Technol.102,9135-9142.|[0068] [5]Lin B,Xu M.Exploring the green total factor productivity of China’s metallurgical industry under carbon tax:A perspective on factorsubstitution[J].Journal of Cleaner Production,2019,233:1322–1333.|[0069] [6]Fang Meng, Zhou Xu Duan, Wang, etc. CO2Chemical absorbent [ J]Chemical progression, 2015, 27 (12): [7]|[0070] Chisti Y.Biodiesel from microalgae[J].Biotechnology Advances,2007,25(3):294–306.|[0071] [8]Novel flat plate type photobioreactor with Nengfu and built-in LED light source for efficiently fixing CO by microalgae2[D]The Qingdao: china ocean university, 2014.808-1814. | (CN110777091)|TECHNICAL FIELD|[0001] The technical field is as follows:|[0002] the invention relates to the technical field of microalgae biological carbon sequestration, and relates to a method for trapping CO by chemical absorption2The carbon capture resource utilization combined with microalgae biological carbon sequestration is a method for developing a high-efficiency BECCS system taking bicarbonate radical as a link.|[0003] Background field:|[0004] by 2017, the energy storage in China has proved that the coal storage amount is up to 1.27 hundred million tons, which accounts for 13.4 percent of the total coal amount all over the world. The reserves of petroleum and natural gas respectively account for 1.5 percent and 2.8 percent of the reserves of the world and are far lower than the reserves of coal[1]. The current situations of rich coal, lack of oil and little gas determine that the energy structure in China mainly uses coal and uses petroleum and natural gas as auxiliary materials. Although the national government strives to adjust and optimize the energy system and expand the use of renewable and sustainable new energy, the consumption of new energy such as nuclear energy, wind energy, solar energy, biomass energy and the like only accounts for 11.7 percent due to the technical limit[2]. On the other hand, China is in a rapid development stage, and the demand for energy is increasing day by day, so that fossil fuel is always in the leading position of Chinese energy in a short period of time, and the combustion of the fossil fuel can generate CO2And the carbon emission in China is far higher than that in developed countries using novel energy sources. It is statistically estimated that there are about 33.4 million tons of CO per year2Discharge to the atmosphere of these CO2From power plants, oil refineries, biogas desulfurization and ethylene oxide, cement and steel production, with 40% CO2Produced by coal-fired power plants[3,4]A series of environmental problems such as global warming and sea level increase are caused.|[0005] Various tradesmen have been striving to alleviate the current situation of environmental degradation due to excessive carbon emissions, and in the past few years, the Chinese government has taken many policies and measures to reduceLess carbon emission and promotion of green transformation in various industries. Among them, carbon taxes are considered to be an effective prospective economic means of reducing carbon emissions in China[5]. The Chinese finishes the 'twelve-five' planning in 2015, and the 'thirteen-five' planning is compiled in order to achieve the carbon emission reduction target. The concept of establishing energy use right, carbon emission right, pollution discharge right trading market and promoting marketable energy-saving carbon emission reduction is provided, and ten specific, measurable, realizable, supervisoble and practical carbon emission reduction measures such as carbon recycling, scientific development of renewable energy sources, clean energy source substitution and the like are provided. In addition to controlling carbon emissions, fossil fuel combustion produces CO2Should also be the focus of the study.|[0006] Chemical absorption is most widely used in a plurality of post-combustion capture technologies, and the chemical absorption method has mature technical support and is promising CO2The method of (1). The typical decarbonization system consists of two parts, namely an absorption tower and a desorption tower, and is generally positioned after dust removal, desulfurization and denitrification, flue gas enters the absorption tower from the bottom of the absorption tower after being cooled and is in reverse contact with a sprayed chemical absorbent, and at the moment, the chemical absorbent and CO are in reverse contact2A reversible chemical reaction occurs. Absorb CO2The rich absorbent solution is pumped out of the absorption tower and exchanges heat with the poor absorbent solution in the heat exchanger, the rich absorbent solution enters the desorption tower after being heated at high temperature, the high-temperature regeneration of the chemical absorbent is realized in the desorption tower, and pure CO is separated2Condensing, drying and compressing CO2Sealed or recycled[6]. Chemical absorption is widely used due to the advantages of high reaction rate, good absorption effect, high recovery degree and the like, and has the defects of high energy consumption, high investment cost and easy occurrence of bubbles and entrainment in solution.|[0007] 1.83t of CO can be utilized in the course of carbon sequestration of spirulina organisms2To produce 1t dry weight of biomass[7]. The principle of carbon sequestration of spirulina organisms is divided into two parts, one part is a light reaction, and the other part is a dark reaction. In the course of photoreaction, the spirulina undergoes light energy absorption, light transmission, photochemical reaction, electron transmission, and photosynthetic phosphorylationProcess for decomposing H while generating ATP and reduced coenzyme (NADPH)2O to O2. The dark reaction stage mainly utilizes ATP and NADPH generated in the light reaction stage to further complete the carbon metabolism process, and finally generates organic matters[8]. Spirulina living in aquatic environment, and inorganic carbon in water has CO2(aq)、CO32-、HCO3-、H2CO3Etc. not every kind of inorganic carbon microalgae can be absorbed and utilized, but two kinds of inorganic carbon that spirulina can utilize are CO2And HCO3-Spirulina Carbonic Anhydrase (CA) activity was very strong and bicarbonate utilization efficiency was higher compared to green algae. But the efficiency of carbon sequestration by spirulina organisms is low.|[0008] Active products such as saturated fatty acid and unsaturated fatty acid can be extracted from biomass of spirulina, and can be used as raw materials for industrially producing biodiesel, biogas, biological hydrogen production, bioethanol and biobutanol. Biodiesel is a green renewable fuel, usually produced from biological feedstocks, and spirulina biomass contains lipids that can be converted to FAME (fatty acid methyl esters) by transesterification to produce biodiesel. Carbohydrates (mainly glucose, starch, cellulose, hemicellulose) can be converted into bioethanol by fermentation. The green residue after the extraction of spirulina oil can be used for producing biobutanol which is more suitable for biofuel than biomethanol or bioethanol because of its higher energy density, and can be used as a solvent in addition to biofuel. Carbon sequestration and emission reduction coal-fired flue gas CO of spirulina organisms2Has important significance for alleviating greenhouse effect, developing pollution control of low-carbon economy and environmental protection industries. The spirulina contains high nutrient content, but the spirulina culture process consumes a large amount of water and inorganic salt nutrient substances. There is a need to provide a method for reducing the cost of spirulina production and promoting the commercial utilization of spirulina on a large scale.|[0009] Due to combustion of fossil fuels, large amounts of CO2The amount of emissions is discharged into the air, and the amount of emissions tends to increase year by year. China is one of the carbon-emitting countries and emits to the atmosphere every yearCO in2Up to 33.4 million tons. CO 22Is a main greenhouse gas, and the environmental hazard brought by the emission into the atmosphere draws attention of people, and simultaneously CO2Is also the most abundant carbon resource, and how to effectively capture carbon and utilize the carbon resource becomes the key point. In the traditional carbon capture process, chemical absorption is the most common, but the problem of high energy consumption exists. The biological carbon fixation is most environment-friendly, and the microalgae uses CO under the photosynthesis2Is a carbon source, synthesizes biomass and other high-value additional products, but has large consumption of nutritive salt in the process of culturing microalgae. In order to solve the problems of high energy consumption in the chemical absorption process and the cost of nutrient salts in the microalgae culture process, a high-efficiency BECCS (bioenergy spent with carbon dioxide capture and storage) system taking bicarbonate radical as a link is developed, namely, chemical absorption carbon fixation and microalgae biosolid carbon fixation are connected together through bicarbonate, the yield of microalgae biomass is improved on the basis of reducing the cost of nutrient salts, and the photosynthetic carbon fixation of microalgae is promoted.|DISCLOSURE|[0010] Disclosure of Invention|[0011] The invention aims to overcome the defects in the prior art and provide a method for carbon fixation by coupling chemical absorption with microalgae carbon fixation.|[0012] The technical scheme of the invention is that the method for developing the high-efficiency BECCS system taking the bicarbonate radical as the ligament comprises the following steps:|[0013] 1) selection of chemical absorbent: the traditional typical chemical absorbent is divided into ammonia water absorbent, alcohol amine absorbent, amino acid salt absorbent and potassium carbonate absorbent. However, some chemical absorbents absorb CO2The substances generated later are corrosive or toxic, and are not beneficial to the culture of the subsequent spirulina. Selection of Na2CO3And K2CO3To fully absorb CO2After generation of NaHCO3And KHCO3And three different concentrations of 0.1mol/L, 0.2mol/L and 0.3mol/L are respectively set.|[0014] 2) And mutagenizing spirulina and spirulina: the spirulina was pre-cultured in a common zarrouk medium at 30 deg.C under 4000luxs light intensity, and 5% CO was introduced at 0.1vvm2Mixed gas (5% CO)2+95%N2) Or air, the microalgae enters the pre-culture stage. After 5 days of ventilation, the mutagenized spirulina grows to the logarithmic phase, the pre-culture stage is finished, and the cultured spirulina seeds are used as the inoculation mother liquor of the formal experiment. Controlling the inoculation amount to OD in formal inoculation experiment560=0.2|[0015] 3) And formal culture experiment: using a zarrouk culture medium without a carbon source as a basal medium, and respectively adding NaHCO with different concentrations3And KHCO3(0.1mol/L, 0.2mol/L and 0.3mol/L) as a carbon source. The culture medium has a volume of 200ml, and is sterilized at 121 deg.C for 30min with NaHCO3And KHCO3Filtering with 0.45 μm filter membrane for sterilization, and inoculating algae with OD5600.2 of induced Spirulina platensis.|[0016] Culturing under the conditions of light intensity of 4000luxs and temperature of 30 +/-1 deg.C for 18 days.|[0017] The induced blunt-ended spirulina in the step 2) is induced blunt-ended spirulina subjected to nuclear radiation.|[0018] Compared with the prior art, the invention has the advantages that:|[0019] 1) the invention researches a BECCS system taking bicarbonate radical as a link, and induces the spirulina platensis to be NaHCO of 0.3mol/L through 18 days of culture3The highest biomass dry weight obtained in the system is 2.29g/L, KHCO at 0.3mol/L32.00g/L of microalgae biomass dry weight is obtained in the system. In NaHCO3The utilization efficiency of carbon in the system is higher than KHCO3Systematic, highest carbon utilization efficiency is 0.3mol/L NaHCO326.71% was obtained in the system. The maximum carbon fixing amount of the induced blunt-top spirulina is 23036mg/L/d, which is higher than the carbon fixing amount of the ordinary microalgae organisms.|[0020] 2) The invention fixes CO by chemical absorption2Coupled with microalgae biological carbon sequestration, the problem of high energy consumption in the desorption process of a chemical absorbent is avoided, and simultaneously, carbonate absorbs CO2The generated bicarbonate is used as a carbon source in the process of culturing the spirulina, so that the cost problem in the process of culturing the microalgae is reduced, and the microalgae can extract high-value added-value products such as grease, polysaccharide, protein and the like.|DRAWINGS DESCRIPTION|[0021] Description of the drawings:|[0022] FIG. 1 is a schematic representation of biomass dry weight of induced Spirulina platensis in bicarbonate system|[0023] FIG. 2 is a schematic diagram showing the variation of inorganic carbon content and carbon utilization efficiency of a solution in a bicarbonate system|[0024] FIG. 3 is a graph showing the carbon fixation of mutagenized blunt-tipped helices in a bicarbonate system|[0025] FIG. 4 shows the change in chlorophyll content of mutagenized spirulina in bicarbonate system|[0026] FIG. 5 is a graph showing the oil content of mutagenized spirulina in a bicarbonate system|INVENTION MODE|[0027] The specific implementation mode is as follows:|[0028] the invention is further illustrated by the following specific examples and the accompanying drawings. The examples are intended to better enable those skilled in the art to better understand the present invention and are not intended to limit the present invention in any way.|[0029] The invention develops a BECCS system taking bicarbonate as a bond, which comprises the following steps:|[0030] 1) selection of chemical absorbent: the economic absorbent is selected, the market price of ammonia water is the cheapest, but the tolerance of the spirulina to ammonia nitrogen is not good, and the high-concentration ammonia nitrogen can generate toxic action on the photosynthetic system of the spirulina. And the carbon source form which the spirulina can utilize is HCO3-And CO2Based on the method, the chemical absorbent adopts carbonate to absorb CO2The bicarbonate produced is then used to culture microalgae. Na having a high absorption rate is preferable2CO3And K2CO3。|[0031] 2) Pre-culturing induced spirulina platensis: the induced blunt-tipped spirulina was inoculated under aseptic conditions and cultured in 200mL autoclaved zarrouk medium in a 250mL Erlenmeyer flask while passing air at a flow rate of 0.1 vvm.|[0032] The composition of SE medium is given in the following table:|[0033] TABLE 1 nutrient component ratios in Zarrouk medium|[0034] |[0035] TABLE 2 A5、B6Composition of solution|[0036] |[0037] Culture conditions for inducing Spirulina platensis: the light intensity is 4000luxs, the illumination is carried out all day long, the temperature is 30 +/-1 ℃, and the culture period is intermittently shaken;|[0038] 3) in the formal experiment, in the experimental process, a Zarrouk culture medium without adding a carbon source is adopted to inoculate OD560The two types of bicarbonate were used as carbon sources at concentrations of 0.1mol/L, 0.2mol/L, and 0.3mol/L, respectively, with no aeration during the main culture.|[0039] The culture conditions include day-to-day illumination, light intensity of 6000luxs, and temperature of 30 + -1 deg.C|[0040] A. Biomass detection:|[0041] collecting 2mL of algae suspension, measuring the biomass of the mutagenized spirulina, measuring a spectrophotometric value at a wavelength of 560nm, and substituting the spectrophotometric value into a dry weight standard curve to convert the dry weight of the biomass. Each sample was run in triplicate, and blank samples were also treated in the same manner, with samples containing no algae as controls.|[0042] The biomass dry weight standard curve of the spirulina is measured by a drying method. Diluting high concentration Spirulina solution with deionized water to OD560100ml of algal solution was measured out when the concentration was 0.2, 0.4, 0.6, 0.8 and 1.0, respectively. Before filtering the algae liquid, drying the filter membrane with the aperture of 0.45 mu m in an oven at 150 ℃ for 2h to remove the interference of water, weighing the filter membrane after the filter membrane is dried to constant weight and cooled down, and recording the weight of the filter membrane before filtering. And then 100ml of the algae liquid is filtered by a membrane, the filtered filter membrane is put into an oven at 150 ℃ again to be dried to constant weight, and the filter membrane after the microalgae filtration is weighed after cooling. The difference value of the two previous filter membrane weighing processes is the biomass dry weight of the spirulina.|[0043] A schematic representation of the spirulina biomass after 18 days of culture is shown in FIG. 1.|[0044] Analysis of FIG. 1, induced Spirulina platensis grow differently in two different species, different bicarbonate concentration systemsThe highest dry weight of biomass was obtained in the system with a concentration of 0.3 mol/L. NaHCO 232.29g/L of KHCO is obtained in the system3The dry weight of biomass in the system was 2.00 g/L. The three concentrations of bicarbonate did not produce a toxic effect on spirulina, but spirulina growth retardation occurred in the high concentration bicarbonate system.|[0045] B. Detection of inorganic carbon|[0046] Taking a certain amount of solution in the system, filtering the solution by a filter membrane of 0.45 mu m, collecting supernatant, and determining the inorganic carbon value in the solution in a liquid-phase TOC detector.|[0047] As shown in the second figure, the Spirulina platensis was induced to have NaHCO content of 0.3mol/L3The inorganic carbon utilization efficiency in the system is highest, mainly because the high-concentration bicarbonate system has higher buffer capacity, the carbon utilization efficiency is improved.|[0048] C. Calculation of the amount of solid carbon|[0049] After the experiment period is finished, taking out all algae liquid, drying the algae, then taking 20mg of microalgae for element analysis in an element analyzer to obtain the C element ratio, multiplying the dry weight of the biomass of the spirulina by the C element in the algae powder, and converting the amount of the spirulina into the fixed carbon dioxide according to the following calculation formula:|[0050] |[0051] -the amount of carbon fixed by the spirulina organisms, mg/L/d;|[0052] Pbiomass-spirulina biomass yield, g/L/d;|[0053] Calgae-spirulina powder C content in% >;|[0054] ----CO2relative molecular mass;|[0055] MC- -C relative to atomic mass.|[0056] D. Chlorophyll content determination|[0057] Centrifuging 5ml of Spirulina solution at 5000rpm for 20min, pouring out supernatant, adding 5ml of methanol into the precipitate, ultrasonically oscillating for 15min in dark condition, placing in a refrigerator at 4 deg.C, extracting for 12 hr, centrifuging again, collecting supernatant, measuring absorbance values at wavelengths of 666nm, 653nm and 470nm, and adjusting to zero with methanol as blank.|[0058] Chlorophyll can be used as an index for evaluating the photosynthesis of spirulina, the higher the chlorophyll concentration is, the stronger the photosynthesis of the spirulina is, the higher the biomass accumulation is, and the highest chlorophyll value can be seen in the culture day 9, 0.3mol/L NaHCO3And (4) obtaining in the system.|[0059] E. Determination of oil content|[0060] Measuring the oil content by adopting a Nile red fluorescent staining method, taking 2.55ml of algae solution, and adding 450 mu L of dimethyl sulfoxide and 24 mu L of Nile red solution; standing in a dark room at 30 deg.C for 10min, and selecting 580nm as fluorescence excitation detection wavelength for determination.|[0061] The grease can be used as an added-value product in the later stage of spirulina culture, can be further used for producing and preparing biodiesel, and is applied to the aspect of energy.|[0062] It should be understood that the embodiments and examples discussed herein are illustrative only and that various modifications or changes in light thereof will be suggested to persons skilled in the art and are to be included within the spirit and purview of this application and scope of the appended claims.|[0063] The related documents are:|[0064] [1] china Ministry of civil republic of China, national resources department, China mining assets report 2018[ C ]. Beijing, 2018.|[0065] [2] China renewable energy development report 2017[ C ].2018, International energy revolution forum.|[0066] [3]Cheng J,Zhu Y,Zhang Z,et al.Modification and improvement ofmicroalgae strains for strengthening CO2fixation from coal-fired flue gas inpower plants[J].Bioresource Technology,2019,291:121850.|[0067] [4]Singh H M,Kothari R,Gupta R,et al.Bio-fixation of flue gas fromthermal power plants with algal biomass:Overview and research perspectives[J].Journal of Environmental Management,2019,245:519–539.dioxide,nitrogenoxide and sulfur dioxide from flue gas using Chlorella sp.cultures.Bioresour.Technol.102,9135-9142.|[0068] [5]Lin B,Xu M.Exploring the green total factor productivity of China’s metallurgical industry under carbon tax:A perspective on factorsubstitution[J].Journal of Cleaner Production,2019,233:1322–1333.|[0069] [6]Fang Meng, Zhou Xu Duan, Wang, etc. CO2Chemical absorbent [ J]Chemical progression, 2015, 27 (12): [7]|[0070] Chisti Y.Biodiesel from microalgae[J].Biotechnology Advances,2007,25(3):294–306.|[0071] [8]Novel flat plate type photobioreactor with Nengfu and built-in LED light source for efficiently fixing CO by microalgae2[D]The Qingdao: china ocean university, 2014.808-1814. | Family Number|(87566585)|87566585|Object of Invention|(CN110777091 A)|( . . . ) microalgae biological carbon sequestration , and relates to a method for trapping CO by chemical absorption 2 The carbon capture resource utilization combined with microalgae biological carbon sequestration is a method for developing a high - efficiency BECCS system taking bicarbonate radical as a link . |The invention discloses a method for developing a high - efficiency BECCS system taking bicarbonate radical as a link , which mainly comprises the following steps : chemical absorbent is Na 2 CO 3 And K 2 CO 3 To fully absorb CO 2 NaHCO to form the corresponding bicarbonate 3 And KHCO 3 Used for mutagenizing a carbon source ( . . . ) |Abstract|(CN110777091 A)|The invention discloses a method for developing a high - efficiency BECCS system taking bicarbonate radical as a link . The method comprises the following main steps : selecting Na2 ( subscript ) CO3 ( subscript ) and K2 ( subscript ) CO3 ( subscript ) as chemical absorbents , and fully absorbing CO2 ( subscript ) to form corresponding bicarbonates , NaHCO3 ( subscript ) and KHCO3 ( subscript ) , to be used as carbon sources in the mutagenized spirulina culture process . Culture conditions in experiments : light intensity |Title|(CN110777091 A)|Method for developing high - efficiency BECCS system taking bicarbonate radical as link |Independent Claims|(CN110777091 A)|1. A method for developing a bicarbonate - based efficient BECCS system , comprising the steps of : ( . . . ) | | Biotechnology | C12N-001/20|C12N-013/00|C12N-015/01 | C12N-001/20|C12N-013/00|C12N-015/01 | C12N-001/20|C12N-013/00|C12N-015/01|C12R-001/01 | C12N-001/20|C12N-013/00|C12N-015/01|C12R-001/01 | CN109456895|CN102533560|WO2020225689|CN111151119|CN110975550|CN109395536|CN109432833|CN109550360|CN109550361|CN109628315|CN108854459|CN108434995|WO2018160956|CN109906111|US20170341942|CN106621707|WO201629316|EP3077080|CN103898088|CN104603403|CN103215212|CN103272476|WO201322349|CN103328073|EP2556881|CN103079676|PL2395206|CN103079671|CN101961636|CN101862666|WO2010107974|WO201059804|CN101564638|CN101485952|CN101456556|CN101066807 | CN109456895 83676134 WHO=Examiner SELF=Y CAT=Y|CN102533560 62240584 WHO=Examiner SELF=N CAT=Y|WO2020225689 91335021 WHO=Examiner SELF=N CAT=T|CN111151119 88789932 WHO=Examiner SELF=N CAT=T|CN110975550 88209146 WHO=Examiner SELF=Y CAT=T|CN109395536 83590985 WHO=Examiner SELF=N CAT=A|CN109432833 83651514 WHO=Examiner SELF=N CAT=A|CN109550360 84005368 WHO=Examiner SELF=N CAT=A|CN109550361 84008988 WHO=Examiner SELF=N CAT=A|CN109628315 84170116 WHO=Examiner SELF=Y CAT=A|CN108854459 82211888 WHO=Examiner SELF=N CAT=A|CN108434995 81029546 WHO=Examiner SELF=N CAT=A|WO2018160956 81095049 WHO=Examiner SELF=N CAT=A|CN109906111 78999153 WHO=Examiner SELF=N CAT=A|US20170341942 77858354 WHO=Examiner SELF=N CAT=A|CN106621707 76067470 WHO=Examiner SELF=N CAT=A|WO201629316 72301408 WHO=Examiner SELF=N CAT=A|EP3077080 69554678 WHO=Examiner SELF=N CAT=A|CN103898088 66515775 WHO=Examiner SELF=N CAT=A|CN104603403 61866792 WHO=Examiner SELF=N CAT=A|CN103215212 45713379 WHO=Examiner SELF=N CAT=A|CN103272476 45907249 WHO=Examiner SELF=N CAT=A|WO201322349 15077454 WHO=Examiner SELF=N CAT=A|CN103328073 45560678 WHO=Examiner SELF=N CAT=A|EP2556881 15077454 WHO=Examiner SELF=N CAT=A|CN103079676 7342390 WHO=Examiner SELF=N CAT=A|PL2395206 4187676 WHO=Examiner SELF=N CAT=A|CN103079671 7406668 WHO=Examiner SELF=N CAT=A|CN101961636 7201822 WHO=Examiner SELF=N CAT=A|CN101862666 7087773 WHO=Examiner SELF=N CAT=A|WO2010107974 4199767 WHO=Examiner SELF=N CAT=A|WO201059804 7503892 WHO=Examiner SELF=N CAT=A|CN101564638 6857303 WHO=Examiner SELF=N CAT=A|CN101485952 6762878 WHO=Examiner SELF=N CAT=A|CN101456556 6773080 WHO=Examiner SELF=N CAT=A|CN101066807 6457883 WHO=Examiner SELF=N CAT=A | WOOKJIN CHOI 等: "Influence of the CO2 absorbent monoethanolamine on growth and carbon fixation by the green alga Scenedesmus sp.", 《BIORESOURCE TECHNOLOGY》 (Cat. A)|JUN CHENG 等: "Mutation of Spirulina sp. by nuclear irradiation to improve growth rate under 15% carbon dioxide in flue gas", 《BIORESOURCE TECHNOLOGY》 (Cat. Y)|C.V.GONZA´LEZ-LO´PEZ 等: "Development of a Process for Efficient Use of CO2 From Flue Gases in the Production of Photosynthetic Microorganisms", 《BIOTECHNOLOGY BIOENGINEERING》 (Cat. Y)|J.TIM CULINANE 等: "Carbon dioxide absorption with aqueous potassium carbonate promoted by piperazine", 《CHEMICAL ENGINEERING SCIENCE》 (Cat. A)|MICHELE GREQUE DE MORAIS 等: "Biofixation of carbon dioxide by Spirulina sp. and Scenedesmus obliquus cultivated in a three-stage serial tubular photobioreactor", 《JOURNAL OF BIOTECHNOLOGY》 (Cat. A)|HANNA KNUUTILA 等: "CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study", 《I NTERNA T I ONAL JOURNA L O F GREENHOU S E GA S CONTROL》 (Cat. A)|谢美连: "新型“化学吸收-微藻转化”耦合的C02再利用系统及优化", 《中国优秀硕士学位论文全文数据库(电子期刊)》 (Cat. T)|朱川等: "CO_2减排、处理技术的量化讨论与分类评价", 《中外能源》 (Cat. A)|陈俊武等: "中国中长期碳减排战略目标初探(Ⅵ)――碳捕集与封存排放目标讨论", 《中外能源》 (Cat. A)|李洪等: "CO_2捕集技术的研究进展", 《天津科技》 (Cat. A)|邓帅 等: "微藻固碳效能研究进展:关于能量转换的生物本征", 《新能源进展》 (Cat. A)|王金莲 等: "吸收CO2 新型混合化学吸收剂的研究", 《环境科学》 (Cat. A)|晏水平 等: "低成本C02化学吸收法分离技术的研究进展", 《现代化工》 (Cat. A) | CN101066807; CN101456556; CN101485952; CN101564638; WO201059804; WO2010107974; CN101862666; CN101961636; CN102533560; EP2556881; WO201322349; CN103079671; CN103079676; CN103215212; CN103272476; CN103328073; CN103898088; CN104603403; PL2395206; WO201629316; EP3077080; CN106621707; US20170341942; CN108434995; WO2018160956; CN108854459; CN109395536; CN109432833; CN109456895; CN109550360; CN109550361; CN109628315; CN109906111; CN110975550; CN111151119; WO2020225689 | LAPSED | (CN110777091)|LAPSED | DEAD | (CN110777091)|DEAD | (CN110777091)|LEGAL DETAILS FOR CN110777091|Actual or expected expiration date=2022-07-15|Legal state=DEAD|Status=LAPSED|Event publication date=2019-10-31|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN201911050763|Application date=2019-10-31|Standardized application number=2019CN-1050763|Event publication date=2020-02-11|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN110777091|Publication stage code=A|Publication date=2020-02-11|Standardized publication number=CN110777091|Event publication date=2020-02-11|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2020-03-06|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|Event publication date=2022-07-15|Event code=CN/WD01|Event indicator=Neg|Event group=Event indicating Not In Force|Patent application deemed withdrawn after publication | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoQJRspm7p52dVfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000033001396&ekey=2199&xpn=CN110777091&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=GNlqwe%252BrpVMFXulIx6OkHJNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN110777091)|CN | (CN110777091)|NAME=TIANJING UNIV , COUNTRY=CN | (CN110777091)|NAME=CHENG XIAOYAN;TIANJIN BEIYANG PATENT AGENCY , REG=12201 | (CN110777091)|NAME=SONG CHUNFENG|NAME=LI MEIDI|NAME=WEI YANLING|NAME=SUN CHENLU|NAME=WANG YU|NAME=HUANG DI | (CN110777091)|5 | 1 | 1 | (CN110777091)|Number of Claims: NCL=2|Gazette date: GAZDATE=2020-02-11|Gazette number: GAZNUM=36-0701|Number of Pages: NPAGES=11| | (CN110777091)|CHINESE (CHI) | (CN110777091)|Patent | Titre: (CN110777091)|Method for developing high-efficiency BECCS system taking bicarbonate radical as link Résumé: (CN110777091)|The invention discloses a method for developing a high-efficiency BECCS system taking bicarbonate radical as a link. The method comprises the following main steps: selecting Na2(subscript)CO3(subscript) and K2(subscript)CO3(subscript) as chemical absorbents, and fully absorbing CO2(subscript) to form corresponding bicarbonates, NaHCO3(subscript) and KHCO3(subscript), to be used as carbon sources in the mutagenized spirulina culture process. Culture conditions in experiments: light intensity Autre: (CN110777091)|1. A method for developing a bicarbonate-based efficient BECCS system, comprising the steps of:|1) selection of chemical absorbent: selection of Na2CO3And K2CO3To fully absorb CO2After generation of NaHCO3And KHCO3Three different concentrations of 0.1mol/L, 0.2mol/L and 0.3mol/L are respectively set;|2) and mutagenizing spirulina and spirulina:|the spirulina was pre-cultured in a common zarrouk medium at 30 deg.C under 4000luxs light intensity, and 5% CO was introduced at 0.1vvm2Mixed gas (5% CO)2+95%N2) Or air, the microalgae enters a pre-culture stage;|inducing the growth of the spirulina to logarithmic growth phase after ventilation, ending the pre-culture stage, and taking the cultured algae seeds as inoculation mother liquor of a formal experiment;|controlling the inoculation amount to OD in formal inoculation experiment560=0.2;|3) And formal culture experiment:|using a zarrouk culture medium without a carbon source as a basal medium, and respectively adding NaHCO with different concentrations3And KHCO3(0.1mol/L, 0.2mol/L and 0.3mol/L) as a carbon source;|the culture medium has a volume of 200ml, and is sterilized at 121 deg.C for 30min with NaHCO3And KHCO3Filtering with 0.45 μm filter membrane for sterilization, and inoculating algae with OD5600.2 of induced Spirulina platensis;|culturing under the conditions of light intensity of 4000luxs and temperature of 30 +/-1 deg.C for 18 days.|2. The method for developing a bicarbonate-bound high-efficiency BECCS system according to claim 1, wherein the induced spirulina platensis of step 2) is nuclear-irradiated induced spirulina platensis. | 0 | Abstract | gpt-4o-mini | no | The article focuses on a method involving bicarbonate radicals and spirulina culture, which does not align with the central topic of biomass energy production combined with CO₂ capture and storage. | |||||||||||||||||||||||
| 8 | CN202510970721 | CN202510970721 | CN120471490 | 115619738 | CN120471490 A 2025-08-12 [CN120471490] | 2025-07-15 | 2025-07-15 | 2025-08-12 | (CN120471490)|2045-07-15 | (CN120471490)|Loss income calculation method based on large algae deposition carbon sequestration and electronic equipment | (CN120471490)|The invention discloses a loss income calculation method based on large algae deposition carbon sequestration and electronic equipment. The method comprises the following steps: indirectly estimating the harvesting cost of each kilogram of large algae through the production cost of each kilogram of fishery; according to the harvesting cost of the big algae per kilogram and the annual yield of the big algae, constructing a cost model of the big algae deposition carbon sequestration loss income; the direct economic value model of the large algae deposition carbon sequestration loss income is quantitatively represented through the large algae output value; according to the cost model and the direct economic value model, constructing a large algae deposition carbon sequestration profit and loss accounting model; constructing an objective function and constraint conditions according to industry profit equilibrium conditions, and solving the large algae deposition carbon sequestration profit and loss accounting model to obtain optimal parameters; and carrying out loss income calculation by using the big algae deposition carbon sequestration profit and loss accounting model with the optimal parameters. | HAINAN INSTITUTE OF ZHEJIANG UNIVERSITY | (CN120471490)|HAINAN INSTITUTE OF ZHEJIANG UNIVERSITY ([CN]) | FAN WEI|YUE LULU|QI YIFAN|ZOU ZHIYU|QU MENGJIE | (CN120471490)|FAN WEI|YUE LULU|QI YIFAN|ZOU ZHIYU|QU MENGJIE | (CN120471490)|YING KONGYUE;HANGZHOU JUNRUIDA INTELLECTUAL PROPERTY AGENCY CO., LTD.|Reg. Nb: 33544 | (CN120471490)|The energy replacement refers to replacing fossil energy with renewable energy sources such as photovoltaic, wind power and the like, but faces the intermittent power supply and the restriction of land resources, the industrial decarburization refers to modifying a high-carbon flow path through hydrogen-based steelmaking, cement carbon capture and the like, but has cost barriers, the biomass energy-carbon capture and storage (BECCS) refers to combining carbon capture by biomass combustion and occupying cultivated land, the direct air carbon capture and storage (DACS) refers to directly capturing CO _2 from the atmosphere and carrying out storage or utilization, but is subject to high energy consumption and thousands of dollar cost bottlenecks, and compared with the ecological carbon sink refers to carbon fixation by depending on ecological systems such as mangrove, large algae and the like, the ecological carbon sink has the advantages of zero energy consumption, low cost, high-efficiency land utilization, biodiversity gain and the like.|The application is definitely limited in the statistical category of the byproduct of the algae of three main economic algae of kelp, laver and undaria pinnatifida.|The invention solves two main core problems in the economic calculation of the carbon sequestration deposited by the microalgae by modeling the benefit of the carbon sequestration deposited by the microalgae, namely, innovation of a cost estimation method. The prior art and data cannot directly quantify the harvesting cost of the microalgae, and the traditional method is easily influenced by industry data fragmentation.|The prior art and data cannot directly quantify the harvesting cost of the microalgae, and the traditional method is easily influenced by industry data fragmentation.| | (CN120471490)|1. The lost revenue accounting model construction method based on carbon sequestration of the microalgae is characterized by comprising the following steps: Indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; constructing a cost model of carbon sequestration loss and income of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae, wherein the cost model has the model assumption that 1 is a strict linear relation between the harvesting cost of the ith microalgae per kilogram and the production cost of fishery per kilogram, 2 is a model assumption that the microalgae cultivation industry presents scale income unchanged characteristics in an observation period; A direct economic value model for quantitatively representing the benefit of carbon sequestration loss of the microalgae through the yield value of the microalgae; Constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model; And constructing an objective function and constraint conditions, and solving the chlorella sediment carbon sequestration loss gain accounting model to obtain the chlorella sediment carbon sequestration loss gain accounting model with optimal parameters. | | (CN120471490)|According to a first aspect of an embodiment of the present application, there is provided a loss and gain accounting model construction method based on carbon sequestration by microalgae, including:|The application relates to the technical field of ecological carbon sinks, in particular to a loss and gain calculation method based on carbon sequestration by chlorella deposition and electronic equipment.|The invention discloses a loss profit calculation method and electronic equipment based on carbon sequestration of a large alga, which comprises the steps of indirectly estimating the harvest cost of the large alga per kilogram through the production cost of fishery per kilogram, constructing a cost model of carbon sequestration loss profit of the large alga according to the harvest cost of the large alga per kilogram and the annual yield of the large alga, quantitatively representing a direct economic value model of the carbon sequestration loss profit of the large alga through the yield value of the large alga, constructing a carbon sequestration damage benefit accounting model of the large alga according to the cost model and the direct economic value model, constructing an objective function and constraint conditions according to industry profit balance conditions, solving the carbon sequestration benefit accounting model of the large alga to obtain optimal parameters, and calculating the loss profit by utilizing the carbon sequestration benefit accounting model of the large alga with the optimal parameters.| | (CN120471490)|CARBON SEQUESTRATION(100,61)|LOSS(100,16)|MICROALGAE HARVESTING COST(100,12)|CALCULATION(100,7)|ELECTRONIC EQUIPMENT(100,5)|CHLORELLA DEPOSITION(100,4)|MICROALGAE CARBON SEQUESTRATION(100,3)|LOST REVENUE(100,2)|MODEL CONSTRUCTION(100,2)|KELP ECONOMIC ALGAE(78,1)|ALGAE SELLING PRICE(77,6)|ALGAE BYPRODUCT(68,8)|LARGE ALGA(66,10)|CHLORELLA SEDIMENT(66,5)|HARVESTING COST(65,25)|MICROALGAE CULTIVATION INDUSTRY(62,2)|KILOGRAM(59,39)|MICROALGAE INCOME(54,2)|FISHERY KILOGRAM(52,5)|PROPORTIONALITY COEFFICIENT(51,9)|CARBON SEQUESTRATION LOSS(49,23)|ECOLOGICAL CARBON SINK(49,3)|MICROALGAE ANNUAL YIELD(48,3)|MACROALGAE DEPOSIT(44,2)|STATISTICAL CATEGORY(44,1)|FISHERY PRODUCT WATER(42,6)|ANNUAL YIELD(42,4)|LOSS PROFIT CALCULATION(42,2)|BIOMASS COMBUSTION(41,1)|HARVESTER(40,2)|BIODIVERSITY GAIN(40,1)|MICROALGAE(39,16)|INDUSTRY PROFIT BALANCE CONDITION(39,1)|FISHERY(38,16)|MODEL ASSUMPTION(38,6)|INDUSTRY DATA FRAGMENTATION(38,2)|ECONOMIC ALGAE(37,2)|MICROALGAE CULTIVATION HARVESTING COST(37,2)|EARTH RESOURCE(37,1)|REPLACING FOSSIL ENERGY(37,1)|ALGAE YIELD(36,7)|MICROALGAE CARBON SEQUESTRATION LOSS(36,2)|ALGAE PRODUCT SELLING PRICE(35,1)|T YEAR FISHERY PRODUCTION(33,6)|DECARBURIZATION(32,1)|DEPOSITED MICROALGAE(31,8)|MICROALGAE KILOGRAM(31,2)|LARGE ALGA ANNUAL YIELD(31,1)|T TH YEAR(30,9)|CARBON SEQUESTRATION DAMAGE(30,1)|ANNUAL TOTAL INCOME(28,4)|LOSS PROFIT ACCOUNTING(27,2)|DOLLAR(26,1)|ALGAE COLLECTION(25,2)|LARGE ALGA CARBON SEQUESTRATION(24,1)|ECONOMIC VALUE MODEL(22,9)|ENDING YEAR(22,2)|T YEAR KILOGRAM(21,2)|ANNUAL AVERAGE(21,1)|MANGROVE(21,1)|UNDARIA PINNATIFIDA(20,3)|CULTIVATED LAND(20,1)|CONSTRAINT CONDITION(19,4)|ENERGY REPLACEMENT(19,2)|OVERFLOW RATIO(18,5)|OBSERVATION PERIOD(18,3)|ECONOMIC CALCULATION(18,1)|LAVER(18,1)|CARBON SEQUESTRATION LOSS BENEFIT(17,1)|MICROALGAE BYPRODUCT INTERSPECIES DISTINCTION(17,1)|PRODUCTION COST(16,5)|CARBON SINK(15,6)|LARGE ALGAE DEPOSITION(15,6)|COMPUTER INSTRUCTION(15,3)|STRICT LINEAR RELATION(14,3)|WATER PRODUCTION(14,2)|LARGE ALGAE(14,1)|NECK(14,1)|ZERO ENERGY CONSUMPTION(13,1)|CARBON CAPTURE(12,4)|CHINESE FISHERY ANNUAL BOOK(12,1)|FISHERY ANNUAL SURVEY OBSERVATION(12,1)|DYNAMIC PRICING(11,5)|SEASONED UNDARIA PINNATIFIDA(11,2)|INTERMITTENT POWER SUPPLY(11,1)|MICROALGAE ECONOMIC ACCOUNTING(11,1)|OBJECTIVE FUNCTION(10,8)|CARBON FIXATION(10,3)|AIR CARBON CAPTURE(10,2)|CHINESE FISHERY YEAR(10,1)|ERROR TERM(9,6)|CONSTRAINT OPTIMIZATION FRAMEWORK(9,3)|COST ESTIMATION(9,2)|GLOBAL OPTIMALITY(9,2)|NET PROFIT MARGIN(9,2)|ROASTED LAVER(9,2)|ECONOMIC VALUE(8,3)|ALGAE CULTIVATION INDUSTRY(8,1)|NATIONAL STATISTIC BUREAU(8,1)|WINDPOWER(8,1)|VARIABLE COST(7,9)|NEGATIVE EMISSION(7,4)|FISHERY COST ANALOGY(7,2)|HISTORICAL CUMULATIVE ECOLOGICAL VALUE(7,2)|TRADITIONAL METHOD(7,2)|ECOLOGICAL SYSTEM(7,1)|INNOVATIVE BREAKTHROUGH(7,1)|MICROALGAE INCOME LOSS(7,1)|TERMINAL YEAR SELLING PRICE(7,1)|PRIMARY PRODUCT(6,4)|ALGAE INDUSTRY(6,2)|FUTURE SCENARIO(6,2)|MARKET PRICE FLUCTUATION(6,2)|RESIDUAL EMISSION OPENING(6,2)|ANNUAL TRADE AVERAGE PRICE(6,1)|BYPRODUCT PRICE(6,1)|DRY KELP KNOT(6,1)|ECONOMIC MICROALGAE(6,1)|FISHERY CULTIVATION COST(6,1)|NOUN INTERPRETATION(6,1)|PRIMARY SALE INCOME(6,1)|RENEWABLE ENERGY SOURCE(6,1)|TRAFFIC DECARBONIZATION(6,1)|REFERENCE YEAR(5,4)|CALCULATION MODULE(5,2)|HABITAT SUPPLY(5,2)|LAND PLANT RESOURCE(5,2)|LOST REVENUE CALCULATION(5,2)|STRICT LINEAR PROPORTIONAL RELATION(5,2)|ALGAE CULTIVATION COST(5,1)|ALGAE SIDELINE PRODUCT(5,1)|HIGH ENERGY CONSUMPTION(5,1)|HISTORICAL SELLING PRICE DATA(5,1)|JUDGEMENT COEFFICIENT(5,1)|METHODOLOGY UNIFORMITY(5,1)|MICROALGAE BYPRODUCT PROCESSED PRODUCT(5,1)|OFFICIAL RECORD(5,1)|PHOTOVOLTAIC MODULE INVESTMENT(5,1)|PRIMARY BYPRODUCT SALES REVENUE(5,1)|TECHNICAL ROUTE HETEROGENEITY(5,1)|FIXED ASSET DEPRECIATION(4,3)|TIME SPAN(4,2)|ECOLOGICAL CARBON SEQUESTRATION(4,1)|FISH AQUATIC PRODUCT(4,1)|MULTIELEMENT CARBON(4,1)|NATIONAL AQUATIC PRODUCT YIELD(4,1)|NATIONAL FISHERY TOTAL EXPENDITURE(4,1)|PRESERVED FOOD STANDARDIZATION(4,1)|FIXED COST(3,9)|DOUBLE DYNAMIC COUPLING MODEL(3,2)|ECOLOGICAL FUNCTION(3,2)|ECONOMIC VALUE QUANTIFICATION(3,2)|INDIRECT COST ESTIMATE(3,2)|LOST BENEFIT(3,2)|MATHEMATICAL RIGOR(3,2)|MODEL R(3,2)|OXYGEN RELEASE(3,2)|REGIONAL PRODUCTION SCALE DIFFERENCE(3,2)|SEAWATER(3,2)|SEAWEED VALUE(3,2)|SUSTAINABILITY(3,2)|TOTAL YIELD STANDARDIZATION TREATMENT(3,2)|UNCERTAINTY(3,2)|YUAN KILOGRAM(3,2)|AGGRESSIVE EMISSION REDUCTION MEASURE(3,1)|ALGAE BYPRODUCT YIELD DATA(3,1)|CHLORELLA PRODUCT(3,1)|COMPOUND ANNUAL(3,1)|FARMED CARBON SINK(3,1)|FITTED MAP(3,1)|HARVEST COST(3,1)|INERT DISSOLVED CARBON POOL(3,1)|INERTNESS(3,1)|INSTRUMENTALITY(3,1)|LISTED ITEM(3,1)| | (CN120471490)|1. The lost revenue accounting model construction method based on carbon sequestration of the microalgae is characterized by comprising the following steps:| Indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; | constructing a cost model of carbon sequestration loss and income of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae, wherein the cost model has the model assumption that 1 is a strict linear relation between the harvesting cost of the ith microalgae per kilogram and the production cost of fishery per kilogram, 2 is a model assumption that the microalgae cultivation industry presents scale income unchanged characteristics in an observation period; | A direct economic value model for quantitatively representing the benefit of carbon sequestration loss of the microalgae through the yield value of the microalgae; | Constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model; | And constructing an objective function and constraint conditions, and solving the chlorella sediment carbon sequestration loss gain accounting model to obtain the chlorella sediment carbon sequestration loss gain accounting model with optimal parameters. |2. The method according to claim 1, wherein the formula for indirectly estimating the harvesting cost per kilogram of microalgae through the production cost per kilogram of fishery is as follows:|;| In the middle of Is the harvesting cost of the microalgae i in each kilogram of t years; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is an error term. |3. The method of claim 1, wherein the cost model for carbon sequestration loss benefit for the macroalgae deposit is expressed as follows:|;| In the middle of Refers to the total cost of the cultivation of the microalgae in the t th year; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term; The yield of the ith algae in the t year is indicated, and I represents the collection of the algae. |4. The method of claim 1, wherein the expression of the direct economic value model is as follows:|;| In the middle of Is the total output value; Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; is the overflow ratio of the byproduct of the algae i compared with the primary product; Dynamic pricing mechanism based on time trend is adopted: |;| In the middle of The selling price of the i-th algae in the reference year is represented by t, wherein t represents the ending year, and t 0 represents the reference year; is the annual average increase rate of the selling price of the algae products, ,The selling price is finished; Is the time span. |5. The method according to claim 1, wherein the expression of the macroalgae deposit carbon sequestration loss profit accounting model R is as follows:|;| in the formula, Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; Is the overflow ratio of the byproduct of the algae i compared with the primary product; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term, and I represents a set of microalgae. |6. The method of claim 5, wherein the objective function is:|;| is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is a theoretical reference ratio. |7. The method of claim 5, wherein the constraints are:| (1) The industry profit balance condition is that the net profit margin is 10% -15%, namely |;|(2) The annual total income of all main and byproduct of the algae is greater than the expenditure:|;| (3) The linear relation between the harvesting cost of the microalgae cultivation per kilogram and the production cost of the whole fishery per kilogram is that When (when)In the time-course of which the first and second contact surfaces,,Is the ratio of the total expenditure of fishery and the yield of aquatic products;| (4) The cost is lower than the selling price: 。|8. the loss profit calculation method based on carbon sequestration by chlorella deposition is characterized by comprising the following steps: | constructing a large algae deposit carbon sequestration loss profit accounting model with optimal parameters by the construction method of claim 1; | and calculating the carbon sequestration loss gain of the deposited microalgae by using a carbon sequestration loss gain accounting model of the deposited microalgae with optimal parameters. |9. An electronic device, comprising:| one or more processors; | a memory for storing one or more programs; | the one or more programs, when executed by the one or more processors, cause the one or more processors to implement the method of any of claims 1-8. |10. A computer readable storage medium having stored thereon computer instructions which, when executed by a processor, implement the method of any of claims 1-8. | (CN120471490)|TECHNICAL FIELD|Technical Field|[0001] The application relates to the technical field of ecological carbon sinks, in particular to a loss and gain calculation method based on carbon sequestration by chlorella deposition and electronic equipment.|BACKGROUND ART|[0002] The carbon balance is realized by relying on a multi-element carbon sealing technology path, and the current mainstream carbon sealing technology can be divided into an emission reduction technology and a negative emission technology. Emission reduction technologies include energy replacement, industrial and traffic decarbonization, etc., and negative emission technologies include biomass energy-carbon capture and sequestration (Bioenergy with Carbon Capture and Storage, BECCS), direct air carbon capture and storage (DIRECT AIR Carbon Capture and Storage, DACS), ecological carbon sequestration, etc.|[0003] The energy replacement refers to replacing fossil energy with renewable energy sources such as photovoltaic, wind power and the like, but faces the intermittent power supply and the restriction of land resources, the industrial decarburization refers to modifying a high-carbon flow path through hydrogen-based steelmaking, cement carbon capture and the like, but has cost barriers, the biomass energy-carbon capture and storage (BECCS) refers to combining carbon capture by biomass combustion and occupying cultivated land, the direct air carbon capture and storage (DACS) refers to directly capturing CO 2 from the atmosphere and carrying out storage or utilization, but is subject to high energy consumption and thousands of dollar cost bottlenecks, and compared with the ecological carbon sink refers to carbon fixation by depending on ecological systems such as mangrove, large algae and the like, the ecological carbon sink has the advantages of zero energy consumption, low cost, high-efficiency land utilization, biodiversity gain and the like.|[0004] Because of the differences of the characteristics and application scenes of different carbon sequestration technologies, a targeted cost accounting method is required to evaluate the economic feasibility of different blue carbon paths. The emission reduction technology is based on a flattening energy cost (LCOE) and full Life Cycle Assessment (LCA) framework, so that dominant costs such as photovoltaic module investment, green hydrogen overflow price and the like can be precisely quantized, and the negative emission technology is broken through by accounting methodology due to technical route heterogeneity, and cross-region data comparability and methodology uniformity are urgently needed to be broken through.|[0005] The existing research refers to a land plant resource value evaluation method to evaluate the ecological functions and the value of seaweed such as water quality purification, carbon fixation, oxygen release, heavy metal substance absorption, biological habitat supply and the like. However, these evaluations focused mainly on quantification of historical cumulative ecological value, and did not predict future scenarios, especially direct economic value quantification of carbon sequestration loss by algae deposition not involving the 2060 year long period.|DISCLOSURE|Disclosure of Invention|[0006] In view of the above, the embodiment of the application provides a loss profit calculation method and electronic equipment based on carbon sequestration by chlorella deposition.|[0007] According to a first aspect of an embodiment of the present application, there is provided a loss and gain accounting model construction method based on carbon sequestration by microalgae, including:| Indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; | constructing a cost model of carbon sequestration loss and income of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae, wherein the cost model has the model assumption that 1 is a strict linear relation between the harvesting cost of the ith microalgae per kilogram and the production cost of fishery per kilogram, 2 is a model assumption that the microalgae cultivation industry presents scale income unchanged characteristics in an observation period; | A direct economic value model for quantitatively representing the benefit of carbon sequestration loss of the microalgae through the yield value of the microalgae; | Constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model; | And constructing an objective function and constraint conditions, and solving the chlorella sediment carbon sequestration loss gain accounting model to obtain the chlorella sediment carbon sequestration loss gain accounting model with optimal parameters. |[0008] According to a second aspect of the embodiment of the present application, there is provided a loss and gain calculation method based on carbon sequestration by chlorella sediment, including:| Constructing a large algae deposition carbon sequestration loss profit accounting model with optimal parameters by the construction method of the first aspect; | and calculating the carbon sequestration loss gain of the deposited microalgae by using a carbon sequestration loss gain accounting model of the deposited microalgae with optimal parameters. |[0009] According to a third aspect of an embodiment of the present application, there is provided an electronic apparatus including:| one or more processors; | a memory for storing one or more programs; | the one or more programs, when executed by the one or more processors, cause the one or more processors to implement the method of the first or second aspect. |[0010] According to a fourth aspect of embodiments of the present application there is provided a computer readable storage medium having stored thereon computer instructions which when executed by a processor perform the steps of the method according to the first or second aspect.|[0011] The technical scheme provided by the embodiment of the application can comprise the following beneficial effects:| first, an innovative breakthrough in the cost estimation method. The prior art and data cannot directly quantify the harvesting cost of the microalgae, and the traditional method is easily influenced by industry data fragmentation. The invention creatively provides a fishery cost analogy method (formula 1), and indirect cost estimation is realized by establishing a strict linear proportional relation (model assumption 1) of the algae and the fishery cost, and mapping a composite structure of fixed cost (fixed asset depreciation and tax) and variable cost (feed, fuel and manual) to the algae cultivation field. The mathematical rigor of the method is characterized in that the influence of regional production scale difference on cost is eliminated through national fishery total yield standardization treatment. |[0012] Second, the global optimality of dynamic economic systems. Aiming at the uncertainty of the long-term development of the algae industry, the invention initiates a 'double dynamic coupling model', wherein ① captures market price fluctuation through time trend extrapolation based on a dynamic pricing mechanism (formula 4) of CAGR, and ② constraint optimization framework (objective function+four-dimensional constraint) realizes double guarantee of industry profit and sustainability.|[0013] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the application as claimed.|DRAWINGS DESCRIPTION|[0014] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the application and together with the description, serve to explain the principles of the application.|[0015] FIG. 1 is a flow chart illustrating a method of constructing a lost revenue accounting model based on carbon sequestration by a large algae deposit, according to an exemplary embodiment.|[0016] FIG. 2 is a flow chart illustrating a method of lost revenue calculation based on carbon sequestration by a large algae deposit, according to an exemplary embodiment.|[0017] Fig. 3 is a linear regression graph showing fishery production cost per kilogram (a) and algae byproduct yield (b) according to an exemplary embodiment.|[0018] Fig. 4 is a schematic diagram of an electronic device according to an exemplary embodiment.|INVENTION MODE|Detailed Description|[0019] Reference will now be made in detail to exemplary embodiments, examples of which are illustrated in the accompanying drawings. When the following description refers to the accompanying drawings, the same numbers in different drawings refer to the same or similar elements, unless otherwise indicated. The implementations described in the following exemplary examples do not represent all implementations consistent with the application. Rather, they are merely examples of apparatus and methods consistent with aspects of the application as detailed in the accompanying claims.|[0020] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the application. As used in this specification and the appended claims, the singular forms "a," "an," and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It should also be understood that the term "and/or" as used herein refers to and encompasses any or all possible combinations of one or more of the associated listed items.|[0021] It should be understood that although the terms first, second, third, etc. may be used herein to describe various information, these information should not be limited by these terms. These terms are only used to distinguish one type of information from another. For example, first information may also be referred to as second information, and similarly, second information may also be referred to as first information, without departing from the scope of the application. The term "if" as used herein may be interpreted as "at..once" or "when..once" or "in response to a determination", depending on the context.|[0022] Noun interpretation:| Carbon sequestration in the form of carbon sink is a form of carbon sink, which means that large algae convert CO 2 and Dissolved Inorganic Carbon (DIC) in seawater to Dissolved Organic Carbon (DOC) and Particulate Organic Carbon (POC) by photosynthesis, and further to Refractory Dissolved Organic Carbon (RDOC) with strong biological inertness by Microbial Carbon Pump (MCP) mechanism, which can be stored in seawater for long periods of time to form a stable inert dissolved carbon pool in the farmed carbon sink. The existing research shows that even though the most aggressive emission reduction measures are adopted, the 'residual emission gap' still exists in China by about 1.5-3.0 Gt CO 2 every year, and the 'residual emission gap' needs to be counteracted by relying on a negative emission technology. |[0023] The existing research refers to a land plant resource value evaluation method to evaluate the ecological functions and the value of seaweed such as water quality purification, carbon fixation, oxygen release, heavy metal substance absorption, biological habitat supply and the like. However, these evaluations focused mainly on quantification of historical cumulative ecological value, and did not predict future scenarios, especially direct economic value quantification of carbon sequestration loss by algae deposition not involving the 2060 year long period. The research firstly provides a loss and gain calculation method based on carbon sequestration deposited by the microalgae, and aims to quantitatively predict the loss and gain of carbon sequestration deposited by the microalgae until 2060 years so as to make up for the study blank in the field.|[0024] FIG. 1 is a flow chart illustrating a method of constructing a loss and gain accounting model based on carbon sequestration by a large algae deposit, according to an exemplary embodiment, as shown in FIG. 1, the method may include the steps of:| s1, indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; | Specifically, considering that the algae cultivation cost is structurally the same as the fishery cultivation cost, the formula is as follows, which is indirectly estimated by the production cost per kilogram of fishery: |(1)| In the middle of Is the harvesting cost of the microalgae i in each kilogram of t years; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products of the t-th year, including five kinds of aquatic products of fishes, shellfishes, crustaceans, microalgae and others which are cultivated and fished; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is an error term. |[0025] The fixed costs may include fixed asset depreciation and tax payment for fishery, and the variable costs may include feed and seed costs, fuel and ice costs, employee compensation, and other costs.|[0026] S2, constructing a cost model of carbon sequestration loss and income loss of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae;| specifically, the cultivation cost of the algae is equal to the product of the harvesting cost per kilogram and the yield, and the formula is as follows: |(2)| In the middle of Refers to the total cost, unit (yuan) of the cultivation of the microalgae in the t year; refers to the harvest cost per kilogram of the ith algae in units of yuan/kilogram in the t year; Refers to the yield of the ith algae in kilograms at the t year. |[0027] The cost model of the carbon sequestration loss benefit of the algae deposition is as follows:|(3)| In the middle of Refers to the total cost of the cultivation of the microalgae in the t th year; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term; the method is characterized in that the yield of the ith algae in the t year is indicated, I represents the collection of the algae, I represents different algae types and is calculated separately according to different types. |[0028] The model has the following assumptions:| The model is assumed to be 1 that the harvesting cost of the algae i per kilogram has a strict linear relation with the production cost of fishery per kilogram, namely ,。|[0029] Model assume 2 that the algae cultivation industry presents scale gain-invariant (Constant Returns to Scale, CRS) characteristics in the observation period (2025-2060), namely that the unit production cost is not obviously reduced along with the scale expansion of the yield.|[0030] S3, quantitatively representing a direct economic value model of the carbon sequestration loss benefit of the microalgae sediment through the yield value of the microalgae;| Specifically, according to the national statistical bureau accounting standard, the total yield value can be obtained by multiplying the yield of the product and its by-products by the selling price of the unit product/by-products (without tax), and thus the direct economic value (total yield value) of the microalgae ) Consisting of primary byproduct sales revenue, the expression of the direct economic value model is as follows:|(4)| In the middle of Is the total output value; Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; is the overflow ratio of the byproduct of the algae i compared with the primary product; Dynamic pricing mechanism based on time trend is adopted: |(5)| In the middle of The selling price of the i-th algae in the reference year is represented by t, wherein t represents the ending year, and t 0 represents the reference year; Is the annual average growth rate of the selling price of the chlorella product, calculated by adopting the compound annual average growth rate (CAGR), namely ,Is the selling price of the terminal year,Is the time span (years).|[0031] S4, constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model;| Specifically, according to the cost model and the direct economic value model obtained in the prior art, a large algae deposition carbon sequestration loss profit accounting model R is constructed, and the expression is as follows: |(6)| in the formula, Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; is the overflow ratio of the byproduct of the algae i compared with the primary product; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term, and I represents a set of microalgae. |[0032] S5, constructing an objective function and constraint conditions, and solving the carbon sequestration loss and gain accounting model of the deposited microalgae to obtain the carbon sequestration loss and gain accounting model of the deposited microalgae with optimal parameters;| specifically, the objective function is: |(7)| is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is a theoretical reference ratio. |[0033] The constraint conditions are as follows:| (1) The industry profit balance condition is that the net profit rate is 10% -15%. Refers to the market price per kilogram of the microalgae i in the t-th year. I.e.|;|(2) The annual total income of all main and byproduct of the algae is greater than the expenditure:|;| (3) The linear relation between the harvesting cost of the microalgae cultivation per kilogram and the production cost of the whole fishery per kilogram is that When (when)In the time-course of which the first and second contact surfaces,,Is the ratio of the total expenditure of the national fishery to the yield of the national aquatic products, yuan/kg;| (4) The cost is lower than the selling price: 。|[0034] the application solves the optimal proportionality coefficient by constructing the constraint optimization framework The coefficient meets the industry profit balance condition, and finally, a large algae deposit carbon sequestration loss profit accounting model with optimal parameters based on net profit margin and dynamic pricing is established.|[0035] FIG. 2 is a flow chart illustrating a method of lost revenue calculation based on carbon sequestration by a large algae deposit, according to an exemplary embodiment. Referring to fig. 2, the method may include:| A1, constructing a large algae deposition carbon sequestration loss profit accounting model with optimal parameters by the construction method; | The method for constructing the model refers to the aforementioned S1-S5, and will not be described here. |[0036] A2, calculating the carbon sequestration loss gain of the deposited microalgae by using a carbon sequestration loss gain accounting model of the deposited microalgae with optimal parameters.|[0037] Table 1 data and parameter source specification table;|[0038] Note that all yield data referred to in this application refer to the dry weight of algae. |[0039] According to the definition of 'annual book of Chinese fishery', the processed product of the microalgae byproduct refers to standardized preserved foods produced by taking the economic microalgae as a raw material, including but not limited to instant products with shelf stability, such as kelp knots, roasted laver, seasoned undaria pinnatifida and the like. The application is definitely limited in the statistical category of the byproduct of the algae of three main economic algae of kelp, laver and undaria pinnatifida.|[0040] The main product price of the algae adopts annual trade average price of import and export general trade, and the data source is China customs office. The prices of the byproducts come from a China local E-commerce platform, and the stores with the highest sales volume are selected to collect historical selling price data. The overflow ratio of the main product (dry weight of economic algae) to the processing byproducts (dry kelp knots, roasted laver and seasoned undaria pinnatifida) was set to γ=0.31 to 2.06, and specific reference values are shown in table 2.|[0041] The yield value calculated by the application only contains the sales income of the primary agricultural and sideline products of the algae, and does not cover the added value of subsequent processing.|[0042] TABLE 2 cost-effective rates of main and byproduct of algaeA reference value table;|[0043] The algae byproduct yield data were obtained from continuous observations of fishery annual survey 2003-2023. Since the existing statistical system does not realize the inter-species distinction of the microalgae byproducts, the microalgae byproducts are distributed to the economic accounting of the microalgae according to the ratio of the microalgae yield to the total yield of each microalgae in the year, the calculation result is shown in table 3, and the fitting diagram is shown in (a) in fig. 3. |[0044] The national fishery production cost data per kilogram is derived from official records of the year of Chinese fishery, 1998-2023, 26 years in succession. The study uses linear regression to analyze historical data, and the model fits the judgment coefficient R 2 to be more than 0.8. Based on this regression model, the national fishery unit production costs during 2025-2060 were predicted, the fitted map is shown in fig. 3 (b), and the data is shown in table 3.|[0045] Table 3 calculation results of the carbon sequestration loss model for the microalgae;|[0046] The invention solves two main core problems in the economic calculation of the carbon sequestration deposited by the microalgae by modeling the benefit of the carbon sequestration deposited by the microalgae, namely, innovation of a cost estimation method. The prior art and data cannot directly quantify the harvesting cost of the microalgae, and the traditional method is easily influenced by industry data fragmentation. The invention provides a fishery cost analogy method (formula 1), and indirect cost estimation is realized by establishing a strict linear proportional relation (model assumption 1) of the cost of the microalgae and the fishery, and mapping a composite structure of fixed cost (fixed asset depreciation + tax) and variable cost (feed, fuel, manual and the like) to the microalgae cultivation. The mathematical rigor of the method is characterized in that the influence of regional production scale difference on cost is eliminated through national fishery total yield standardization treatment. |[0047] Second, the global optimality of dynamic economic systems. Aiming at the uncertainty of the long-term development of the algae industry, the invention provides a 'double dynamic coupling model', wherein ① captures market price fluctuation through time trend extrapolation based on a dynamic pricing mechanism (formula 4) of CAGR, and ② constraint optimization framework (objective function+four-dimensional constraint) realizes double guarantee of industry profit and sustainability.|[0048] Correspondingly, the application also provides electronic equipment, which comprises one or more processors, a memory and a calculation module, wherein the memory is used for storing one or more programs, and when the one or more programs are executed by the one or more processors, the one or more processors realize the calculation module for lost benefit based on carbon sequestration of the microalgae or the calculation method for lost benefit based on carbon sequestration of the microalgae. As shown in fig. 4, a hardware configuration diagram of any device with data processing capability, except for a processor and a memory shown in fig. 4, where the device with data processing capability in the embodiment is located, may further include other hardware according to the actual function of the any device with data processing capability, which is not described herein.|[0049] Correspondingly, the application also provides a computer readable storage medium, wherein computer instructions are stored on the computer readable storage medium, and the instructions are executed by a processor to realize the method for constructing the loss profit accounting model based on carbon sequestration by using the microalgae or the method for calculating the loss profit based on carbon sequestration by using the microalgae. The computer readable storage medium may be an internal storage unit, such as a hard disk or a memory, of any of the data processing enabled devices described in any of the previous embodiments. The computer readable storage medium may also be an external storage device, such as a plug-in hard disk, a smart memory card (SMART MEDIA CARD, SMC), an SD card, a flash memory card (FLASH CARD), etc. provided on the device. Further, the computer readable storage medium may include both internal storage units and external storage devices of any data processing device. The computer readable storage medium is used for storing the computer program and other programs and data required by the arbitrary data processing apparatus, and may also be used for temporarily storing data that has been output or is to be output.|[0050] Other embodiments of the application will be apparent to those skilled in the art from consideration of the specification and practice of the disclosure herein. This application is intended to cover any variations, uses, or adaptations of the application following, in general, the principles of the application and including such departures from the present disclosure as come within known or customary practice within the art to which the application pertains. It is intended that the specification and examples be considered as exemplary only, with a true scope and spirit of the application being indicated by the following claims.|[0051] It is to be understood that the application is not limited to the precise arrangements and instrumentalities shown in the drawings, which have been described above, and that various modifications and changes may be effected without departing from the scope thereof. The scope of the application is limited only by the appended claims. | (CN120471490)|TECHNICAL FIELD|Technical Field|[0001] The application relates to the technical field of ecological carbon sinks, in particular to a loss and gain calculation method based on carbon sequestration by chlorella deposition and electronic equipment.|BACKGROUND ART|[0002] The carbon balance is realized by relying on a multi-element carbon sealing technology path, and the current mainstream carbon sealing technology can be divided into an emission reduction technology and a negative emission technology. Emission reduction technologies include energy replacement, industrial and traffic decarbonization, etc., and negative emission technologies include biomass energy-carbon capture and sequestration (Bioenergy with Carbon Capture and Storage, BECCS), direct air carbon capture and storage (DIRECT AIR Carbon Capture and Storage, DACS), ecological carbon sequestration, etc.|[0003] The energy replacement refers to replacing fossil energy with renewable energy sources such as photovoltaic, wind power and the like, but faces the intermittent power supply and the restriction of land resources, the industrial decarburization refers to modifying a high-carbon flow path through hydrogen-based steelmaking, cement carbon capture and the like, but has cost barriers, the biomass energy-carbon capture and storage (BECCS) refers to combining carbon capture by biomass combustion and occupying cultivated land, the direct air carbon capture and storage (DACS) refers to directly capturing CO 2 from the atmosphere and carrying out storage or utilization, but is subject to high energy consumption and thousands of dollar cost bottlenecks, and compared with the ecological carbon sink refers to carbon fixation by depending on ecological systems such as mangrove, large algae and the like, the ecological carbon sink has the advantages of zero energy consumption, low cost, high-efficiency land utilization, biodiversity gain and the like.|[0004] Because of the differences of the characteristics and application scenes of different carbon sequestration technologies, a targeted cost accounting method is required to evaluate the economic feasibility of different blue carbon paths. The emission reduction technology is based on a flattening energy cost (LCOE) and full Life Cycle Assessment (LCA) framework, so that dominant costs such as photovoltaic module investment, green hydrogen overflow price and the like can be precisely quantized, and the negative emission technology is broken through by accounting methodology due to technical route heterogeneity, and cross-region data comparability and methodology uniformity are urgently needed to be broken through.|[0005] The existing research refers to a land plant resource value evaluation method to evaluate the ecological functions and the value of seaweed such as water quality purification, carbon fixation, oxygen release, heavy metal substance absorption, biological habitat supply and the like. However, these evaluations focused mainly on quantification of historical cumulative ecological value, and did not predict future scenarios, especially direct economic value quantification of carbon sequestration loss by algae deposition not involving the 2060 year long period.|DISCLOSURE|Disclosure of Invention|[0006] In view of the above, the embodiment of the application provides a loss profit calculation method and electronic equipment based on carbon sequestration by chlorella deposition.|[0007] According to a first aspect of an embodiment of the present application, there is provided a loss and gain accounting model construction method based on carbon sequestration by microalgae, including:| Indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; | constructing a cost model of carbon sequestration loss and income of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae, wherein the cost model has the model assumption that 1 is a strict linear relation between the harvesting cost of the ith microalgae per kilogram and the production cost of fishery per kilogram, 2 is a model assumption that the microalgae cultivation industry presents scale income unchanged characteristics in an observation period; | A direct economic value model for quantitatively representing the benefit of carbon sequestration loss of the microalgae through the yield value of the microalgae; | Constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model; | And constructing an objective function and constraint conditions, and solving the chlorella sediment carbon sequestration loss gain accounting model to obtain the chlorella sediment carbon sequestration loss gain accounting model with optimal parameters. |[0008] According to a second aspect of the embodiment of the present application, there is provided a loss and gain calculation method based on carbon sequestration by chlorella sediment, including:| Constructing a large algae deposition carbon sequestration loss profit accounting model with optimal parameters by the construction method of the first aspect; | and calculating the carbon sequestration loss gain of the deposited microalgae by using a carbon sequestration loss gain accounting model of the deposited microalgae with optimal parameters. |[0009] According to a third aspect of an embodiment of the present application, there is provided an electronic apparatus including:| one or more processors; | a memory for storing one or more programs; | the one or more programs, when executed by the one or more processors, cause the one or more processors to implement the method of the first or second aspect. |[0010] According to a fourth aspect of embodiments of the present application there is provided a computer readable storage medium having stored thereon computer instructions which when executed by a processor perform the steps of the method according to the first or second aspect.|[0011] The technical scheme provided by the embodiment of the application can comprise the following beneficial effects:| first, an innovative breakthrough in the cost estimation method. The prior art and data cannot directly quantify the harvesting cost of the microalgae, and the traditional method is easily influenced by industry data fragmentation. The invention creatively provides a fishery cost analogy method (formula 1), and indirect cost estimation is realized by establishing a strict linear proportional relation (model assumption 1) of the algae and the fishery cost, and mapping a composite structure of fixed cost (fixed asset depreciation and tax) and variable cost (feed, fuel and manual) to the algae cultivation field. The mathematical rigor of the method is characterized in that the influence of regional production scale difference on cost is eliminated through national fishery total yield standardization treatment. |[0012] Second, the global optimality of dynamic economic systems. Aiming at the uncertainty of the long-term development of the algae industry, the invention initiates a 'double dynamic coupling model', wherein ① captures market price fluctuation through time trend extrapolation based on a dynamic pricing mechanism (formula 4) of CAGR, and ② constraint optimization framework (objective function+four-dimensional constraint) realizes double guarantee of industry profit and sustainability.|[0013] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the application as claimed.|DRAWINGS DESCRIPTION|[0014] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the application and together with the description, serve to explain the principles of the application.|[0015] FIG. 1 is a flow chart illustrating a method of constructing a lost revenue accounting model based on carbon sequestration by a large algae deposit, according to an exemplary embodiment.|[0016] FIG. 2 is a flow chart illustrating a method of lost revenue calculation based on carbon sequestration by a large algae deposit, according to an exemplary embodiment.|[0017] Fig. 3 is a linear regression graph showing fishery production cost per kilogram (a) and algae byproduct yield (b) according to an exemplary embodiment.|[0018] Fig. 4 is a schematic diagram of an electronic device according to an exemplary embodiment.|INVENTION MODE|Detailed Description|[0019] Reference will now be made in detail to exemplary embodiments, examples of which are illustrated in the accompanying drawings. When the following description refers to the accompanying drawings, the same numbers in different drawings refer to the same or similar elements, unless otherwise indicated. The implementations described in the following exemplary examples do not represent all implementations consistent with the application. Rather, they are merely examples of apparatus and methods consistent with aspects of the application as detailed in the accompanying claims.|[0020] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting of the application. As used in this specification and the appended claims, the singular forms "a," "an," and "the" are intended to include the plural forms as well, unless the context clearly indicates otherwise. It should also be understood that the term "and/or" as used herein refers to and encompasses any or all possible combinations of one or more of the associated listed items.|[0021] It should be understood that although the terms first, second, third, etc. may be used herein to describe various information, these information should not be limited by these terms. These terms are only used to distinguish one type of information from another. For example, first information may also be referred to as second information, and similarly, second information may also be referred to as first information, without departing from the scope of the application. The term "if" as used herein may be interpreted as "at..once" or "when..once" or "in response to a determination", depending on the context.|[0022] Noun interpretation:| Carbon sequestration in the form of carbon sink is a form of carbon sink, which means that large algae convert CO 2 and Dissolved Inorganic Carbon (DIC) in seawater to Dissolved Organic Carbon (DOC) and Particulate Organic Carbon (POC) by photosynthesis, and further to Refractory Dissolved Organic Carbon (RDOC) with strong biological inertness by Microbial Carbon Pump (MCP) mechanism, which can be stored in seawater for long periods of time to form a stable inert dissolved carbon pool in the farmed carbon sink. The existing research shows that even though the most aggressive emission reduction measures are adopted, the 'residual emission gap' still exists in China by about 1.5-3.0 Gt CO 2 every year, and the 'residual emission gap' needs to be counteracted by relying on a negative emission technology. |[0023] The existing research refers to a land plant resource value evaluation method to evaluate the ecological functions and the value of seaweed such as water quality purification, carbon fixation, oxygen release, heavy metal substance absorption, biological habitat supply and the like. However, these evaluations focused mainly on quantification of historical cumulative ecological value, and did not predict future scenarios, especially direct economic value quantification of carbon sequestration loss by algae deposition not involving the 2060 year long period. The research firstly provides a loss and gain calculation method based on carbon sequestration deposited by the microalgae, and aims to quantitatively predict the loss and gain of carbon sequestration deposited by the microalgae until 2060 years so as to make up for the study blank in the field.|[0024] FIG. 1 is a flow chart illustrating a method of constructing a loss and gain accounting model based on carbon sequestration by a large algae deposit, according to an exemplary embodiment, as shown in FIG. 1, the method may include the steps of:| s1, indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; | Specifically, considering that the algae cultivation cost is structurally the same as the fishery cultivation cost, the formula is as follows, which is indirectly estimated by the production cost per kilogram of fishery: |(1)| In the middle of Is the harvesting cost of the microalgae i in each kilogram of t years; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products of the t-th year, including five kinds of aquatic products of fishes, shellfishes, crustaceans, microalgae and others which are cultivated and fished; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is an error term. |[0025] The fixed costs may include fixed asset depreciation and tax payment for fishery, and the variable costs may include feed and seed costs, fuel and ice costs, employee compensation, and other costs.|[0026] S2, constructing a cost model of carbon sequestration loss and income loss of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae;| specifically, the cultivation cost of the algae is equal to the product of the harvesting cost per kilogram and the yield, and the formula is as follows: |(2)| In the middle of Refers to the total cost, unit (yuan) of the cultivation of the microalgae in the t year; refers to the harvest cost per kilogram of the ith algae in units of yuan/kilogram in the t year; Refers to the yield of the ith algae in kilograms at the t year. |[0027] The cost model of the carbon sequestration loss benefit of the algae deposition is as follows:|(3)| In the middle of Refers to the total cost of the cultivation of the microalgae in the t th year; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term; the method is characterized in that the yield of the ith algae in the t year is indicated, I represents the collection of the algae, I represents different algae types and is calculated separately according to different types. |[0028] The model has the following assumptions:| The model is assumed to be 1 that the harvesting cost of the algae i per kilogram has a strict linear relation with the production cost of fishery per kilogram, namely ,。|[0029] Model assume 2 that the algae cultivation industry presents scale gain-invariant (Constant Returns to Scale, CRS) characteristics in the observation period (2025-2060), namely that the unit production cost is not obviously reduced along with the scale expansion of the yield.|[0030] S3, quantitatively representing a direct economic value model of the carbon sequestration loss benefit of the microalgae sediment through the yield value of the microalgae;| Specifically, according to the national statistical bureau accounting standard, the total yield value can be obtained by multiplying the yield of the product and its by-products by the selling price of the unit product/by-products (without tax), and thus the direct economic value (total yield value) of the microalgae ) Consisting of primary byproduct sales revenue, the expression of the direct economic value model is as follows:|(4)| In the middle of Is the total output value; Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; is the overflow ratio of the byproduct of the algae i compared with the primary product; Dynamic pricing mechanism based on time trend is adopted: |(5)| In the middle of The selling price of the i-th algae in the reference year is represented by t, wherein t represents the ending year, and t 0 represents the reference year; Is the annual average growth rate of the selling price of the chlorella product, calculated by adopting the compound annual average growth rate (CAGR), namely ,Is the selling price of the terminal year,Is the time span (years).|[0031] S4, constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model;| Specifically, according to the cost model and the direct economic value model obtained in the prior art, a large algae deposition carbon sequestration loss profit accounting model R is constructed, and the expression is as follows: |(6)| in the formula, Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; is the overflow ratio of the byproduct of the algae i compared with the primary product; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term, and I represents a set of microalgae. |[0032] S5, constructing an objective function and constraint conditions, and solving the carbon sequestration loss and gain accounting model of the deposited microalgae to obtain the carbon sequestration loss and gain accounting model of the deposited microalgae with optimal parameters;| specifically, the objective function is: |(7)| is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is a theoretical reference ratio. |[0033] The constraint conditions are as follows:| (1) The industry profit balance condition is that the net profit rate is 10% -15%. Refers to the market price per kilogram of the microalgae i in the t-th year. I.e.|;|(2) The annual total income of all main and byproduct of the algae is greater than the expenditure:|;| (3) The linear relation between the harvesting cost of the microalgae cultivation per kilogram and the production cost of the whole fishery per kilogram is that When (when)In the time-course of which the first and second contact surfaces,,Is the ratio of the total expenditure of the national fishery to the yield of the national aquatic products, yuan/kg;| (4) The cost is lower than the selling price: 。|[0034] the application solves the optimal proportionality coefficient by constructing the constraint optimization framework The coefficient meets the industry profit balance condition, and finally, a large algae deposit carbon sequestration loss profit accounting model with optimal parameters based on net profit margin and dynamic pricing is established.|[0035] FIG. 2 is a flow chart illustrating a method of lost revenue calculation based on carbon sequestration by a large algae deposit, according to an exemplary embodiment. Referring to fig. 2, the method may include:| A1, constructing a large algae deposition carbon sequestration loss profit accounting model with optimal parameters by the construction method; | The method for constructing the model refers to the aforementioned S1-S5, and will not be described here. |[0036] A2, calculating the carbon sequestration loss gain of the deposited microalgae by using a carbon sequestration loss gain accounting model of the deposited microalgae with optimal parameters.|[0037] Table 1 data and parameter source specification table;|[0038] Note that all yield data referred to in this application refer to the dry weight of algae. |[0039] According to the definition of 'annual book of Chinese fishery', the processed product of the microalgae byproduct refers to standardized preserved foods produced by taking the economic microalgae as a raw material, including but not limited to instant products with shelf stability, such as kelp knots, roasted laver, seasoned undaria pinnatifida and the like. The application is definitely limited in the statistical category of the byproduct of the algae of three main economic algae of kelp, laver and undaria pinnatifida.|[0040] The main product price of the algae adopts annual trade average price of import and export general trade, and the data source is China customs office. The prices of the byproducts come from a China local E-commerce platform, and the stores with the highest sales volume are selected to collect historical selling price data. The overflow ratio of the main product (dry weight of economic algae) to the processing byproducts (dry kelp knots, roasted laver and seasoned undaria pinnatifida) was set to γ=0.31 to 2.06, and specific reference values are shown in table 2.|[0041] The yield value calculated by the application only contains the sales income of the primary agricultural and sideline products of the algae, and does not cover the added value of subsequent processing.|[0042] TABLE 2 cost-effective rates of main and byproduct of algaeA reference value table;|[0043] The algae byproduct yield data were obtained from continuous observations of fishery annual survey 2003-2023. Since the existing statistical system does not realize the inter-species distinction of the microalgae byproducts, the microalgae byproducts are distributed to the economic accounting of the microalgae according to the ratio of the microalgae yield to the total yield of each microalgae in the year, the calculation result is shown in table 3, and the fitting diagram is shown in (a) in fig. 3. |[0044] The national fishery production cost data per kilogram is derived from official records of the year of Chinese fishery, 1998-2023, 26 years in succession. The study uses linear regression to analyze historical data, and the model fits the judgment coefficient R 2 to be more than 0.8. Based on this regression model, the national fishery unit production costs during 2025-2060 were predicted, the fitted map is shown in fig. 3 (b), and the data is shown in table 3.|[0045] Table 3 calculation results of the carbon sequestration loss model for the microalgae;|[0046] The invention solves two main core problems in the economic calculation of the carbon sequestration deposited by the microalgae by modeling the benefit of the carbon sequestration deposited by the microalgae, namely, innovation of a cost estimation method. The prior art and data cannot directly quantify the harvesting cost of the microalgae, and the traditional method is easily influenced by industry data fragmentation. The invention provides a fishery cost analogy method (formula 1), and indirect cost estimation is realized by establishing a strict linear proportional relation (model assumption 1) of the cost of the microalgae and the fishery, and mapping a composite structure of fixed cost (fixed asset depreciation + tax) and variable cost (feed, fuel, manual and the like) to the microalgae cultivation. The mathematical rigor of the method is characterized in that the influence of regional production scale difference on cost is eliminated through national fishery total yield standardization treatment. |[0047] Second, the global optimality of dynamic economic systems. Aiming at the uncertainty of the long-term development of the algae industry, the invention provides a 'double dynamic coupling model', wherein ① captures market price fluctuation through time trend extrapolation based on a dynamic pricing mechanism (formula 4) of CAGR, and ② constraint optimization framework (objective function+four-dimensional constraint) realizes double guarantee of industry profit and sustainability.|[0048] Correspondingly, the application also provides electronic equipment, which comprises one or more processors, a memory and a calculation module, wherein the memory is used for storing one or more programs, and when the one or more programs are executed by the one or more processors, the one or more processors realize the calculation module for lost benefit based on carbon sequestration of the microalgae or the calculation method for lost benefit based on carbon sequestration of the microalgae. As shown in fig. 4, a hardware configuration diagram of any device with data processing capability, except for a processor and a memory shown in fig. 4, where the device with data processing capability in the embodiment is located, may further include other hardware according to the actual function of the any device with data processing capability, which is not described herein.|[0049] Correspondingly, the application also provides a computer readable storage medium, wherein computer instructions are stored on the computer readable storage medium, and the instructions are executed by a processor to realize the method for constructing the loss profit accounting model based on carbon sequestration by using the microalgae or the method for calculating the loss profit based on carbon sequestration by using the microalgae. The computer readable storage medium may be an internal storage unit, such as a hard disk or a memory, of any of the data processing enabled devices described in any of the previous embodiments. The computer readable storage medium may also be an external storage device, such as a plug-in hard disk, a smart memory card (SMART MEDIA CARD, SMC), an SD card, a flash memory card (FLASH CARD), etc. provided on the device. Further, the computer readable storage medium may include both internal storage units and external storage devices of any data processing device. The computer readable storage medium is used for storing the computer program and other programs and data required by the arbitrary data processing apparatus, and may also be used for temporarily storing data that has been output or is to be output.|[0050] Other embodiments of the application will be apparent to those skilled in the art from consideration of the specification and practice of the disclosure herein. This application is intended to cover any variations, uses, or adaptations of the application following, in general, the principles of the application and including such departures from the present disclosure as come within known or customary practice within the art to which the application pertains. It is intended that the specification and examples be considered as exemplary only, with a true scope and spirit of the application being indicated by the following claims.|[0051] It is to be understood that the application is not limited to the precise arrangements and instrumentalities shown in the drawings, which have been described above, and that various modifications and changes may be effected without departing from the scope thereof. The scope of the application is limited only by the appended claims. | Family Number|(115619738)|115619738|Advantages / Prev. Drawbacks|(CN120471490 A)|( . . . ) restriction of land resources , the industrial decarburization refers to modifying a high - carbon flow path through hydrogen - based steelmaking , cement carbon capture and the like , but has cost barriers , the biomass energy - carbon capture and storage ( BECCS ) refers to combining carbon capture by biomass combustion and occupying cultivated land , the direct air carbon capture and storage ( DACS ) refers to directly capturing CO _ 2 from the atmosphere and carrying out storage or utilization , but is ( . . . ) | | IT methods for management | G06F-017/18|G06Q-050/02|G06Q-050/26 | G06F-017/18|G06Q-050/02|G06Q-050/26 | G06F-017/18|G06Q-010/0637|G06Q-050/02|G06Q-050/26 | G06F-017/18|G06Q-010/0637|G06Q-050/02|G06Q-050/26 | PENDING | (CN120471490)|PENDING | ALIVE | (CN120471490)|ALIVE | (CN120471490)|LEGAL DETAILS FOR CN120471490|Actual or expected expiration date=2045-07-15|Legal state=ALIVE|Status=PENDING|Event publication date=2025-07-15|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202510970721|Application date=2025-07-15|Standardized application number=2025CN-0970721|Event publication date=2025-08-12|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN120471490|Publication stage code=A|Publication date=2025-08-12|Standardized publication number=CN120471490|Event publication date=2025-08-12|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2025-08-29|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination | (CN120471490)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=r6DqxGvtRKdmopy9u1QSm1fn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000078577803&ekey=2168&xpn=CN120471490&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=G3%252B7UR0N%252FN9%252B3AXWcwalG5NXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN120471490)|CN | (CN120471490)|NAME=HAINAN INSTITUTE OF ZHEJIANG UNIVERSITY , COUNTRY=CN | (CN120471490)|NAME=YING KONGYUE;HANGZHOU JUNRUIDA INTELLECTUAL PROPERTY AGENCY CO., LTD. , REG=33544 | (CN120471490)|CN | (CN120471490)|NAME=FAN WEI, COUNTRY=CN |NAME=YUE LULU|NAME=QI YIFAN|NAME=ZOU ZHIYU|NAME=QU MENGJIE | (CN120471490)|4 | 1 | 1 | (CN120471490)|Number of Claims: NCL=10|Gazette date: GAZDATE=2025-08-12|Gazette number: GAZNUM=41-3301|Number of Pages: NPAGES=13| | (CN120471490)|CHINESE (CHI) | (CN120471490)|Patent | Titre: (CN120471490)|Loss income calculation method based on large algae deposition carbon sequestration and electronic equipment Résumé: (CN120471490)|The invention discloses a loss income calculation method based on large algae deposition carbon sequestration and electronic equipment. The method comprises the following steps: indirectly estimating the harvesting cost of each kilogram of large algae through the production cost of each kilogram of fishery; according to the harvesting cost of the big algae per kilogram and the annual yield of the big algae, constructing a cost model of the big algae deposition carbon sequestration loss income; the direct economic value model of the large algae deposition carbon sequestration loss income is quantitatively represented through the large algae output value; according to the cost model and the direct economic value model, constructing a large algae deposition carbon sequestration profit and loss accounting model; constructing an objective function and constraint conditions according to industry profit equilibrium conditions, and solving the large algae deposition carbon sequestration profit and loss accounting model to obtain optimal parameters; and carrying out loss income calculation by using the big algae deposition carbon sequestration profit and loss accounting model with the optimal parameters. Autre: (CN120471490)|1. The lost revenue accounting model construction method based on carbon sequestration of the microalgae is characterized by comprising the following steps:| Indirectly estimating the harvesting cost of the microalgae per kilogram through the production cost per kilogram of fishery; | constructing a cost model of carbon sequestration loss and income of the microalgae sediment according to the harvesting cost of the microalgae per kilogram and the annual yield of the microalgae, wherein the cost model has the model assumption that 1 is a strict linear relation between the harvesting cost of the ith microalgae per kilogram and the production cost of fishery per kilogram, 2 is a model assumption that the microalgae cultivation industry presents scale income unchanged characteristics in an observation period; | A direct economic value model for quantitatively representing the benefit of carbon sequestration loss of the microalgae through the yield value of the microalgae; | Constructing a large algae deposition carbon sequestration loss profit accounting model according to the cost model and the direct economic value model; | And constructing an objective function and constraint conditions, and solving the chlorella sediment carbon sequestration loss gain accounting model to obtain the chlorella sediment carbon sequestration loss gain accounting model with optimal parameters. |2. The method according to claim 1, wherein the formula for indirectly estimating the harvesting cost per kilogram of microalgae through the production cost per kilogram of fishery is as follows:|;| In the middle of Is the harvesting cost of the microalgae i in each kilogram of t years; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is an error term. |3. The method of claim 1, wherein the cost model for carbon sequestration loss benefit for the macroalgae deposit is expressed as follows:|;| In the middle of Refers to the total cost of the cultivation of the microalgae in the t th year; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term; The yield of the ith algae in the t year is indicated, and I represents the collection of the algae. |4. The method of claim 1, wherein the expression of the direct economic value model is as follows:|;| In the middle of Is the total output value; Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; is the overflow ratio of the byproduct of the algae i compared with the primary product; Dynamic pricing mechanism based on time trend is adopted: |;| In the middle of The selling price of the i-th algae in the reference year is represented by t, wherein t represents the ending year, and t 0 represents the reference year; is the annual average increase rate of the selling price of the algae products, ,The selling price is finished; Is the time span. |5. The method according to claim 1, wherein the expression of the macroalgae deposit carbon sequestration loss profit accounting model R is as follows:|;| in the formula, Refers to the yield of the ith algae in the t year; is the selling price of the ith algae in the t year; Is the byproduct yield of the algae i in the t year; Is the overflow ratio of the byproduct of the algae i compared with the primary product; And (3) with The fixed cost and the variable cost of the fishery production of the t year are respectively; Is the total yield of fishery aquatic products in the t th year; is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; is an error term, and I represents a set of microalgae. |6. The method of claim 5, wherein the objective function is:|;| is the proportionality coefficient of the harvesting cost of the algae i per kilogram and the production cost of fishery per kilogram; Is a theoretical reference ratio. |7. The method of claim 5, wherein the constraints are:| (1) The industry profit balance condition is that the net profit margin is 10% -15%, namely |;|(2) The annual total income of all main and byproduct of the algae is greater than the expenditure:|;| (3) The linear relation between the harvesting cost of the microalgae cultivation per kilogram and the production cost of the whole fishery per kilogram is that When (when)In the time-course of which the first and second contact surfaces,,Is the ratio of the total expenditure of fishery and the yield of aquatic products;| (4) The cost is lower than the selling price: 。|8. the loss profit calculation method based on carbon sequestration by chlorella deposition is characterized by comprising the following steps: | constructing a large algae deposit carbon sequestration loss profit accounting model with optimal parameters by the construction method of claim 1; | and calculating the carbon sequestration loss gain of the deposited microalgae by using a carbon sequestration loss gain accounting model of the deposited microalgae with optimal parameters. |9. An electronic device, comprising:| one or more processors; | a memory for storing one or more programs; | the one or more programs, when executed by the one or more processors, cause the one or more processors to implement the method of any of claims 1-8. |10. A computer readable storage medium having stored thereon computer instructions which, when executed by a processor, implement the method of any of claims 1-8. | 8 | Abstract | gpt-4o-mini | no | The article focuses on carbon sequestration from large algae without involving biomass energy production or carbon capture and storage systems. | |||||||||||||||||||||||||
| 9 | US63/513,706P|US18/771,456 | US18/771,456 | US20250018356 | 112981296 | US20250018356 A1 2025-01-16 [US20250018356] | 2023-07-14|2024-07-12 | 2024-07-12 | 2025-01-16 | (US20250018356)|2044-07-12 | (US20250018356)|Systems and methods for thermal storage integration into high temperature decomposition reactor | (US20250018356)|A high-temperature decomposition reactor is provided. The reactor includes a reaction vessel, a furnace, and an insulation layer. The reaction vessel includes an inner volume configured to contain a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium. The furnace is disposed around the reaction vessel and includes a furnace material. The furnace material is configured to simultaneously absorb heat and transmit heat. In some instances, the furnace material transmits heat to the inner volume to heat the carbonated medium. The insulation layer is disposed around the furnace and configured to prevent thermal losses from the reactor. | HEIRLOOM CARBON TECHNOLOGY | (US20250018356)|Heirloom Carbon Technologies, Inc. ([US]) | MCQUEEN NOAH|SAMALA SHASHANK|DUBEL ANDREW | (US20250018356)|MCQUEEN Noah|SAMALA Shashank|DUBEL Andrew | (US20250018356)|Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|Thus, a need exists for a means of energy storage in high temperature reactors.|Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO_2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO_2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | (US20250018356)|1. A reactor, comprising: a reaction vessel defining an inner volume configured to contain a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium; a furnace disposed around the reaction vessel, the furnace including a furnace material configured to absorb and/or transmit heat; and an insulation layer disposed around the furnace and configured to reduce thermal losses from the reactor.|12. A method, comprising: feeding a carbonated medium into an inner volume of a reaction vessel; heating a furnace material, the furnace material contacting and at least partially surrounding the reaction vessel; transferring heat from the furnace material to the inner volume of the reaction vessel such that the carbonated medium is separated into a carbonation medium and carbon dioxide; removing the carbon dioxide from the reaction vessel; and removing the carbonation medium from the reaction vessel.| | (US20250018356)|A high-temperature decomposition reactor is provided. The reactor includes a reaction vessel, a furnace, and an insulation layer.| | (US20250018356)|REACTOR(100,32)|STORAGE INTEGRATION(100,1)|TEMPERATURE DECOMPOSITION REACTOR(100,1)|TERRESTRIAL BIOSPHERE(100,1)|TONNE(87,333)|OCEAN UPTAKE(77,1)|CARBONATED MEDIUM TRANSITION(76,3)|FURNACE(72,62)|GLOBAL RELIANCE(70,1)|MEDIUM CARBONATION(69,19)|ANDAN INSULATION LAYER(69,1)|CARBONATION MEDIUM(66,16)|NATURAL ACCELERATION(58,1)|FURNACE MATERIAL(53,16)|DECOMPOSITION REACTOR(50,14)|REACTOR VESSEL(49,8)|ENTERPRISE USER(48,1)|INSULATION LAYER(45,41)|PORTFOLIO(45,1)|REACTION VESSEL(44,119)|CUSTOMIZATION(41,1)|DESIRE(41,1)|FACILITATION(39,15)|RENEWABLE ELECTRICITY SOURCE(38,2)|BIOENERGY(38,1)|DATABASE CONFIGURATION(38,1)|INNER VOLUME(37,31)|CARBONATION(37,4)|FOREST(33,1)|FRAMEWORK(33,1)|QUARTZITE(32,4)|BECCS(32,1)|MOLTEN SALT(30,6)|FOSSIL FUEL(30,1)|BASALT(29,4)|GRANITE(29,4)|MINERAL(29,1)|RELATIONAL MODEL(29,1)|FURNACE POROSITY(27,8)|GRAPHITE(27,6)|POLYISOCYANURATE(27,2)|SYNTAX STRUCTURE(27,1)|LITHIUM NITRATE(26,3)|PERICLASE(26,2)|TEMPERATURE REACTOR(25,4)|DATA TRANSMISSION(25,1)|SIMULTANEOUSLY ABSORB HEAT(25,1)|CARBON DIOXIDE(23,9)|POTASSIUM NITRATE(22,4)|REACTOR SEQUESTRATION CAPACITY(22,4)|AXIS AX(21,19)|CARBONATED MEDIUM THROUGHPUT(21,5)|CEMENTITIOUS FOAM(21,2)|FIBERGLASS(21,2)|N ETHYLPYRIDINIUM(20,2)|PERLITE(20,2)|POLYSTYRENE(20,2)|POLYURETHANE(20,2)|ROTATIONAL MOTION(20,2)|TRANSFERRING HEAT(20,1)|SODIUM NITRATE(19,4)|LOSS PREVENTION(19,1)|CARBONATION PLOT(18,3)|CARBONATION MEDIA(17,4)|MINERAL WOOL(17,2)|SODIUM CHLORIDE(15,3)|ACETYLENE TORCH(15,2)|CALCINE CARBONATED MEDIUM(15,2)|CARBONATED MEDIUM CDM(15,2)|CARBONATION MEDIUM CNM(15,2)|METAL CONDUCTION(14,4)|FURNACE THICKNESS(13,7)|POTENTIAL ENERGY(13,6)|CARBONATED MEDIA(13,3)|CARBONATED MEDIUM DECOMPOSITION(13,2)|CARBONATION MEDIUM THROUGHPUT(13,2)|CARBON CAPTURE(12,5)|CARBONATION METRIC TONNE(12,1)|MATERIAL CONDUCTION(12,1)|ELECTRICITY INPUT(11,4)|ALUMINA REFRACTORY MATERIAL(11,2)|GEOTHERMAL POWER(11,2)|LESSER POROSITY(11,2)|NATURAL FIBER(11,2)|DIVERSE PORTFOLIO(11,1)|NONCONTIGUOUS PLOT(11,1)|UNLISTED ITEM(11,1)|INSULATION THICKNESS(10,5)|SOLAR POWER(10,2)|CALCINER(9,4)|LAYER INSULATION(9,4)|ENERGY STORAGE(9,3)|CARBONATION MEDIUM REMOVAL(9,2)|NONLINEARITY(9,2)|STORAGE MATERIAL(9,2)|SWEEP GAS INLET(9,2)|CALCINATION REACTOR(9,1)|DECOMPOSED CARBONATED MEDIUM(9,1)|DIRECT AIR CAPTURE(9,1)|INSULATION POROSITY(9,1)|PLURAL REFERENT(9,1)|SPECIES CALCINATION(9,1)|ROTATIONAL VELOCITY(8,7)|CALCINING TEMPERATURE(8,3)|VOID VOLUME(8,3)|EXCLUSIVITY TERM(8,1)|ROSE QUARTZ(8,1)|SIMULTANEOUS CHARGING(8,1)|ELECTROCHEMICAL CELL(7,4)|WINDPOWER(7,2)|LIMESTONE(6,2)|REACTOR CLOCKWISE ROTATION(6,2)|REACTOR COUNTERCLOCKWISE ROTATION(6,2)|RENEWABLE ELECTRICITY(6,2)|BLUE STONE(6,1)|CARBON DIOXIDE SEQUESTRATION(6,1)|CARBON DIOXIDE TONNE(6,1)|CARBONATION MEDIUM PRODUCTION(6,1)|ENERGY SURPLUS(6,1)|EXCLUSION LIMIT(6,1)|GEOMETRIC RELATIONSHIP(6,1)|MITIGATION(6,1)|SEQUESTRATION SPACE(6,1)|SINGULAR FEATURE(6,1)|STORAGE ENTITY(6,1)|TERM ORDINARY MEANING(6,1)|CALCIUM CARBONATE(5,3)|SOLAR CELL(5,3)|SOLAR PANEL(5,3)|SUN(5,3)|ALABASTER(4,1)|AMBIENT ENVIRONMENT(4,1)|AMETHYST(4,1)|ARAGONITE(4,1)|CALCITE(4,1)|CALM WEATHER(4,1)|CAPITAL INVESTMENT(4,1)|CARBONATED MEDIUM MOVEMENT(4,1)|COMPRESSOR(4,1)|CONDENSATION(4,1)|CONVEYER(4,1)|CREVICE(4,1)|DACS(4,1)|DEHYDRATION(4,1)|DICTIONARY DEFINITION(4,1)|DISCHARGING HEAT(4,1)|DISPENSING(4,1)|DISSOLUTION PRECIPITATION(4,1)|DOLOMITE(4,1)|DOLOMITIC LIME(4,1)|ENERGY BACKUP SOURCE(4,1)| | (US20250018356)|1. A reactor, comprising:| a reaction vessel defining an inner volume configured to contain a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium;| a furnace disposed around the reaction vessel, the furnace including a furnace material configured to absorb and/or transmit heat; and| an insulation layer disposed around the furnace and configured to reduce thermal losses from the reactor.|2. The reactor of claim 1, wherein the reaction vessel comprises a conductive metal.|3. The reactor of claim 1, wherein the reaction vessel comprises a thermal storage material.|4. The reactor of claim 1, wherein the furnace includes at least one of graphite, granite, basalt, quartzite.|5. The reactor of claim 1, wherein the furnace includes a chamber configured to contain a flow of molten salt.|6. The reactor of claim 1, wherein the insulation layer includes at least one of periclase, a silica based refractory material, an alumina-based refractory material, fiberglass, mineral wool, cellulose, natural fibers, cementitious foam, polyurethane, perlite, polystyrene, or polyisocyanurate.|7. The reactor of claim 1, further comprising:| a rotation mechanism configured to impart rotational motion of-to the reaction vessel.|8. The reactor of claim 1, wherein the furnace material is configured to simultaneously absorb and transmit heat.|9. The reactor of claim 5, wherein the molten salt includes at least one of sodium nitrate, lithium nitrate, potassium nitrate, sodium chloride, or N-ethylpyridinium.|10. The reactor of claim 7, further comprising:| a facilitation device disposed in the reaction vessel, the facilitation device configured to move the carbonated medium from a first position to a second position within the reactor vessel when the rotation mechanism imparts rotational motion to the reactor vessel.|11. The reactor of claim 9, wherein the second position is at a lower potential energy state than the first position.|12. A method, comprising:| feeding a carbonated medium into an inner volume of a reaction vessel;| heating a furnace material, the furnace material contacting and at least partially surrounding the reaction vessel;| transferring heat from the furnace material to the inner volume of the reaction vessel such that the carbonated medium is separated into a carbonation medium and carbon dioxide;| removing the carbon dioxide from the reaction vessel; and| removing the carbonation medium from the reaction vessel.|13. The method of claim 12, wherein heating the furnace material includes providing heat to the furnace material from a renewable electricity source, the renewable electricity source including at least one of solar power, wind power, or geothermal power.|14. The method of claim 12, wherein the furnace material includes at least one of graphite, granite, basalt, quartzite.|15. The method of claim 12, wherein the furnace material includes a molten salt.|16. The method of claim 15, wherein the molten salt including at least one sodium nitrate, lithium nitrate, potassium nitrate, sodium chloride, or N-ethylpyridinium.|17. The method of claim 12, further comprising:| rotating the reaction vessel to facilitate the movement of the carbonated medium through the reaction vessel from a first end of the reactor vessel to a second end of the reactor vessel.|18. The method of claim 17, wherein the first end of the reactor vessel is at a lower potential energy state than the second end of the reactor vessel.|19. The method of claim 12, further comprising:| purifying the carbon dioxide.|20. The method of claim 12, wherein the reactor vessel comprises a conductive material. | (US20250018356)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims the benefit of U.S. Provisional Application No. 63/513,706, entitled “Systems and Methods for Thermal Storage Integration into High-Temperature Decomposition Reactor,” filed Jul. 14, 2023, the disclosure of which is incorporated herein by reference.|(US20250018356)|TECHNICAL FIELD|[0002] Embodiments described herein relate to extraction and sequestration of carbon dioxide from ambient air.|BACKGROUND|[0003] The atmospheric concentration of carbon dioxide (CO2) has reached 420 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 billion tonnes of C02 per year (GtCO2/year), a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's average surface temperature by the year 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. State of the art DACS systems rely on media to capture CO2 from the atmosphere.|[0004] High temperature reactors can be used to separate CO2 from media used to capture the CO2. High temperature reactors often require continuous operation to avoid extensive startup and shutdown periods, as well as to utilize the capital investment. However, the availability of renewable energy sources is typically intermittent—limited to times when the sun is shining and/or wind is blowing. Thus, a need exists for a means of energy storage in high temperature reactors.|SUMMARY|[0005] Embodiments described herein relate to thermal energy storage in high temperature reactors (e.g., calciners). In some aspects, a reactor can include a reaction vessel that includes an inner volume the contains a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium. The reactor can further include a furnace disposed around the reaction vessel. The furnace includes a furnace material that simultaneously absorbs and transmits heat. The reactor further includes an insulation layer disposed around the furnace. The insulation layer can prevent thermal losses from the reactor. In some embodiments, the reaction vessel can be composed of a conductive metal. In some embodiments, the reaction vessel can be composed of a thermal storage material. In some embodiments, the furnace can include graphite, granite, basalt, and/or quartzite. In some embodiments, the reactor can include a crevice, into which molten salt circulates to provide heat to the reaction vessel.|(US20250018356)|BRIEF DESCRIPTION OF THE DRAWINGS|[0006] FIG. 1 is a block diagram of a high-temperature decomposition reactor, according to an embodiment.|[0007] FIG. 2 is an illustration of a high-temperature decomposition reactor, according to an embodiment.|[0008] FIG. 3 is a perspective view of a portion of the high-temperature decomposition reactor of FIG. 2.|[0009] FIG. 4 is a perspective view of a portion of a high-temperature decomposition reactor, according to an embodiment.|[0010] FIG. 5 is a flow diagram of a method of operating the high-temperature decomposition reactor of any of FIGS. 1-4.|(US20250018356)|DETAILED DESCRIPTION|[0011] Integrating thermal energy storage into a high-temperature reactor can enable the use of stored energy during hours when renewable energy is normally not available, abundant, or cheap. Such thermal integration can also enable use of such resources when they are not available (e.g., using stored solar energy at night, using stored wind energy during calm weather). Integrated energy storage can ease the issues caused by the intermittency of renewable energy sources and can reduce the cost of energy, as energy surpluses can be stored during the day when such resources are available. This can also act as a means to store excess energy from the grid for use.|[0012] Materials that store thermal energy (e.g., graphite) can also allow the use of multiple electricity inputs as a source of energy. For example, a first electricity input can be fed from an onsite renewable energy source (e.g., solar, wind) and a second electricity input can be fed from the electric grid. The second electricity input can allow for a backup source of energy when there are prolonged periods of time, in which renewable energy is not directly available (e.g., times when the wind is not blowing and/or the sun is not shining).|[0013] In the current state of the art, thermal storage systems are in development for various applications, including building temperature control, point source carbon capture, and renewable energy storage. These systems often include a single block of solid material. In some cases, such systems can include liquids and/or gases. These blocks are used to consistently provide heat to the system.|[0014] Embodiments described herein include the integration of a thermal storage system and a calcining reactor into a single piece of equipment that can increase the thermal efficiency of the system and prevent energy losses associated with transport from the storage entity to the reaction system itself. Several other approaches include individual charging and discharging of the system's energy. Embodiments described herein include simultaneous charging and discharging of a thermal storage system.|[0015] In some embodiments, calciners or other processing equipment described herein can be the same or substantially similar to equipment described in U.S. patent application Ser. No. 18/067,896 (“the '896 application”), filed Dec. 19, 2022, and titled “Systems and Methods of Carbon Capture from Cement Production Process,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, carbonation media or carbonated media described herein can be the same or similar to those described in the '896 application. In some embodiments, carbonation media or carbonated media described herein can include water, or can be processed with water to improve uptake, as described in International Patent Publication No. US2022/018484 (“the '484 publication”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering in and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety.|[0016] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions.|[0017] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0018] As used herein, “carbonation medium” refers to a medium that can take on carbon dioxide when exposed to ambient air. This can include but is not limited to calcium oxide (CaO), calcium hydroxide (Ca(OH)2), magnesium oxide (MgO), magnesium hydroxide (MgOH), sodium oxide (Na2O), sodium hydroxide (NaOH), and/or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation medium can originate from a natural source (e.g., limestone). Carbonation medium can also be regenerated or recycled (i.e., a regenerated carbonated medium from a calciner).|[0019] As used herein, “carbonated medium” refers to a carbonation medium that has taken up carbon dioxide from ambient air. This can include but is not limited to calcium carbonate (CaCO3), magnesium carbonate (MgCO3), sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), mixed calcium-magnesium carbonate phases ((Ca,Mg)CO3). Carbonated medium can be converted back to a carbonation medium (e.g., via the use of a calciner, a dissolution/precipitation-based system, and/or an electrochemical system).|[0020] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0021] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0022] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of electrodes, the set of electrodes can be considered as one electrode with multiple portions, or the set of electrodes can be considered as multiple, distinct electrodes. Additionally, for example, when referring to a plurality of electrochemical cells, the plurality of electrochemical cells can be considered as multiple, distinct electrochemical cells or as one electrochemical cell with multiple portions. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0023] FIG. 1 is a block diagram of a high-temperature decomposition reactor 100 (hereinafter “reactor 100”), according to an embodiment. As shown, the reactor 100 includes a reaction vessel 110, a furnace 130, and an insulation layer 150. In some embodiments, the reactor 100 is used for calcination of species used for carbon capture.|[0024] The reaction vessel 110 includes an inner volume (not shown), in which heat permeates (e.g., to facilitate calcination). In some embodiments, the heat that permeates into the reaction vessel 110 can be a direct product solar energy. In other words, the sun can shine onto the furnace 130 and heat the furnace 130, and the heat in the furnace 130 can radiate into the reaction vessel 110. In some embodiments, the heat that permeates into the reaction vessel 110 can be a product of energy collected on solar cells and/or solar panels. In some embodiments, the heat that permeates into the reaction vessel 110 can be provided via electricity. In some embodiments, the heat that permeates into the reaction vessel 110 can be a product of wind energy (e.g., electricity from wind energy). In some embodiments, the heat that permeates into the reaction vessel 110 can be provided by electricity. In some embodiments, the heat that permeates into the reaction vessel 110 can be provided by combustion.|[0025] In some embodiments, the reaction vessel 110 can be composed of a metal. In some embodiments, the reaction vessel 110 can be composed of a conductive metal. In some embodiments, the reaction vessel 110 can be composed of stainless steel, 304 stainless steel, 316 stainless steel, aluminum, iron, wrought iron, cast iron, brass, tin, copper, antimony, or any combination thereof. In some embodiments, the reaction vessel 110 can be composed of an alloy. In some embodiments, the reaction vessel 110 can be composed of a copper-containing alloy. In some embodiments, the reaction vessel 110 can be composed of an aluminum-containing alloy. In some embodiments, the reaction vessel 110 can be formed via extrusion. In some embodiments, the reaction vessel 110 can be formed via welding of a metal sheet. In some embodiments, the reaction vessel 110 can be formed via electric resistance welding (ERW) of a metal sheet. In some embodiments, the reaction vessel 110 can be formed via acetylene torch welding of a metal sheet.|[0026] In some embodiments, during operation, the volume in the reaction vessel 110 can have a temperature of at least about 400° C., at least about 450° C., at least about 500° C., at least about 550° C., at least about 600° C., at least about 650° C., at least about 700° C., at least about 750° C., at least about 800° C., at least about 850° C., at least about 900° C., at least about 950° C., at least about 1,000° C., at least about 1,050° C., at least about 1,100° C., at least about 1,150° C., at least about 1,200° C., at least about 1,250° C., at least about 1,300° C., at least about 1,350° C., at least about 1,400° C., or at least about 1,450° C. In some embodiments, during operation, the volume in the reaction vessel 110 can have a temperature of no more than about 1,500° C., no more than about 1,450° C., no more than about 1,400° C., no more than about 1,350° C., no more than about 1,300° C., no more than about 1,250° C., no more than about 1,200° C., no more than about 1,150° C., no more than about 1,100° C., no more than about 1,050° C., no more than about 1,000° C., no more than about 950° C., no more than about 900° C., no more than about 850° C., no more than about 800° C., no more than about 750° C., no more than about 700° C., no more than about 650° C., no more than about 600° C., no more than about 550° C., no more than about 500° C., or no more than about 450° C. Combinations of the above-referenced temperatures are also possible (e.g., at least about 400° C. and no more than about 1,500° C. or at least about 750° C. and no more than about 1,200° C.) inclusive of all values and ranges therebetween. In some embodiments, during operation, the volume within the reaction vessel 110 can have a temperature of about 400° C., about 450° C., about 500° C., about 550° C., about 600° C., about 650° C., about 700° C., about 750° C., about 800° C., about 850° C., about 900° C., about 950° C., about 1,000° C., about 1,050° C., about 1,100° C., about 1,150° C., about 1,200° C., about 1,250° C., about 1,300° C., about 1,350° C., about 1,400° C., about 1,450° C., or about 1,500° C.|[0027] In some embodiments, the inner volume of the reaction vessel 110 can have a volume of at least about 10 L, at least about 20 L, at least about 30 L, at least about 40 L, at least about 50 L, at least about 60 L, at least about 70 L, at least about 80 L, at least about 90 L, at least about 100 L, at least about 200 L, at least about 300 L, at least about 400 L, at least about 500 L, at least about 600 L, at least about 700 L, at least about 800 L, at least about 900 L, at least about 1 m3, at least about 2 m3, at least about 3 m3, at least about 4 m3, at least about 5 m3, at least about 6 m3, at least about 7 m3, at least about 8 m3, at least about 9 m3, at least about 10 m3, at least about 20 m3, at least about 30 m3, at least about 40 m3, at least about 50 m3, at least about 60 m3, at least about 70 m3, at least about 80 m3, at least about 90 m3, at least about 100 m3, at least about 200 m3, at least about 300 m3, at least about 400 m3, at least about 500 m3, at least about 600 m3, at least about 700 m3, at least about 800 m3, at least about 900 m3. In some embodiments, the space inside the reaction vessel 110 can have a volume of no more than about 1,000 m3, no more than about 900 m3, no more than about 800 m3, no more than about 700 m3, no more than about 600 m3, no more than about 500 m3, no more than about 400 m3, no more than about 300 m3, no more than about 200 m3, no more than about 100 m3, no more than about 90 m3, no more than about 80 m3, no more than about 70 m3, no more than about 60 m3, no more than about 50 m3, no more than about 40 m3, no more than about 30 m3, no more than about 20 m3, no more than about 10 m3, no more than about 9 m3, no more than about 8 m3, no more than about 7 m3, no more than about 6 m3, no more than about 5 m3, no more than about 4 m3, no more than about 3 m3, no more than about 2 m3, no more than about 1 m3, no more than about 900 L, no more than about 800 L, no more than about 700 L, no more than about 600 L, no more than about 500 L, no more than about 400 L, no more than about 300 L, no more than about 200 L, no more than about 100 L, no more than about 90 L, no more than about 80 L, no more than about 70 L, no more than about 60 L, no more than about 50 L, no more than about 40 L, no more than about 30 L, or no more than about 20 L. Combinations of the above-referenced volumes are also possible (e.g., at least about 10 L and no more than about 1,000 m3 or at least about 50 L and no more than about 1 m3), inclusive of all values and ranges therebetween. In some embodiments, the space inside the reaction vessel 110 can have a volume of about 10 L, about 20 L, about 30 L, about 40 L, about 50 L, about 60 L, about 70 L, about 80 L, about 90 L, about 100 L, about 200 L, about 300 L, about 400 L, about 500 L, about 600 L, about 700 L, about 800 L, about 900 L, about 1 m3, about 2 m3, about 3 m3, about 4 m3, about 5 m3, about 6 m3, about 7 m3, about 8 m3, about 9 m3, about 10 m3, about 20 m3, about 30 m3, about 40 m3, about 50 m3, about 60 m3, about 70 m3, about 80 m3, about 90 m3, about 100 m3, about 200 m3, about 300 m3, about 400 m3, about 500 m3, about 600 m3, about 700 m3, about 800 m3, about 900 m3, or about 1,000 m3.|[0028] The furnace 130 is disposed around the outside of the reaction vessel 110 and is composed of a material (e.g., furnace material) capable of storing energy (e.g., renewable energy) and dispensing (e.g., discharging) the renewable energy into the reaction vessel 110 as heat. In some embodiments, the furnace 130 is symmetrically disposed around the reaction vessel 110 such that an equal or substantially equal thickness of the furnace 130 is disposed around the reaction vessel 110. In some embodiments, the furnace 130 is asymmetrically disposed around the reaction vessel 110 such that a greater thickness of the furnace 130 is disposed around some portions of the reaction vessel 130 than other portions. In some embodiments, the furnace 130 has a cylindrical shape or a substantially cylindrical shape. In some embodiments, the furnace 130 can have a rectangular pyramidal shape. In some embodiments, the furnace 130 can be composed of a solid thermal storage material. In some embodiments, the furnace 130 can include graphite. Graphite can simultaneously store energy and dispense the energy in the form of heat to the reaction vessel 110. In some embodiments, the furnace 130 can include granite, basalt, quartzite, travertine, sandstone, marble, slate, quartz, onyx, bluestone, laterite, dolomite, alabaster, amethyst, soapstone, metamorphic rock, gneiss, igneous rock, sedimentary rock, flint, jasper, rose quartz, or any other forms of stone or combinations thereof. In some embodiments, the furnace 130 can include a chamber, through which molten salt flows. The molten salt can provide heat to the reaction vessel. In some embodiments, the furnace 130 can be composed of sodium nitrate, lithium nitrate, potassium nitrate, sodium chloride, N-ethylpyridinium bromide mixtures if sodium nitrate and potassium nitrate, or any combination thereof.|[0029] The insulation layer 150 inhibits or at least partially prevents thermal losses from the reactor 100. In some embodiments, the insulation layer 150 can be composed of an insulative material. In some embodiments, the insulation layer 150 can be composed of a refractory material. In some embodiments, the insulation layer 150 can include periclase. In some embodiments, the insulation layer 150 can include a silica-based refractory material. In some embodiments, the insulation layer 150 can include an alumina-based refractory material. In some embodiments, the insulation layer 150 can include a fibrous material. In some embodiments, the insulation layer 150 can include fiberglass, mineral wool, cellulose, natural fibers, cementitious foam, polyurethane, perlite, polystyrene, polyisocyanurate, or any combination thereof. In some embodiments, the insulation layer 150 can be disposed about the furnace 130 symmetrically such that an equal thickness of the insulation layer 150 covers the exterior surface area of the furnace 130.|[0030] FIG. 2 is an illustration of a high-temperature decomposition reactor 200 (hereinafter “reactor 200”), according to an embodiment. As shown, the reactor 200 includes a reaction vessel 210, a furnace 230, and an insulation layer 250. In some embodiments, the reaction vessel 210, the furnace 230, and the insulation layer 250 can be the same or substantially similar to the reaction vessel 110, the furnace 130, and the insulation layer 150, as described above with reference to FIG. 1. Thus, certain aspects of the reaction vessel 210, the furnace 230, and the insulation layer 250 are not described in greater detail herein.|[0031] In use, carbonated medium CDM enters an inner volume 212 of the reaction vessel 210 at a first vessel end 214. As the carbonated medium CDM is heated within the inner volume 212, the carbonated medium CDM is separated (e.g., decomposed) into a carbonation medium CNM and a gas G. The carbonation medium CNM exits the reaction vessel 210 at a second vessel end 216.|[0032] The gas G exits the reaction vessel 210 via a conduit 260 fluidly coupled to the inner volume 212. While the conduit 260 is shown positioned proximate to the first vessel end 214, the conduit 260 may be disposed at any position along the length of the reaction vessel 210 between the first vessel end 214 and the second vessel end 216. In some implementations, the conduit 260 is in fluid communication with a sequestration space (e.g., CO2 sequestration space) positioned at an end of the conduit 260 opposite the inner volume 212. An optional sweep gas inlet 261 is shown near the second vessel end 216.|[0033] FIG. 3 is a detailed illustration of a portion of the reactor 200 of FIG. 2, as viewed along view window AA. Heat permeates into the inner volume 212 to facilitate calcination. In some embodiments, the heat that permeates into the inner volume 212 can be a direct product solar energy. In some embodiments, the heat that permeates into the inner volume 212 can be a product of energy collected on solar cells and/or solar panels. In other words, electricity collected via solar cells and/or solar panels can be converted to heat. In some embodiments, the heat that permeates into the inner volume 212 is a product of wind energy. In other words, electricity collected via wind energy can be converted to heat.|[0034] In some embodiments, the reaction vessel 210 can be composed of a metal. In some embodiments, the reaction vessel 210 can be composed of a conductive metal. In some embodiments, the reaction vessel 210 can be composed of stainless steel, 304 stainless steel, 316 stainless steel, aluminum, iron, wrought iron, cast iron, brass, tin, copper, antimony, or any combination thereof. In some embodiments, the reaction vessel 210 can be composed of an alloy. In some embodiments, the reaction vessel 210 can be composed of a copper-containing alloy. In some embodiments, the reaction vessel 210 can be composed of an aluminum-containing alloy. In some embodiments, the reaction vessel 210 can be formed via extrusion. In some embodiments, the reaction vessel 210 can be formed via welding of a metal sheet. In some embodiments, the reaction vessel 210 can be formed via electric resistance welding (ERW) of a metal sheet. In some embodiments, the reaction vessel 210 can be formed via acetylene torch welding of a metal sheet.|[0035] In some embodiments, the reaction vessel 210 includes a substantially cylindrical (e.g., annular, round, circular, etc.) body centered on an axis AX. In some embodiments, the reaction vessel 210 can have an elliptical, or similarly rotationally symmetrical cross-sectional shape centered on the axis AX and extending between the first vessel end 214 and the second vessel end 216.|[0036] The reaction vessel 210 has a diameter D, measured as inner diameter of the reaction vessel 210. The diameter D may be between about 50 cm and about 10 m. In some embodiments, the diameter D can be at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, at least about 4.5 m, at least about 5 m, at least about 5.5 m, at least about 6 m, at least about 6.5 m, at least about 7 m, at least about 7.5 m, at least about 8 m, at least about 8.5 m, at least about 9 m, at least about 9.5 m, or at least about 10 m. In some embodiments, the diameter D can be no more than about 10 m, no more than about 9.5 m, no more than about 9 m, no more than about 8.5 m, no more than about 8 m, no more than about 7.5 m, no more than about 7 m, no more than about 6.5 m, no more than about 6 m, no more than about 5.5 m, no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.5 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, or no more than about 50 cm. Combinations of the above-referenced diameter D values are also possible (e.g., at least about 50 cm and no more than about 10 m or at least about 2 m and no more than about 6 m), inclusive of all values and ranges therebetween. In some embodiments, the diameter D can be about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.5 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, about 5 m, about 5.5 m, about 6 m, about 6.5 m, about 7 m, about 7.5 m, about 8 m, about 8.5 m, about 9 m, about 9.5 m, or about 10 m.|[0037] The reaction vessel 210 has a wall thickness T1, measured as the radial thickness between an inner surface of the reaction vessel 210 (e.g., vessel surface nearest the axis AX) and an outer surface of the reaction vessel 210 (e.g., vessel surface furthest from the axis AX; vessel surface abutting the furnace 230). In some embodiments, the wall thickness T1 can be between about 1 mm and about 50 cm, inclusive.|[0038] In some embodiments, the wall thickness T1 can be at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 11 cm, at least about 12 cm, at least about 13 cm, at least about 14 cm, at least about 15 cm, at least about 16 cm, at least about 17 cm, at least about 18 cm, at least about 19 cm, at least about 20 cm, at least about 21 cm, at least about 22 cm, at least about 23 cm, at least about 24 cm, at least about 25 cm, at least about 26 cm, at least about 27 cm, at least about 28 cm, at least about 29 cm, at least about 30 cm, at least about 31 cm, at least about 32 cm, at least about 33 cm, at least about 34 cm, at least about 35 cm, at least about 36 cm, at least about 37 cm, at least about 38 cm, at least about 39 cm, at least about 40 cm, at least about 41 cm, at least about 42 cm, at least about 43 cm, at least about 44 cm, at least about 45 cm, at least about 46 cm, at least about 47 cm, at least about 48 cm, at least about 49 cm, or at least about 50 cm. In some embodiments, the wall thickness T1 can be no more than about 50 cm, no more than about 49 cm, no more than about 48 cm, no more than about 47 cm, no more than about 46 cm, no more than about 45 cm, no more than about 44 cm, no more than about 43 cm, no more than about 42 cm, no more than about 41 cm, no more than about 40 cm, no more than about 39 cm, no more than about 38 cm, no more than about 37 cm, no more than about 36 cm, no more than about 35 cm, no more than about 34 cm, no more than about 33 cm, no more than about 32 cm, no more than about 31 cm, no more than about 30 cm, no more than about 29 cm, no more than about 28 cm, no more than about 27 cm, no more than about 26 cm, no more than about 25 cm, no more than about 24 cm, no more than about 23 cm, no more than about 22 cm, no more than about 21 cm, no more than about 20 cm, no more than about 19 cm, no more than about 18 cm, no more than about 17 cm, no more than about 16 cm, no more than about 15 cm, no more than about 14 cm, no more than about 13 cm, no more than about 12 cm, no more than about 11 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, or no more than about 1 mm. Combinations of the above-referenced thicknesses are also possible (e.g., at least about 1 mm and no more than about 50 cm or at least about 4 cm and no more than about 25 cm), inclusive of all values and ranges therebetween. In some embodiments, the wall thickness T1 can be about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 11 cm, about 12 cm, about 13 cm, about 14 cm, about 15 cm, about 16 cm, about 17 cm, about 18 cm, about 19 cm, about 20 cm, about 21 cm, about 22 cm, about 23 cm, about 24 cm, about 25 cm, about 26 cm, about 27 cm, about 28 cm, about 29 cm, about 30 cm, about 31 cm, about 32 cm, about 33 cm, about 34 cm, about 35 cm, about 36 cm, about 37 cm, about 38 cm, about 39 cm, about 40 cm, about 41 cm, about 42 cm, about 43 cm, about 44 cm, about 45 cm, about 46 cm, about 47 cm, about 48 cm, about 49 cm, or about 50 cm.|[0039] In some embodiments, the furnace 230 includes a substantially cylindrical (e.g., annular, round, circular, etc.) body centered on the axis AX and disposed around the reaction vessel 210. In some embodiments, the furnace 230 includes an elliptical or similarly rotationally symmetrical cross-sectional shape centered on the axis AX and extending between the first vessel end 214 and the second vessel end 216. In some embodiments, a cross-sectional shape of the furnace 230 is different from a cross-sectional shape of the reaction vessel 210.|[0040] The furnace 230 further includes a furnace thickness T2, measured as the radial thickness between an inner surface of the furnace 230 (e.g., furnace surface nearest the axis AX; furnace surface abutting the reaction vessel 210) and an outer surface of the furnace 230 (e.g., furnace surface furthest from the axis AX; furnace surface abutting the insulation layer 250). The furnace thickness T2 can be between about 5 cm and about 10 m, inclusive.|[0041] In some embodiments, the furnace thickness T2 can be at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 2 m, at least about 3 m, at least about 4 m, at least about 5 m, at least about 6 m, at least about 7 m, at least about 8 m, at least about 9 m, or at least about 10 m. In some embodiments, the furnace thickness T2 can be no more than about 10 m, no more than about 9 m, no more than about 8 m, no more than about 7 m, no more than about 6 m, no more than about 5 m, no more than about 4 m, no more than about 3 m, no more than about 2 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, or no more than about 5 cm. Combinations of the above-referenced thickness values are also possible (e.g., at least about 5 cm and no more than about 10 m or at least about 40 cm and no more than about 80 cm), inclusive of all values and ranges therebetween. In some embodiments, the furnace thickness T2 can measure about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, or about 10 m.|[0042] The furnace 230 has a porosity ((D; percent), measured as the void volume divided by the total volume, where a porosity equal to zero percent is a solid object. In some embodiments, the porosity of the furnace 230 is evenly distributed throughout the furnace 230. In some embodiments, the porosity of the furnace is asymmetrically distributed or randomly distributed throughout the furnace 230. In some embodiments, the porosity of the furnace 230 changes dependent on the distance the furnace 230 is from the axis AX. For example, portions of the furnace 230 positioned radially further from the axis AX may have a lesser porosity than portions of the furnace 230 positioned radially nearer to the axis AX and abutting the reaction vessel 210. The porosity of the furnace 230 can be between 0% and 95%, inclusive.|[0043] In some embodiments, the porosity of the furnace 230 is 0%. In some embodiments, the porosity of the furnace 230 is at least about 0.1%, at least about 0.2%, at least about 0.3%, at least about 0.4%, at least about 0.5%, at least about 0.6%, at least about 0.7%, at least about 0.8%, at least about 0.9%, at least about 1%, at least about 2%, at least about 3%, at least about 4%, at least about 5%, at least about 6%, at least about 7%, at least about 8%, at least about 9%, at least about 10%, at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, or at least about 95%. In some embodiments, the furnace 230 can have a porosity of no more than about 95%, no more than about 94%, no more than about 93%, no more than about 92%, no more than about 91%, no more than about 90%, no more than about 80%, no more than about 70%, no more than about 60%, no more than about 50%, no more than about 40%, no more than about 30%, no more than about 20%, no more than about 10%, no more than about 9%, no more than about 8%, no more than about 7%, no more than about 6%, no more than about 5%, no more than about 4%, no more than about 3%, no more than about 2%, no more than about 1%, no more than about 0.9%, no more than about 0.8%, no more than about 0.7%, no more than about 0.6%, no more than about 0.5%, no more than about 0.4%, no more than about 0.3%, no more than about 0.2%, or no more than about 0.1%. Combinations of the above-referenced porosity values are also possible (e.g., at least about 0.1% and no more than about 95% or at least about 15% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, the porosity of the furnace 230 is about 0%, about 0.1%, about 0.2%, about 0.3%, about 0.4%, about 0.5%, about 0.6%, about 0.7%, about 0.8%, about 0.9%, about 1%, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8%, about 9%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 91%, about 92%, about 93%, about 94%, or about 95%.|[0044] In some embodiments, the insulation layer 250 includes a substantially cylindrical (e.g., annular, round, circular, etc.) body centered on the axis AX and disposed around the furnace 230. In some embodiments, the insulation layer 250 includes an elliptical or similarly rotationally symmetrical cross-sectional shape centered on the axis AX and extending between the first vessel end 214 and the second vessel end 216. In some embodiments, a cross-sectional shape of the insulation layer 250 is different from a cross-sectional shape of the furnace 230.|[0045] The insulation layer 250 further includes an insulation thickness T3, measured as the radial thickness between an inner surface of the insulation layer 250 (e.g., insulation layer surface nearest the axis AX; insulation layer surface abutting the furnace 230) and an outer surface of the insulation layer 270 (e.g., insulation layer surface furthest from the axis AX; insulation layer surface exposed to an ambient environment). The insulation thickness T3 may be between 1 centimeter (cm) and 3 meters (m), inclusive.|[0046] In some embodiments, the insulation thickness T3 can be at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 2 m, or at least about 3 m. In some embodiments, the insulation thickness T3 can be no more than about 3 m, no more than about 2 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, or no more than about 1 cm. Combinations of the above-referenced thickness values are also possible (e.g., at least about 1 cm and no more than about 3 m or at least about 10 cm and no more than about 60 cm), inclusive of all values and ranges therebetween. In some embodiments, the insulation thickness T3 can be about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, or about 3 m.|[0047] The insulation layer 250 further includes a porosity (<D; percent), measured as the void volume divided by the total volume, where a porosity equal to zero percent is a solid object. In some embodiments, the porosity of the insulation layer 250 is evenly distributed throughout the insulation layer 250. In some embodiments, the porosity of the insulation later 250 is asymmetrically distributed or randomly distributed throughout the insulation later 250. In some embodiments, the porosity of the insulation layer 250 changes dependent on the distance the insulation layer 250 is from the axis 270. For example, portions of the insulation layer 250 positioned radially further from the axis 270 may have a lesser porosity than portions of the insulation layer 250 positioned radially nearer to the axis 270 and abutting the furnace 230. The porosity of the insulation layer 250 can be between 0% and 95%, inclusive.|[0048] In some embodiments, the porosity of the insulation layer 250 is 0%. In some embodiments, the porosity of the furnace 230 is at least about 0.1%, at least about 0.2%, at least about 0.3%, at least about 0.4%, at least about 0.5%, at least about 0.6%, at least about 0.7%, at least about 0.8%, at least about 0.9%, at least about 1%, at least about 2%, at least about 3%, at least about 4%, at least about 5%, at least about 6%, at least about 7%, at least about 8%, at least about 9%, at least about 10%, at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, or at least about 95%. In some embodiments, the insulation layer 250 can have a porosity of no more than about 95%, no more than about 94%, no more than about 93%, no more than about 92%, no more than about 91%, no more than about 90%, no more than about 80%, no more than about 70%, no more than about 60%, no more than about 50%, no more than about 40%, no more than about 30%, no more than about 20%, no more than about 10%, no more than about 9%, no more than about 8%, no more than about 7%, no more than about 6%, no more than about 5%, no more than about 4%, no more than about 3%, no more than about 2%, no more than about 1%, no more than about 0.9%, no more than about 0.8%, no more than about 0.7%, no more than about 0.6%, no more than about 0.5%, no more than about 0.4%, no more than about 0.3%, no more than about 0.2%, or no more than about 0.1%. Combinations of the above-referenced porosity values are also possible (e.g., at least about 0.1% and no more than about 95% or at least about 15% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, the porosity of the insulation layer 250 can be about 0%, about 0.1%, about 0.2%, about 0.3%, about 0.4%, about 0.5%, about 0.6%, about 0.7%, about 0.8%, about 0.9%, about 1%, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8%, about 9%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 91%, about 92%, about 93%, about 94%, or about 95%.|[0049] FIG. 4 is an illustration of a portion high-temperature decomposition reactor 300 (hereinafter “reactor 300”) shown through viewing window BB, according to an embodiment. As shown, the reactor 300 includes a reaction vessel 310, a furnace 330, and an insulating layer 350. The reaction vessel 310 includes an inner volume 312, a first vessel end 314, and a second vessel end 316. In some embodiments, the reaction vessel 310, the inner volume 312, the first vessel end 314, the second vessel end 316, the furnace 330, and the insulating layer 350 can be the same or substantially similar to the reaction vessel 210, the inner volume 212, the first vessel end 214, the second vessel end 216, the furnace 230, and the insulating layer 250, as described above with reference to FIG. 2 and FIG. 3. Thus, certain aspects of the reaction vessel 310, the inner volume 312, the first vessel end 314, the second vessel end 316, the furnace 330, and the insulating layer 350 are not described in greater detail herein.|[0050] Carbonated medium enters the inner volume 312 of the reaction vessel 310 through the first vessel end 314 and/or the second vessel end 316. As the carbonated medium is heated within the inner volume 312, the carbonated medium is separated (e.g., decomposed) into a carbonation media and a gas. The carbonation medium exits the reaction vessel 310 via the first vessel end 314 and/or the second vessel end 316. An optional sweep gas inlet 361 is shown near the second vessel end 316.|[0051] The reactor 300 may be positioned horizontally, such that a central axis AX of the reactor 300 extends parallel to the ground. In some embodiments, the reactor 300 is positioned at a non-zero angle α, measured between the ground and the axis AX. The angle α may be between about 0 and about 90 degrees, inclusive. In some embodiments, the angle α can at least about 1 degree, at least about 2 degrees, at least about 3 degrees, at least about 4 degrees, at least about 5 degrees, at least about 6 degrees, at least about 7 degrees, at least about 8 degrees, at least about 9 degrees, at least about 10 degrees, at least about 20 degrees, at least about 21 degrees, at least about 22 degrees, at least about 23 degrees, at least about 24 degrees, at least about 25 degrees, at least about 26 degrees, at least about 27 degrees, at least about 28 degrees, at least about 29 degrees, at least about 30 degrees, at least about 31 degrees, at least about 32 degrees, at least about 33 degrees, at least about 34 degrees, at least about 35 degrees, at least about 40 degrees, at least about 50 degrees, at least about 60 degrees, at least about 70 degrees, at least about 80 degrees, or at least about 89 degrees. In some embodiments, the angle α can be no more than about 89 degrees, no more than about 80 degrees, no more than about 70 degrees, no more than about 60 degrees, no more than about 50 degrees, no more than about 40 degrees, no more than about 35 degrees, no more than about 34 degrees, no more than about 33 degrees, no more than about 32 degrees, no more than about 31 degrees, no more than about 30 degrees, no more than about 29 degrees, no more than about 28 degrees, no more than about 27 degrees, no more than about 26 degrees, no more than about 25 degrees, no more than about 24 degrees, no more than about 23 degrees, no more than about 22 degrees, no more than about 21 degrees, no more than about 20 degrees, no more than about 19 degrees, no more than about 18 degrees, no more than about 17 degrees, no more than about 16 degrees, no more than about 15 degrees, no more than about 14 degrees, no more than about 13 degrees, no more than about 12 degrees, no more than about 11 degrees, no more than about 10 degrees, no more than about 9 degrees, no more than about 8 degrees, no more than about 7 degrees, no more than about 6 degrees, no more than about 5 degrees, no more than about 4 degrees, no more than about 3 degrees, no more than about 2 degrees, or no more than about 1 degree. Combinations of the above-referenced angles are also possible (e.g., at least about 1 degree and no more than about 89 degrees or at least about 10 degrees and no more than about 40 degrees), inclusive of all values and ranges therebetween. In some embodiments, the angle α is about 1 degree, about 2 degrees, about 3 degrees, about 4 degrees, about 5 degrees, about 6 degrees, about 7 degrees, about 8 degrees, about 9 degrees, about 10 degrees, about 20 degrees, about 21 degrees, about 22 degrees, about 23 degrees, about 24 degrees, about 25 degrees, about 26 degrees, about 27 degrees, about 28 degrees, about 29 degrees, about 30 degrees, about 31 degrees, about 32 degrees, about 33 degrees, about 34 degrees, about 35 degrees, about 40 degrees, about 50 degrees, about 60 degrees, about 70 degrees, about 80 degrees, or about 89 degrees.|[0052] The reactor 300 can optionally include a facilitation device 380 positioned within (e.g., disposed within) the reaction vessel 310. The facilitation device 380 is configured to move (e.g., facilitate the movement of) the carbonated media and the carbonation media within the reaction vessel 310 between the first vessel end 314 and the second vessel end 316. In some instances, as shown in FIG. 4, the facilitation device 380 extends radially inward from an inner wall of the reaction vessel 310 toward a central axis 370. The facilitation device 380 may be an Archimedes Screw or a similar device configured to move a medium (e.g., carbonated medium, carbonation medium, etc.) from a first position to a second position when the reaction vessel 310 rotates about the axis AX. In some embodiments, the second position is at a higher potential energy state than the first position. In some embodiments, the second position is at a lower potential energy state than the first position. In some embodiments, the facilitation device 380 is structured such that a counterclockwise rotation of the reactor 300 about the axis AX facilitates movement of material within the reaction vessel 310 from the first vessel end 314 to the second vessel end 316. In some embodiments, the facilitation device 380 is structured such that a clockwise rotation of the reactor 300 about the axis AX facilitates movement of material within the reaction vessel 310 from the first vessel end 314 to the second vessel end 316. In some embodiments, the facilitation device 380 is structured such that a counterclockwise rotation of the reactor 300 about the axis 380 facilitates movement of material within the reaction vessel 310 from the second vessel end 316 to the first vessel end 314. In some embodiments, the facilitation device 380 is structured such that a clockwise rotation of the reactor 300 about the axis 380 facilitates movement of material within the reaction vessel 310 from the second vessel end 316 to the first vessel end 314.|[0053] The reactor 300 further includes a rotational mechanism 365 operatively coupled to the reactor 300 and configured to rotate the reactor 300 about the axis 370. In some embodiments, the rotational mechanism is operatively coupled to the facilitation device 380 and configured to rotate the facilitation device 380 about the axis 370 and relative to the reactor 300. The rotational mechanism 365 may be an actuator, a pair of rollers, a motor, and the like. The rotational mechanism 365 is configured to rotate the reactor 300 at a rotational velocity ω.|[0054] The reactor 300 can be rotated at a rotational velocity of ω about the axis 370. In some embodiments, the rotational velocity ω is between about 0.1 rotations per minute (rpm) and about 10 rpm. In some embodiments, the rotational velocity ω is at least about 0.1 rpm, at least about 0.2 rpm, at least about 0.3 rpm, at least about 0.4 rpm, at least about 0.5 rpm, at least about 0.6 rpm, at least about 0.7 rpm, at least about 0.8 rpm, at least about 0.9 rpm, at least about 1 rpm, at least about 2 rpm, at least about 3 rpm, at least about 4 rpm, at least about 5 rpm, at least about 6 rpm, at least about 7 rpm, at least about 8 rpm, at least about 9 rpm, or at least about 10 rpm. In some embodiments, the rotational velocity ω can be no more than about 10 rpm, no more than about 9 rpm, no more than about 8 rpm, no more than about 7 rpm, no more than about 6 rpm, no more than about 5 rpm, no more than about 4 rpm, no more than about 3 rpm, no more than about 2 rpm, no more than about 1 rpm, no more than about 0.9 rpm, no more than about 0.8 rpm, no more than about 0.7 rpm, no more than about 0.6 rpm, no more than about 0.5 rpm, no more than about 0.4 rpm, no more than about 0.3 rpm, no more than about 0.2 rpm, or no more than about 0.1 rpm. Combinations of the above-referenced rotational velocities are also possible (e.g., at least about 0.1 rpm and no more than about 10 rpm or at least about 0.5 rpm and no more than about 5 rpm), inclusive of all values and ranges therebetween. In some embodiments, the rotational velocity ω is about 0.1 rpm, about 0.2 rpm, about 0.3 rpm, about 0.4 rpm, about 0.5 rpm, about 0.6 rpm, about 0.7 rpm, about 0.8 rpm, about 0.9 rpm, about 1 rpm, about 2 rpm, about 3 rpm, about 4 rpm, about 5 rpm, about 6 rpm, about 7 rpm, about 8 rpm, about 9 rpm, or about 10 rpm.|[0055] The reactor 300 can decompose an amount of carbonated medium in a unit of time, represented as a carbonated medium throughput, and measured as metric tonnes (i.e., metric tonnes, or 1,000 kg) of carbonated medium per hour. In some embodiments, the carbonated medium throughput is at least about 0.1 tonne per hour, at least about 0.2 tonnes per hour, at least about 0.3 tonnes per hour, at least about 0.4 tonnes per hour, at least about 0.5 tonnes per hour, at least about 0.6 tonnes per hour, at least about 0.7 tonnes per hour, at least about 0.8 tonnes per hour, at least about 0.9 tonnes per hour, at least about 1 tonne per hour, at least about 2 tonnes per hour, at least about 3 tonnes per hour, at least about 4 tonnes per hour, at least about 5 tonnes per hour, at least about 6 tonnes per hour, at least about 7 tonnes per hour, at least about 8 tonnes per hour, at least about 9 tonnes per hour, at least about 10 tonnes per hour, at least about 20 tonnes per hour, at least about 30 tonnes per hour, at least about 40 tonnes per hour, at least about 50 tonnes per hour, at least about 60 tonnes per hour, at least about 70 tonnes per hour, at least about 80 tonnes per hour, at least about 90 tonnes per hour, at least about 100 tonnes per hour, at least about 200 tonnes per hour, at least about 500 tonnes per hour, at least about 1,000 tonnes per hour, or at least about 5,000 tonnes per hour. In some embodiments, the carbonated medium throughput is no more than about 5,000 tonnes per hour, no more than about 1,000 tonnes per hour, no more than about 500 tonnes per hour, no more than about 200 tonnes per hour, no more than about 100 tonnes per hour, no more than about 90 tonnes per hour, no more than about 80 tonnes per hour, no more than about 70 tonnes per hour, no more than about 60 tonnes per hour, no more than about 50 tonnes per hour, no more than about 40 tonnes per hour, no more than about 30 tonnes per hour, no more than about 20 tonnes per hour, no more than about 10 tonnes per hour, no more than about 9 tonnes per hour, no more than about 8 tonnes per hour, no more than about 7 tonnes per hour, no more than about 6 tonnes per hour, no more than about 5 tonnes per hour, no more than about 4 tonnes per hour, no more than about 3 tonnes per hour, no more than about 2 tonnes per hour, no more than about 1 tonne per hour, no more than about 0.9 tonnes per hour, no more than about 0.8 tonnes per hour, no more than about 0.7 tonnes per hour, no more than about 0.6 tonnes per hour, no more than about 0.5 tonnes per hour, no more than about 0.4 tonnes per hour, no more than about 0.3 tonnes per hour, no more than about 0.2 tonnes per hour, or no more than about 0.1 tonnes per hour. Combinations of the above-referenced throughput values are also possible (e.g., at least about 0.1 tonnes per hour and no more than about 5,000 tonnes per hour or at least about 2 tonnes per hour and no more than about 50 tonnes per hour), inclusive of all values and ranges therebetween. In some embodiments, the carbonated medium throughput is about 0.1 tonnes per hour, about 0.2 tonnes per hour, about 0.3 tonnes per hour, about 0.4 tonnes per hour, about 0.5 tonnes per hour, about 0.6 tonnes per hour, about 0.7 tonnes per hour, about 0.8 tonnes per hour, about 0.9 tonnes per hour, about 1 tonne per hour, about 2 tonnes per hour, about 3 tonnes per hour, about 4 tonnes per hour, about 5 tonnes per hour, about 6 tonnes per hour, about 7 tonnes per hour, about 8 tonnes per hour, about 9 tonnes per hour, about 10 tonnes per hour, about 20 tonnes per hour, about 30 tonnes per hour, about 40 tonnes per hour, about 50 tonnes per hour, about 60 tonnes per hour, about 70 tonnes per hour, about 80 tonnes per hour, about 90 tonnes per hour, about 100 tonnes per hour, about 200 tonnes per hour, about 500 tonnes per hour, about 1000 tonnes per hour, or about 5000 tonnes per hour.|[0056] The reactor 300 can generate an amount of carbon dioxide (CO2) from the carbonated medium in a unit of time, represented as a CO2 sequestration capacity, and measured as metric tonnes of CO2 per hour.|[0057] In some embodiments, the CO2 sequestration capacity of the reactor 300 (i.e., the amount of CO2 the reactor 300 can sequester) is at least about 0.01 tonnes per hour, at least about 0.02 tonnes per hour, at least about 0.03 tonnes per hour, at least about 0.04 tonnes per hour, at least about 0.05 tonnes per hour, at least about 0.06 tonnes per hour, at least about 0.07 tonnes per hour, at least about 0.08 tonnes per hour, at least about 0.09 tonnes per hour, at least about 0.1 tonnes per hour, at least about 0.2 tonnes per hour, at least about 0.3 tonnes per hour, at least about 0.4 tonnes per hour, at least about 0.5 tonnes per hour, at least about 0.6 tonnes per hour, at least about 0.7 tonnes per hour, at least about 0.8 tonnes per hour, at least about 0.9 tonnes per hour, at least about 1 tonne per hour, at least about 2 tonnes per hour, at least about 3 tonnes per hour, at least about 4 tonnes per hour, at least about 5 tonnes per hour, at least about 6 tonnes per hour, at least about 7 tonnes per hour, at least about 8 tonnes per hour, at least about 9 tonnes per hour, at least about 10 tonnes per hour, at least about 20 tonnes per hour, at least about 50 tonnes per hour, at least about 100 tonnes per hour, or at least about 500 tonnes per hour. In some embodiments, the CO2 sequestration capacity of the reactor 300 is no more than about 500 tonnes per hour, no more than about 100 tonnes per hour, no more than about 50 tonnes per hour, no more than about 20 tonnes per hour, no more than about 10 tonnes per hour, no more than about 9 tonnes per hour, no more than about 8 tonnes per hour, no more than about 7 tonnes per hour, no more than about 6 tonnes per hour, no more than about 5 tonnes per hour, no more than about 4 tonnes per hour, no more than about 3 tonnes per hour, no more than about 2 tonnes per hour, no more than about 1 tonne per hour, no more than about 0.9 tonnes per hour, no more than about 0.8 tonnes per hour, no more than about 0.7 tonnes per hour, no more than about 0.6 tonnes per hour, no more than about 0.5 tonnes per hour, no more than about 0.4 tonnes per hour, no more than about 0.3 tonnes per hour, no more than about 0.2 tonnes per hour, no more than about 0.1 tonne per hour, no more than about 0.09 tonnes per hour, no more than about 0.08 tonnes per hour, no more than about 0.07 tonnes per hour, no more than about 0.06 tonnes per hour, no more than about 0.05 tonnes per hour, no more than about 0.04 tonnes per hour, no more than about 0.03 tonnes per hour, no more than about 0.02 tonnes per hour, or no more than about 0.01 tonnes per hour. Combinations of the above-referenced sequestration capacities are also possible (e.g., at least about 0.01 tonnes per hour and no more than about 500 tonnes per hour or at least about 0.1 tonnes per hour and no more than about 5 tonnes per hour), inclusive of all values and ranges therebetween. In some embodiments, the CO2 sequestration capacity of the reactor 300 is no more than 0.1 tonnes per hour, no more than 0.2 tonnes per hour, no more than 0.3 tonnes per hour, no more than 0.4 tonnes per hour, no more than 0.5 tonnes per hour, no more than 0.6 tonnes per hour, no more than 0.7 tonnes per hour, no more than 0.8 tonnes per hour, no more than 0.9 tonnes per hour, no more than 1 tonne per hour, no more than 2 tonnes per hour, no more than 3 tonnes per hour, no more than 4 tonnes per hour, no more than 5 tonnes per hour, no more than 6 tonnes per hour, no more than 7 tonnes per hour, no more than 8 tonnes per hour, no more than 9 tonnes per hour, no more than 10 tonnes per hour, no more than 20 tonnes per hour, no more than 30 tonnes per hour, no more than 40 tonnes per hour, no more than 50 tonnes per hour, no more than 60 tonnes per hour, no more than 70 tonnes per hour, no more than 80 tonnes per hour, no more than 90 tonnes per hour, no more than 100 tonnes per hour, no more than 200 tonnes per hour, no more than 500 tonnes per hour, no more than 1000 tonnes per hour, or no more than 5000 tonnes per hour. In some embodiments, the CO2 sequestration capacity of the reactor 300 is about 0.01 tonnes per hour, about 0.02 tonnes per hour, about 0.03 tonnes per hour, about 0.04 tonnes per hour, about 0.05 tonnes per hour, about 0.06 tonnes per hour, about 0.07 tonnes per hour, about 0.08 tonnes per hour, about 0.09 tonnes per hour, about 0.1 tonnes per hour, about 0.2 tonnes per hour, about 0.3 tonnes per hour, about 0.4 tonnes per hour, about 0.5 tonnes per hour, about 0.6 tonnes per hour, about 0.7 tonnes per hour, about 0.8 tonnes per hour, about 0.9 tonnes per hour, about 1 tonne per hour, about 2 tonnes per hour, about 3 tonnes per hour, about 4 tonnes per hour, about 5 tonnes per hour, about 6 tonnes per hour, about 7 tonnes per hour, about 8 tonnes per hour, about 9 tonnes per hour, about 10 tonnes per hour, about 20 tonnes per hour, about 50 tonnes per hour, about 100 tonnes per hour, or about 500 tonnes per hour.|[0058] The reactor 300 can produce an amount of carbonation medium in a unit of time, represented as a carbonation medium throughput, and measured as metric tonnes of carbonation medium per hour. In some embodiments, the carbonation medium production is at least about 0.1 tonnes per hour, at least about 0.2 tonnes per hour, at least about 0.3 tonnes per hour, at least about 0.4 tonnes per hour, at least about 0.5 tonnes per hour, at least about 0.6 tonnes per hour, at least about 0.7 tonnes per hour, at least about 0.8 tonnes per hour, at least about 0.9 tonnes per hour, at least about 1 tonne per hour, at least about 2 tonnes per hour, at least about 3 tonnes per hour, at least about 4 tonnes per hour, at least about 5 tonnes per hour, at least about 6 tonnes per hour, at least about 7 tonnes per hour, at least about 8 tonnes per hour, at least about 9 tonnes per hour, at least about 10 tonnes per hour, at least about 20 tonnes per hour, at least about 30 tonnes per hour, at least about 40 tonnes per hour, at least about 50 tonnes per hour, at least about 60 tonnes per hour, at least about 70 tonnes per hour, at least about 80 tonnes per hour, at least about 90 tonnes per hour, at least about 100 tonnes per hour, at least about 200 tonnes per hour, at least about 500 tonnes per hour, at least about 1000 tonnes per hour, or at least about 5000 tonnes per hour.|[0059] In some embodiments, the carbonated medium throughput is no more than about 5,000 tonnes per hour, no more than about 1,000 tonnes per hour, no more than about 500 tonnes per hour, no more than about 200 tonnes per hour, no more than about 100 tonnes per hour, no more than about 90 tonnes per hour, no more than about 80 tonnes per hour, no more than about 70 tonnes per hour, no more than about 60 tonnes per hour, no more than about 50 tonnes per hour, no more than about 40 tonnes per hour, no more than about 30 tonnes per hour, no more than about 20 tonnes per hour, no more than about 10 tonnes per hour, no more than about 9 tonnes per hour, no more than about 8 tonnes per hour, no more than about 7 tonnes per hour, no more than about 6 tonnes per hour, no more than about 5 tonnes per hour, no more than about 4 tonnes per hour, no more than about 3 tonnes per hour, no more than about 2 tonnes per hour, no more than about 1 tonne per hour, no more than about 0.9 tonnes per hour, no more than about 0.8 tonnes per hour, no more than about 0.7 tonnes per hour, no more than about 0.6 tonnes per hour, no more than about 0.5 tonnes per hour, no more than about 0.4 tonnes per hour, no more than about 0.3 tonnes per hour, no more than about 0.2 tonnes per hour, or no more than about 0.1 tonnes per hour. Combinations of the above-referenced throughputs are also possible (e.g., at least about 0.1 tonnes per hour and no more than about 5,000 tonnes per hour or at least about 5 tonnes per hour and no more than about 50 tonnes per hour), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium throughput is about 0.1 tonnes per hour, about 0.2 tonnes per hour, about 0.3 tonnes per hour, about 0.4 tonnes per hour, about 0.5 tonnes per hour, about 0.6 tonnes per hour, about 0.7 tonnes per hour, about 0.8 tonnes per hour, about 0.9 tonnes per hour, about 1 tonne per hour, about 2 tonnes per hour, about 3 tonnes per hour, about 4 tonnes per hour, about 5 tonnes per hour, about 6 tonnes per hour, about 7 tonnes per hour, about 8 tonnes per hour, about 9 tonnes per hour, about 10 tonnes per hour, about 20 tonnes per hour, about 30 tonnes per hour, about 40 tonnes per hour, about 50 tonnes per hour, about 60 tonnes per hour, about 70 tonnes per hour, about 80 tonnes per hour, about 90 tonnes per hour, about 100 tonnes per hour, about 200 tonnes per hour, about 500 tonnes per hour, about 1000 tonnes per hour, or about 5000 tonnes per hour.|[0060] FIG. 5 is a block diagram of a method 400 of decomposing a carbonated medium into a gas and a carbonation medium, according to an embodiment. As shown, the method 400 includes feeding a carbonated medium into an inner volume (e.g., void volume) of a reaction vessel at step 401, heating a furnace material at step 402, and discharging heat from the furnace material to the inner volume of the reactor vessel while heating the furnace material at step 403. Step 404 is optional and includes rotating the reaction vessel to facilitate movement of carbonated medium through the reaction vessel while carbonated medium transitions to carbonation medium. The method 400 further includes sequestering a CO2 stream from the carbonation medium at step 405, optionally purifying the CO2 stream at step 406, and removing the carbonation medium from the reaction vessel at step 407.|[0061] At step 401, a carbonated medium is provided to an inner volume of a reaction vessel of a high-temperature decomposition reactor. In some instances, the carbonated medium can include limestone, calcite, aragonite, or calcium carbonate (CaCO3). At step 402, a furnace material of the high-temperature decomposition reactor is heated. The furnace material contacts the reaction vessel and at least partially surrounds the reaction vessel. In some embodiments, the heat provided to the furnace material can be applied at least partially by renewable electricity. For example, the heat can be applied at least partially by renewable electricity via solar power, wind power, nuclear power, geothermal power, and/or any other suitable renewable or low carbon energy source or combinations thereof. In some embodiments, all or substantially all of the heat can be applied by renewable energy.|[0062] At step 403, the heat stored in the furnace material is discharged to the inner volume of the reaction vessel. In some implementations, steps 402 and 403 can occur at least partially simultaneously, such that the furnace material is heated while the furnace material is also discharging heat into the inner volume of the reaction vessel. The heat discharged by the furnace material into the inner volume facilitates the decomposition of the carbonated medium disposed within the inner volume.|[0063] As an example, the decomposition (e.g., calcination) of calcium carbonate occurs according to the following reaction:|CaCO3+energy(heat)→CaO+CO2 |[0064] In some embodiments, the calcining (e.g., decomposing) temperature can be at least about 500° C., at least about 550° C., at least about 600° C., at least about 650° C., at least about 700° C., at least about 750° C., at least about 800° C., at least about 850° C., at least about 900° C., at least about 950° C., at least about 1,000° C., at least about 1,050° C., at least about 1,100° C., at least about 1,150° C., at least about 1,200° C., at least about 1,250° C., at least about 1,300° C., at least about 1,350° C., at least about 1,400° C., or at least about 1,450° C. In some embodiments, the calcining temperature can be no more than about 1,450° C., no more than about 1,400° C., no more than about 1,350° C., no more than about 1,300° C., no more than about 1,250° C., no more than about 1,200° C., no more than about 1,150° C., no more than about 1,100° C., no more than about 1,050° C., no more than about 1,000° C., no more than about 950° C., no more than about 900° C., no more than about 850° C., no more than about 800° C., no more than about 750° C., no more than about 700° C., no more than about 650° C., no more than about 600° C., or no more than about 550° C. Combinations of the above-referenced calcining temperatures are also possible (e.g., at least about 500° C. and no more than about 1,500° C. or at least about 600° C. and no more than about 800° C.), inclusive of all values and ranges therebetween. In some embodiments, the calcining temperature can be about 500° C., about 550° C., about 600° C., about 650° C., about 700° C., about 750° C., about 800° C., about 850° C., about 900° C., about 950° C., about 1,000° C., about 1,050° C., about 1,100° C., about 1,150° C., about 1,200° C., about 1,250° C., about 1,300° C., about 1,350° C., about 1,400° C., about 1,450° C., or about 1,500° C.|[0065] At optional step 404, the reaction vessel is rotated to facilitate the movement of the carbonated medium (i.e., as the carbonated medium decomposes) along the length of the reaction vessel. For example, the reaction vessel may include a facilitation device configured to move the decomposing carbonated medium from a position of high potential energy to a position of low potential energy or from a position of low potential energy to a position of high potential energy. The reaction vessel may be rotated slowly or quickly depending on the heat provided by the furnace material and the amount of carbonated medium disposed within the inner volume. Rotation of the reaction vessel can cooperate with the facilitation device to ensure even heating of the carbonated medium, which may reduce the time required to calcine the carbonated medium, and may reduce the heat requirements to calcine the carbonated medium.|[0066] At step 405, the gas (e.g., CO2) created from the decomposition of the carbonated medium is removed from the inner volume, captured, and sequestered. In some embodiments, the CO2 stream can naturally flow from the reactor (i.e., without any added compression). In some embodiments, the CO2 stream can be compressed to desired transport conditions (i.e., a transport pressure) and pumped via pipeline to a storage location. In some embodiments, the transport pressure can be about 2 bar, about 3 bar, about 4 bar, about 5 bar, about 6 bar, about 7 bar, about 8 bar, about 9 bar, about 10 bar, about 15 bar, about 20 bar, about 25 bar, about 30 bar, about 35 bar, about 40 bar, about 45 bar, about 50 bar, about 55 bar, about 60 bar, about 65 bar, about 70 bar, about 75 bar, about 80 bar, about 85 bar, about 90 bar, about 95 bar, about 100 bar, about 110 bar, about 120 bar, about 130 bar, about 140 bar, about 150 bar, about 160 bar, about 170 bar, about 180 bar, about 190 bar, or about 200 bar, inclusive of all values and ranges therebetween.|[0067] In some embodiments, the CO2 stream can be subject to post-processing prior to storage such that the CO2 stream is compliant with applicable specifications for storage. In some embodiments, the post-processing can include dehydration (e.g., via a condenser) and/or compression (e.g., via a compressor).|[0068] Step 406 is optional and includes purifying the CO2 stream. In some embodiments, the CO2 stream can be purified via condensation of water or other post processing treatment. In some embodiments, the CO2 stream can be compressed into gas storage. In some embodiments, the compressed CO2 stream can be direct injected in a co-located facility. In some embodiments, the compressed CO2 stream can be transported to a location where it can be sequestered. In some embodiments, the CO2 stream can have a high purity. In some embodiments, the CO2 stream can include at least about 80 vol %, at least about 85 vol %, at least about 90 vol %, at least about 91 vol %, at least about 92 vol %, at least about 93 vol %, at least about 94 vol %, at least about 95 vol %, at least about 96 vol %, at least about 97 vol %, at least about 98 vol %, at least about 99 vol %, at least about 99.1 vol %, at least about 99.2 vol %, at least about 99.3 vol %, at least about 99.4 vol %, at least about 99.5 vol %, at least about 99.6 vol %, at least about 99.7 vol %, at least about 99.8 vol %, at least about 99.9 vol %, at least about 99.99 vol %, or at least about 99.999 vol % CO2.|[0069] At step 407, the decomposed carbonated medium, or carbonation medium, is removed from the reaction vessel. Removal of the carbonation medium may be facilitated by the facilitation device and rotation of the reaction vessel. In some implementations, such as when the reaction vessel is oriented vertically, removal of the carbonation medium is facilitated by gravity. | (US20250018356)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims the benefit of U.S. Provisional Application No. 63/513,706, entitled “Systems and Methods for Thermal Storage Integration into High-Temperature Decomposition Reactor,” filed Jul. 14, 2023, the disclosure of which is incorporated herein by reference.|(US20250018356)|TECHNICAL FIELD|[0002] Embodiments described herein relate to extraction and sequestration of carbon dioxide from ambient air.|BACKGROUND|[0003] The atmospheric concentration of carbon dioxide (CO2) has reached 420 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 billion tonnes of C02 per year (GtCO2/year), a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's average surface temperature by the year 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. State of the art DACS systems rely on media to capture CO2 from the atmosphere.|[0004] High temperature reactors can be used to separate CO2 from media used to capture the CO2. High temperature reactors often require continuous operation to avoid extensive startup and shutdown periods, as well as to utilize the capital investment. However, the availability of renewable energy sources is typically intermittent—limited to times when the sun is shining and/or wind is blowing. Thus, a need exists for a means of energy storage in high temperature reactors.|SUMMARY|[0005] Embodiments described herein relate to thermal energy storage in high temperature reactors (e.g., calciners). In some aspects, a reactor can include a reaction vessel that includes an inner volume the contains a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium. The reactor can further include a furnace disposed around the reaction vessel. The furnace includes a furnace material that simultaneously absorbs and transmits heat. The reactor further includes an insulation layer disposed around the furnace. The insulation layer can prevent thermal losses from the reactor. In some embodiments, the reaction vessel can be composed of a conductive metal. In some embodiments, the reaction vessel can be composed of a thermal storage material. In some embodiments, the furnace can include graphite, granite, basalt, and/or quartzite. In some embodiments, the reactor can include a crevice, into which molten salt circulates to provide heat to the reaction vessel.|(US20250018356)|BRIEF DESCRIPTION OF THE DRAWINGS|[0006] FIG. 1 is a block diagram of a high-temperature decomposition reactor, according to an embodiment.|[0007] FIG. 2 is an illustration of a high-temperature decomposition reactor, according to an embodiment.|[0008] FIG. 3 is a perspective view of a portion of the high-temperature decomposition reactor of FIG. 2.|[0009] FIG. 4 is a perspective view of a portion of a high-temperature decomposition reactor, according to an embodiment.|[0010] FIG. 5 is a flow diagram of a method of operating the high-temperature decomposition reactor of any of FIGS. 1-4.|(US20250018356)|DETAILED DESCRIPTION|[0011] Integrating thermal energy storage into a high-temperature reactor can enable the use of stored energy during hours when renewable energy is normally not available, abundant, or cheap. Such thermal integration can also enable use of such resources when they are not available (e.g., using stored solar energy at night, using stored wind energy during calm weather). Integrated energy storage can ease the issues caused by the intermittency of renewable energy sources and can reduce the cost of energy, as energy surpluses can be stored during the day when such resources are available. This can also act as a means to store excess energy from the grid for use.|[0012] Materials that store thermal energy (e.g., graphite) can also allow the use of multiple electricity inputs as a source of energy. For example, a first electricity input can be fed from an onsite renewable energy source (e.g., solar, wind) and a second electricity input can be fed from the electric grid. The second electricity input can allow for a backup source of energy when there are prolonged periods of time, in which renewable energy is not directly available (e.g., times when the wind is not blowing and/or the sun is not shining).|[0013] In the current state of the art, thermal storage systems are in development for various applications, including building temperature control, point source carbon capture, and renewable energy storage. These systems often include a single block of solid material. In some cases, such systems can include liquids and/or gases. These blocks are used to consistently provide heat to the system.|[0014] Embodiments described herein include the integration of a thermal storage system and a calcining reactor into a single piece of equipment that can increase the thermal efficiency of the system and prevent energy losses associated with transport from the storage entity to the reaction system itself. Several other approaches include individual charging and discharging of the system's energy. Embodiments described herein include simultaneous charging and discharging of a thermal storage system.|[0015] In some embodiments, calciners or other processing equipment described herein can be the same or substantially similar to equipment described in U.S. patent application Ser. No. 18/067,896 (“the '896 application”), filed Dec. 19, 2022, and titled “Systems and Methods of Carbon Capture from Cement Production Process,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, carbonation media or carbonated media described herein can be the same or similar to those described in the '896 application. In some embodiments, carbonation media or carbonated media described herein can include water, or can be processed with water to improve uptake, as described in International Patent Publication No. US2022/018484 (“the '484 publication”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering in and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety.|[0016] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions.|[0017] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0018] As used herein, “carbonation medium” refers to a medium that can take on carbon dioxide when exposed to ambient air. This can include but is not limited to calcium oxide (CaO), calcium hydroxide (Ca(OH)2), magnesium oxide (MgO), magnesium hydroxide (MgOH), sodium oxide (Na2O), sodium hydroxide (NaOH), and/or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation medium can originate from a natural source (e.g., limestone). Carbonation medium can also be regenerated or recycled (i.e., a regenerated carbonated medium from a calciner).|[0019] As used herein, “carbonated medium” refers to a carbonation medium that has taken up carbon dioxide from ambient air. This can include but is not limited to calcium carbonate (CaCO3), magnesium carbonate (MgCO3), sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), mixed calcium-magnesium carbonate phases ((Ca,Mg)CO3). Carbonated medium can be converted back to a carbonation medium (e.g., via the use of a calciner, a dissolution/precipitation-based system, and/or an electrochemical system).|[0020] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0021] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0022] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of electrodes, the set of electrodes can be considered as one electrode with multiple portions, or the set of electrodes can be considered as multiple, distinct electrodes. Additionally, for example, when referring to a plurality of electrochemical cells, the plurality of electrochemical cells can be considered as multiple, distinct electrochemical cells or as one electrochemical cell with multiple portions. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0023] FIG. 1 is a block diagram of a high-temperature decomposition reactor 100 (hereinafter “reactor 100”), according to an embodiment. As shown, the reactor 100 includes a reaction vessel 110, a furnace 130, and an insulation layer 150. In some embodiments, the reactor 100 is used for calcination of species used for carbon capture.|[0024] The reaction vessel 110 includes an inner volume (not shown), in which heat permeates (e.g., to facilitate calcination). In some embodiments, the heat that permeates into the reaction vessel 110 can be a direct product solar energy. In other words, the sun can shine onto the furnace 130 and heat the furnace 130, and the heat in the furnace 130 can radiate into the reaction vessel 110. In some embodiments, the heat that permeates into the reaction vessel 110 can be a product of energy collected on solar cells and/or solar panels. In some embodiments, the heat that permeates into the reaction vessel 110 can be provided via electricity. In some embodiments, the heat that permeates into the reaction vessel 110 can be a product of wind energy (e.g., electricity from wind energy). In some embodiments, the heat that permeates into the reaction vessel 110 can be provided by electricity. In some embodiments, the heat that permeates into the reaction vessel 110 can be provided by combustion.|[0025] In some embodiments, the reaction vessel 110 can be composed of a metal. In some embodiments, the reaction vessel 110 can be composed of a conductive metal. In some embodiments, the reaction vessel 110 can be composed of stainless steel, 304 stainless steel, 316 stainless steel, aluminum, iron, wrought iron, cast iron, brass, tin, copper, antimony, or any combination thereof. In some embodiments, the reaction vessel 110 can be composed of an alloy. In some embodiments, the reaction vessel 110 can be composed of a copper-containing alloy. In some embodiments, the reaction vessel 110 can be composed of an aluminum-containing alloy. In some embodiments, the reaction vessel 110 can be formed via extrusion. In some embodiments, the reaction vessel 110 can be formed via welding of a metal sheet. In some embodiments, the reaction vessel 110 can be formed via electric resistance welding (ERW) of a metal sheet. In some embodiments, the reaction vessel 110 can be formed via acetylene torch welding of a metal sheet.|[0026] In some embodiments, during operation, the volume in the reaction vessel 110 can have a temperature of at least about 400° C., at least about 450° C., at least about 500° C., at least about 550° C., at least about 600° C., at least about 650° C., at least about 700° C., at least about 750° C., at least about 800° C., at least about 850° C., at least about 900° C., at least about 950° C., at least about 1,000° C., at least about 1,050° C., at least about 1,100° C., at least about 1,150° C., at least about 1,200° C., at least about 1,250° C., at least about 1,300° C., at least about 1,350° C., at least about 1,400° C., or at least about 1,450° C. In some embodiments, during operation, the volume in the reaction vessel 110 can have a temperature of no more than about 1,500° C., no more than about 1,450° C., no more than about 1,400° C., no more than about 1,350° C., no more than about 1,300° C., no more than about 1,250° C., no more than about 1,200° C., no more than about 1,150° C., no more than about 1,100° C., no more than about 1,050° C., no more than about 1,000° C., no more than about 950° C., no more than about 900° C., no more than about 850° C., no more than about 800° C., no more than about 750° C., no more than about 700° C., no more than about 650° C., no more than about 600° C., no more than about 550° C., no more than about 500° C., or no more than about 450° C. Combinations of the above-referenced temperatures are also possible (e.g., at least about 400° C. and no more than about 1,500° C. or at least about 750° C. and no more than about 1,200° C.) inclusive of all values and ranges therebetween. In some embodiments, during operation, the volume within the reaction vessel 110 can have a temperature of about 400° C., about 450° C., about 500° C., about 550° C., about 600° C., about 650° C., about 700° C., about 750° C., about 800° C., about 850° C., about 900° C., about 950° C., about 1,000° C., about 1,050° C., about 1,100° C., about 1,150° C., about 1,200° C., about 1,250° C., about 1,300° C., about 1,350° C., about 1,400° C., about 1,450° C., or about 1,500° C.|[0027] In some embodiments, the inner volume of the reaction vessel 110 can have a volume of at least about 10 L, at least about 20 L, at least about 30 L, at least about 40 L, at least about 50 L, at least about 60 L, at least about 70 L, at least about 80 L, at least about 90 L, at least about 100 L, at least about 200 L, at least about 300 L, at least about 400 L, at least about 500 L, at least about 600 L, at least about 700 L, at least about 800 L, at least about 900 L, at least about 1 m3, at least about 2 m3, at least about 3 m3, at least about 4 m3, at least about 5 m3, at least about 6 m3, at least about 7 m3, at least about 8 m3, at least about 9 m3, at least about 10 m3, at least about 20 m3, at least about 30 m3, at least about 40 m3, at least about 50 m3, at least about 60 m3, at least about 70 m3, at least about 80 m3, at least about 90 m3, at least about 100 m3, at least about 200 m3, at least about 300 m3, at least about 400 m3, at least about 500 m3, at least about 600 m3, at least about 700 m3, at least about 800 m3, at least about 900 m3. In some embodiments, the space inside the reaction vessel 110 can have a volume of no more than about 1,000 m3, no more than about 900 m3, no more than about 800 m3, no more than about 700 m3, no more than about 600 m3, no more than about 500 m3, no more than about 400 m3, no more than about 300 m3, no more than about 200 m3, no more than about 100 m3, no more than about 90 m3, no more than about 80 m3, no more than about 70 m3, no more than about 60 m3, no more than about 50 m3, no more than about 40 m3, no more than about 30 m3, no more than about 20 m3, no more than about 10 m3, no more than about 9 m3, no more than about 8 m3, no more than about 7 m3, no more than about 6 m3, no more than about 5 m3, no more than about 4 m3, no more than about 3 m3, no more than about 2 m3, no more than about 1 m3, no more than about 900 L, no more than about 800 L, no more than about 700 L, no more than about 600 L, no more than about 500 L, no more than about 400 L, no more than about 300 L, no more than about 200 L, no more than about 100 L, no more than about 90 L, no more than about 80 L, no more than about 70 L, no more than about 60 L, no more than about 50 L, no more than about 40 L, no more than about 30 L, or no more than about 20 L. Combinations of the above-referenced volumes are also possible (e.g., at least about 10 L and no more than about 1,000 m3 or at least about 50 L and no more than about 1 m3), inclusive of all values and ranges therebetween. In some embodiments, the space inside the reaction vessel 110 can have a volume of about 10 L, about 20 L, about 30 L, about 40 L, about 50 L, about 60 L, about 70 L, about 80 L, about 90 L, about 100 L, about 200 L, about 300 L, about 400 L, about 500 L, about 600 L, about 700 L, about 800 L, about 900 L, about 1 m3, about 2 m3, about 3 m3, about 4 m3, about 5 m3, about 6 m3, about 7 m3, about 8 m3, about 9 m3, about 10 m3, about 20 m3, about 30 m3, about 40 m3, about 50 m3, about 60 m3, about 70 m3, about 80 m3, about 90 m3, about 100 m3, about 200 m3, about 300 m3, about 400 m3, about 500 m3, about 600 m3, about 700 m3, about 800 m3, about 900 m3, or about 1,000 m3.|[0028] The furnace 130 is disposed around the outside of the reaction vessel 110 and is composed of a material (e.g., furnace material) capable of storing energy (e.g., renewable energy) and dispensing (e.g., discharging) the renewable energy into the reaction vessel 110 as heat. In some embodiments, the furnace 130 is symmetrically disposed around the reaction vessel 110 such that an equal or substantially equal thickness of the furnace 130 is disposed around the reaction vessel 110. In some embodiments, the furnace 130 is asymmetrically disposed around the reaction vessel 110 such that a greater thickness of the furnace 130 is disposed around some portions of the reaction vessel 130 than other portions. In some embodiments, the furnace 130 has a cylindrical shape or a substantially cylindrical shape. In some embodiments, the furnace 130 can have a rectangular pyramidal shape. In some embodiments, the furnace 130 can be composed of a solid thermal storage material. In some embodiments, the furnace 130 can include graphite. Graphite can simultaneously store energy and dispense the energy in the form of heat to the reaction vessel 110. In some embodiments, the furnace 130 can include granite, basalt, quartzite, travertine, sandstone, marble, slate, quartz, onyx, bluestone, laterite, dolomite, alabaster, amethyst, soapstone, metamorphic rock, gneiss, igneous rock, sedimentary rock, flint, jasper, rose quartz, or any other forms of stone or combinations thereof. In some embodiments, the furnace 130 can include a chamber, through which molten salt flows. The molten salt can provide heat to the reaction vessel. In some embodiments, the furnace 130 can be composed of sodium nitrate, lithium nitrate, potassium nitrate, sodium chloride, N-ethylpyridinium bromide mixtures if sodium nitrate and potassium nitrate, or any combination thereof.|[0029] The insulation layer 150 inhibits or at least partially prevents thermal losses from the reactor 100. In some embodiments, the insulation layer 150 can be composed of an insulative material. In some embodiments, the insulation layer 150 can be composed of a refractory material. In some embodiments, the insulation layer 150 can include periclase. In some embodiments, the insulation layer 150 can include a silica-based refractory material. In some embodiments, the insulation layer 150 can include an alumina-based refractory material. In some embodiments, the insulation layer 150 can include a fibrous material. In some embodiments, the insulation layer 150 can include fiberglass, mineral wool, cellulose, natural fibers, cementitious foam, polyurethane, perlite, polystyrene, polyisocyanurate, or any combination thereof. In some embodiments, the insulation layer 150 can be disposed about the furnace 130 symmetrically such that an equal thickness of the insulation layer 150 covers the exterior surface area of the furnace 130.|[0030] FIG. 2 is an illustration of a high-temperature decomposition reactor 200 (hereinafter “reactor 200”), according to an embodiment. As shown, the reactor 200 includes a reaction vessel 210, a furnace 230, and an insulation layer 250. In some embodiments, the reaction vessel 210, the furnace 230, and the insulation layer 250 can be the same or substantially similar to the reaction vessel 110, the furnace 130, and the insulation layer 150, as described above with reference to FIG. 1. Thus, certain aspects of the reaction vessel 210, the furnace 230, and the insulation layer 250 are not described in greater detail herein.|[0031] In use, carbonated medium CDM enters an inner volume 212 of the reaction vessel 210 at a first vessel end 214. As the carbonated medium CDM is heated within the inner volume 212, the carbonated medium CDM is separated (e.g., decomposed) into a carbonation medium CNM and a gas G. The carbonation medium CNM exits the reaction vessel 210 at a second vessel end 216.|[0032] The gas G exits the reaction vessel 210 via a conduit 260 fluidly coupled to the inner volume 212. While the conduit 260 is shown positioned proximate to the first vessel end 214, the conduit 260 may be disposed at any position along the length of the reaction vessel 210 between the first vessel end 214 and the second vessel end 216. In some implementations, the conduit 260 is in fluid communication with a sequestration space (e.g., CO2 sequestration space) positioned at an end of the conduit 260 opposite the inner volume 212. An optional sweep gas inlet 261 is shown near the second vessel end 216.|[0033] FIG. 3 is a detailed illustration of a portion of the reactor 200 of FIG. 2, as viewed along view window AA. Heat permeates into the inner volume 212 to facilitate calcination. In some embodiments, the heat that permeates into the inner volume 212 can be a direct product solar energy. In some embodiments, the heat that permeates into the inner volume 212 can be a product of energy collected on solar cells and/or solar panels. In other words, electricity collected via solar cells and/or solar panels can be converted to heat. In some embodiments, the heat that permeates into the inner volume 212 is a product of wind energy. In other words, electricity collected via wind energy can be converted to heat.|[0034] In some embodiments, the reaction vessel 210 can be composed of a metal. In some embodiments, the reaction vessel 210 can be composed of a conductive metal. In some embodiments, the reaction vessel 210 can be composed of stainless steel, 304 stainless steel, 316 stainless steel, aluminum, iron, wrought iron, cast iron, brass, tin, copper, antimony, or any combination thereof. In some embodiments, the reaction vessel 210 can be composed of an alloy. In some embodiments, the reaction vessel 210 can be composed of a copper-containing alloy. In some embodiments, the reaction vessel 210 can be composed of an aluminum-containing alloy. In some embodiments, the reaction vessel 210 can be formed via extrusion. In some embodiments, the reaction vessel 210 can be formed via welding of a metal sheet. In some embodiments, the reaction vessel 210 can be formed via electric resistance welding (ERW) of a metal sheet. In some embodiments, the reaction vessel 210 can be formed via acetylene torch welding of a metal sheet.|[0035] In some embodiments, the reaction vessel 210 includes a substantially cylindrical (e.g., annular, round, circular, etc.) body centered on an axis AX. In some embodiments, the reaction vessel 210 can have an elliptical, or similarly rotationally symmetrical cross-sectional shape centered on the axis AX and extending between the first vessel end 214 and the second vessel end 216.|[0036] The reaction vessel 210 has a diameter D, measured as inner diameter of the reaction vessel 210. The diameter D may be between about 50 cm and about 10 m. In some embodiments, the diameter D can be at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, at least about 4.5 m, at least about 5 m, at least about 5.5 m, at least about 6 m, at least about 6.5 m, at least about 7 m, at least about 7.5 m, at least about 8 m, at least about 8.5 m, at least about 9 m, at least about 9.5 m, or at least about 10 m. In some embodiments, the diameter D can be no more than about 10 m, no more than about 9.5 m, no more than about 9 m, no more than about 8.5 m, no more than about 8 m, no more than about 7.5 m, no more than about 7 m, no more than about 6.5 m, no more than about 6 m, no more than about 5.5 m, no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.5 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, or no more than about 50 cm. Combinations of the above-referenced diameter D values are also possible (e.g., at least about 50 cm and no more than about 10 m or at least about 2 m and no more than about 6 m), inclusive of all values and ranges therebetween. In some embodiments, the diameter D can be about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.5 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, about 5 m, about 5.5 m, about 6 m, about 6.5 m, about 7 m, about 7.5 m, about 8 m, about 8.5 m, about 9 m, about 9.5 m, or about 10 m.|[0037] The reaction vessel 210 has a wall thickness T1, measured as the radial thickness between an inner surface of the reaction vessel 210 (e.g., vessel surface nearest the axis AX) and an outer surface of the reaction vessel 210 (e.g., vessel surface furthest from the axis AX; vessel surface abutting the furnace 230). In some embodiments, the wall thickness T1 can be between about 1 mm and about 50 cm, inclusive.|[0038] In some embodiments, the wall thickness T1 can be at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 11 cm, at least about 12 cm, at least about 13 cm, at least about 14 cm, at least about 15 cm, at least about 16 cm, at least about 17 cm, at least about 18 cm, at least about 19 cm, at least about 20 cm, at least about 21 cm, at least about 22 cm, at least about 23 cm, at least about 24 cm, at least about 25 cm, at least about 26 cm, at least about 27 cm, at least about 28 cm, at least about 29 cm, at least about 30 cm, at least about 31 cm, at least about 32 cm, at least about 33 cm, at least about 34 cm, at least about 35 cm, at least about 36 cm, at least about 37 cm, at least about 38 cm, at least about 39 cm, at least about 40 cm, at least about 41 cm, at least about 42 cm, at least about 43 cm, at least about 44 cm, at least about 45 cm, at least about 46 cm, at least about 47 cm, at least about 48 cm, at least about 49 cm, or at least about 50 cm. In some embodiments, the wall thickness T1 can be no more than about 50 cm, no more than about 49 cm, no more than about 48 cm, no more than about 47 cm, no more than about 46 cm, no more than about 45 cm, no more than about 44 cm, no more than about 43 cm, no more than about 42 cm, no more than about 41 cm, no more than about 40 cm, no more than about 39 cm, no more than about 38 cm, no more than about 37 cm, no more than about 36 cm, no more than about 35 cm, no more than about 34 cm, no more than about 33 cm, no more than about 32 cm, no more than about 31 cm, no more than about 30 cm, no more than about 29 cm, no more than about 28 cm, no more than about 27 cm, no more than about 26 cm, no more than about 25 cm, no more than about 24 cm, no more than about 23 cm, no more than about 22 cm, no more than about 21 cm, no more than about 20 cm, no more than about 19 cm, no more than about 18 cm, no more than about 17 cm, no more than about 16 cm, no more than about 15 cm, no more than about 14 cm, no more than about 13 cm, no more than about 12 cm, no more than about 11 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, or no more than about 1 mm. Combinations of the above-referenced thicknesses are also possible (e.g., at least about 1 mm and no more than about 50 cm or at least about 4 cm and no more than about 25 cm), inclusive of all values and ranges therebetween. In some embodiments, the wall thickness T1 can be about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 11 cm, about 12 cm, about 13 cm, about 14 cm, about 15 cm, about 16 cm, about 17 cm, about 18 cm, about 19 cm, about 20 cm, about 21 cm, about 22 cm, about 23 cm, about 24 cm, about 25 cm, about 26 cm, about 27 cm, about 28 cm, about 29 cm, about 30 cm, about 31 cm, about 32 cm, about 33 cm, about 34 cm, about 35 cm, about 36 cm, about 37 cm, about 38 cm, about 39 cm, about 40 cm, about 41 cm, about 42 cm, about 43 cm, about 44 cm, about 45 cm, about 46 cm, about 47 cm, about 48 cm, about 49 cm, or about 50 cm.|[0039] In some embodiments, the furnace 230 includes a substantially cylindrical (e.g., annular, round, circular, etc.) body centered on the axis AX and disposed around the reaction vessel 210. In some embodiments, the furnace 230 includes an elliptical or similarly rotationally symmetrical cross-sectional shape centered on the axis AX and extending between the first vessel end 214 and the second vessel end 216. In some embodiments, a cross-sectional shape of the furnace 230 is different from a cross-sectional shape of the reaction vessel 210.|[0040] The furnace 230 further includes a furnace thickness T2, measured as the radial thickness between an inner surface of the furnace 230 (e.g., furnace surface nearest the axis AX; furnace surface abutting the reaction vessel 210) and an outer surface of the furnace 230 (e.g., furnace surface furthest from the axis AX; furnace surface abutting the insulation layer 250). The furnace thickness T2 can be between about 5 cm and about 10 m, inclusive.|[0041] In some embodiments, the furnace thickness T2 can be at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 2 m, at least about 3 m, at least about 4 m, at least about 5 m, at least about 6 m, at least about 7 m, at least about 8 m, at least about 9 m, or at least about 10 m. In some embodiments, the furnace thickness T2 can be no more than about 10 m, no more than about 9 m, no more than about 8 m, no more than about 7 m, no more than about 6 m, no more than about 5 m, no more than about 4 m, no more than about 3 m, no more than about 2 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, or no more than about 5 cm. Combinations of the above-referenced thickness values are also possible (e.g., at least about 5 cm and no more than about 10 m or at least about 40 cm and no more than about 80 cm), inclusive of all values and ranges therebetween. In some embodiments, the furnace thickness T2 can measure about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, or about 10 m.|[0042] The furnace 230 has a porosity ((D; percent), measured as the void volume divided by the total volume, where a porosity equal to zero percent is a solid object. In some embodiments, the porosity of the furnace 230 is evenly distributed throughout the furnace 230. In some embodiments, the porosity of the furnace is asymmetrically distributed or randomly distributed throughout the furnace 230. In some embodiments, the porosity of the furnace 230 changes dependent on the distance the furnace 230 is from the axis AX. For example, portions of the furnace 230 positioned radially further from the axis AX may have a lesser porosity than portions of the furnace 230 positioned radially nearer to the axis AX and abutting the reaction vessel 210. The porosity of the furnace 230 can be between 0% and 95%, inclusive.|[0043] In some embodiments, the porosity of the furnace 230 is 0%. In some embodiments, the porosity of the furnace 230 is at least about 0.1%, at least about 0.2%, at least about 0.3%, at least about 0.4%, at least about 0.5%, at least about 0.6%, at least about 0.7%, at least about 0.8%, at least about 0.9%, at least about 1%, at least about 2%, at least about 3%, at least about 4%, at least about 5%, at least about 6%, at least about 7%, at least about 8%, at least about 9%, at least about 10%, at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, or at least about 95%. In some embodiments, the furnace 230 can have a porosity of no more than about 95%, no more than about 94%, no more than about 93%, no more than about 92%, no more than about 91%, no more than about 90%, no more than about 80%, no more than about 70%, no more than about 60%, no more than about 50%, no more than about 40%, no more than about 30%, no more than about 20%, no more than about 10%, no more than about 9%, no more than about 8%, no more than about 7%, no more than about 6%, no more than about 5%, no more than about 4%, no more than about 3%, no more than about 2%, no more than about 1%, no more than about 0.9%, no more than about 0.8%, no more than about 0.7%, no more than about 0.6%, no more than about 0.5%, no more than about 0.4%, no more than about 0.3%, no more than about 0.2%, or no more than about 0.1%. Combinations of the above-referenced porosity values are also possible (e.g., at least about 0.1% and no more than about 95% or at least about 15% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, the porosity of the furnace 230 is about 0%, about 0.1%, about 0.2%, about 0.3%, about 0.4%, about 0.5%, about 0.6%, about 0.7%, about 0.8%, about 0.9%, about 1%, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8%, about 9%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 91%, about 92%, about 93%, about 94%, or about 95%.|[0044] In some embodiments, the insulation layer 250 includes a substantially cylindrical (e.g., annular, round, circular, etc.) body centered on the axis AX and disposed around the furnace 230. In some embodiments, the insulation layer 250 includes an elliptical or similarly rotationally symmetrical cross-sectional shape centered on the axis AX and extending between the first vessel end 214 and the second vessel end 216. In some embodiments, a cross-sectional shape of the insulation layer 250 is different from a cross-sectional shape of the furnace 230.|[0045] The insulation layer 250 further includes an insulation thickness T3, measured as the radial thickness between an inner surface of the insulation layer 250 (e.g., insulation layer surface nearest the axis AX; insulation layer surface abutting the furnace 230) and an outer surface of the insulation layer 270 (e.g., insulation layer surface furthest from the axis AX; insulation layer surface exposed to an ambient environment). The insulation thickness T3 may be between 1 centimeter (cm) and 3 meters (m), inclusive.|[0046] In some embodiments, the insulation thickness T3 can be at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 2 m, or at least about 3 m. In some embodiments, the insulation thickness T3 can be no more than about 3 m, no more than about 2 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, or no more than about 1 cm. Combinations of the above-referenced thickness values are also possible (e.g., at least about 1 cm and no more than about 3 m or at least about 10 cm and no more than about 60 cm), inclusive of all values and ranges therebetween. In some embodiments, the insulation thickness T3 can be about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, or about 3 m.|[0047] The insulation layer 250 further includes a porosity (<D; percent), measured as the void volume divided by the total volume, where a porosity equal to zero percent is a solid object. In some embodiments, the porosity of the insulation layer 250 is evenly distributed throughout the insulation layer 250. In some embodiments, the porosity of the insulation later 250 is asymmetrically distributed or randomly distributed throughout the insulation later 250. In some embodiments, the porosity of the insulation layer 250 changes dependent on the distance the insulation layer 250 is from the axis 270. For example, portions of the insulation layer 250 positioned radially further from the axis 270 may have a lesser porosity than portions of the insulation layer 250 positioned radially nearer to the axis 270 and abutting the furnace 230. The porosity of the insulation layer 250 can be between 0% and 95%, inclusive.|[0048] In some embodiments, the porosity of the insulation layer 250 is 0%. In some embodiments, the porosity of the furnace 230 is at least about 0.1%, at least about 0.2%, at least about 0.3%, at least about 0.4%, at least about 0.5%, at least about 0.6%, at least about 0.7%, at least about 0.8%, at least about 0.9%, at least about 1%, at least about 2%, at least about 3%, at least about 4%, at least about 5%, at least about 6%, at least about 7%, at least about 8%, at least about 9%, at least about 10%, at least about 20%, at least about 30%, at least about 40%, at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, or at least about 95%. In some embodiments, the insulation layer 250 can have a porosity of no more than about 95%, no more than about 94%, no more than about 93%, no more than about 92%, no more than about 91%, no more than about 90%, no more than about 80%, no more than about 70%, no more than about 60%, no more than about 50%, no more than about 40%, no more than about 30%, no more than about 20%, no more than about 10%, no more than about 9%, no more than about 8%, no more than about 7%, no more than about 6%, no more than about 5%, no more than about 4%, no more than about 3%, no more than about 2%, no more than about 1%, no more than about 0.9%, no more than about 0.8%, no more than about 0.7%, no more than about 0.6%, no more than about 0.5%, no more than about 0.4%, no more than about 0.3%, no more than about 0.2%, or no more than about 0.1%. Combinations of the above-referenced porosity values are also possible (e.g., at least about 0.1% and no more than about 95% or at least about 15% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, the porosity of the insulation layer 250 can be about 0%, about 0.1%, about 0.2%, about 0.3%, about 0.4%, about 0.5%, about 0.6%, about 0.7%, about 0.8%, about 0.9%, about 1%, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8%, about 9%, about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 91%, about 92%, about 93%, about 94%, or about 95%.|[0049] FIG. 4 is an illustration of a portion high-temperature decomposition reactor 300 (hereinafter “reactor 300”) shown through viewing window BB, according to an embodiment. As shown, the reactor 300 includes a reaction vessel 310, a furnace 330, and an insulating layer 350. The reaction vessel 310 includes an inner volume 312, a first vessel end 314, and a second vessel end 316. In some embodiments, the reaction vessel 310, the inner volume 312, the first vessel end 314, the second vessel end 316, the furnace 330, and the insulating layer 350 can be the same or substantially similar to the reaction vessel 210, the inner volume 212, the first vessel end 214, the second vessel end 216, the furnace 230, and the insulating layer 250, as described above with reference to FIG. 2 and FIG. 3. Thus, certain aspects of the reaction vessel 310, the inner volume 312, the first vessel end 314, the second vessel end 316, the furnace 330, and the insulating layer 350 are not described in greater detail herein.|[0050] Carbonated medium enters the inner volume 312 of the reaction vessel 310 through the first vessel end 314 and/or the second vessel end 316. As the carbonated medium is heated within the inner volume 312, the carbonated medium is separated (e.g., decomposed) into a carbonation media and a gas. The carbonation medium exits the reaction vessel 310 via the first vessel end 314 and/or the second vessel end 316. An optional sweep gas inlet 361 is shown near the second vessel end 316.|[0051] The reactor 300 may be positioned horizontally, such that a central axis AX of the reactor 300 extends parallel to the ground. In some embodiments, the reactor 300 is positioned at a non-zero angle α, measured between the ground and the axis AX. The angle α may be between about 0 and about 90 degrees, inclusive. In some embodiments, the angle α can at least about 1 degree, at least about 2 degrees, at least about 3 degrees, at least about 4 degrees, at least about 5 degrees, at least about 6 degrees, at least about 7 degrees, at least about 8 degrees, at least about 9 degrees, at least about 10 degrees, at least about 20 degrees, at least about 21 degrees, at least about 22 degrees, at least about 23 degrees, at least about 24 degrees, at least about 25 degrees, at least about 26 degrees, at least about 27 degrees, at least about 28 degrees, at least about 29 degrees, at least about 30 degrees, at least about 31 degrees, at least about 32 degrees, at least about 33 degrees, at least about 34 degrees, at least about 35 degrees, at least about 40 degrees, at least about 50 degrees, at least about 60 degrees, at least about 70 degrees, at least about 80 degrees, or at least about 89 degrees. In some embodiments, the angle α can be no more than about 89 degrees, no more than about 80 degrees, no more than about 70 degrees, no more than about 60 degrees, no more than about 50 degrees, no more than about 40 degrees, no more than about 35 degrees, no more than about 34 degrees, no more than about 33 degrees, no more than about 32 degrees, no more than about 31 degrees, no more than about 30 degrees, no more than about 29 degrees, no more than about 28 degrees, no more than about 27 degrees, no more than about 26 degrees, no more than about 25 degrees, no more than about 24 degrees, no more than about 23 degrees, no more than about 22 degrees, no more than about 21 degrees, no more than about 20 degrees, no more than about 19 degrees, no more than about 18 degrees, no more than about 17 degrees, no more than about 16 degrees, no more than about 15 degrees, no more than about 14 degrees, no more than about 13 degrees, no more than about 12 degrees, no more than about 11 degrees, no more than about 10 degrees, no more than about 9 degrees, no more than about 8 degrees, no more than about 7 degrees, no more than about 6 degrees, no more than about 5 degrees, no more than about 4 degrees, no more than about 3 degrees, no more than about 2 degrees, or no more than about 1 degree. Combinations of the above-referenced angles are also possible (e.g., at least about 1 degree and no more than about 89 degrees or at least about 10 degrees and no more than about 40 degrees), inclusive of all values and ranges therebetween. In some embodiments, the angle α is about 1 degree, about 2 degrees, about 3 degrees, about 4 degrees, about 5 degrees, about 6 degrees, about 7 degrees, about 8 degrees, about 9 degrees, about 10 degrees, about 20 degrees, about 21 degrees, about 22 degrees, about 23 degrees, about 24 degrees, about 25 degrees, about 26 degrees, about 27 degrees, about 28 degrees, about 29 degrees, about 30 degrees, about 31 degrees, about 32 degrees, about 33 degrees, about 34 degrees, about 35 degrees, about 40 degrees, about 50 degrees, about 60 degrees, about 70 degrees, about 80 degrees, or about 89 degrees.|[0052] The reactor 300 can optionally include a facilitation device 380 positioned within (e.g., disposed within) the reaction vessel 310. The facilitation device 380 is configured to move (e.g., facilitate the movement of) the carbonated media and the carbonation media within the reaction vessel 310 between the first vessel end 314 and the second vessel end 316. In some instances, as shown in FIG. 4, the facilitation device 380 extends radially inward from an inner wall of the reaction vessel 310 toward a central axis 370. The facilitation device 380 may be an Archimedes Screw or a similar device configured to move a medium (e.g., carbonated medium, carbonation medium, etc.) from a first position to a second position when the reaction vessel 310 rotates about the axis AX. In some embodiments, the second position is at a higher potential energy state than the first position. In some embodiments, the second position is at a lower potential energy state than the first position. In some embodiments, the facilitation device 380 is structured such that a counterclockwise rotation of the reactor 300 about the axis AX facilitates movement of material within the reaction vessel 310 from the first vessel end 314 to the second vessel end 316. In some embodiments, the facilitation device 380 is structured such that a clockwise rotation of the reactor 300 about the axis AX facilitates movement of material within the reaction vessel 310 from the first vessel end 314 to the second vessel end 316. In some embodiments, the facilitation device 380 is structured such that a counterclockwise rotation of the reactor 300 about the axis 380 facilitates movement of material within the reaction vessel 310 from the second vessel end 316 to the first vessel end 314. In some embodiments, the facilitation device 380 is structured such that a clockwise rotation of the reactor 300 about the axis 380 facilitates movement of material within the reaction vessel 310 from the second vessel end 316 to the first vessel end 314.|[0053] The reactor 300 further includes a rotational mechanism 365 operatively coupled to the reactor 300 and configured to rotate the reactor 300 about the axis 370. In some embodiments, the rotational mechanism is operatively coupled to the facilitation device 380 and configured to rotate the facilitation device 380 about the axis 370 and relative to the reactor 300. The rotational mechanism 365 may be an actuator, a pair of rollers, a motor, and the like. The rotational mechanism 365 is configured to rotate the reactor 300 at a rotational velocity ω.|[0054] The reactor 300 can be rotated at a rotational velocity of ω about the axis 370. In some embodiments, the rotational velocity ω is between about 0.1 rotations per minute (rpm) and about 10 rpm. In some embodiments, the rotational velocity ω is at least about 0.1 rpm, at least about 0.2 rpm, at least about 0.3 rpm, at least about 0.4 rpm, at least about 0.5 rpm, at least about 0.6 rpm, at least about 0.7 rpm, at least about 0.8 rpm, at least about 0.9 rpm, at least about 1 rpm, at least about 2 rpm, at least about 3 rpm, at least about 4 rpm, at least about 5 rpm, at least about 6 rpm, at least about 7 rpm, at least about 8 rpm, at least about 9 rpm, or at least about 10 rpm. In some embodiments, the rotational velocity ω can be no more than about 10 rpm, no more than about 9 rpm, no more than about 8 rpm, no more than about 7 rpm, no more than about 6 rpm, no more than about 5 rpm, no more than about 4 rpm, no more than about 3 rpm, no more than about 2 rpm, no more than about 1 rpm, no more than about 0.9 rpm, no more than about 0.8 rpm, no more than about 0.7 rpm, no more than about 0.6 rpm, no more than about 0.5 rpm, no more than about 0.4 rpm, no more than about 0.3 rpm, no more than about 0.2 rpm, or no more than about 0.1 rpm. Combinations of the above-referenced rotational velocities are also possible (e.g., at least about 0.1 rpm and no more than about 10 rpm or at least about 0.5 rpm and no more than about 5 rpm), inclusive of all values and ranges therebetween. In some embodiments, the rotational velocity ω is about 0.1 rpm, about 0.2 rpm, about 0.3 rpm, about 0.4 rpm, about 0.5 rpm, about 0.6 rpm, about 0.7 rpm, about 0.8 rpm, about 0.9 rpm, about 1 rpm, about 2 rpm, about 3 rpm, about 4 rpm, about 5 rpm, about 6 rpm, about 7 rpm, about 8 rpm, about 9 rpm, or about 10 rpm.|[0055] The reactor 300 can decompose an amount of carbonated medium in a unit of time, represented as a carbonated medium throughput, and measured as metric tonnes (i.e., metric tonnes, or 1,000 kg) of carbonated medium per hour. In some embodiments, the carbonated medium throughput is at least about 0.1 tonne per hour, at least about 0.2 tonnes per hour, at least about 0.3 tonnes per hour, at least about 0.4 tonnes per hour, at least about 0.5 tonnes per hour, at least about 0.6 tonnes per hour, at least about 0.7 tonnes per hour, at least about 0.8 tonnes per hour, at least about 0.9 tonnes per hour, at least about 1 tonne per hour, at least about 2 tonnes per hour, at least about 3 tonnes per hour, at least about 4 tonnes per hour, at least about 5 tonnes per hour, at least about 6 tonnes per hour, at least about 7 tonnes per hour, at least about 8 tonnes per hour, at least about 9 tonnes per hour, at least about 10 tonnes per hour, at least about 20 tonnes per hour, at least about 30 tonnes per hour, at least about 40 tonnes per hour, at least about 50 tonnes per hour, at least about 60 tonnes per hour, at least about 70 tonnes per hour, at least about 80 tonnes per hour, at least about 90 tonnes per hour, at least about 100 tonnes per hour, at least about 200 tonnes per hour, at least about 500 tonnes per hour, at least about 1,000 tonnes per hour, or at least about 5,000 tonnes per hour. In some embodiments, the carbonated medium throughput is no more than about 5,000 tonnes per hour, no more than about 1,000 tonnes per hour, no more than about 500 tonnes per hour, no more than about 200 tonnes per hour, no more than about 100 tonnes per hour, no more than about 90 tonnes per hour, no more than about 80 tonnes per hour, no more than about 70 tonnes per hour, no more than about 60 tonnes per hour, no more than about 50 tonnes per hour, no more than about 40 tonnes per hour, no more than about 30 tonnes per hour, no more than about 20 tonnes per hour, no more than about 10 tonnes per hour, no more than about 9 tonnes per hour, no more than about 8 tonnes per hour, no more than about 7 tonnes per hour, no more than about 6 tonnes per hour, no more than about 5 tonnes per hour, no more than about 4 tonnes per hour, no more than about 3 tonnes per hour, no more than about 2 tonnes per hour, no more than about 1 tonne per hour, no more than about 0.9 tonnes per hour, no more than about 0.8 tonnes per hour, no more than about 0.7 tonnes per hour, no more than about 0.6 tonnes per hour, no more than about 0.5 tonnes per hour, no more than about 0.4 tonnes per hour, no more than about 0.3 tonnes per hour, no more than about 0.2 tonnes per hour, or no more than about 0.1 tonnes per hour. Combinations of the above-referenced throughput values are also possible (e.g., at least about 0.1 tonnes per hour and no more than about 5,000 tonnes per hour or at least about 2 tonnes per hour and no more than about 50 tonnes per hour), inclusive of all values and ranges therebetween. In some embodiments, the carbonated medium throughput is about 0.1 tonnes per hour, about 0.2 tonnes per hour, about 0.3 tonnes per hour, about 0.4 tonnes per hour, about 0.5 tonnes per hour, about 0.6 tonnes per hour, about 0.7 tonnes per hour, about 0.8 tonnes per hour, about 0.9 tonnes per hour, about 1 tonne per hour, about 2 tonnes per hour, about 3 tonnes per hour, about 4 tonnes per hour, about 5 tonnes per hour, about 6 tonnes per hour, about 7 tonnes per hour, about 8 tonnes per hour, about 9 tonnes per hour, about 10 tonnes per hour, about 20 tonnes per hour, about 30 tonnes per hour, about 40 tonnes per hour, about 50 tonnes per hour, about 60 tonnes per hour, about 70 tonnes per hour, about 80 tonnes per hour, about 90 tonnes per hour, about 100 tonnes per hour, about 200 tonnes per hour, about 500 tonnes per hour, about 1000 tonnes per hour, or about 5000 tonnes per hour.|[0056] The reactor 300 can generate an amount of carbon dioxide (CO2) from the carbonated medium in a unit of time, represented as a CO2 sequestration capacity, and measured as metric tonnes of CO2 per hour.|[0057] In some embodiments, the CO2 sequestration capacity of the reactor 300 (i.e., the amount of CO2 the reactor 300 can sequester) is at least about 0.01 tonnes per hour, at least about 0.02 tonnes per hour, at least about 0.03 tonnes per hour, at least about 0.04 tonnes per hour, at least about 0.05 tonnes per hour, at least about 0.06 tonnes per hour, at least about 0.07 tonnes per hour, at least about 0.08 tonnes per hour, at least about 0.09 tonnes per hour, at least about 0.1 tonnes per hour, at least about 0.2 tonnes per hour, at least about 0.3 tonnes per hour, at least about 0.4 tonnes per hour, at least about 0.5 tonnes per hour, at least about 0.6 tonnes per hour, at least about 0.7 tonnes per hour, at least about 0.8 tonnes per hour, at least about 0.9 tonnes per hour, at least about 1 tonne per hour, at least about 2 tonnes per hour, at least about 3 tonnes per hour, at least about 4 tonnes per hour, at least about 5 tonnes per hour, at least about 6 tonnes per hour, at least about 7 tonnes per hour, at least about 8 tonnes per hour, at least about 9 tonnes per hour, at least about 10 tonnes per hour, at least about 20 tonnes per hour, at least about 50 tonnes per hour, at least about 100 tonnes per hour, or at least about 500 tonnes per hour. In some embodiments, the CO2 sequestration capacity of the reactor 300 is no more than about 500 tonnes per hour, no more than about 100 tonnes per hour, no more than about 50 tonnes per hour, no more than about 20 tonnes per hour, no more than about 10 tonnes per hour, no more than about 9 tonnes per hour, no more than about 8 tonnes per hour, no more than about 7 tonnes per hour, no more than about 6 tonnes per hour, no more than about 5 tonnes per hour, no more than about 4 tonnes per hour, no more than about 3 tonnes per hour, no more than about 2 tonnes per hour, no more than about 1 tonne per hour, no more than about 0.9 tonnes per hour, no more than about 0.8 tonnes per hour, no more than about 0.7 tonnes per hour, no more than about 0.6 tonnes per hour, no more than about 0.5 tonnes per hour, no more than about 0.4 tonnes per hour, no more than about 0.3 tonnes per hour, no more than about 0.2 tonnes per hour, no more than about 0.1 tonne per hour, no more than about 0.09 tonnes per hour, no more than about 0.08 tonnes per hour, no more than about 0.07 tonnes per hour, no more than about 0.06 tonnes per hour, no more than about 0.05 tonnes per hour, no more than about 0.04 tonnes per hour, no more than about 0.03 tonnes per hour, no more than about 0.02 tonnes per hour, or no more than about 0.01 tonnes per hour. Combinations of the above-referenced sequestration capacities are also possible (e.g., at least about 0.01 tonnes per hour and no more than about 500 tonnes per hour or at least about 0.1 tonnes per hour and no more than about 5 tonnes per hour), inclusive of all values and ranges therebetween. In some embodiments, the CO2 sequestration capacity of the reactor 300 is no more than 0.1 tonnes per hour, no more than 0.2 tonnes per hour, no more than 0.3 tonnes per hour, no more than 0.4 tonnes per hour, no more than 0.5 tonnes per hour, no more than 0.6 tonnes per hour, no more than 0.7 tonnes per hour, no more than 0.8 tonnes per hour, no more than 0.9 tonnes per hour, no more than 1 tonne per hour, no more than 2 tonnes per hour, no more than 3 tonnes per hour, no more than 4 tonnes per hour, no more than 5 tonnes per hour, no more than 6 tonnes per hour, no more than 7 tonnes per hour, no more than 8 tonnes per hour, no more than 9 tonnes per hour, no more than 10 tonnes per hour, no more than 20 tonnes per hour, no more than 30 tonnes per hour, no more than 40 tonnes per hour, no more than 50 tonnes per hour, no more than 60 tonnes per hour, no more than 70 tonnes per hour, no more than 80 tonnes per hour, no more than 90 tonnes per hour, no more than 100 tonnes per hour, no more than 200 tonnes per hour, no more than 500 tonnes per hour, no more than 1000 tonnes per hour, or no more than 5000 tonnes per hour. In some embodiments, the CO2 sequestration capacity of the reactor 300 is about 0.01 tonnes per hour, about 0.02 tonnes per hour, about 0.03 tonnes per hour, about 0.04 tonnes per hour, about 0.05 tonnes per hour, about 0.06 tonnes per hour, about 0.07 tonnes per hour, about 0.08 tonnes per hour, about 0.09 tonnes per hour, about 0.1 tonnes per hour, about 0.2 tonnes per hour, about 0.3 tonnes per hour, about 0.4 tonnes per hour, about 0.5 tonnes per hour, about 0.6 tonnes per hour, about 0.7 tonnes per hour, about 0.8 tonnes per hour, about 0.9 tonnes per hour, about 1 tonne per hour, about 2 tonnes per hour, about 3 tonnes per hour, about 4 tonnes per hour, about 5 tonnes per hour, about 6 tonnes per hour, about 7 tonnes per hour, about 8 tonnes per hour, about 9 tonnes per hour, about 10 tonnes per hour, about 20 tonnes per hour, about 50 tonnes per hour, about 100 tonnes per hour, or about 500 tonnes per hour.|[0058] The reactor 300 can produce an amount of carbonation medium in a unit of time, represented as a carbonation medium throughput, and measured as metric tonnes of carbonation medium per hour. In some embodiments, the carbonation medium production is at least about 0.1 tonnes per hour, at least about 0.2 tonnes per hour, at least about 0.3 tonnes per hour, at least about 0.4 tonnes per hour, at least about 0.5 tonnes per hour, at least about 0.6 tonnes per hour, at least about 0.7 tonnes per hour, at least about 0.8 tonnes per hour, at least about 0.9 tonnes per hour, at least about 1 tonne per hour, at least about 2 tonnes per hour, at least about 3 tonnes per hour, at least about 4 tonnes per hour, at least about 5 tonnes per hour, at least about 6 tonnes per hour, at least about 7 tonnes per hour, at least about 8 tonnes per hour, at least about 9 tonnes per hour, at least about 10 tonnes per hour, at least about 20 tonnes per hour, at least about 30 tonnes per hour, at least about 40 tonnes per hour, at least about 50 tonnes per hour, at least about 60 tonnes per hour, at least about 70 tonnes per hour, at least about 80 tonnes per hour, at least about 90 tonnes per hour, at least about 100 tonnes per hour, at least about 200 tonnes per hour, at least about 500 tonnes per hour, at least about 1000 tonnes per hour, or at least about 5000 tonnes per hour.|[0059] In some embodiments, the carbonated medium throughput is no more than about 5,000 tonnes per hour, no more than about 1,000 tonnes per hour, no more than about 500 tonnes per hour, no more than about 200 tonnes per hour, no more than about 100 tonnes per hour, no more than about 90 tonnes per hour, no more than about 80 tonnes per hour, no more than about 70 tonnes per hour, no more than about 60 tonnes per hour, no more than about 50 tonnes per hour, no more than about 40 tonnes per hour, no more than about 30 tonnes per hour, no more than about 20 tonnes per hour, no more than about 10 tonnes per hour, no more than about 9 tonnes per hour, no more than about 8 tonnes per hour, no more than about 7 tonnes per hour, no more than about 6 tonnes per hour, no more than about 5 tonnes per hour, no more than about 4 tonnes per hour, no more than about 3 tonnes per hour, no more than about 2 tonnes per hour, no more than about 1 tonne per hour, no more than about 0.9 tonnes per hour, no more than about 0.8 tonnes per hour, no more than about 0.7 tonnes per hour, no more than about 0.6 tonnes per hour, no more than about 0.5 tonnes per hour, no more than about 0.4 tonnes per hour, no more than about 0.3 tonnes per hour, no more than about 0.2 tonnes per hour, or no more than about 0.1 tonnes per hour. Combinations of the above-referenced throughputs are also possible (e.g., at least about 0.1 tonnes per hour and no more than about 5,000 tonnes per hour or at least about 5 tonnes per hour and no more than about 50 tonnes per hour), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium throughput is about 0.1 tonnes per hour, about 0.2 tonnes per hour, about 0.3 tonnes per hour, about 0.4 tonnes per hour, about 0.5 tonnes per hour, about 0.6 tonnes per hour, about 0.7 tonnes per hour, about 0.8 tonnes per hour, about 0.9 tonnes per hour, about 1 tonne per hour, about 2 tonnes per hour, about 3 tonnes per hour, about 4 tonnes per hour, about 5 tonnes per hour, about 6 tonnes per hour, about 7 tonnes per hour, about 8 tonnes per hour, about 9 tonnes per hour, about 10 tonnes per hour, about 20 tonnes per hour, about 30 tonnes per hour, about 40 tonnes per hour, about 50 tonnes per hour, about 60 tonnes per hour, about 70 tonnes per hour, about 80 tonnes per hour, about 90 tonnes per hour, about 100 tonnes per hour, about 200 tonnes per hour, about 500 tonnes per hour, about 1000 tonnes per hour, or about 5000 tonnes per hour.|[0060] FIG. 5 is a block diagram of a method 400 of decomposing a carbonated medium into a gas and a carbonation medium, according to an embodiment. As shown, the method 400 includes feeding a carbonated medium into an inner volume (e.g., void volume) of a reaction vessel at step 401, heating a furnace material at step 402, and discharging heat from the furnace material to the inner volume of the reactor vessel while heating the furnace material at step 403. Step 404 is optional and includes rotating the reaction vessel to facilitate movement of carbonated medium through the reaction vessel while carbonated medium transitions to carbonation medium. The method 400 further includes sequestering a CO2 stream from the carbonation medium at step 405, optionally purifying the CO2 stream at step 406, and removing the carbonation medium from the reaction vessel at step 407.|[0061] At step 401, a carbonated medium is provided to an inner volume of a reaction vessel of a high-temperature decomposition reactor. In some instances, the carbonated medium can include limestone, calcite, aragonite, or calcium carbonate (CaCO3). At step 402, a furnace material of the high-temperature decomposition reactor is heated. The furnace material contacts the reaction vessel and at least partially surrounds the reaction vessel. In some embodiments, the heat provided to the furnace material can be applied at least partially by renewable electricity. For example, the heat can be applied at least partially by renewable electricity via solar power, wind power, nuclear power, geothermal power, and/or any other suitable renewable or low carbon energy source or combinations thereof. In some embodiments, all or substantially all of the heat can be applied by renewable energy.|[0062] At step 403, the heat stored in the furnace material is discharged to the inner volume of the reaction vessel. In some implementations, steps 402 and 403 can occur at least partially simultaneously, such that the furnace material is heated while the furnace material is also discharging heat into the inner volume of the reaction vessel. The heat discharged by the furnace material into the inner volume facilitates the decomposition of the carbonated medium disposed within the inner volume.|[0063] As an example, the decomposition (e.g., calcination) of calcium carbonate occurs according to the following reaction:|CaCO3+energy(heat)→CaO+CO2 |[0064] In some embodiments, the calcining (e.g., decomposing) temperature can be at least about 500° C., at least about 550° C., at least about 600° C., at least about 650° C., at least about 700° C., at least about 750° C., at least about 800° C., at least about 850° C., at least about 900° C., at least about 950° C., at least about 1,000° C., at least about 1,050° C., at least about 1,100° C., at least about 1,150° C., at least about 1,200° C., at least about 1,250° C., at least about 1,300° C., at least about 1,350° C., at least about 1,400° C., or at least about 1,450° C. In some embodiments, the calcining temperature can be no more than about 1,450° C., no more than about 1,400° C., no more than about 1,350° C., no more than about 1,300° C., no more than about 1,250° C., no more than about 1,200° C., no more than about 1,150° C., no more than about 1,100° C., no more than about 1,050° C., no more than about 1,000° C., no more than about 950° C., no more than about 900° C., no more than about 850° C., no more than about 800° C., no more than about 750° C., no more than about 700° C., no more than about 650° C., no more than about 600° C., or no more than about 550° C. Combinations of the above-referenced calcining temperatures are also possible (e.g., at least about 500° C. and no more than about 1,500° C. or at least about 600° C. and no more than about 800° C.), inclusive of all values and ranges therebetween. In some embodiments, the calcining temperature can be about 500° C., about 550° C., about 600° C., about 650° C., about 700° C., about 750° C., about 800° C., about 850° C., about 900° C., about 950° C., about 1,000° C., about 1,050° C., about 1,100° C., about 1,150° C., about 1,200° C., about 1,250° C., about 1,300° C., about 1,350° C., about 1,400° C., about 1,450° C., or about 1,500° C.|[0065] At optional step 404, the reaction vessel is rotated to facilitate the movement of the carbonated medium (i.e., as the carbonated medium decomposes) along the length of the reaction vessel. For example, the reaction vessel may include a facilitation device configured to move the decomposing carbonated medium from a position of high potential energy to a position of low potential energy or from a position of low potential energy to a position of high potential energy. The reaction vessel may be rotated slowly or quickly depending on the heat provided by the furnace material and the amount of carbonated medium disposed within the inner volume. Rotation of the reaction vessel can cooperate with the facilitation device to ensure even heating of the carbonated medium, which may reduce the time required to calcine the carbonated medium, and may reduce the heat requirements to calcine the carbonated medium.|[0066] At step 405, the gas (e.g., CO2) created from the decomposition of the carbonated medium is removed from the inner volume, captured, and sequestered. In some embodiments, the CO2 stream can naturally flow from the reactor (i.e., without any added compression). In some embodiments, the CO2 stream can be compressed to desired transport conditions (i.e., a transport pressure) and pumped via pipeline to a storage location. In some embodiments, the transport pressure can be about 2 bar, about 3 bar, about 4 bar, about 5 bar, about 6 bar, about 7 bar, about 8 bar, about 9 bar, about 10 bar, about 15 bar, about 20 bar, about 25 bar, about 30 bar, about 35 bar, about 40 bar, about 45 bar, about 50 bar, about 55 bar, about 60 bar, about 65 bar, about 70 bar, about 75 bar, about 80 bar, about 85 bar, about 90 bar, about 95 bar, about 100 bar, about 110 bar, about 120 bar, about 130 bar, about 140 bar, about 150 bar, about 160 bar, about 170 bar, about 180 bar, about 190 bar, or about 200 bar, inclusive of all values and ranges therebetween.|[0067] In some embodiments, the CO2 stream can be subject to post-processing prior to storage such that the CO2 stream is compliant with applicable specifications for storage. In some embodiments, the post-processing can include dehydration (e.g., via a condenser) and/or compression (e.g., via a compressor).|[0068] Step 406 is optional and includes purifying the CO2 stream. In some embodiments, the CO2 stream can be purified via condensation of water or other post processing treatment. In some embodiments, the CO2 stream can be compressed into gas storage. In some embodiments, the compressed CO2 stream can be direct injected in a co-located facility. In some embodiments, the compressed CO2 stream can be transported to a location where it can be sequestered. In some embodiments, the CO2 stream can have a high purity. In some embodiments, the CO2 stream can include at least about 80 vol %, at least about 85 vol %, at least about 90 vol %, at least about 91 vol %, at least about 92 vol %, at least about 93 vol %, at least about 94 vol %, at least about 95 vol %, at least about 96 vol %, at least about 97 vol %, at least about 98 vol %, at least about 99 vol %, at least about 99.1 vol %, at least about 99.2 vol %, at least about 99.3 vol %, at least about 99.4 vol %, at least about 99.5 vol %, at least about 99.6 vol %, at least about 99.7 vol %, at least about 99.8 vol %, at least about 99.9 vol %, at least about 99.99 vol %, or at least about 99.999 vol % CO2.|[0069] At step 407, the decomposed carbonated medium, or carbonation medium, is removed from the reaction vessel. Removal of the carbonation medium may be facilitated by the facilitation device and rotation of the reaction vessel. In some implementations, such as when the reaction vessel is oriented vertically, removal of the carbonation medium is facilitated by gravity.|(US20250018356)|Example 1—Furnace|[0070] Embodiments described herein can give way to calcination of carbonated medium that uses renewable energy and is more cost efficient than traditional methods of calcination. An example high-temperature decomposition reactor includes a reaction vessel having an internal diameter of about two meters with a reactor wall thickness of about 0.1 to about 0.2 m. Disposed around the reaction vessel is a furnace having an outer diameter of about 6.2 meters. Accordingly, the furnace thickness is approximately 2.1 meters.|[0071] The example high-temperature decomposition reactor requires approximately 1,700 kilowatt hours (“kWh”) of energy to decompose enough carbonated medium to capture one tonne of carbon dioxide (tCO2). The furnace is composed of a furnace material having an energy storage density of approximately 100 kilowatt hours per cubic meter (kWh/m3) and a production utilization of 50%. In other words, the furnace is able to be utilized 50% of the time.|[0072] The furnace diameter of 6.2 m offsets the energy requirements for the high-temperature decomposition reactor during 50% of the operation time. If the cost of electricity during this time is $0.06/kWh compared to $0.03/kWh during the day, this would result in a 25% decrease in the operating costs of the system. At scale, operating costs dominate the overall costs of the system and energy dominates the operating costs.|[0073] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0074] In addition, the disclosure may include other innovations not presently described. Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0075] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0076] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0077] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0078] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0079] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0080] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0081] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | Family Number|(112981296)|112981296|Advantages / Prev. Drawbacks|(US20250018356 A1)| (...) and future CO_2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO_2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | Chemical engineering | B01J-019/00/53|B01J-2219/00155|B01J-2219/02 | B01J-019/00/53|B01J-2219/00155|B01J-2219/02 | B01J-019/00 | B01J-019/00 | PENDING | (US20250018356)|PENDING | ALIVE | (US20250018356)|ALIVE | (US20250018356)|LEGAL DETAILS FOR US20250018356|Actual or expected expiration date=2044-07-12|Legal state=ALIVE|Status=PENDING|Event publication date=2024-07-12|Event code=US/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=US US18771456|Application date=2024-07-12|Standardized application number=2024US-18771456|Event publication date=2024-07-12|Event code=US/EXMR|Event group=Administrative notifications|USPTO Examiner Name|PRIMARY EXAMINER:CENTRAL, DOCKET|Event publication date=2024-07-12|Event code=US/ART|Event group=Administrative notifications|USPTO Art Group|ART=OPAP|Event publication date=2024-07-12|Event code=US/DK|Event group=Examination events|Attorney Docket Number|Docket Nbr: HRLM-005/01US 342972-2028|Event publication date=2024-07-12|Event code=US/CUST|Event group=Examination events|Attorney/Agent Customer Number|Customer Nbr: 58249|Event publication date=2024-07-12|Event code=US/SMALL|Event group=Administrative notifications|Appl Has Filed a Verified Statement of Micro to Small Entity Status|Business Entity Status: Small|Event publication date=2024-07-12|Event code=US/AIA|Event group=Administrative notifications|First Inventor File Indicated:|AIA=Yes|Event publication date=2024-07-12|Event code=US/ENT|Event group=Administrative notifications|Entity Status Set to Undiscounted|Event publication date=2024-07-12|Event code=US/PTARDY|Event indicator=Pos|Event group=Examination events|Patent Term Adjustment - Ready for Examination|Event publication date=2024-07-25|Event code=US/SMALL|Event group=Administrative notifications|Appl Has Filed a Verified Statement of Micro to Small Entity Status|Event publication date=2024-07-30|Event code=US/APPFILEREC|Event group=Administrative notifications OAO|Filing Receipt|Event publication date=2024-08-27|Event code=US/DKNC|Event indicator=Pos|Event group=Examination events|Docketed New Case - Ready for Examination|Event publication date=2024-08-27|Event code=US/DOCK|Event indicator=Pos|Event group=Examination events|Case Docketed to Examiner|Event publication date=2024-09-20|Event code=US/APE|Event group=Corrections|Preliminary amendments|Event publication date=2024-09-20|Event code=US/IDS|Event group=Examination events OAI|Information Disclosure Statement Filed|Event publication date=2025-01-16|Event code=US/A1|Event group=Examination events|Application published|Publication country=US|Publication number=US20250018356|Publication stage code=A1|Publication date=2025-01-16|Standardized publication number=US20250018356|Event publication date=2025-01-16|Event code=US/PGPUBN|Event indicator=Pos|Event group=Examination events OAO|PG-Pub Issue Notification | (US20250018356)|US | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=lOckPE/DvcNrO7st3g60e190CpEah8ymJjY7t3dG27hjSQxYBqJq7iT+uVYGOkHbowE3xwgjWi0myP6vhetDsA==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000022478886&ekey=2238&xpn=US20250018356&kind=A1 | https://data.uspto.gov/patent-file-wrapper/search/details/18771456/application-data | https://permalink.orbit.com/RenderStaticFirstPage?XPN=cCByeZzzOl7Szt61tQwdisRHIQdPpfyajIQBIFKxQPE%3D%26n%3D1&id=0&base=FAMPAT | US | (US20250018356)|US | (US20250018356)|NAME=Heirloom Carbon Technologies, Inc. , CITY=Brisbane , STATE=CA , COUNTRY=US | (US20250018356)|US; US; US | (US20250018356)|NAME=MCQUEEN Noah, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=SAMALA Shashank, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=DUBEL Andrew, CITY=Moss Beach, STATE=CA , COUNTRY=US | (US20250018356)|5 | 2 | 1 | (US20250018356)|Number of Claims: NCL=20|Number of Drawings: NDR=5|Number of Figures: NFG=5|Independent Claim Number: ICL=1,12|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1| | (US20250018356)|Provisional Appl: US63/513,706 FDD=2023-07-14 [2023US-63513706] | (US20250018356)|ENGLISH (ENG) | (US20250018356)|Patent | Titre: (US20250018356)|Systems and methods for thermal storage integration into high temperature decomposition reactor Résumé: (US20250018356)|A high-temperature decomposition reactor is provided. The reactor includes a reaction vessel, a furnace, and an insulation layer. The reaction vessel includes an inner volume configured to contain a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium. The furnace is disposed around the reaction vessel and includes a furnace material. The furnace material is configured to simultaneously absorb heat and transmit heat. In some instances, the furnace material transmits heat to the inner volume to heat the carbonated medium. The insulation layer is disposed around the furnace and configured to prevent thermal losses from the reactor. Autre: (US20250018356)|1. A reactor, comprising:| a reaction vessel defining an inner volume configured to contain a quantity of carbonated medium while the quantity of carbonated medium transitions to a quantity of carbonation medium;| a furnace disposed around the reaction vessel, the furnace including a furnace material configured to absorb and/or transmit heat; and| an insulation layer disposed around the furnace and configured to reduce thermal losses from the reactor.|2. The reactor of claim 1, wherein the reaction vessel comprises a conductive metal.|3. The reactor of claim 1, wherein the reaction vessel comprises a thermal storage material.|4. The reactor of claim 1, wherein the furnace includes at least one of graphite, granite, basalt, quartzite.|5. The reactor of claim 1, wherein the furnace includes a chamber configured to contain a flow of molten salt.|6. The reactor of claim 1, wherein the insulation layer includes at least one of periclase, a silica based refractory material, an alumina-based refractory material, fiberglass, mineral wool, cellulose, natural fibers, cementitious foam, polyurethane, perlite, polystyrene, or polyisocyanurate.|7. The reactor of claim 1, further comprising:| a rotation mechanism configured to impart rotational motion of-to the reaction vessel.|8. The reactor of claim 1, wherein the furnace material is configured to simultaneously absorb and transmit heat.|9. The reactor of claim 5, wherein the molten salt includes at least one of sodium nitrate, lithium nitrate, potassium nitrate, sodium chloride, or N-ethylpyridinium.|10. The reactor of claim 7, further comprising:| a facilitation device disposed in the reaction vessel, the facilitation device configured to move the carbonated medium from a first position to a second position within the reactor vessel when the rotation mechanism imparts rotational motion to the reactor vessel.|11. The reactor of claim 9, wherein the second position is at a lower potential energy state than the first position.|12. A method, comprising:| feeding a carbonated medium into an inner volume of a reaction vessel;| heating a furnace material, the furnace material contacting and at least partially surrounding the reaction vessel;| transferring heat from the furnace material to the inner volume of the reaction vessel such that the carbonated medium is separated into a carbonation medium and carbon dioxide;| removing the carbon dioxide from the reaction vessel; and| removing the carbonation medium from the reaction vessel.|13. The method of claim 12, wherein heating the furnace material includes providing heat to the furnace material from a renewable electricity source, the renewable electricity source including at least one of solar power, wind power, or geothermal power.|14. The method of claim 12, wherein the furnace material includes at least one of graphite, granite, basalt, quartzite.|15. The method of claim 12, wherein the furnace material includes a molten salt.|16. The method of claim 15, wherein the molten salt including at least one sodium nitrate, lithium nitrate, potassium nitrate, sodium chloride, or N-ethylpyridinium.|17. The method of claim 12, further comprising:| rotating the reaction vessel to facilitate the movement of the carbonated medium through the reaction vessel from a first end of the reactor vessel to a second end of the reactor vessel.|18. The method of claim 17, wherein the first end of the reactor vessel is at a lower potential energy state than the second end of the reactor vessel.|19. The method of claim 12, further comprising:| purifying the carbon dioxide.|20. The method of claim 12, wherein the reactor vessel comprises a conductive material. | 10 | Abstract | gpt-4o-mini | no | The article focuses on a high-temperature decomposition reactor and thermal storage, without any mention of biomass energy production, CO₂ capture, or storage. | ||||||||||||||||||||||||||
| 10 | CN202510631366 | CN202510631366 | CN120474102|CN120474102 | 115620750 | CN120474102 B 2026-03-13 [CN120474102B]|CN120474102 A 2025-08-12 [CN120474102] | 2025-05-16 | 2025-05-16 | 2026-03-13|2025-08-12 | (CN120474102B)|2026-03-13 | (CN120474102)|2045-05-16 | (CN120474102)|Mine renewable energy development method for closing | (CN120474102)|The invention provides a method for developing renewable energy sources of a closed mine. The method comprises the following steps: calculating a wind-light capacity coefficient of a closed mine unit; evaluating the wind-solar power generation potential of the closed mine unit; closing a wind-solar power generation grid-connected line of the mine unit based on the grid division design; designing a power generation dispatching layer; and constructing a power system model containing a shut-down mine unit to minimize the construction operation cost. | INSTITUTE OF GEOGRAPHIC SCIENCES & NATURAL RESOURCES RESEARCH CAS | (CN120474102)|INSTITUTE OF GEOGRAPHIC SCIENCES & NATURAL RESOURCES RESEARCH CAS ([CN])|(CN120474102)|INSTITUTE OF GEOGRAPHIC SCIENCES & NATURAL RESOURCES RESEARCH CAS ([CN]) | LIN GANG|FU JINGYING|JIANG DONG | (CN120474102)|Lin Gang|Fu Jingying|Jiang Dong|(CN120474102)|LIN GANG|FU JINGYING|JIANG DONG | (CN120474102)|Qi Gongjun;CHINA SCIENCE PATENT TRADEMARK AGENTS LTD. (CSPTAL)|Reg. Nb: 11021 | (CN120474102)|The above and other objects, features and advantages of the present disclosure will become more apparent from the following description of embodiments thereof with reference to the accompanying drawings in which:|The current research scale is mainly limited to the single mine level, focuses on the feasibility analysis, suitability evaluation and physical utilization potential evaluation of a specific mine, and the adopted research method has stronger scenario dependency, so that the universality and popularization of the research result are insufficient.| | (CN120474102)|1. A method of shutting down mine renewable energy development comprising: Calculating a wind-solar capacity coefficient of a closed mine unit, wherein the wind-solar capacity coefficient comprises a wind-solar capacity coefficient of the closed mine unit and a photovoltaic power generation capacity coefficient of the closed mine unit; Evaluating the wind-solar power generation potential of the closed mine unit, wherein the evaluating the wind-solar power generation potential of the closed mine unit comprises evaluating the photovoltaic power generation potential of the closed mine unit; the method comprises the steps of designing a closed mine unit wind-solar power generation grid-connected line based on grid division, wherein the grid division comprises dividing wind-solar power generation unit grids based on geographical longitude and latitude information, connecting closed mine units serving as closed mine units in the grids of each wind-solar power generation unit with a transformer substation with the nearest province distance through branch lines, and connecting the transformer substation with a main node with the nearest province distance through a trunk line under the principle of ensuring the shortest total wind-solar power generation grid-connected distance; The method comprises the steps of designing a power generation scheduling layer, wherein the power generation scheduling layer comprises various power generation units which reasonably distribute annual power demands to supply ends in an hour-by-hour time scale according to a heuristic scheduling sequence, wherein a fixed unit is positioned on a first layer of the power generation scheduling layer, the first layer comprises a nuclear power unit, a BECCS unit and a CHP-CCS unit which must be operated, a power generation unit which is closed to a mine unit is positioned on a second layer of the power generation scheduling layer, the second layer further comprises a common wind-solar power generation unit and an offshore wind power unit, the third layer comprises a hydroelectric unit, the fourth layer comprises a CHP-CCS unit which is remained except the CHP-CCS unit which must be operated on the first layer, the fifth layer comprises a natural gas CCS unit, the power generation amount of each power saving is calculated based on the power demand and the power generation amount of the first layer of the model power generation scheduling layer, and gradually replenishing the power gaps by sequentially using the power generation amounts of the second layer to the fifth layer, and And constructing a power system model comprising a closed mine unit, and establishing an objective function with the aim of minimizing construction and operation cost, wherein constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, reserve capacity requirement, climbing capacity constraint and energy storage operation constraint.| | (CN120474102)|In view of this, the present disclosure provides a method of shutting down mine renewable energy development in order to at least partially solve at least one of the above-mentioned technical problems.|The disclosure relates to the technical field of new energy development and smart grids, in particular to a method for developing renewable energy sources for closing mines.|The invention provides a method for developing renewable energy sources of closed mines, which comprises the steps of calculating wind-light capacity coefficients of closed mine units, evaluating wind-light power generation potential of the closed mine units, designing wind-light power generation grid-connected circuits of the closed mine units based on grid division, designing a power generation scheduling layer, and constructing a power system model containing the closed mine units to minimize construction and operation costs.| | (CN120474102)|RENEWABLE ENERGY DEVELOPMENT(100,9)|CLOSURE(100,1)|MINE RENEWABLE ENERGY DEVELOPMENT(100,1)|WIND SOLAR CAPACITY COEFFICIENT(99,6)|CHP CCS(99,3)|SCENARIO DEPENDENCY(89,1)|CAPACITY COEFFICIENT(87,21)|MINE UTILIZATION POTENTIAL EVALUATION(86,1)|WIND SOLAR POWER GENERATION(85,13)|RESERVE CAPACITY REQUIREMENT(81,1)|GEOGRAPHICAL LONGITUDE(78,3)|GRID SECTION(78,3)|SUITABILITY EVALUATION(74,1)|CLOSED MINE(71,62)|CLIMBING CAPACITY CONSTRAINT(71,4)|POWER GENERATION(64,22)|UTILIZATION POTENTIAL EVALUATION(61,1)|SHUTTING DOWN MINE(55,5)|CLOSED MINE CAPACITY COEFFICIENT(53,5)|PROVINCE(51,45)|TRANSFORMER SUBSTATION(50,18)|RESEARCH SCALE(49,1)|WIND SOLAR POWER(48,12)|EVALUATION(48,1)|UNIVERSALITY(48,1)|NATURAL GAS CCS(46,1)|TRANSPROVINCIAL CONVEYING LINE CONSTRAINT(43,3)|LATITUDE INFORMATION(41,3)|BECCS(40,2)|CLOSING MINE(39,8)|DIVIDING WIND SOLAR POWER(38,2)|RESEARCH RESULT POPULARIZATION(38,1)|CONSTRUCTION MINIMIZATION(36,2)|PHOTOVOLTAIC POWER GENERATION CONSTRAINT(34,4)|POWER GENERATION SCHEDULING(33,11)|HEURISTIC(32,4)|POWER GENERATION SCHEDULING LAYER(31,10)|FEASIBILITY ANALYSIS(31,1)|SMART GRID(31,1)|PHOTOVOLTAIC POWER GENERATION(30,18)|MINE(30,8)|LINE CONSTRAINT(27,7)|MODEL POWER GENERATION SCHEDULING(26,1)|SPUR LEVELING CONNECTION COST(26,1)|GRID(24,6)|GENERATION UNIT GRID(24,5)|ANNUAL POWER DEMAND(24,4)|WIND LIGHT POWER GENERATION(24,4)|RENEWABLE ENERGY RESOURCE DEVELOPMENT(24,2)|POWER OPENING(23,3)|LEVEL CITY(23,1)|TIMEIS MOMENT(22,5)|DEVELOPING RENEWABLE ENERGY SOURCE(21,6)|GENERATION COST(21,1)|PROVINCE ANDVARIABLE INVESTMENT(21,1)|DISTRICT(20,4)|PROVINCE RENEWABLE ENERGY(18,5)|SPARE CAPACITY TIMETHE(18,2)|TRANSFORMER SUBSTATIONIS(18,2)|ENERGY DEVELOPMENT(18,1)|PROVINCE NEUTRALIZING TRANSFORMER(18,1)|SINGLE MINE LEVEL(18,1)|OPERATION CONSTRAINT(17,4)|NUCLEAR POWER(17,2)|POWER SAVING(17,2)|OFFSHORE WINDPOWER(16,2)|RESERVE CAPACITY CONSTRAINT(16,2)|TIMETHE MOMENT(16,2)|OBJECTIVE FUNCTION(15,8)|OPERATION COST(15,5)|RESOURCE ENDOWMENT CONDITION(14,2)|DAMAGED LAND ACRE(14,1)|MEDIUM TRANSFORMER SUBSTATIONTHE LEVELING(14,1)|PROVINCE ANDINVESTMENT(14,1)|PROVINCE NEUTRAL TRANSFORMER(14,1)|PROVINCESPOWER GENERATION LAYERIN(14,1)|RESEARCH METHOD ADOPTION(14,1)|ABANDONED MINE TAILING DAM(13,1)|GRID CONNECTED CIRCUIT(13,1)|RUNNING COAL COGENERATION(13,1)|POWER DEMAND(12,4)|ENERGY STORAGE(11,22)|YUAN KWH(11,5)|UNIT POWER SUPPLY CONSTRAINT(11,3)|STANDBY CAPACITY DEMAND(11,2)|CLIMBING CONSTRAINT(11,1)|COAL ELECTRIC COGENERATION(11,1)|FUTURE TRANSPROVINCIAL(11,1)|GENERATION DEPLOYMENT PLANNING(11,1)|GENERATION TECHNOLOGYPOSSIBLE UTILIZATION(11,1)|MINE MINING(11,1)|MINE PHOTOVOLTAIC MODULE(11,1)|PROVINCE COLLECTION(11,1)|RESTRAINING SUITABILITY(11,1)|SHUTDOWN MINE CELL(11,1)|SPARE CAPACITY CONSTRAINT(11,1)|STUDENT HOME(11,1)|SUBSTATION COLLECTION(11,1)|TECHNOLOGY INVESTMENT RECOVERY COEFFICIENT(11,1)|THETHE INSTALLATION COEFFICIENT(11,1)|TIMEHOUR CAPACITY COEFFICIENT REPRESENTATION(11,1)|TIMESTORE MOMENT(11,1)|WINDPOWER(10,14)|LOAD CENTER(10,12)|ENERGY STORAGE OPERATION CONSTRAINT(10,3)|CITY GROUP(9,4)|CONNECTION PROVINCE MIDDLE(9,2)|FIRSTMAXIMUM INSTALLED CAPACITY(9,2)|GRID CONNECTED DISTANCE(9,2)|PROVINCE INSTALLED CAPACITY(9,2)|PROVINCIAL DISTANCE(9,2)|CAPACITY MARGINAL COEFFICIENT(9,1)|CLOSING MINE UNITSLEVELING COST(9,1)|DEVELOPMENT UTILIZATION SUITABILITY(9,1)|GRID UNITLEVELING COST(9,1)|MATURE PROGRESS(9,1)|PHOTOVOLTAIC MODULE INSTALLATION COEFFICIENT(9,1)|RESERVE CAPACITY MINUS(9,1)|TIMETHE RELEASED ENERGY MOMENT(9,1)|TIMETO MOMENT(9,1)|POWER SYSTEM MODEL(8,6)|RENEWABLE ENERGY POWER(8,6)|COUNTY CENTRAL POINT(8,4)|ANNUAL AVERAGE CAPACITY COEFFICIENT(8,1)|CHARGING EFFICIENCY REPRESENTATION(8,1)|CLOSING MINE DEVELOPMENT(8,1)|COUPLED SHUTDOWN MINE(8,1)|EARLY INVESTMENT(8,1)|ENERGYIS INSTALLED CAPACITY PLANNING(8,1)|GENERATION LAYERAT(8,1)|GENERATION TECHNOLOGYAT(8,1)|GRID UNITTHE RATIO(8,1)|INFRASTRUCTURE CAPACITY(8,1)|INSTALLED PLANNING(8,1)|MINE SCALE(8,1)|NATIONAL CLOSED MINE SUITABILITY(8,1)|PHOTOVOLTAIC INSTALLATION COEFFICIENT(8,1)|PROVINCE ANDTHE FIXED INVESTMENT(8,1)|RESEARCH STAY(8,1)|SOLAR PROJECT(8,1)|STANDBY COEFFICIENT(8,1)|SUBSTATIONCONNECTED RENEWABLE ENERGY(8,1)|TARGET ALTITUDE(8,1)|TIMETHE OFFERED LOAD MOMENT(8,1)|UTILIZATION SUITABILITY EVALUATION INDEX(8,1)|WASTE MINE(8,1)|YUAN KW KM(8,1)|GRID CELL(7,5)|CAPACITY PROPORTIONAL REPRESENTATION(7,2)|CAPITAL INVESTMENT(7,2)|ELECTRICAL EQUIPMENT(7,2)|FAN RATED POWER(7,2)|GRID DIVISION DESIGN(7,2)|MAXIMUM RAMP(7,2)|MINE WINDPOWER GENERATION(7,2)|THETECHNOLOGY(7,2)|THETHE DISTANCE(7,2)|WINDPOWER GENERATION EVALUATION(7,2)|PROVINCE MIDDLE POWER(6,4)|GRID CONNECTED LINE CONSTRAINT(6,3)|ABANDONED MINE SUSTAINABLE DEVELOPMENT(6,1)|CAPACITY ALLOCATION(6,1)|CAPITAL RECOVERY PERIOD(6,1)|CONSTRAINT CONDITION(6,1)|DAMAGED STATE(6,1)|DISCHARGE CAPACITY PLUS(6,1)|DISCHARGE EFFICIENCY(6,1)|ELECTRICITY(6,1)|FUSION MODEL(6,1)|GENERATION LAYER SCHEDULING(6,1)|GENERATION POTENTIAL EVALUATION(6,1)|INTEGRAL PLANNING(6,1)|LOAD CENTREIS(6,1)|MINIMIZING CONSTRUCTION OBJECTIVE(6,1)|PROVINCETHE(6,1)|RENEWABLE ENERGY INSTALLATION(6,1)|SPACE LAYOUT OPTIMIZATION(6,1)|TECHNOLOGY INSTALLATION(6,1)|TIMENET POWER DEMAND MOMENT(6,1)|URGENT WORK(6,1)|TRUNK LINE(5,8)|BRANCH LEVELING CONNECTION COST(5,3)|ENERGY STORAGE TECHNOLOGYIS(5,3)|WINDPOWER CAPACITY COEFFICIENT(5,3)|ANDWIND SPEED(4,1)|ANNUITY(4,1)|BLOWER(4,1)|CAPACITY CONFIGURATION OPTIMIZATION(4,1)|CARBON EMISSION STATE(4,1)|CARBON NEUTRAL TARGET(4,1)|CCS(4,1)|CHARGE DISCHARGE SCHEDULE(4,1)|CLIMB RATE(4,1)|CLIMBING COST(4,1)|CLOSED MINE DEPLOYMENT(4,1)|DESIGN MINE(4,1)|DETERMINED SPARE CAPACITY(4,1)|DEVELOPMENT METHOD(4,1)|DEVELOPMENT PHYSICAL POTENTIAL(4,1)|DOMESTIC(4,1)|EANDTHE RATIO(4,1)|ECONOMIC BENEFIT PERSPECTIVE(4,1)|ENERGY CONSUMPTION STATE(4,1)||(CN120474102)|RENEWABLE ENERGY DEVELOPMENT(100,9)|SHUTTING DOWN MINE(100,7)|CLOSURE(100,1)|MINE RENEWABLE ENERGY DEVELOPMENT(100,1)|SCENARIO DEPENDENCY(100,1)|MINE UTILIZATION POTENTIAL EVALUATION(96,1)|DIVISION SHUTDOWN MINE(85,1)|SUITABILITY EVALUATION(83,1)|CAPACITY COEFFICIENT(72,20)|WIND SOLAR CAPACITY COEFFICIENT(70,5)|CLOSED MINE(69,65)|UTILIZATION POTENTIAL EVALUATION(68,1)|GRID SECTION(57,2)|GEOGRAPHICAL LONGITUDE(55,3)|RESEARCH SCALE(55,1)|CLIMBING CAPACITY CONSTRAINT(53,4)|UNIVERSALITY(53,1)|WIND SOLAR POWER GENERATION(52,10)|RENEWABLE ENERGY RESOURCE DEVELOPMENT(52,4)|RESERVE CAPACITY REQUIREMENT(51,1)|MINE(50,10)|SHUTDOWN MINE UNIT WIND(50,1)|SHUTDOWN(48,10)|CLOSED MINE CAPACITY COEFFICIENT(48,5)|CLOSING MINE(43,8)|RESEARCH RESULT POPULARIZATION(42,1)|POWER GENERATION(40,19)|DEVELOPING RENEWABLE ENERGY SOURCE(36,9)|GRID DIVISION DESIGN(36,3)|FEASIBILITY ANALYSIS(35,1)|SMART GRID(35,1)|PROVINCIAL DISTANCE(33,3)|CLOSED MINE GENERATOR(33,1)|TRANSPROVINCIAL CONVEYING LINE CONSTRAINT(32,3)|LATITUDE INFORMATION(29,3)|SPUR LEVELING CONNECTION COST(29,1)|WIND LIGHT POWER GENERATION(27,4)|PHOTOVOLTAIC POWER GENERATION CONSTRAINT(25,4)|LEVEL CITY(25,1)|TIMEIS MOMENT(24,5)|HEURISTIC(24,4)|GENERATION COST(24,1)|PROVINCE ANDVARIABLE INVESTMENT(24,1)|DISTRICT(23,4)|POWER GENERATION SCHEDULING(20,8)|PROVINCE RENEWABLE ENERGY(20,5)|SPARE CAPACITY TIMETHE(20,2)|TRANSFORMER SUBSTATIONIS(20,2)|CONSTRUCTION RUNNING COST(20,1)|ENERGY DEVELOPMENT(20,1)|PROVINCE NEUTRALIZING TRANSFORMER(20,1)|SINGLE MINE LEVEL(20,1)|SOLAR POWER GENERATION POTENTIAL(20,1)|POWER GENERATION SCHEDULING LAYER(18,7)|RESERVE CAPACITY CONSTRAINT(18,2)|TIMETHE MOMENT(18,2)|OPERATION COST(17,5)|ANNUAL POWER DEMAND(17,4)|WINDPOWER CAPACITY COEFFICIENT(16,4)|DAMAGED LAND ACRE(16,1)|MEDIUM TRANSFORMER SUBSTATIONTHE LEVELING(16,1)|PROVINCE ANDINVESTMENT(16,1)|PROVINCE NEUTRAL TRANSFORMER(16,1)|PROVINCESPOWER GENERATION LAYERIN(16,1)|RESEARCH METHOD ADOPTION(16,1)|RESOURCE ENDOWMENT CONDITION(15,2)|GENERATION GRID CONNECTION(14,3)|ABANDONED MINE TAILING DAM(14,1)|GRID CONNECTED CIRCUIT(14,1)|RUNNING COAL COGENERATION(14,1)|POWER GENERATION UNIT GRID(13,2)|SHORT TOTAL(13,2)|STANDBY CAPACITY DEMAND(13,2)|YUAN KWH(12,5)|CLIMBING CONSTRAINT(12,1)|COAL ELECTRIC COGENERATION(12,1)|FUTURE TRANSPROVINCIAL(12,1)|GENERATION DEPLOYMENT PLANNING(12,1)|GENERATION TECHNOLOGYPOSSIBLE UTILIZATION(12,1)|MINE MINING(12,1)|MINE PHOTOVOLTAIC MODULE(12,1)|PROVINCE COLLECTION(12,1)|RESTRAINING SUITABILITY(12,1)|SHUTDOWN MINE CELL(12,1)|SPARE CAPACITY CONSTRAINT(12,1)|STUDENT HOME(12,1)|SUBSTATION COLLECTION(12,1)|TECHNOLOGY INVESTMENT RECOVERY COEFFICIENT(12,1)|THETHE INSTALLATION COEFFICIENT(12,1)|TIMEHOUR CAPACITY COEFFICIENT REPRESENTATION(12,1)|TIMESTORE MOMENT(12,1)|LOAD CENTER(11,12)|OBJECTIVE FUNCTION(11,8)|RENEWABLE ENERGY GENERATION(11,2)|CAPACITY MARGINAL COEFFICIENT(11,1)|CLOSING MINE UNITSLEVELING COST(11,1)|DEVELOPMENT UTILIZATION SUITABILITY(11,1)|GRID UNITLEVELING COST(11,1)|MATURE PROGRESS(11,1)|PHOTOVOLTAIC MODULE INSTALLATION COEFFICIENT(11,1)|RESERVE CAPACITY MINUS(11,1)|TIMETHE RELEASED ENERGY MOMENT(11,1)|TIMETO MOMENT(11,1)|CITY GROUP(10,4)|CONNECTION PROVINCE MIDDLE(10,2)|FIRSTMAXIMUM INSTALLED CAPACITY(10,2)|PROVINCE INSTALLED CAPACITY(10,2)|RENEWABLE ENERGY POWER(9,6)|COUNTY CENTRAL POINT(9,4)|ANNUAL AVERAGE CAPACITY COEFFICIENT(9,1)|CHARGING EFFICIENCY REPRESENTATION(9,1)|CLOSING MINE DEVELOPMENT(9,1)|COUPLED SHUTDOWN MINE(9,1)|DESIGN POWER GENERATION SCHEDULING(9,1)|EARLY INVESTMENT(9,1)|ENERGYIS INSTALLED CAPACITY PLANNING(9,1)|GENERATION LAYERAT(9,1)|GENERATION TECHNOLOGYAT(9,1)|GRID UNITTHE RATIO(9,1)|INFRASTRUCTURE CAPACITY(9,1)|INSTALLED PLANNING(9,1)|MINE SCALE(9,1)|NATIONAL CLOSED MINE SUITABILITY(9,1)|PHOTOVOLTAIC INSTALLATION COEFFICIENT(9,1)|PROVINCE ANDTHE FIXED INVESTMENT(9,1)|RESEARCH STAY(9,1)|SOLAR PROJECT(9,1)|STANDBY COEFFICIENT(9,1)|SUBSTATIONCONNECTED RENEWABLE ENERGY(9,1)|TARGET ALTITUDE(9,1)|TIMETHE OFFERED LOAD MOMENT(9,1)|UTILIZATION SUITABILITY EVALUATION INDEX(9,1)|WASTE MINE(9,1)|YUAN KW KM(9,1)|GRID CELL(8,5)|UNIT POWER SUPPLY CONSTRAINT(8,3)|PROVINCE MIDDLE POWER(7,4)|ENERGY STORAGE OPERATION CONSTRAINT(7,3)|CAPACITY PROPORTIONAL REPRESENTATION(7,2)|CAPITAL INVESTMENT(7,2)|ELECTRICAL EQUIPMENT(7,2)|FAN RATED POWER(7,2)|MAXIMUM RAMP(7,2)|MINE WINDPOWER GENERATION(7,2)|THETECHNOLOGY(7,2)|THETHE DISTANCE(7,2)|WINDPOWER GENERATION EVALUATION(7,2)|ABANDONED MINE SUSTAINABLE DEVELOPMENT(7,1)|CAPACITY ALLOCATION(7,1)|CAPITAL RECOVERY PERIOD(7,1)|CONSTRAINT CONDITION(7,1)|DAMAGED STATE(7,1)|DISCHARGE CAPACITY PLUS(7,1)|DISCHARGE EFFICIENCY(7,1)|ELECTRICITY(7,1)|FUSION MODEL(7,1)|GENERATION LAYER SCHEDULING(7,1)|GENERATION POTENTIAL EVALUATION(7,1)|INTEGRAL PLANNING(7,1)|LOAD CENTREIS(7,1)|MINIMIZING CONSTRUCTION OBJECTIVE(7,1)|PROVINCETHE(7,1)|RENEWABLE ENERGY INSTALLATION(7,1)|SPACE LAYOUT OPTIMIZATION(7,1)|TECHNOLOGY INSTALLATION(7,1)|TIMENET POWER DEMAND MOMENT(7,1)|URGENT WORK(7,1)|POWER SYSTEM MODEL(6,6)|BRANCH LEVELING CONNECTION COST(6,3)|ENERGY STORAGE TECHNOLOGYIS(6,3)|ANDWIND SPEED(5,1)|ANNUITY(5,1)|BLOWER(5,1)|CAPACITY CONFIGURATION OPTIMIZATION(5,1)|CARBON EMISSION STATE(5,1)|CARBON NEUTRAL TARGET(5,1)|CHARGE DISCHARGE SCHEDULE(5,1)|CLIMB RATE(5,1)|CLIMBING COST(5,1)|CLOSED MINE DEPLOYMENT(5,1)|CONSTRUCTION MINIMIZATION(5,1)|DESIGN MINE(5,1)|DETERMINED SPARE CAPACITY(5,1)|DEVELOPMENT METHOD(5,1)|DEVELOPMENT PHYSICAL POTENTIAL(5,1)|DIVIDING WIND SOLAR POWER(5,1)|DOMESTIC(5,1)|EANDTHE RATIO(5,1)|ECONOMIC BENEFIT PERSPECTIVE(5,1)|ELECTRICAL POWER SYSTEM MODEL(5,1)|ENERGY CONSUMPTION STATE(5,1)|ENERGY STORAGE TECHNOLOGYTHE(5,1)| | (CN120474102)|1. A method of shutting down mine renewable energy development comprising:| Calculating a wind-solar capacity coefficient of a closed mine unit, wherein the wind-solar capacity coefficient comprises a wind-solar capacity coefficient of the closed mine unit and a photovoltaic power generation capacity coefficient of the closed mine unit; | Evaluating the wind-solar power generation potential of the closed mine unit, wherein the evaluating the wind-solar power generation potential of the closed mine unit comprises evaluating the photovoltaic power generation potential of the closed mine unit; | the method comprises the steps of designing a closed mine unit wind-solar power generation grid-connected line based on grid division, wherein the grid division comprises dividing wind-solar power generation unit grids based on geographical longitude and latitude information, connecting closed mine units serving as closed mine units in the grids of each wind-solar power generation unit with a transformer substation with the nearest province distance through branch lines, and connecting the transformer substation with a main node with the nearest province distance through a trunk line under the principle of ensuring the shortest total wind-solar power generation grid-connected distance; | The method comprises the steps of designing a power generation scheduling layer, wherein the power generation scheduling layer comprises various power generation units which reasonably distribute annual power demands to supply ends in an hour-by-hour time scale according to a heuristic scheduling sequence, wherein a fixed unit is positioned on a first layer of the power generation scheduling layer, the first layer comprises a nuclear power unit, a BECCS unit and a CHP-CCS unit which must be operated, a power generation unit which is closed to a mine unit is positioned on a second layer of the power generation scheduling layer, the second layer further comprises a common wind-solar power generation unit and an offshore wind power unit, the third layer comprises a hydroelectric unit, the fourth layer comprises a CHP-CCS unit which is remained except the CHP-CCS unit which must be operated on the first layer, the fifth layer comprises a natural gas CCS unit, the power generation amount of each power saving is calculated based on the power demand and the power generation amount of the first layer of the model power generation scheduling layer, and gradually replenishing the power gaps by sequentially using the power generation amounts of the second layer to the fifth layer, and |And constructing a power system model comprising a closed mine unit, and establishing an objective function with the aim of minimizing construction and operation cost, wherein constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, reserve capacity requirement, climbing capacity constraint and energy storage operation constraint.|2. The method for developing renewable energy resources for shutting down mines according to claim 1, wherein the central point of each county or district is used as the space position of a transformer substation, all cities in the city group at or above the level city are positioned as the load centers, and the central point of the load centers in space is used as the main node of the power grid.|3. The shut down mine renewable energy source development method of claim 1, further comprising calculating a shut down mine unit wind-solar power generation cost and calculating a spur leveling connection cost. | (CN120474102)|TECHNICAL FIELD|Technical Field|[0001] The disclosure relates to the technical field of new energy development and smart grids, in particular to a method for developing renewable energy sources for closing mines.|BACKGROUND ART|[0002] China is the largest energy consumption country and carbon emission country in the world at present, and under the pressure of energy structure adjustment and carbon emission reduction, the task of developing renewable energy resources in China is not yet sustained. Meanwhile, as soon as 2024 years, mining of mines nationwide occupies about 5400 tens of thousands of acres of damaged land, so how to perform renewable energy resource modification development on closed mines is a necessary and urgent work.|DISCLOSURE|Disclosure of Invention|[0003] In view of this, the present disclosure provides a method of shutting down mine renewable energy development in order to at least partially solve at least one of the above-mentioned technical problems.|[0004] In order to achieve the above object, the technical scheme of the present disclosure is as follows:|[0005] According to the embodiment of the disclosure, the method for developing the renewable energy sources of the closed mine comprises the steps of calculating the wind-light capacity coefficient of the closed mine unit, evaluating wind-light power generation potential of the closed mine unit, designing a wind-light power generation grid-connected line of the closed mine unit based on grid division, designing a power generation scheduling layer, and constructing a power system model containing the closed mine unit to minimize construction and operation costs. |[0006] According to the embodiment of the disclosure, calculating the wind-solar capacity coefficient of the closed mine unit comprises calculating the wind-power capacity coefficient of the closed mine unit and calculating the photovoltaic power generation capacity coefficient of the closed mine unit.|[0007] According to embodiments of the present disclosure, assessing the wind power generation potential of a shut down mine unit includes assessing the wind power generation potential of a shut down mine unit, and assessing the photovoltaic power generation potential of a shut down mine unit.|[0008] According to the embodiment of the disclosure, the grid division design-based mine unit wind-solar power generation grid-connected line comprises dividing wind-solar power generation unit grids based on geographical longitude and latitude information, connecting each wind-solar power generation unit grid serving as a mine unit which is closed to a transformer substation with the nearest province distance through a branch line, and connecting the transformer substation with a main node with the nearest province distance through a trunk line under the principle of ensuring that the total wind-solar power generation grid-connected distance is the shortest.|[0009] According to the embodiment of the disclosure, the central point of each county or district is taken as the space position of a transformer substation, all the cities in the city group at or above the ground level are positioned as the load centers, and the central point of the load centers in the space is taken as the main node of the power grid.|[0010] According to the embodiment of the disclosure, designing the power generation scheduling layer comprises reasonably distributing annual power demands to various power generating sets at a supply end in an hour scale according to a heuristic scheduling sequence. The fixed unit is positioned on a first layer of the power generation dispatching layer, and the generator unit for closing the mine unit is positioned on a second layer of the power generation dispatching layer.|[0011] According to embodiments of the present disclosure, an objective function is established when constructing a power system model that includes shut down mine units with the objective of minimizing construction and operation costs. The constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, standby capacity demand, climbing capacity constraint and energy storage operation constraint.|[0012] According to an embodiment of the present disclosure, the method for developing renewable energy sources of closed mines further includes calculating a cost of wind-solar power generation of closed mine units and calculating a branch leveling connection cost.|DRAWINGS DESCRIPTION|[0013] The above and other objects, features and advantages of the present disclosure will become more apparent from the following description of embodiments thereof with reference to the accompanying drawings in which:|[0014] fig. 1 is a schematic diagram of the working principle of a waste mine photovoltaic-pumped storage power station. |[0015] FIG. 2 is a flow chart of a method of shutting down mine renewable energy development in accordance with an embodiment of the present disclosure.|[0016] Fig. 3 is a schematic diagram of a technical flow and principle of a method for developing renewable energy resources in a closed mine according to an embodiment of the disclosure.|INVENTION MODE|Detailed Description|[0017] The invention provides a renewable energy development method for a closed mine, which uses wind power and photovoltaic power generation as main renewable energy power generation technologies, creatively combines the resource endowment condition and the geographic space characteristic of the closed mine with new energy power system planning, and realizes the space site selection and capacity configuration optimization of the renewable energy development for the closed mine.|[0018] Research and practice that has combined shut down mines and renewable energy sources abroad has made relatively mature progress. For example, the german luer mining area has been able to realize a wind power project for continuous power generation. Meanwhile, domestic scholars Zhang Zhenji consider that the application of the photovoltaic power generation technology in the abandoned mine tailing dam has certain feasibility, and indicate that the photovoltaic power generation system is an effective choice for sustainable development of the abandoned mine from the perspective of economic benefit. However, the prior art is generally based on a single closed mine, combines pumped storage with photovoltaic power generation, utilizes a photovoltaic array to convey solar power generation to a nearby pumped storage power station through converging, pumps water in a lower reservoir to an upper reservoir by transformer power generation when electric equipment is less and power grid load is low, stores low-valley electric energy in the form of potential energy of water, discharges water from the upper reservoir when electric equipment is increased and power grid load is increased, maintains the stability of a power grid, and has the working flow and principle shown in figure 1. However, the above prior art has the following disadvantages:|[0019] 1. there is little research in domestic on the development and site selection of renewable energy sources for closing mines, and most of the research stays in theoretical stages, and no specific experiment is proved. |[0020] 2. The current research scale is mainly limited to the single mine level, focuses on the feasibility analysis, suitability evaluation and physical utilization potential evaluation of a specific mine, and the adopted research method has stronger scenario dependency, so that the universality and popularization of the research result are insufficient.|[0021] 3. The existing research is less from the perspective of an integral energy system, a plurality of closed mines in a large scale range are brought into a new energy power network to carry out integral planning, and particularly, research blank exists in key links such as capacity configuration, space layout optimization and the like of multiple power generation layer complementation.|[0022] 4. The existing research rarely considers the problem of accurate matching of the supply capacity and the demand response in time and space after the renewable energy development of the closed mine is connected with the grid, and the closed mine is not taken as an important renewable energy power generation supply end to be incorporated into the planning of a new energy power system in the future.|[0023] Therefore, the method for developing renewable energy sources of closed mines, which is provided by the invention, adopts wind power and photovoltaic power generation as main renewable energy source power generation technologies, creatively combines the resource endowment conditions and the geographic space characteristics of closed mines with new energy power system planning, and realizes the optimization of space site selection and capacity allocation of the development of renewable energy sources of closed mines.|[0024] For the purposes of promoting an understanding of the principles and advantages of the disclosure, reference will now be made to the embodiments illustrated in the drawings and specific language will be used to describe the same.|[0025] In an embodiment of the present disclosure, as shown in fig. 2 and 3, there is provided a method of shutting down mine renewable energy development, including the operations S1 to S5 of:|[0026] s1, calculating a wind-light capacity coefficient of a closed mine unit; |[0027] S2, evaluating the wind-solar power generation potential of a closed mine unit; |[0028] S3, closing a mine unit wind-solar power generation grid-connected line based on grid division design; |[0029] s4, designing a power generation scheduling layer, and |[0030] And S5, constructing a power system model comprising closing the mine units to minimize construction and operation costs.|[0031] According to the embodiment of the disclosure, calculating the wind-solar capacity coefficient of the closed mine unit comprises calculating the wind-solar capacity coefficient of the closed mine unit and calculating the photovoltaic power generation capacity coefficient of the closed mine unit.|[0032] And (3) calculating the wind power capacity coefficient, namely calculating the wind power capacity coefficient of the closed mine unit according to the following formula based on the wind speed simulation data in the east-west direction and the north-south direction of the hour scale. First, wind speed data in two directions is synthesized using equation 1.|[0033] (1);|[0034] (2);|[0035] Then, the real-time wind speed data at the height of the fan hub is obtained by using the conversion of the 2,AndWind speed representing the target altitude and the original altitude respectively,AndRepresenting the target height and the original height, respectively.As a conversion factor, it varies from geographic location to geographic location. Then, the real-time power of the wind generator is inferred from the wind speed as shown in equation 3.|[0036] (3);|[0037] (4);|[0038] In the formula,Representing the real-time power of the blower,Indicating the rated power of the fan,Representing the real-time wind speed,、AndThe cut-in wind speed, the rated wind speed and the cut-out wind speed of the fan are respectively indicated. Finally, calculating the ratio of the real-time power to the rated power of the fan as the capacity coefficient for shutting down the wind power generation of the mine through a formula 4。|[0039] And (3) calculating the photovoltaic power generation capacity coefficient, namely calculating the photovoltaic power generation capacity coefficient of the closed mine for 8760 hours every year based on the solar radiation data of the closed mine unit scale through a method of 5.|[0040] (5);|[0041] In the formula,AndRespectively representing the solar energy conversion efficiency of the photovoltaic module under the calculation time and standard experiment conditions (the temperature of the photovoltaic module is 25 ℃, the solar radiation amount is 1000W/m 2, and the air quality is 1.5 AM). It is assumed herein that the conversion efficiency of the photovoltaic module remains unchanged when the amount of solar radiation is varied, i.eAndThe ratio is always 1.Represents the power loss in the power generation process of the photovoltaic module,AndRepresenting the calculated occlusion effect coefficient and temperature effect coefficient, respectively.|[0042] According to the embodiment of the disclosure, the evaluation of the wind power generation potential of the mine unit comprises the evaluation of the wind power generation potential of the mine unit, and the evaluation of the photovoltaic power generation potential of the mine unit.|[0043] Regarding wind power potential evaluation, firstly, a closed mine wind power development utilization suitability evaluation index system is constructed by combining the attribute characteristics of the closed mine, the suitability of the national closed mine wind power development is evaluated, and the closed mine is classified into a closed mine suitable for wind power development and a closed mine unsuitable for wind power development. The evaluation index system is shown in Table 1.|[0044] Table 1 shows the suitability evaluation index system for mine wind power development|[0045] |[0046] Next, for a shutdown mine unit suitable for developing wind power, its wind power development physical potential was calculated using equation 6:|[0047] (6);|[0048] In the middle of Represents the maximum installed capacity potential of the wind power generation of the mine land resource,Indicating the area of the mine that is shut down,Representing the installed capacity of wind power per unit area.|[0049] And (3) regarding photovoltaic power generation potential evaluation, constructing a closed mine photovoltaic power generation development and utilization suitability evaluation index system, and restraining suitability of a closed mine deployment photovoltaic power generation project. The evaluation index system is shown in Table 2.|[0050] Table 2 evaluation index system for suitability of mine photovoltaic power generation|[0051] |[0052] Assuming that photovoltaic power generation adopts a fixed inclination installation mode, the installation coefficient of the photovoltaic module closing the scale of the mine unit needs to be calculated. The photovoltaic installation coefficient refers to the effective photovoltaic panel area coefficient of unit land area, and a specific calculation formula is as follows:|[0053] (7);|[0054] in the formula, Refers to the installation factor of the photovoltaic. Finally, the photovoltaic installed capacity potential is calculated according to equation 8:|[0055] (9);|[0056] in the formula, The maximum installed capacity potential of the mine photovoltaic power generation project is closed; the generated power per unit area of the photovoltaic panel is represented. |[0057] According to an embodiment of the present disclosure, closing a mine unit wind-solar power generation grid-connected line based on grid division design includes:|[0058] dividing a wind-light power generation unit grid based on geographic longitude and latitude information; |[0059] connecting each wind-solar power generation unit grid with a closed mine as a closed mine unit and a transformer substation with the nearest provincial distance through a branch line, and |[0060] Under the principle of ensuring the shortest total distance of wind-solar power generation grid connection, the transformer substation is connected with the main node with the nearest same province distance through a trunk line.|[0061] According to the embodiment of the disclosure, the central point of each county or district is taken as the space position of a transformer substation, all cities in the city group at or above the ground level are positioned as the load centers, and the central point of the load centers in the space is taken as the main node of the power grid.|[0062] Specifically, each wind-solar power generation unit grid (comprising a common space grid unit and a closed mine unit) is connected with a transformer substation with the nearest provincial distance through branch lines. Then, under the principle of ensuring that the total distance of wind-solar power generation grid connection is shortest, the transformer substation is connected with the main node closest to the province through a trunk line (the central point of each county or district in China is used as the space position of the transformer substation in the model, all cities in the city group at or above the city level are positioned as the load center, and the central point of the load center in space is used as the main node of a future power grid).|[0063] According to the embodiment of the disclosure, designing the power generation scheduling layer comprises reasonably distributing annual power demands to various power generating units at a supply end in an hour scale according to a heuristic scheduling sequence. The fixed unit is positioned on a first layer of the power generation dispatching layer, and the generator unit for closing the mine unit is positioned on a second layer of the power generation dispatching layer.|[0064] Specifically, according to the heuristic scheduling sequence, annual power demands are reasonably distributed to various generator sets at the supply end in an hour scale, for example, refer to the following table 3. Based on the power saving requirements and the generated energy of a first layer G1 (a fixed power generation layer, the power is used preferentially and is the power which must be operated) of the power generation scheduling layer, after the power gaps existing in each power saving are calculated, the generated energy of a second layer G2 to a fifth layer G5 is utilized in sequence to gradually fill the power gaps. The shut down mine renewable energy generation is placed in a second layer of the model, also known as a variable energy generation layer.|[0065] TABLE 4 Power Generation layer scheduling order|[0066] |[0067] According to the embodiment of the disclosure, an objective function is established with the aim of minimizing construction operation cost when constructing a power system model comprising closed mine units. The constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, standby capacity demand, climbing capacity constraint and energy storage operation constraint.|[0068] The objective function is built by minimizing the construction and operation cost of the new energy power system for the development of the renewable energy of the coupled shut-down mine on the basis of the existing capacity of the infrastructure and the fixed machine. Setting upRepresenting a collection of provinces; indicating the province involved in nine major clean energy bases is Is a subset of (a); representing a collection of renewable energy power generation technologies (ordinary onshore wind power, ordinary photovoltaic power generation, offshore wind power, shut down mine photovoltaic power generation, shut down mine wind power); representing provinces Renewable energy power generation technologyA set of grid cells that may be utilized; representing provinces Neutralizing transformer substationConnected renewable energy power generation technologyA set of grid cells that may be utilized; representing provinces Renewable energy power generation technologyA set of shut down mine units that may be utilized; representing provinces Neutral transformer stationConnected renewable energy power generation technologyA set of shut down mine units that may be utilized; Representing a collection of substations; representing a set of load centers; representing a collection of energy storage technologies (pumped storage and lithium battery chemical storage); Representing a collection of power generation layers; representing a set of time slices. Province of nine large clean energy basesTechnology for new energyIs installed capacity planning unit of GW; Representing a power generation layer The unit of climbing cost is yuan/kW; Representing a power generation layer Is measured in yuan/kW; Representing a power generation layer Is set up to be a unit standby cost of (a), the unit is yuan/kW; Representing a power generation layer Is yuan/kW per unit fuel cost; Representing a power generation layer The unit variable operation and maintenance cost of (3) is yuan/kW; Representing energy storage technology Is per unit yuan/kW; Representing energy storage technology Is of the fixed operation and maintenance cost of yuan/kWyr;Representing energy storage technologyIs given in yuan/kWh; representing provinces AndThe fixed investment of the electric power transmission line is yuan/kW; representing provinces AndVariable investment in electric power transmission line between, unit is yuan/kWkm;Representing provincesPower generation layerIn time slicesIs given in GW; representing provinces Renewable energy power generation technologyPossible utilization of the firstMaximum installed capacity potential of each grid cell in GW; representing provinces Renewable energy technologyPossible utilization of the firstMaximum installed capacity potential of each closed mine unit in GW; representing provinces AndThe unit of the transmission capacity of the existing power transmission line is GW; representing provinces The unit of the future maximum installation capacity of pumped storage is GW; representing provinces The installed pumped storage capacity is GW; representing provinces The unit of the maximum capacity of the running coal cogeneration is GW; representing provinces Power generation layerAt the moment of timeHour capacity coefficient representation of time; representing provinces First, theRenewable energy power generation technology for each grid unitAt the moment of timeIs represented by a capacity coefficient of (a); representing provinces First, theRenewable energy power generation technology for closing mine unitsAt the moment of timeIs represented by a capacity coefficient of (a); representing provinces First, theRenewable energy power generation technology for each grid unitAnnual average capacity coefficient representation; representing provinces First, theRenewable energy power generation technology for closing mine unitsAnnual average capacity coefficient representation; representing provinces First, theThe installation coefficients of the photovoltaic modules of the mine units are closed; Representing renewable energy power generation technology The unit installed capacity occupation area of the system is GW/km 2; representing provinces First, theThe area of each closed mine is km 2; representing provinces First, theRenewable energy source technology for each grid unitLeveling costs in yuan/kWh for the branch lines connected to the substation; representing provinces First, theRenewable energy source technology for closing mine unitsLeveling costs in yuan/kWh for the branch lines connected to the substation; representing provinces AndThe distance between the two adjacent sections is km; representing provinces First, theThe distance between each grid unit and the transformer substation is in km; representing provinces First, theThe distance between each closed mine unit and the transformer substation is in km; representing provinces Is of the transformer substation of (a)Distance connected to load center in km; representing provinces At the moment of timeIs given in GW; representing provinces At the moment of timeNet power demand remaining after subtracting the supply that L1 must operate, in GW; representing provinces First, theRenewable energy power generation technology for each grid unitThe ratio of installed capacity to maximum potential installed capacity; representing provinces First, theRenewable energy power generation technology for closing mine unitsThe ratio of installed capacity to maximum potential installed capacity; representing provinces First, theRenewable energy power generation technology for each grid unitThe unit of the leveling degree electric cost is yuan/kWh; representing provinces First, theRenewable energy power generation technology for closing mine unitsThe unit of the leveling degree electric cost is yuan/kWh; Representing energy storage technology Investment recovery coefficients of (a); representing provinces AndInvestment recovery coefficients of the inter-span conveying line; Representing the investment recovery coefficient of the grid-connected branch line; Representing the investment recovery coefficient of the grid-connected trunk line; Representing a power generation layer Is represented by the maximum ramp rate of (a); Representing a power generation layer Is represented by the maximum ramp down rate of (a); Representing energy storage technology Is a charging efficiency representation of (2); Representing energy storage technology Is a discharge efficiency representation of (2); representing the lowest power transmission efficiency representation of coal cogeneration during an unnecessary operation period if the coal cogeneration is in online operation; Representing energy storage technology Is a self-discharge rate representation of (2); A reserve capacity demand rate representation representing an electrical load; a reserve capacity demand rate representation representing a renewable energy power generation technology; Representing energy storage technology Is given in h; represents the capital investment cost of the grid-tie line in yuan/kW km;The transmission loss rate of branch lines and trunk lines connected by wind and light grid connection is expressed in%/km; representing provinces AndThe energy loss rate of the inter-span transmission line is expressed as%/km; Representing a power generation layer Energy loss rate after using CCS technology.Representing provincesFirst, theTechnology for developing renewable energy sources by using grid cellsA proportional representation of the capacity of (2) in relation to the maximum potential; representing provinces First, theTechnology for closing mine development renewable energy sourcesA proportional representation of the capacity of (2) in relation to the maximum potential; Representing the connection province Middle (f)Renewable energy power generation technology for each grid unitWith the transformer substationIs given in GW; Representing the connection province Middle (f)Renewable energy power generation technology for closing mine unitsWith the transformer substationIs given in GW; Representing the connection province Medium transformer substationWith a load centreIs the unit of GW; representing provinces AndThe unit of the capacity of the inter-span conveying line is GW; representing provinces Middle energy storage technologyIs given in GW; representing provinces Renewable energy power generation technologyAt the moment of timeIs summarized by grid cells and shut down mine cells, the unit is GW; representing provinces Medium power generation technology(Power generation layers L2-L4 and renewable energy power generation technology) at the momentThe generated electric quantity is transmitted to other provinces of electric quantity, and the unit is GW; representing provinces At the moment of timeTo the provinceThe unit of the electric quantity is GW; representing provinces Medium power generation technologyAt the moment of timeStore to energy storage technologyThe unit of the electric quantity is GW; representing provinces Middle energy storage technologyAt the moment of timeThe released energy is in GW; Indicating the time of expiration Province and partIs stored in energy storage technologyIs given in units of GWh; representing provinces Middle energy storage technologyAt the moment of timeThe unit of the spare capacity is GW; representing provinces Middle power generation layerAt the moment of timeThe unit of the spare capacity is GW; representing provinces Middle power generation layerAt the moment of timeThe offered load, in GW; representing provinces Middle power generation layerAt the moment of timeThe unit is GW; representing provinces Middle power generation layerAt the moment of timeThe unit is GW; Representing binary variables for determining provinces during unnecessary run-time Coal cogeneration technology of middle L3 layer at momentWhether to operate or not; representing provinces In the transformer substationWith a load centreTotal power transmission year, in GWh; representing provinces Medium transformer substationThe leveling cost of the trunk line connected with the load center is yuan/kW; representing provinces Is a power generation layer of (a)At the moment of timeIs a unit GW. The specific calculation formula of the objective function is as follows:|[0069] (9);|[0070] In the embodiment of the disclosure, in combination with fig. 3, a circuit system model including a closed mine unit male is a bottom-up multi-scale fusion model, and aims at minimizing the cost of integral construction operation of a power system in China, and a grid unit and a wind-solar new energy power generation technology of a closed mine unit scale and a traditional power generation technology of a provincial area scale are used on a space unit scale, for example, the traditional power generation technology comprises coal electric cogeneration, nuclear power, biomass power generation (BECCS), water power and natural gas power generation (natural gas+ccs), and the operation constraint of the power system per hour is jointly met, including supply-demand balance constraint, reserve capacity constraint, climbing constraint and the like. Based on the model, the capacity of the conventional power generation technology, the capacity of the power trans-provincial transmission and the new energy power generation technology at the supply end on the space grid and the closed mine units is newly built, expanded, scheduled and spatially laid out are optimized, so that the development potential configuration and spatially laid out planning of the China closed mine renewable energy optimum under the carbon neutral target are obtained, and the constraint conditions can comprise, for example: |[0071] ① Supply and demand balance constraint: |[0072] the power demand of each province at each time slice should be equal to the total power supply. The specific formula is as follows: |[0073] (10);|[0074] ② Wind power and photovoltaic power generation constraints: |[0075] The power generation utilization amount of each renewable energy technology at each moment should be less than or equal to the maximum power generation capacity that the technology installation can provide at the moment. |[0076] (11);|[0077] The total area occupied by wind power and photovoltaic power generation cannot exceed the total area of a mining area, and a specific constraint function is as follows:|[0078] (12);|[0079] constraint is carried out on the wind-solar installed capacity of the nine-large clean energy base, the wind-solar installed capacity of each province related to the nine-large clean energy base is required to be larger than or equal to the national wind-solar power generation deployment planning of the provinces, and the wind-solar power generation deployment planning is shown in a formula 13: |[0080] (13);|[0081] ③ Fixing unit power supply constraint: |[0082] For a fixed unit, the amount of electricity provided by the fixed unit in a time slice should be less than or equal to the maximum power transmission capacity of the time slice. |[0083] (14);|[0084] In addition, if the coal cogeneration unit needs to be run online to meet the power demand during the unnecessary operation period, the limitation of the minimum output power of the coal cogeneration unit needs to be met:|[0085] (15);|[0086] (16);|[0087] ④ Wind-solar grid-connected line constraint: |[0088] the installed capacity of each branch line should be equal to or greater than the maximum power generation of the renewable energy installation of the grid unit connected to the substation or the closed mine unit, as shown in the following formula: |[0089] (17);|[0090] (18);|[0091] And for a trunk line connected with a load center of the transformer substation in the wind-solar grid connection process, the installed capacity of the trunk line is larger than or equal to the maximum power transmitted by the transformer substation. |[0092] (19);|[0093] ⑤ Cross-provincial conveyor line constraints:|[0094] at the same time, from province To the point ofThe sum of the electric power transmission amounts in the middle and the electric power transmission amounts in the opposite directions should be equal to or less than the installation capacity of the trans-provincial transmission line between the two provincials, and the trans-provincial transmission line connecting the same provincial should have the same installation capacity regardless of the transmission direction, the specific constraint function is as follows:|[0095] (20);|[0096] (21);|[0097] for two provinces that have built power trans-provincial transmission lines, their future trans-provincial transmission line capacity should be equal to or greater than the existing installation capacity: |[0098] (22);|[0099] ⑥ Spare capacity demand: |[0100] the provinces need to ensure that the sum of all power sources can not only cover the sufficient power demand, but also meet the requirement of the power supply caused by the capacity marginal coefficient The determined spare capacity. Specific spare capacity constraints are as follows:|[0101] (23);|[0102] the standby capacity provided by the fixed unit and the energy storage unit is greater than or equal to the wind-light supply quantity multiplied by a standby coefficient . The reserve capacity constraints of the renewable energy unit are as follows:|[0103] (24);|[0104] ⑦ Climbing capacity constraint: |[0105] in order to prolong the service life of the unit and reduce the running cost of the power system, the output change of the fixed unit in two continuous time periods is subjected to the climbing rate Is shown below:|[0106] (25);|[0107] (26);|[0108] ⑧ Constraint of energy storage operation: |[0109] The energy stored by the energy storage system at the starting time is identical to the energy stored by the last time slice, and a specific constraint function is as follows: |[0110] (27);|[0111] the total energy stored by the energy storage system during a time slice is a function of the energy stored by the energy storage system during the time slice and the charge/discharge schedule during the time slice. And the energy stored in the energy storage system cannot exceed the limit of the capacity and the energy storage duration ) The specific limiting function is as follows:|[0112] (28);|[0113] (29);|[0114] For any province and any energy storage technology, the discharge capacity plus the reserve capacity minus the charge capacity at each moment should be less than or equal to its prescribed capacity. |[0115] (30);|[0116] (31);|[0117] (32);|[0118] In addition, the sum of the discharge amount of the energy storage system and the reserve capacity provided at any time should be less than or equal to the total energy stored in the energy storage system at the previous time, and a specific constraint function is as follows:|[0119] (33);|[0120] According to the installed pumped-storage installed capacity of each province and the future pumped-storage installed planning, the upper limit and the lower limit of the installed capacity of each province are set by the model through a formula 34: |[0121] (34);|[0122] According to the embodiment of the disclosure, the method for developing renewable energy sources of closed mines further comprises the steps of calculating wind-solar power generation cost of closed mine units and calculating branch leveling connection cost. |[0123] In the disclosed embodiment, the wind power generation capacity coefficient of each grid cell and the closed mine cell and the capital investment and operation maintenance cost of the corresponding technology are taken as important parameters to determine the leveling degree electric cost of wind power and photovoltaic of each space grid cell and the closed mine cell by using a power generation cost model. And calculating the branch line cost for closing the mine unit, namely calculating the leveling connection cost of the branch line based on the transmission electric quantity of the branch line for connecting the power generation unit and the transformer substation. First utilizing capital recovery coefficientsThe early investment is converted to annuity as shown in equation 35:|[0124] (35);|[0125] in the formula, For a practical weighted average capital cost,Representing the capital recovery period required for the wind and solar project. Next, the branch leveling connection cost for each power generation unit is calculated as shown by 36:|[0126] (36);|[0127] in the formula, Capital investment representing transmission line unit capacity; the annual average capacity coefficient of wind power and photovoltaic power generation of each grid unit and the closed mine unit; Refers to the loss rate of the transmission line; Refers to the distance between the power generation unit and the branch line of the substation, and 8760 refers to 8760 hours throughout the year. |[0128] Thus, embodiments of the present disclosure have been described in detail with reference to the accompanying drawings. It should be noted that, in the drawings or the text of the specification, implementations not shown or described are all forms known to those of ordinary skill in the art, and not described in detail. Furthermore, the above definitions of the elements and methods are not limited to the specific structures, shapes or modes mentioned in the embodiments, and may be simply modified or replaced by those of ordinary skill in the art.|[0129] Furthermore, unless specifically described or steps must occur in sequence, the order of the above steps is not limited to the list above and may be changed or rearranged according to the desired design. In addition, the above embodiments may be mixed with each other or other embodiments based on design and reliability, i.e. the technical features of the different embodiments may be freely combined to form more embodiments.|[0130] While the foregoing embodiments have been described in some detail for purposes of clarity of understanding, it will be understood that the foregoing embodiments are merely illustrative of the invention and are not intended to limit the invention, and that any modifications, equivalents, improvements, etc. that fall within the spirit and principles of the present disclosure are intended to be included within the scope of the present disclosure. | (CN120474102)|TECHNICAL FIELD|Technical Field|[0001] The disclosure relates to the technical field of new energy development and smart grids, in particular to a method for developing renewable energy sources for closing mines.|BACKGROUND ART|[0002] China is the largest energy consumption country and carbon emission country in the world at present, and under the pressure of energy structure adjustment and carbon emission reduction, the task of developing renewable energy resources in China is not yet sustained. Meanwhile, as soon as 2024 years, mining of mines nationwide occupies about 5400 tens of thousands of acres of damaged land, so how to perform renewable energy resource modification development on closed mines is a necessary and urgent work.|DISCLOSURE|Disclosure of Invention|[0003] In view of this, the present disclosure provides a method of shutting down mine renewable energy development in order to at least partially solve at least one of the above-mentioned technical problems.|[0004] In order to achieve the above object, the technical scheme of the present disclosure is as follows:|[0005] According to the embodiment of the disclosure, the method for developing the renewable energy sources of the closed mine comprises the steps of calculating the wind-light capacity coefficient of the closed mine unit, evaluating wind-light power generation potential of the closed mine unit, designing a wind-light power generation grid-connected line of the closed mine unit based on grid division, designing a power generation scheduling layer, and constructing a power system model containing the closed mine unit to minimize construction and operation costs. |[0006] According to the embodiment of the disclosure, calculating the wind-solar capacity coefficient of the closed mine unit comprises calculating the wind-power capacity coefficient of the closed mine unit and calculating the photovoltaic power generation capacity coefficient of the closed mine unit.|[0007] According to embodiments of the present disclosure, assessing the wind power generation potential of a shut down mine unit includes assessing the wind power generation potential of a shut down mine unit, and assessing the photovoltaic power generation potential of a shut down mine unit.|[0008] According to the embodiment of the disclosure, the grid division design-based mine unit wind-solar power generation grid-connected line comprises dividing wind-solar power generation unit grids based on geographical longitude and latitude information, connecting each wind-solar power generation unit grid serving as a mine unit which is closed to a transformer substation with the nearest province distance through a branch line, and connecting the transformer substation with a main node with the nearest province distance through a trunk line under the principle of ensuring that the total wind-solar power generation grid-connected distance is the shortest.|[0009] According to the embodiment of the disclosure, the central point of each county or district is taken as the space position of a transformer substation, all the cities in the city group at or above the ground level are positioned as the load centers, and the central point of the load centers in the space is taken as the main node of the power grid.|[0010] According to the embodiment of the disclosure, designing the power generation scheduling layer comprises reasonably distributing annual power demands to various power generating sets at a supply end in an hour scale according to a heuristic scheduling sequence. The fixed unit is positioned on a first layer of the power generation dispatching layer, and the generator unit for closing the mine unit is positioned on a second layer of the power generation dispatching layer.|[0011] According to embodiments of the present disclosure, an objective function is established when constructing a power system model that includes shut down mine units with the objective of minimizing construction and operation costs. The constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, standby capacity demand, climbing capacity constraint and energy storage operation constraint.|[0012] According to an embodiment of the present disclosure, the method for developing renewable energy sources of closed mines further includes calculating a cost of wind-solar power generation of closed mine units and calculating a branch leveling connection cost.|DRAWINGS DESCRIPTION|[0013] The above and other objects, features and advantages of the present disclosure will become more apparent from the following description of embodiments thereof with reference to the accompanying drawings in which:|[0014] fig. 1 is a schematic diagram of the working principle of a waste mine photovoltaic-pumped storage power station. |[0015] FIG. 2 is a flow chart of a method of shutting down mine renewable energy development in accordance with an embodiment of the present disclosure.|[0016] Fig. 3 is a schematic diagram of a technical flow and principle of a method for developing renewable energy resources in a closed mine according to an embodiment of the disclosure.|INVENTION MODE|Detailed Description|[0017] The invention provides a renewable energy development method for a closed mine, which uses wind power and photovoltaic power generation as main renewable energy power generation technologies, creatively combines the resource endowment condition and the geographic space characteristic of the closed mine with new energy power system planning, and realizes the space site selection and capacity configuration optimization of the renewable energy development for the closed mine.|[0018] Research and practice that has combined shut down mines and renewable energy sources abroad has made relatively mature progress. For example, the german luer mining area has been able to realize a wind power project for continuous power generation. Meanwhile, domestic scholars Zhang Zhenji consider that the application of the photovoltaic power generation technology in the abandoned mine tailing dam has certain feasibility, and indicate that the photovoltaic power generation system is an effective choice for sustainable development of the abandoned mine from the perspective of economic benefit. However, the prior art is generally based on a single closed mine, combines pumped storage with photovoltaic power generation, utilizes a photovoltaic array to convey solar power generation to a nearby pumped storage power station through converging, pumps water in a lower reservoir to an upper reservoir by transformer power generation when electric equipment is less and power grid load is low, stores low-valley electric energy in the form of potential energy of water, discharges water from the upper reservoir when electric equipment is increased and power grid load is increased, maintains the stability of a power grid, and has the working flow and principle shown in figure 1. However, the above prior art has the following disadvantages:|[0019] 1. there is little research in domestic on the development and site selection of renewable energy sources for closing mines, and most of the research stays in theoretical stages, and no specific experiment is proved. |[0020] 2. The current research scale is mainly limited to the single mine level, focuses on the feasibility analysis, suitability evaluation and physical utilization potential evaluation of a specific mine, and the adopted research method has stronger scenario dependency, so that the universality and popularization of the research result are insufficient.|[0021] 3. The existing research is less from the perspective of an integral energy system, a plurality of closed mines in a large scale range are brought into a new energy power network to carry out integral planning, and particularly, research blank exists in key links such as capacity configuration, space layout optimization and the like of multiple power generation layer complementation.|[0022] 4. The existing research rarely considers the problem of accurate matching of the supply capacity and the demand response in time and space after the renewable energy development of the closed mine is connected with the grid, and the closed mine is not taken as an important renewable energy power generation supply end to be incorporated into the planning of a new energy power system in the future.|[0023] Therefore, the method for developing renewable energy sources of closed mines, which is provided by the invention, adopts wind power and photovoltaic power generation as main renewable energy source power generation technologies, creatively combines the resource endowment conditions and the geographic space characteristics of closed mines with new energy power system planning, and realizes the optimization of space site selection and capacity allocation of the development of renewable energy sources of closed mines.|[0024] For the purposes of promoting an understanding of the principles and advantages of the disclosure, reference will now be made to the embodiments illustrated in the drawings and specific language will be used to describe the same.|[0025] In an embodiment of the present disclosure, as shown in fig. 2 and 3, there is provided a method of shutting down mine renewable energy development, including the operations S1 to S5 of:|[0026] s1, calculating a wind-light capacity coefficient of a closed mine unit; |[0027] S2, evaluating the wind-solar power generation potential of a closed mine unit; |[0028] S3, closing a mine unit wind-solar power generation grid-connected line based on grid division design; |[0029] s4, designing a power generation scheduling layer, and |[0030] And S5, constructing a power system model comprising closing the mine units to minimize construction and operation costs.|[0031] According to the embodiment of the disclosure, calculating the wind-solar capacity coefficient of the closed mine unit comprises calculating the wind-solar capacity coefficient of the closed mine unit and calculating the photovoltaic power generation capacity coefficient of the closed mine unit.|[0032] And (3) calculating the wind power capacity coefficient, namely calculating the wind power capacity coefficient of the closed mine unit according to the following formula based on the wind speed simulation data in the east-west direction and the north-south direction of the hour scale. First, wind speed data in two directions is synthesized using equation 1.|[0033] (1);|[0034] (2);|[0035] Then, the real-time wind speed data at the height of the fan hub is obtained by using the conversion of the 2,AndWind speed representing the target altitude and the original altitude respectively,AndRepresenting the target height and the original height, respectively.As a conversion factor, it varies from geographic location to geographic location. Then, the real-time power of the wind generator is inferred from the wind speed as shown in equation 3.|[0036] (3);|[0037] (4);|[0038] In the formula,Representing the real-time power of the blower,Indicating the rated power of the fan,Representing the real-time wind speed,、AndThe cut-in wind speed, the rated wind speed and the cut-out wind speed of the fan are respectively indicated. Finally, calculating the ratio of the real-time power to the rated power of the fan as the capacity coefficient for shutting down the wind power generation of the mine through a formula 4。|[0039] And (3) calculating the photovoltaic power generation capacity coefficient, namely calculating the photovoltaic power generation capacity coefficient of the closed mine for 8760 hours every year based on the solar radiation data of the closed mine unit scale through a method of 5.|[0040] (5);|[0041] In the formula,AndRespectively representing the solar energy conversion efficiency of the photovoltaic module under the calculation time and standard experiment conditions (the temperature of the photovoltaic module is 25 ℃, the solar radiation amount is 1000W/m 2, and the air quality is 1.5 AM). It is assumed herein that the conversion efficiency of the photovoltaic module remains unchanged when the amount of solar radiation is varied, i.eAndThe ratio is always 1.Represents the power loss in the power generation process of the photovoltaic module,AndRepresenting the calculated occlusion effect coefficient and temperature effect coefficient, respectively.|[0042] According to the embodiment of the disclosure, the evaluation of the wind power generation potential of the mine unit comprises the evaluation of the wind power generation potential of the mine unit, and the evaluation of the photovoltaic power generation potential of the mine unit.|[0043] Regarding wind power potential evaluation, firstly, a closed mine wind power development utilization suitability evaluation index system is constructed by combining the attribute characteristics of the closed mine, the suitability of the national closed mine wind power development is evaluated, and the closed mine is classified into a closed mine suitable for wind power development and a closed mine unsuitable for wind power development. The evaluation index system is shown in Table 1.|[0044] Table 1 shows the suitability evaluation index system for mine wind power development|[0045] |[0046] Next, for a shutdown mine unit suitable for developing wind power, its wind power development physical potential was calculated using equation 6:|[0047] (6);|[0048] In the middle of Represents the maximum installed capacity potential of the wind power generation of the mine land resource,Indicating the area of the mine that is shut down,Representing the installed capacity of wind power per unit area.|[0049] And (3) regarding photovoltaic power generation potential evaluation, constructing a closed mine photovoltaic power generation development and utilization suitability evaluation index system, and restraining suitability of a closed mine deployment photovoltaic power generation project. The evaluation index system is shown in Table 2.|[0050] Table 2 evaluation index system for suitability of mine photovoltaic power generation|[0051] |[0052] Assuming that photovoltaic power generation adopts a fixed inclination installation mode, the installation coefficient of the photovoltaic module closing the scale of the mine unit needs to be calculated. The photovoltaic installation coefficient refers to the effective photovoltaic panel area coefficient of unit land area, and a specific calculation formula is as follows:|[0053] (7);|[0054] in the formula, Refers to the installation factor of the photovoltaic. Finally, the photovoltaic installed capacity potential is calculated according to equation 8:|[0055] (9);|[0056] in the formula, The maximum installed capacity potential of the mine photovoltaic power generation project is closed; the generated power per unit area of the photovoltaic panel is represented. |[0057] According to an embodiment of the present disclosure, closing a mine unit wind-solar power generation grid-connected line based on grid division design includes:|[0058] dividing a wind-light power generation unit grid based on geographic longitude and latitude information; |[0059] connecting each wind-solar power generation unit grid with a closed mine as a closed mine unit and a transformer substation with the nearest provincial distance through a branch line, and |[0060] Under the principle of ensuring the shortest total distance of wind-solar power generation grid connection, the transformer substation is connected with the main node with the nearest same province distance through a trunk line.|[0061] According to the embodiment of the disclosure, the central point of each county or district is taken as the space position of a transformer substation, all cities in the city group at or above the ground level are positioned as the load centers, and the central point of the load centers in the space is taken as the main node of the power grid.|[0062] Specifically, each wind-solar power generation unit grid (comprising a common space grid unit and a closed mine unit) is connected with a transformer substation with the nearest provincial distance through branch lines. Then, under the principle of ensuring that the total distance of wind-solar power generation grid connection is shortest, the transformer substation is connected with the main node closest to the province through a trunk line (the central point of each county or district in China is used as the space position of the transformer substation in the model, all cities in the city group at or above the city level are positioned as the load center, and the central point of the load center in space is used as the main node of a future power grid).|[0063] According to the embodiment of the disclosure, designing the power generation scheduling layer comprises reasonably distributing annual power demands to various power generating units at a supply end in an hour scale according to a heuristic scheduling sequence. The fixed unit is positioned on a first layer of the power generation dispatching layer, and the generator unit for closing the mine unit is positioned on a second layer of the power generation dispatching layer.|[0064] Specifically, according to the heuristic scheduling sequence, annual power demands are reasonably distributed to various generator sets at the supply end in an hour scale, for example, refer to the following table 3. Based on the power saving requirements and the generated energy of a first layer G1 (a fixed power generation layer, the power is used preferentially and is the power which must be operated) of the power generation scheduling layer, after the power gaps existing in each power saving are calculated, the generated energy of a second layer G2 to a fifth layer G5 is utilized in sequence to gradually fill the power gaps. The shut down mine renewable energy generation is placed in a second layer of the model, also known as a variable energy generation layer.|[0065] TABLE 4 Power Generation layer scheduling order|[0066] |[0067] According to the embodiment of the disclosure, an objective function is established with the aim of minimizing construction operation cost when constructing a power system model comprising closed mine units. The constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, standby capacity demand, climbing capacity constraint and energy storage operation constraint.|[0068] The objective function is built by minimizing the construction and operation cost of the new energy power system for the development of the renewable energy of the coupled shut-down mine on the basis of the existing capacity of the infrastructure and the fixed machine. Setting upRepresenting a collection of provinces; indicating the province involved in nine major clean energy bases is Is a subset of (a); representing a collection of renewable energy power generation technologies (ordinary onshore wind power, ordinary photovoltaic power generation, offshore wind power, shut down mine photovoltaic power generation, shut down mine wind power); representing provinces Renewable energy power generation technologyA set of grid cells that may be utilized; representing provinces Neutralizing transformer substationConnected renewable energy power generation technologyA set of grid cells that may be utilized; representing provinces Renewable energy power generation technologyA set of shut down mine units that may be utilized; representing provinces Neutral transformer stationConnected renewable energy power generation technologyA set of shut down mine units that may be utilized; Representing a collection of substations; representing a set of load centers; representing a collection of energy storage technologies (pumped storage and lithium battery chemical storage); Representing a collection of power generation layers; representing a set of time slices. Province of nine large clean energy basesTechnology for new energyIs installed capacity planning unit of GW; Representing a power generation layer The unit of climbing cost is yuan/kW; Representing a power generation layer Is measured in yuan/kW; Representing a power generation layer Is set up to be a unit standby cost of (a), the unit is yuan/kW; Representing a power generation layer Is yuan/kW per unit fuel cost; Representing a power generation layer The unit variable operation and maintenance cost of (3) is yuan/kW; Representing energy storage technology Is per unit yuan/kW; Representing energy storage technology Is of the fixed operation and maintenance cost of yuan/kWyr;Representing energy storage technologyIs given in yuan/kWh; representing provinces AndThe fixed investment of the electric power transmission line is yuan/kW; representing provinces AndVariable investment in electric power transmission line between, unit is yuan/kWkm;Representing provincesPower generation layerIn time slicesIs given in GW; representing provinces Renewable energy power generation technologyPossible utilization of the firstMaximum installed capacity potential of each grid cell in GW; representing provinces Renewable energy technologyPossible utilization of the firstMaximum installed capacity potential of each closed mine unit in GW; representing provinces AndThe unit of the transmission capacity of the existing power transmission line is GW; representing provinces The unit of the future maximum installation capacity of pumped storage is GW; representing provinces The installed pumped storage capacity is GW; representing provinces The unit of the maximum capacity of the running coal cogeneration is GW; representing provinces Power generation layerAt the moment of timeHour capacity coefficient representation of time; representing provinces First, theRenewable energy power generation technology for each grid unitAt the moment of timeIs represented by a capacity coefficient of (a); representing provinces First, theRenewable energy power generation technology for closing mine unitsAt the moment of timeIs represented by a capacity coefficient of (a); representing provinces First, theRenewable energy power generation technology for each grid unitAnnual average capacity coefficient representation; representing provinces First, theRenewable energy power generation technology for closing mine unitsAnnual average capacity coefficient representation; representing provinces First, theThe installation coefficients of the photovoltaic modules of the mine units are closed; Representing renewable energy power generation technology The unit installed capacity occupation area of the system is GW/km 2; representing provinces First, theThe area of each closed mine is km 2; representing provinces First, theRenewable energy source technology for each grid unitLeveling costs in yuan/kWh for the branch lines connected to the substation; representing provinces First, theRenewable energy source technology for closing mine unitsLeveling costs in yuan/kWh for the branch lines connected to the substation; representing provinces AndThe distance between the two adjacent sections is km; representing provinces First, theThe distance between each grid unit and the transformer substation is in km; representing provinces First, theThe distance between each closed mine unit and the transformer substation is in km; representing provinces Is of the transformer substation of (a)Distance connected to load center in km; representing provinces At the moment of timeIs given in GW; representing provinces At the moment of timeNet power demand remaining after subtracting the supply that L1 must operate, in GW; representing provinces First, theRenewable energy power generation technology for each grid unitThe ratio of installed capacity to maximum potential installed capacity; representing provinces First, theRenewable energy power generation technology for closing mine unitsThe ratio of installed capacity to maximum potential installed capacity; representing provinces First, theRenewable energy power generation technology for each grid unitThe unit of the leveling degree electric cost is yuan/kWh; representing provinces First, theRenewable energy power generation technology for closing mine unitsThe unit of the leveling degree electric cost is yuan/kWh; Representing energy storage technology Investment recovery coefficients of (a); representing provinces AndInvestment recovery coefficients of the inter-span conveying line; Representing the investment recovery coefficient of the grid-connected branch line; Representing the investment recovery coefficient of the grid-connected trunk line; Representing a power generation layer Is represented by the maximum ramp rate of (a); Representing a power generation layer Is represented by the maximum ramp down rate of (a); Representing energy storage technology Is a charging efficiency representation of (2); Representing energy storage technology Is a discharge efficiency representation of (2); representing the lowest power transmission efficiency representation of coal cogeneration during an unnecessary operation period if the coal cogeneration is in online operation; Representing energy storage technology Is a self-discharge rate representation of (2); A reserve capacity demand rate representation representing an electrical load; a reserve capacity demand rate representation representing a renewable energy power generation technology; Representing energy storage technology Is given in h; represents the capital investment cost of the grid-tie line in yuan/kW km;The transmission loss rate of branch lines and trunk lines connected by wind and light grid connection is expressed in%/km; representing provinces AndThe energy loss rate of the inter-span transmission line is expressed as%/km; Representing a power generation layer Energy loss rate after using CCS technology.Representing provincesFirst, theTechnology for developing renewable energy sources by using grid cellsA proportional representation of the capacity of (2) in relation to the maximum potential; representing provinces First, theTechnology for closing mine development renewable energy sourcesA proportional representation of the capacity of (2) in relation to the maximum potential; Representing the connection province Middle (f)Renewable energy power generation technology for each grid unitWith the transformer substationIs given in GW; Representing the connection province Middle (f)Renewable energy power generation technology for closing mine unitsWith the transformer substationIs given in GW; Representing the connection province Medium transformer substationWith a load centreIs the unit of GW; representing provinces AndThe unit of the capacity of the inter-span conveying line is GW; representing provinces Middle energy storage technologyIs given in GW; representing provinces Renewable energy power generation technologyAt the moment of timeIs summarized by grid cells and shut down mine cells, the unit is GW; representing provinces Medium power generation technology(Power generation layers L2-L4 and renewable energy power generation technology) at the momentThe generated electric quantity is transmitted to other provinces of electric quantity, and the unit is GW; representing provinces At the moment of timeTo the provinceThe unit of the electric quantity is GW; representing provinces Medium power generation technologyAt the moment of timeStore to energy storage technologyThe unit of the electric quantity is GW; representing provinces Middle energy storage technologyAt the moment of timeThe released energy is in GW; Indicating the time of expiration Province and partIs stored in energy storage technologyIs given in units of GWh; representing provinces Middle energy storage technologyAt the moment of timeThe unit of the spare capacity is GW; representing provinces Middle power generation layerAt the moment of timeThe unit of the spare capacity is GW; representing provinces Middle power generation layerAt the moment of timeThe offered load, in GW; representing provinces Middle power generation layerAt the moment of timeThe unit is GW; representing provinces Middle power generation layerAt the moment of timeThe unit is GW; Representing binary variables for determining provinces during unnecessary run-time Coal cogeneration technology of middle L3 layer at momentWhether to operate or not; representing provinces In the transformer substationWith a load centreTotal power transmission year, in GWh; representing provinces Medium transformer substationThe leveling cost of the trunk line connected with the load center is yuan/kW; representing provinces Is a power generation layer of (a)At the moment of timeIs a unit GW. The specific calculation formula of the objective function is as follows:|[0069] (9);|[0070] In the embodiment of the disclosure, in combination with fig. 3, a circuit system model including a closed mine unit male is a bottom-up multi-scale fusion model, and aims at minimizing the cost of integral construction operation of a power system in China, and a grid unit and a wind-solar new energy power generation technology of a closed mine unit scale and a traditional power generation technology of a provincial area scale are used on a space unit scale, for example, the traditional power generation technology comprises coal electric cogeneration, nuclear power, biomass power generation (BECCS), water power and natural gas power generation (natural gas+ccs), and the operation constraint of the power system per hour is jointly met, including supply-demand balance constraint, reserve capacity constraint, climbing constraint and the like. Based on the model, the capacity of the conventional power generation technology, the capacity of the power trans-provincial transmission and the new energy power generation technology at the supply end on the space grid and the closed mine units is newly built, expanded, scheduled and spatially laid out are optimized, so that the development potential configuration and spatially laid out planning of the China closed mine renewable energy optimum under the carbon neutral target are obtained, and the constraint conditions can comprise, for example: |[0071] ① Supply and demand balance constraint: |[0072] the power demand of each province at each time slice should be equal to the total power supply. The specific formula is as follows: |[0073] (10);|[0074] ② Wind power and photovoltaic power generation constraints: |[0075] The power generation utilization amount of each renewable energy technology at each moment should be less than or equal to the maximum power generation capacity that the technology installation can provide at the moment. |[0076] (11);|[0077] The total area occupied by wind power and photovoltaic power generation cannot exceed the total area of a mining area, and a specific constraint function is as follows:|[0078] (12);|[0079] constraint is carried out on the wind-solar installed capacity of the nine-large clean energy base, the wind-solar installed capacity of each province related to the nine-large clean energy base is required to be larger than or equal to the national wind-solar power generation deployment planning of the provinces, and the wind-solar power generation deployment planning is shown in a formula 13: |[0080] (13);|[0081] ③ Fixing unit power supply constraint: |[0082] For a fixed unit, the amount of electricity provided by the fixed unit in a time slice should be less than or equal to the maximum power transmission capacity of the time slice. |[0083] (14);|[0084] In addition, if the coal cogeneration unit needs to be run online to meet the power demand during the unnecessary operation period, the limitation of the minimum output power of the coal cogeneration unit needs to be met:|[0085] (15);|[0086] (16);|[0087] ④ Wind-solar grid-connected line constraint: |[0088] the installed capacity of each branch line should be equal to or greater than the maximum power generation of the renewable energy installation of the grid unit connected to the substation or the closed mine unit, as shown in the following formula: |[0089] (17);|[0090] (18);|[0091] And for a trunk line connected with a load center of the transformer substation in the wind-solar grid connection process, the installed capacity of the trunk line is larger than or equal to the maximum power transmitted by the transformer substation. |[0092] (19);|[0093] ⑤ Cross-provincial conveyor line constraints:|[0094] at the same time, from province To the point ofThe sum of the electric power transmission amounts in the middle and the electric power transmission amounts in the opposite directions should be equal to or less than the installation capacity of the trans-provincial transmission line between the two provincials, and the trans-provincial transmission line connecting the same provincial should have the same installation capacity regardless of the transmission direction, the specific constraint function is as follows:|[0095] (20);|[0096] (21);|[0097] for two provinces that have built power trans-provincial transmission lines, their future trans-provincial transmission line capacity should be equal to or greater than the existing installation capacity: |[0098] (22);|[0099] ⑥ Spare capacity demand: |[0100] the provinces need to ensure that the sum of all power sources can not only cover the sufficient power demand, but also meet the requirement of the power supply caused by the capacity marginal coefficient The determined spare capacity. Specific spare capacity constraints are as follows:|[0101] (23);|[0102] the standby capacity provided by the fixed unit and the energy storage unit is greater than or equal to the wind-light supply quantity multiplied by a standby coefficient . The reserve capacity constraints of the renewable energy unit are as follows:|[0103] (24);|[0104] ⑦ Climbing capacity constraint: |[0105] in order to prolong the service life of the unit and reduce the running cost of the power system, the output change of the fixed unit in two continuous time periods is subjected to the climbing rate Is shown below:|[0106] (25);|[0107] (26);|[0108] ⑧ Constraint of energy storage operation: |[0109] The energy stored by the energy storage system at the starting time is identical to the energy stored by the last time slice, and a specific constraint function is as follows: |[0110] (27);|[0111] the total energy stored by the energy storage system during a time slice is a function of the energy stored by the energy storage system during the time slice and the charge/discharge schedule during the time slice. And the energy stored in the energy storage system cannot exceed the limit of the capacity and the energy storage duration ) The specific limiting function is as follows:|[0112] (28);|[0113] (29);|[0114] For any province and any energy storage technology, the discharge capacity plus the reserve capacity minus the charge capacity at each moment should be less than or equal to its prescribed capacity. |[0115] (30);|[0116] (31);|[0117] (32);|[0118] In addition, the sum of the discharge amount of the energy storage system and the reserve capacity provided at any time should be less than or equal to the total energy stored in the energy storage system at the previous time, and a specific constraint function is as follows:|[0119] (33);|[0120] According to the installed pumped-storage installed capacity of each province and the future pumped-storage installed planning, the upper limit and the lower limit of the installed capacity of each province are set by the model through a formula 34: |[0121] (34);|[0122] According to the embodiment of the disclosure, the method for developing renewable energy sources of closed mines further comprises the steps of calculating wind-solar power generation cost of closed mine units and calculating branch leveling connection cost. |[0123] In the disclosed embodiment, the wind power generation capacity coefficient of each grid cell and the closed mine cell and the capital investment and operation maintenance cost of the corresponding technology are taken as important parameters to determine the leveling degree electric cost of wind power and photovoltaic of each space grid cell and the closed mine cell by using a power generation cost model. And calculating the branch line cost for closing the mine unit, namely calculating the leveling connection cost of the branch line based on the transmission electric quantity of the branch line for connecting the power generation unit and the transformer substation. First utilizing capital recovery coefficientsThe early investment is converted to annuity as shown in equation 35:|[0124] (35);|[0125] in the formula, For a practical weighted average capital cost,Representing the capital recovery period required for the wind and solar project. Next, the branch leveling connection cost for each power generation unit is calculated as shown by 36:|[0126] (36);|[0127] in the formula, Capital investment representing transmission line unit capacity; the annual average capacity coefficient of wind power and photovoltaic power generation of each grid unit and the closed mine unit; Refers to the loss rate of the transmission line; Refers to the distance between the power generation unit and the branch line of the substation, and 8760 refers to 8760 hours throughout the year. |[0128] Thus, embodiments of the present disclosure have been described in detail with reference to the accompanying drawings. It should be noted that, in the drawings or the text of the specification, implementations not shown or described are all forms known to those of ordinary skill in the art, and not described in detail. Furthermore, the above definitions of the elements and methods are not limited to the specific structures, shapes or modes mentioned in the embodiments, and may be simply modified or replaced by those of ordinary skill in the art.|[0129] Furthermore, unless specifically described or steps must occur in sequence, the order of the above steps is not limited to the list above and may be changed or rearranged according to the desired design. In addition, the above embodiments may be mixed with each other or other embodiments based on design and reliability, i.e. the technical features of the different embodiments may be freely combined to form more embodiments.|[0130] While the foregoing embodiments have been described in some detail for purposes of clarity of understanding, it will be understood that the foregoing embodiments are merely illustrative of the invention and are not intended to limit the invention, and that any modifications, equivalents, improvements, etc. that fall within the spirit and principles of the present disclosure are intended to be included within the scope of the present disclosure. | Family Number|(115620750)|115620750|Independent Claims|(CN120474102B B)|( . . . ) demands to supply ends in an hour - by - hour time scale according to a heuristic scheduling sequence , wherein a fixed unit is positioned on a first layer of the power generation scheduling layer , the first layer comprises a nuclear power unit , a BECCS unit and a CHP - CCS unit which must be operated , a power generation unit which is closed to a mine unit is positioned on a second layer of the power generation scheduling layer , the second layer further comprises a common wind - solar power generation ( . . . ) | | Electrical machinery, apparatus, energy|IT methods for management | F02C-007/32|G01R-031/36/48|G05B-015/02|G05B-2219/32021|G05F-001/625|G05F-001/66|G06F-003/01/1|G06F-016/9535|G06F-017/50/09|G06F-030/20|G06N-003/00/6|G06Q-010/04|G06Q-010/06/3|G06Q-010/06/31|G06Q-010/06/7|G06Q-020/14|G06Q-030/02/01|G06Q-030/02/06|G06Q-030/02/08|G06Q-030/02/38|G06Q-030/02/78|G06Q-030/02/84|G06Q-050/02|G06Q-050/06|G07F-013/02/5|G07F-015/00/1|G07F-015/00/6|H02J-003/00|H02J-003/00/8|H02J-003/003|H02J-003/12|H02J-003/28|H02J-003/32|H02J-003/38|H02J-003/38/1|H02J-003/38/2|H02J-003/38/3|H02J-003/38/6|H02J-003/388|H02J-003/46|H02J-003/50|H02J-007/00|H02J-007/35|H02J-013/00|H02J-013/00/06|H02J-013/00/75|H02J-013/00001|H02J-2003/003|H02J-2003/007|H02J-2203/20|H02J-2300/24|H02P-009/36|Y02A-030/12|Y02A-030/62|Y02B-010/14|Y02B-070/3266|Y02E-010/563|Y02E-010/566|Y02E-010/58|Y02E-010/763|Y02E-010/766|Y02E-040/76|Y02E-060/7853|Y02E-060/7869|Y02E-070/30|Y02P-080/114|Y02P-080/14|Y02P-090/84|Y02T-090/128|Y04S-010/16|Y04S-010/40|Y04S-010/527|Y04S-010/545|Y04S-020/242|Y04S-040/126|Y04S-040/128 | F02C-007/32|G01R-031/36/48|G05B-015/02|G05B-2219/32021|G05F-001/625|G05F-001/66|G06F-003/01/1|G06F-016/9535|G06F-017/50/09|G06F-030/20|G06N-003/00/6|G06Q-010/04|G06Q-010/06/3|G06Q-010/06/31|G06Q-010/06/7|G06Q-020/14|G06Q-030/02/01|G06Q-030/02/06|G06Q-030/02/08|G06Q-030/02/38|G06Q-030/02/78|G06Q-030/02/84|G06Q-050/02|G06Q-050/06|G07F-013/02/5|G07F-015/00/1|G07F-015/00/6|H02J-003/00|H02J-003/00/8|H02J-003/003|H02J-003/12|H02J-003/28|H02J-003/32|H02J-003/38|H02J-003/38/1|H02J-003/38/2|H02J-003/38/3|H02J-003/38/6|H02J-003/388|H02J-003/46|H02J-003/50|H02J-007/00|H02J-007/35|H02J-013/00|H02J-013/00/06|H02J-013/00/75|H02J-013/00001|H02J-2003/003|H02J-2003/007|H02J-2203/20|H02J-2300/24|H02P-009/36|Y02A-030/12|Y02A-030/62|Y02B-010/14|Y02B-070/3266|Y02E-010/563|Y02E-010/566|Y02E-010/58|Y02E-010/763|Y02E-010/766|Y02E-040/76|Y02E-060/7853|Y02E-060/7869|Y02E-070/30|Y02P-080/114|Y02P-080/14|Y02P-090/84|Y02T-090/128|Y04S-010/16|Y04S-010/40|Y04S-010/527|Y04S-010/545|Y04S-020/242|Y04S-040/126|Y04S-040/128 | G06F-030/20|G06Q-050/02|H02J-003/466|H02J-101/24|H02J-101/28|H02J-103/35 | G06F-030/20|G06Q-050/02|H02J-003/46|H02J-003/466|H02J-101/24|H02J-101/28|H02J-103/35 | CN119419748|CN118646043|CN116260165|CA3156352|CN111489047|KR20180063436|CN119205203 | CN119419748 113317450 WHO=Examiner SELF=N CAT=A|CN118646043 111439114 WHO=Examiner SELF=N CAT=A|CN116260165 105311743 WHO=Examiner SELF=N CAT=A|CA3156352 100876561 WHO=Examiner SELF=N CAT=A|CN111489047 90041838 WHO=Examiner SELF=N CAT=A|KR20180063436 80058865 WHO=Examiner SELF=N CAT=A|CN119205203 112814119 WHO=Examiner SELF=Y | KR20180063436; 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(CSPTAL) , REG=11021|(CN120474102)|NAME=Qi Gongjun;CHINA SCIENCE PATENT TRADEMARK AGENTS LTD. (CSPTAL) , REG=11021 | (CN120474102)|CN| | (CN120474102)|NAME=Lin Gang 100101 Beijing city Chaoyang District Datun Road No. 11 Chaoyang District, CITY=Beijing City, POSTCODE=100101, STATE=Beijing City , COUNTRY=CN |NAME=Fu Jingying|NAME=Jiang Dong|(CN120474102)|NAME=LIN GANG|NAME=FU JINGYING|NAME=JIANG DONG | (CN120474102)|3 | 1 | 1 | (CN120474102)|Number of Claims: NCL=3|Gazette date: GAZDATE=2026-03-13|Gazette number: GAZNUM=42-1102|Substantial examination effective date: 20250829 Examination duration: 6 months|Number of Pages: NPAGES=17|Primary examiner: 刘师语|Primary examiner: Liu Shiyu||(CN120474102)|Number of Claims: NCL=10|Gazette date: GAZDATE=2025-08-12|Gazette number: GAZNUM=41-3301|Number of Pages: NPAGES=17|Primary examiner: 刘师语|Primary examiner: Liu Shiyu| | (CN120474102)|Previous publication: CN120474102 A 2025-08-12 [CN120474102] | (CN120474102)|CHINESE (CHI) | (CN120474102B)|Patent|(CN120474102)|Patent | Titre: (CN120474102)|Mine renewable energy development method for closing Résumé: (CN120474102)|The invention provides a method for developing renewable energy sources of a closed mine. The method comprises the following steps: calculating a wind-light capacity coefficient of a closed mine unit; evaluating the wind-solar power generation potential of the closed mine unit; closing a wind-solar power generation grid-connected line of the mine unit based on the grid division design; designing a power generation dispatching layer; and constructing a power system model containing a shut-down mine unit to minimize the construction operation cost. Autre: (CN120474102)|1. A method of shutting down mine renewable energy development comprising:| Calculating a wind-solar capacity coefficient of a closed mine unit, wherein the wind-solar capacity coefficient comprises a wind-solar capacity coefficient of the closed mine unit and a photovoltaic power generation capacity coefficient of the closed mine unit; | Evaluating the wind-solar power generation potential of the closed mine unit, wherein the evaluating the wind-solar power generation potential of the closed mine unit comprises evaluating the photovoltaic power generation potential of the closed mine unit; | the method comprises the steps of designing a closed mine unit wind-solar power generation grid-connected line based on grid division, wherein the grid division comprises dividing wind-solar power generation unit grids based on geographical longitude and latitude information, connecting closed mine units serving as closed mine units in the grids of each wind-solar power generation unit with a transformer substation with the nearest province distance through branch lines, and connecting the transformer substation with a main node with the nearest province distance through a trunk line under the principle of ensuring the shortest total wind-solar power generation grid-connected distance; | The method comprises the steps of designing a power generation scheduling layer, wherein the power generation scheduling layer comprises various power generation units which reasonably distribute annual power demands to supply ends in an hour-by-hour time scale according to a heuristic scheduling sequence, wherein a fixed unit is positioned on a first layer of the power generation scheduling layer, the first layer comprises a nuclear power unit, a BECCS unit and a CHP-CCS unit which must be operated, a power generation unit which is closed to a mine unit is positioned on a second layer of the power generation scheduling layer, the second layer further comprises a common wind-solar power generation unit and an offshore wind power unit, the third layer comprises a hydroelectric unit, the fourth layer comprises a CHP-CCS unit which is remained except the CHP-CCS unit which must be operated on the first layer, the fifth layer comprises a natural gas CCS unit, the power generation amount of each power saving is calculated based on the power demand and the power generation amount of the first layer of the model power generation scheduling layer, and gradually replenishing the power gaps by sequentially using the power generation amounts of the second layer to the fifth layer, and |And constructing a power system model comprising a closed mine unit, and establishing an objective function with the aim of minimizing construction and operation cost, wherein constraint conditions of the objective function comprise supply and demand balance constraint, wind power and photovoltaic power generation constraint, fixed unit power supply constraint, wind and light grid-connected line constraint, trans-provincial conveying line constraint, reserve capacity requirement, climbing capacity constraint and energy storage operation constraint.|2. The method for developing renewable energy resources for shutting down mines according to claim 1, wherein the central point of each county or district is used as the space position of a transformer substation, all cities in the city group at or above the level city are positioned as the load centers, and the central point of the load centers in space is used as the main node of the power grid.|3. The shut down mine renewable energy source development method of claim 1, further comprising calculating a shut down mine unit wind-solar power generation cost and calculating a spur leveling connection cost. | 7 | Abstract | gpt-4o-mini | no | The article focuses on renewable energy development from a closed mine, specifically wind and solar power, without any mention of biomass, CO₂ capture, or storage. | ||||||||||||||||||||
| 11 | US63/494,285|US63/494,285P|US18/626,398|WOUS2024/023029 | WOUS2024/023029|EP24724340|CA3288230|US18/626,398 | EP4688224|CA3288230|US20240336446|WO2024/211540 | 111695406 | WO2024/211540 A1 2024-10-10 [WO2024211540]|EP4688224 A1 2026-02-11 [EP4688224]|CA3288230 A1 2024-10-10 [CA3288230]|US20240336446 A1 2024-10-10 [US20240336446] | 2023-04-05|2024-04-04 | 2024-04-04|2024-04-04|2024-04-04|2024-04-04 | 2026-02-11|2024-10-10|2024-10-10|2024-10-10 | (EP4688224)|2044-04-04|(US20240336446)|2044-04-04|(WO2024/211540)|2026-10-05|(CA3288230)|2044-04-04 | (EP4688224)|Tray processing units for carbon capture and removal systems, and methods of operating the same | (EP4688224)|Embodiments described herein relate to tray processing units for processing CO2 capture media. In some aspects a tray processing unit can include a loading dock configured to receive a caddy including trays disposed thereon, a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays, a filling station configured to transfer a carbonation medium to the trays, a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station, an unloading dock configured to support the caddy while loading the caddy with trays, a second tray mover configured to transport trays from the collection station to the filling station, and a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock. | HEIRLOOM CARBON TECHNOLOGIES|HEIRLOOM CARBON TECHNOLOGY | (EP4688224)|Heirloom Carbon Technologies, Inc. ([US])|(US20240336446)|Heirloom Carbon Technologies, Inc. ([US])|(WO2024/211540)|HEIRLOOM CARBON TECHNOLOGIES, INC. ([US])|(CA3288230)|HEIRLOOM CARBON TECHNOLOGIES, INC. ([US]) | MAI ROCKY|GARNIER HUNTER|GUEBLE ISABEL|KARR CHARLES|PEDERSEN KRISTEN|PAUL-GIN NOAH|LIU ROUFEI|NASSAR MARYAM|ELAHI SHAZIB|DRENNAN DAVID|MANEM TEJAS|SANCHEZ HUGO|MILLS JENNIFER|DUNCAN ROBERT|KANE MARGARET|DUBEL ANDREW|MCQUEEN NOAH|CUSON MARK | (EP4688224)|MAI, Rocky|GARNIER, Hunter|GUEBLE, Isabel|KARR, Charles|PEDERSEN, Kristen|PAUL-GIN, Noah|LIU, Roufei|NASSAR, Maryam|ELAHI, Shazib|DRENNAN, David|MANEM, Tejas|SANCHEZ, Hugo|MILLS, Jennifer|DUNCAN, Robert|KANE, Margaret|DUBEL, Andrew|MCQUEEN, Noah|CUSON, Mark | (EP4688224)|Cooley (UK) LLP ([GB])|Reg. Nb: 101544956|(WO2024/211540)|HILTON, Ramsey Mitchell et al. ([US])|(CA3288230)|Borden Ladner Gervais LLP ([CA]) | (US20240336446)|By reducing the number of components involved in the process, there is less need for equipment maintenance and labor costs associated with operating the process are also reduced.|Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|Once the media has been exhausted, in some systems it must be transported for further processing and recycling.| | (US20240336446)|35. A tray processing unit (TPU), comprising: a loading dock configured to receive a caddy including trays disposed thereon; a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays; a filling station configured to transfer a carbonation medium to the trays; a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station; an unloading dock configured to support the caddy while loading the caddy with trays; a second tray mover configured to transport trays from the collection station to the filling station; and a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock.|51. A method, comprising: loading a first caddy onto a loading dock, the first caddy including a tray, the tray including a carbonated medium; transporting the tray from the first caddy at the loading dock to a collection station; at the collection station, at least partially removing the carbonated medium from the tray; transporting the tray from the collection station to a filling station; at the filling station, at least partially filling the tray with a carbonation medium; and transporting the tray with the carbonation medium to a second caddy at an unloading dock.| | (US20240336446)|Embodiments described herein relate to tray processing units for processing CO2 capture media. In some aspects a tray processing unit can include a loading dock configured to receive a caddy including trays disposed thereon, a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays, a filling station configured to transfer a carbonation medium to the trays, a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station, an unloading dock configured to support the caddy while loading the caddy with trays, a second tray mover configured to transport trays from the collection station to the filling station, and a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock.| | (US20240336446)|TRAY(100,178)|TRAY PROCESSING UNIT(100,67)|UNLOADING DOCK(100,21)|CARBON CAPTURE(100,8)|TRAY MOVER(72,88)|CADDY(60,114)|COLLECTION STATION(59,21)|CARBONATION CONTACTOR(50,4)|OCEAN CO2 UPTAKE(49,1)|TERRESTRIAL BIOSPHERE(46,1)|MEDIUM CARBONATION(38,36)|LOADING DOCK(36,26)|FUTURE CO2 EMISSION(35,1)|CARBONATION MEDIUM(33,60)|GLOBAL RELIANCE(32,1)|CARBONATION(30,23)|FILLING STATION(27,60)|TRAY ENCLOSURE(26,3)|NATURAL ACCELERATION(26,1)|CO2 UPTAKE(24,2)|CARBONATED MEDIUM CARBONATION EXTENT(24,1)|ENTERPRISE USER(22,1)|PROCESSING TRAY(20,12)|EQUIPMENT MAINTENANCE(20,1)|PORTFOLIO(20,1)|CUSTOMIZATION(19,1)|DESIRE(19,1)|SILO(17,27)|LIFTER MODULE(17,2)|BIOENERGY(17,1)|CARBONATED MEDIUM FALL(17,1)|DATABASE CONFIGURATION(17,1)|FOREST(15,1)|FRAMEWORK(15,1)|PROCESSING CO2(14,3)|BECCS(14,1)|FOSSIL FUEL(14,1)|MINERAL(13,1)|RELATIONAL MODEL(13,1)|TRAY DISTRIBUTOR(12,8)|RECYCLING(12,2)|SYNTAX STRUCTURE(12,1)|CO2 MITIGATION DIVERSE PORTFOLIO(11,1)|DATA TRANSMISSION(11,1)|AUGER(10,11)|CADDY DOCKING STATION(10,6)|PNEUMATIC CONVEYER(10,1)|STRUCTURAL CLARITY(9,11)|TRAY MOVER PLATFORM(9,2)|ULTRASOUND APPLICATION(9,2)|SPRAYING(9,1)|CALCINER(8,14)|CARBONATION MEDIUM RESERVOIR(8,4)|CARBONATION PLOT(8,3)|LABOR COST(8,1)|WEIGH STATION(7,11)|CONTACTOR TOWER HEIGHT(7,2)|AIRPORT LUGGAGE CONVEYER(7,1)|PNEUMATIC POWERED KINEMATIC COUPLER(7,1)|GROMMET(6,8)|QUALITY INSPECTION STATION(6,8)|CADDY MOVEMENT(6,5)|DISPENSATION(6,5)|CARBONATED MEDIUM TRAY HR(6,3)|CONTACTOR NETWORK(6,3)|CONVEYING ROLLER(6,3)|DISPENSING NOZZLE(6,3)|TRAY FILLER(6,3)|UNLOADING STATION(6,3)|CARBONATION MEDIUM DELIVERY(6,2)|STATIONARY CADDY(6,2)|CARBONATION FILL UNIFORMITY(6,1)|LOCATING PIN(5,8)|CO2 PROCESSOR(5,4)|PURITY CO2(5,2)|TRAY MOVER NEXT PLATFORM(5,2)|AEROMECHANICAL CONVEYER(5,1)|CABINET DRAWER RAIL WHEEL(5,1)|CADDIE RETRIEVAL(5,1)|CADDY TRANSPORTATION(5,1)|CARBONATION MEDIUM CLUMPING(5,1)|CARBONATION MEDIUM DISPENSER(5,1)|CARBONATION MEDIUM OUTFLOW(5,1)|CARBONATION MEDIUM TRANSPORTATION(5,1)|CARBONATION MEDIUM UPTAKE(5,1)|CO2 SEQUESTRATION(5,1)|ELECTROMAGNET CONTACTOR(5,1)|NONCONTIGUOUS PLOT(5,1)|OMNIDIRECTIONAL WHEEL PLATFORM(5,1)|REGENERATED CARBONATION MEDIUM(5,1)|UNLISTED ITEM(5,1)|AGITATION(4,5)|MINI DISTRIBUTOR(4,5)|CADDY VEHICLE INTERFACE(4,4)|CO2 STORAGE(4,4)|LANE(4,4)|DESTACKER(4,3)|COLLECTION VEHICLE(4,2)|EMPTY TRAY(4,2)|NONLINEARITY(4,2)|BUCKET CONVEYER(4,1)|CADDY ATTACHMENT(4,1)|CARBONATED MEDIUM COLLECTION(4,1)|CARBONATED MEDIUM OUTFLOW(4,1)|CARBONATED MEDIUM TONNE HR(4,1)|CARBONATION MEDIUM HR(4,1)|CARBONATION MEDIUM TONNE HR(4,1)|CO2 PROCESSER(4,1)|CONTACTOR ROW(4,1)|DISTRIBUTOR ACTUATOR(4,1)|LIFTING CADDY(4,1)|OVERHEAD CONVEYER(4,1)|OVERHEAD DEPICTION(4,1)|PERMEABLE CRUST(4,1)|PLURAL REFERENT(4,1)|PNEUMATIC CONVEYANCE(4,1)|THROUGHPUT MISMATCH(4,1)|TOOL CHANGER MAGNETIC(4,1)|TRANSPORTING CARBONATION MEDIUM(4,1)|TRAY CAROUSEL(4,1)|TRAY LOADER(4,1)|TRAY UNLOADING(4,1)|HOPPER(3,5)|PATHWAY(3,4)|SCISSOR LIFT(3,3)|CALCINATION(3,2)|CO2 REMOVAL(3,2)|CONTRACTOR(3,2)|DIRECT AIR CAPTURE(3,2)|DISSOLUTION PRECIPITATION(3,2)|DISTRIBUTION VEHICLE(3,2)|DOLOMITIC LIME(3,2)|END EFFECTOR ACTUATION(3,2)|HORIZONTAL MOTION(3,2)|MANIPULATION(3,2)|ROTATING ARM(3,2)|VERTICALLY MOBILE INSTRUMENT(3,2)|VISUAL INSPECTION TOOL(3,2)|CARBONATED MEDIUM CONVERSION(3,1)|CARBONATED MEDIUM HR(3,1)|ELEVATOR BED(3,1)|EXCLUSIVITY TERM(3,1)|IDENTIFICATION(3,1)|PINCH ROLLER(3,1)|PLACING CARBONATION MEDIUM(3,1)|RETRACTABLE ALIGNMENT(3,1)|TRAY CLEANING(3,1)|TRAY LIP(3,1)|TRAY RIDE(3,1)|WRAPAROUND CHAIN(3,1)|WATER DISPENSER(2,9)|CACO3(2,4)|LABEL(2,4)|SPRAY NOZZLE(2,4)|TRAY MOVEMENT(2,4)|BELT CONVEYER(2,3)|ACTIVE ROLLER CONVEYER(2,1)|ACTUATING MOTION PLATFORM(2,1)|ADHESION(2,1)|AUTOMATIC FEEDING(2,1)|BUFFER STATION(2,1)|CAO MOVE STREAM(2,1)|CARBON CAPTURE MEDIUM TURNOVER(2,1)|CARBON REGENERATION EQUIPMENT(2,1)|CARBON UPTAKE(2,1)|CARBONATION MEDIUM FLUID(2,1)|CARBONATION MEDIUM THICKNESS(2,1)|CARBONATION MOVEMENT(2,1)|CENTRALIZED LOCATION(2,1)|DRYING TOOL(2,1)|EFFECTOR PIN(2,1)|EXCLUSION LIMIT(2,1)|EXPANSION(2,1)|GEOMETRIC RELATIONSHIP(2,1)|GRABBING ARM(2,1)|HITCH FEED(2,1)|HYDRAULIC PNEUMATIC BED(2,1)|INTERACTION BENEFIT(2,1)|MOBILE STORAGE CONTAINER(2,1)|MOVEABLE SHELF(2,1)|PASSIVE ROLLER(2,1)|POWER RAIL CAR(2,1)|PULL TRAY(2,1)|REMOVEABLE HANDLE(2,1)|RETRACTABLE GUIDE RAIL(2,1)|ROBOTIC ARM(2,1)|ROLLER BELT(2,1)|SCREW ACTUATOR(2,1)|SHUTTLING(2,1)|SINGULAR FEATURE(2,1)|TERM ORDINARY MEANING(2,1)|TRAY SENSOR(2,1)|TRAY TRAVEL(2,1)||(WO2024/211540)|TRAY(100,184)|TRAY PROCESSING UNIT(100,75)|UNLOADING DOCK(100,23)|CARBON CAPTURE(100,9)|TRAY MOVER(72,90)|CADDY(63,122)|CARBONATION CONTACTOR(56,5)|COLLECTION STATION(55,21)|OCEAN CO2 UPTAKE(46,1)|TERRESTRIAL BIOSPHERE(43,1)|CARBONATION MEDIUM(38,64)|MEDIUM CARBONATION(37,37)|LOADING DOCK(37,29)|FUTURE CO2 EMISSION(33,1)|GLOBAL RELIANCE(30,1)|FILLING STATION(29,64)|CARBONATION(28,23)|SILO(27,34)|TRAY ENCLOSURE(25,3)|NATURAL ACCELERATION(25,1)|CARBONATED MEDIUM CARBONATION EXTENT(23,1)|CO2 UPTAKE(22,2)|ENTERPRISE USER(20,1)|PROCESSING TRAY(19,12)|PORTFOLIO(19,1)|CUSTOMIZATION(18,1)|DESIRE(18,1)|EQUIPMENT MAINTENANCE(18,1)|LIFTER MODULE(16,2)|BIOENERGY(16,1)|CARBONATED MEDIUM FALL(16,1)|DATABASE CONFIGURATION(16,1)|AUGER(14,13)|FOREST(14,1)|FRAMEWORK(14,1)|PROCESSING CO2(13,3)|BECCS(13,1)|FOSSIL FUEL(13,1)|MINERAL(12,1)|RELATIONAL MODEL(12,1)|TRAY DISTRIBUTOR(11,8)|RECYCLING(11,2)|DATA TRANSMISSION(11,1)|SYNTAX STRUCTURE(11,1)|CADDY DOCKING STATION(10,6)|CO2 MITIGATION DIVERSE PORTFOLIO(10,1)|STRUCTURAL CLARITY(9,11)|CHARGING STATION(9,4)|PNEUMATIC CONVEYER(9,1)|SPRAYING(9,1)|CARBONATION MEDIUM RESERVOIR(8,4)|CARBONATION PLOT(8,3)|TRAY MOVER PLATFORM(8,2)|ULTRASOUND APPLICATION(8,2)|CALCINER(7,14)|WEIGH STATION(7,11)|LABOR COST(7,1)|CADDY MOVEMENT(6,5)|DISPENSATION(6,5)|CARBONATED MEDIUM TRAY HR(6,3)|CONTACTOR NETWORK(6,3)|CONVEYING ROLLER(6,3)|DISPENSING NOZZLE(6,3)|UNLOADING STATION(6,3)|CONTACTOR TOWER HEIGHT(6,2)|AIRPORT LUGGAGE CONVEYER(6,1)|CARBONATION FILL UNIFORMITY(6,1)|PNEUMATIC POWERED KINEMATIC COUPLER(6,1)|GROMMET(5,8)|QUALITY INSPECTION STATION(5,8)|CADDY VEHICLE INTERFACE(5,4)|CO2 PROCESSOR(5,4)|CARBONATION MEDIUM DELIVERY(5,2)|STATIONARY CADDY(5,2)|CADDY TRANSPORTATION(5,1)|ELECTROMAGNET CONTACTOR(5,1)|OMNIDIRECTIONAL WHEEL PLATFORM(5,1)|LOCATING PIN(4,8)|AGITATION(4,5)|MINI DISTRIBUTOR(4,5)|CO2 STORAGE(4,4)|LANE(4,4)|DESTACKER(4,3)|EMPTY TRAY(4,2)|PURITY CO2(4,2)|TRAY MOVER NEXT PLATFORM(4,2)|AEROMECHANICAL CONVEYER(4,1)|BUCKET CONVEYER(4,1)|CABINET DRAWER RAIL WHEEL(4,1)|CADDIE RETRIEVAL(4,1)|CADDY ATTACHMENT(4,1)|CARBONATED MEDIUM COLLECTION(4,1)|CARBONATED MEDIUM OUTFLOW(4,1)|CARBONATED MEDIUM TONNE HR(4,1)|CARBONATION MEDIUM CLUMPING(4,1)|CARBONATION MEDIUM DISPENSER(4,1)|CARBONATION MEDIUM HR(4,1)|CARBONATION MEDIUM OUTFLOW(4,1)|CARBONATION MEDIUM TONNE HR(4,1)|CARBONATION MEDIUM TRANSPORTATION(4,1)|CARBONATION MEDIUM UPTAKE(4,1)|CO2 PROCESSER(4,1)|CO2 SEQUESTRATION(4,1)|CONTACTOR ROW(4,1)|DISTRIBUTOR ACTUATOR(4,1)|LIFTING CADDY(4,1)|NONCONTIGUOUS PLOT(4,1)|OVERHEAD CONVEYER(4,1)|OVERHEAD DEPICTION(4,1)|PERMEABLE CRUST(4,1)|PLURAL REFERENT(4,1)|PNEUMATIC CONVEYANCE(4,1)|REGENERATED CARBONATION MEDIUM(4,1)|THROUGHPUT MISMATCH(4,1)|TOOL CHANGER MAGNETIC(4,1)|TRANSPORTING CARBONATION MEDIUM(4,1)|TRAY CAROUSEL(4,1)|TRAY LOADER(4,1)|TRAY UNLOADING(4,1)|UNLISTED ITEM(4,1)|HOPPER(3,5)|PATHWAY(3,4)|SCISSOR LIFT(3,3)|COLLECTION VEHICLE(3,2)|END EFFECTOR ACTUATION(3,2)|NONLINEARITY(3,2)|VISUAL INSPECTION TOOL(3,2)|CARBONATED MEDIUM CONVERSION(3,1)|CARBONATED MEDIUM HR(3,1)|ELEVATOR BED(3,1)|EXCLUSIVITY TERM(3,1)|IDENTIFICATION(3,1)|PINCH ROLLER(3,1)|PLACING CARBONATION MEDIUM(3,1)|RETRACTABLE ALIGNMENT(3,1)|TRAY CLEANING(3,1)|TRAY LIP(3,1)|TRAY RIDE(3,1)|WRAPAROUND CHAIN(3,1)|WATER DISPENSER(2,9)|LABEL(2,4)|SPRAY NOZZLE(2,4)|TRAY MOVEMENT(2,4)|BELT CONVEYER(2,3)|CALCINATION(2,2)|CO2 REMOVAL(2,2)|CONTRACTOR(2,2)|DIRECT AIR CAPTURE(2,2)|DISSOLUTION PRECIPITATION(2,2)|DISTRIBUTION VEHICLE(2,2)|DOLOMITIC LIME(2,2)|HORIZONTAL MOTION(2,2)|MANIPULATION(2,2)|ROTATING ARM(2,2)|TRANSFER TRAY(2,2)|VERTICALLY MOBILE INSTRUMENT(2,2)|ACTIVE ROLLER CONVEYER(2,1)|ACTUATING MOTION PLATFORM(2,1)|ADHESION(2,1)|AIR ACTUATOR(2,1)|AUTOMATIC FEEDING(2,1)|BUFFER STATION(2,1)|CABLE CYLINDER(2,1)|CAO MOVE STREAM(2,1)|CARBON CAPTURE MEDIUM TURNOVER(2,1)|CARBON REGENERATION EQUIPMENT(2,1)|CARBONATION MEDIUM FLUID(2,1)|CARBONATION MEDIUM THICKNESS(2,1)|CARBONATION MOVEMENT(2,1)|CENTRALIZED LOCATION(2,1)|DRYING TOOL(2,1)|EFFECTOR PIN(2,1)|EXCLUSION LIMIT(2,1)|EXPANSION(2,1)|GEOMETRIC RELATIONSHIP(2,1)|GRABBING ARM(2,1)|HITCH FEED(2,1)|HYDRAULIC PNEUMATIC BED(2,1)|INTERACTION BENEFIT(2,1)|MOBILE STORAGE CONTAINER(2,1)|MOVEABLE SHELF(2,1)|PASSIVE ROLLER(2,1)|POWER RAIL CAR(2,1)|PULL TRAY(2,1)|REMOVEABLE HANDLE(2,1)|RETRACTABLE GUIDE RAIL(2,1)|ROBOTIC ARM(2,1)|ROLLER BELT(2,1)|SCREW ACTUATOR(2,1)|SHUTTLING(2,1)|SINGULAR FEATURE(2,1)|TERM ORDINARY MEANING(2,1)|TRAY SENSOR(2,1)|TRAY TRAVEL(2,1)| | (US20240336446)|1-34. (canceled)|35. A tray processing unit (TPU), comprising:| a loading dock configured to receive a caddy including trays disposed thereon;| a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays;| a filling station configured to transfer a carbonation medium to the trays;| a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station;| an unloading dock configured to support the caddy while loading the caddy with trays;| a second tray mover configured to transport trays from the collection station to the filling station; and| a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock.|36. The TPU of claim 35, further comprising:| an unloader configured to transport trays from the loading dock to the collection station, the unloader configured to move vertically to select a vertical placement position of the trays in the caddy.|37. The TPU of claim 36, further comprising:| a loader configured to transport trays from the second tray mover to the caddy at the unloading dock.|38. The TPU of claim 35, further comprising:| a first vehicle configured to transport the caddy between the unloading dock and a carbonation contactor.|39. The TPU of claim 35, wherein the collection station includes a tray enclosure and a trough, the tray enclosure configured to manipulate the trays, such that the carbonated medium falls from the tray to the trough.|40. The TPU of claim 39, wherein manipulating the trays includes at least one of rotating, applying a vacuum, vibrating, stirring, or applying ultrasonic waves to the trays.|41. The TPU of claim 39, further comprising:| a silo in communication with the trough;| a conveyor configured to transport carbonated medium from the trough to the silo; and| a vacuum configured to reduce pressure inside the silo and draw carbonated medium into the silo.|42. The TPU of claim 41, wherein the conveyor includes an auger.|43. The TPU of claim 41, wherein the conveyor includes a pneumatic conveyor.|44. The TPU of claim 35, wherein the filling station includes a spraying apparatus configured to wet the carbonation medium.|45. The TPU of claim 35, wherein the first tray mover and the second tray mover include actuated end effector pins configured to move the trays.|46. The TPU of claim 35, wherein the unloading dock includes a roller configured to transfer the caddy from the unloading dock to a vehicle.|47. The TPU of claim 38, wherein the first vehicle includes a lifter module configured to dock and undock caddies to the loading dock and from the unloading dock.|48. The TPU of claim 47, wherein the unloading dock includes a locating pin configured to actuate to lock the caddy in place.|49. The TPU of claim 35, further comprising:| a weigh station configured to weigh the trays.|50. The TPU of claim 35, further comprising:| an inspection tool configured to measure an amount of at least one of carbonation medium or carbonated medium in a tray.|51. A method, comprising:| loading a first caddy onto a loading dock, the first caddy including a tray, the tray including a carbonated medium;| transporting the tray from the first caddy at the loading dock to a collection station;| at the collection station, at least partially removing the carbonated medium from the tray;| transporting the tray from the collection station to a filling station;| at the filling station, at least partially filling the tray with a carbonation medium; and| transporting the tray with the carbonation medium to a second caddy at an unloading dock.|52. The method of claim 51, wherein the tray is selected based on the carbonation extent of the carbonated medium included therein.|53. The method of claim 51, further comprising:| transporting the second caddy from the unloading dock to a carbonation contactor via a vehicle.|54. The method of claim 51, further comprising:| transporting the first caddy from a carbonation contactor to the loading dock.|55. The method of claim 51, further comprising:| spraying water onto the carbonation medium at the filling station and/or after the tray has exited the filling station.|56. The method of claim 51, further comprising:| vertically translating the tray to place the tray in the second caddy. | (US20240336446)|RELATED APPLICATIONS|[0001] This application claims priority and the benefit of U.S. Provisional Application No. 63/494,285, filed Apr. 5, 2023 and titled, “Central Tray Processing Units for Carbon Capture and Removal Systems, and Methods of Operating the Same” the disclosure of which is hereby incorporated by reference in its entirety.|(US20240336446)|TECHNICAL FIELD|[0002] Embodiments described herein relate to control systems and methods for processing CO2 capture media.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 420 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's average surface temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. State of the art DACS systems rely on media to capture CO2 from the atmosphere. Once the media has been exhausted, in some systems it must be transported for further processing and recycling. The turnover of the carbon capture medium can be a rate limiting step in the overall carbon capture process. By minimizing the turnover and processing time of the carbon capture medium, the efficiency of a carbon capture system can be improved.|SUMMARY|[0004] Embodiments described herein relate to tray processing units for processing CO2 capture media. In some aspects a tray processing unit can include a loading dock configured to receive a caddy including trays disposed thereon, a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays, a filling station configured to transfer a carbonation medium to the trays, a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station, an unloading dock configured to support the caddy while loading the caddy with trays, a second tray mover configured to transport trays from the collection station to the filling station, and a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock. In some embodiments, the tray processing unit can further include an unloader configured to transport trays from the loading dock to the collection station, the unloader configured to move vertically to select a vertical placement position of the trays in the caddy. In some embodiments, the unloader and the first tray mover can be part of the same structure and the structure can include a vertical mover configured to collect trays at different positions in the caddy supported by the loading dock. In some embodiments, the tray processing unit can further include a loader that transport trays from the second tray mover to the caddy at the unloading dock.|(US20240336446)|BRIEF DESCRIPTION OF THE DRAWINGS|[0005] FIG. 1 is a block diagram of a tray processing unit, according to an embodiment.|[0006] FIG. 2 is a block diagram of a carbon capture system, according to an embodiment.|[0007] FIGS. 3A-3B are schematic diagrams of a tray processing unit, according to an embodiment.|[0008] FIG. 4 illustrates a tray processing scheme in a tray processing unit, according to an embodiment.|[0009] FIG. 5 is an overhead diagram of a tray processing unit in relation to a contactor system, according to an embodiment.|[0010] FIG. 6 shows the transportation of a caddy to a carbonation contactor, according to an embodiment.|[0011] FIGS. 7A-7B show a caddy with trays thereon, according to an embodiment.|[0012] FIG. 8 shows a collection station, according to an embodiment.|[0013] FIG. 9 shows a filling station, according to an embodiment.|[0014] FIG. 10 shows a spraying apparatus, according to an embodiment.|[0015] FIG. 11 shows a carbonation medium dispenser, according to an embodiment.|[0016] FIG. 12 shows a tray mover, according to an embodiment.|[0017] FIG. 13 shows a tray movement scheme, according to an embodiment.|[0018] FIG. 14 shows a tray distributor, according to an embodiment.|[0019] FIGS. 15A-15B show a tray stacking scheme, according to an embodiment.|[0020] FIGS. 16A-16B show an engagement between a vehicle, a caddy, and a docking station, according to an embodiment.|[0021] FIG. 17 shows an overhead view of a carbonation medium delivery scheme, according to an embodiment.|[0022] FIG. 18 shows an overhead view of a carbonation medium delivery scheme, according to an embodiment.|[0023] FIG. 19 shows a flow diagram of a method of processing trays in a carbonation system, according to an embodiment.|(US20240336446)|DETAILED DESCRIPTION|[0024] Embodiments described herein relate to tray processing unit (TPU) for incorporation into carbon capture systems. TPU systems provide a centralized location for collection of material to undergo regeneration into a carbonation medium. Fresh or regenerated carbonation medium (i.e., material that has been processed in a system that removes CO2 from CaCO3) is distributed onto trays. The carbonation medium can then be processed via the addition of water. The carbon medium is then sent to carbonation plots via a distribution vehicle. Once the carbonation medium has taken up CO2 from ambient air, the trays including the now carbonated medium can be collected by a collection vehicle and sent back to the TPU. In some embodiments, the trays can be selected and placed into the vehicle to achieve a desired condition (e.g., carbonation extent). In some embodiments, the collection vehicle can be the same vehicle as the distribution vehicle. The carbonated medium can then be sent back to a regeneration system, where the carbonated medium is transformed back to a carbonation medium. In some embodiments, the regeneration system can include a calciner, a dissolution/precipitation-based system, and/or an electrochemical system for conversion of the carbonated medium to the carbonation medium.|[0025] Embodiments described herein can reduce capital expenses and operating expenses by centralizing two important components of the carbon capture process: (1) filling (i.e., placing carbonation medium onto a tray) and (2) collection (i.e., removing carbonated material from a tray). Embodiments described herein can resolve throughput mismatches in carbon capture and carbon regeneration equipment. Previously, tray distributors (i.e., components that deliver and collect trays of material in a contactor or carbonation plot) and trays were bottlenecks for throughput. The trays are bottlenecks due to the carbonation time of the material. Filling and collection stations are often under-utilized.|[0026] Embodiments described herein work to maintain process-sensitive equipment. Filling and collection processes are sensitive to parameter changes. By reducing the number of components involved in the process, there is less need for equipment maintenance and labor costs associated with operating the process are also reduced.|[0027] In some embodiments, trays and contactor units described herein can be the same or substantially similar to those described in U.S. Provisional Patent Application No. 63/358,602 (“the '602 application”), filed Jul. 6, 2022, and titled, “Direct Air Capture Contactor for Carbon Uptake, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, calciners or other processing equipment described herein can be the same or substantially similar to equipment described in U.S. patent application Ser. No. 18/067,896 (“the '896 application), filed Dec. 19, 2022 and titled “Systems and Methods of Carbon Capture from Cement Production Process,” the disclosure of which is hereby incorporated by reference in its entirety.|[0028] In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2020/263910 (“the '910 publication”), filed Jun. 24, 2020, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2022/187336 (“the '336 publication”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. Benefits of interactions between water and carbonation medium are described in greater detail in the '910 publication and the '336 publication.|[0029] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions.|[0030] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0031] As used herein, “carbonation medium” refers to a medium that can take on carbon dioxide when exposed to ambient air. This can include but is not limited to calcium oxide (CaO), calcium hydroxide (Ca(OH)2), magnesium oxide (MgO), magnesium hydroxide (MgOH), sodium oxide (Na2O), sodium hydroxide (NaOH), and/or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation medium can originate from a natural source (e.g., limestone). Carbonation medium can also be regenerated or recycled (i.e., a regenerated carbonated medium from a calciner).|[0032] As used herein, “carbonated medium” refers to a carbonation medium that has taken up carbon dioxide from ambient air. This can include but is not limited to calcium carbonate (CaCO3), magnesium carbonate (MgCO3), sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), mixed calcium-magnesium carbonate phases ((Ca,Mg)CO3). Carbonated medium can be converted back to a carbonation medium (e.g., via the use of a calciner, a dissolution/precipitation-based system, and/or an electrochemical system).|[0033] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0034] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0035] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0036] As used herein, a “caddy” can refer to a movable storage container. In some embodiments, movement of a caddy can be automated. In some embodiments, movement of a caddy can be controlled by an algorithm. In some embodiments, movement of a caddy can be controlled by user inputs. In some embodiments, movement of a caddy can be via physical pushing or pulling by a user. In some embodiments, a caddy can move along the ground via wheels. In some embodiments, a caddy can slide along the ground. In some embodiments, a caddy can include a mobile storage container that holds a multitude of carbonation medium and/or carbonated medium in contact with air.|[0037] As used herein, the term “about” and “approximately” generally means plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0038] FIG. 1 is a block diagram of a tray processing unit (TPU) 100, according to an embodiment. As shown, the TPU 100 includes a filling station 110, a collection station 120, tray movers 130a, 130b, optional loader 140a, unloader 140b, and a caddy docking station 150. In some embodiments, the TPU 100 can include a tray mover 130c that transports trays from the caddy docking station 150 to the collection station 120 and/or the loader 140a. The tray movers 130a, 130b, 130c are collectively referred to herein as tray movers 130. In some embodiments, the TPU 100 can include a conveyor (not shown) that transports caddies between a loading dock of the caddy docking station 150 and an unloading dock of the caddy docking station 150.|[0039] Carbonation medium is placed into trays at the filling station 110. In some embodiments, the filling station 110 can include an assembly line of trays that are filled with carbonation medium. In some embodiments, the filling of the trays can be via a dispensation device. In some embodiments, the carbonation medium can be stored in one or more silos and dispensed from the silos to the trays via the dispensation device. In some embodiments, the carbonation medium can include CaO, MgO, Na2O, Ca(OH)2, Mg(OH)2, NaOH, dolomitic lime, or any combination thereof. In some embodiments, the trays can be dual-sided and/or include multiple compartments, such that multiple dispensations can be fed to a single tray.|[0040] In some embodiments, at least about 0.5 kg, at least about 1 kg, at least about 2 kg, at least about 3 kg, at least about 4 kg, at least about 5 kg, at least about 6 kg, at least about 7 kg, at least about 8 kg, at least about 9 kg, at least about 10 kg, at least about 11 kg, at least about 12 kg, at least about 13 kg, at least about 14 kg, at least about 15 kg, at least about 16 kg, at least about 17 kg, at least about 18 kg, or at least about 19 kg of carbonation medium can be dispensed into each tray. In some embodiments, no more than about 20 kg, no more than about 19 kg, no more than about 18 kg, no more than about 17 kg, no more than about 16 kg, no more than about 15 kg, no more than about 14 kg, no more than about 13 kg, no more than about 12 kg, no more than about 11 kg, no more than about 10 kg, no more than about 9 kg, no more than about 8 kg, no more than about 7 kg, no more than about 6 kg, no more than about 5 kg, no more than about 4 kg, no more than about 3 kg, no more than about 2 kg, or no more than about 1 kg of carbonation medium can be dispensed into each tray. Combinations of the above-referenced amounts of carbonation medium are also possible (e.g., at least about 0.5 kg and no more than about 10 kg or at least about 1 kg and no more than about 5 kg), inclusive of all values and ranges therebetween. In some embodiments, about 0.5 kg, about 1 kg, about 2 kg, about 3 kg, about 4 kg, about 5 kg, about 6 kg, about 7 kg, about 8 kg, about 9 kg, about 10 kg, about 11 kg, about 12 kg, about 13 kg, about 14 kg, about 15 kg, about 16 kg, about 17 kg, about 18 kg, about 19 kg, or about 20 kg of carbonation medium can be dispensed into each tray.|[0041] In some embodiments, the carbonation medium can be dispensed into each tray at a thickness of at least about 0.5 mm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm. In some embodiments, the carbonation medium can be dispensed into each tray at a thickness of no more than about 10 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, or no more than about 1 mm. Combinations of the above-referenced thicknesses of the carbonation medium are also possible (e.g., at least about 0.5 mm and no more than about 10 cm or at least about 5 mm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be dispensed into each tray at a thickness of about 0.5 mm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, or about 10 cm.|[0042] In some embodiments, the filling station 110 can include a water addition station (not shown). At the water addition station, water can be added to the carbonation medium. The water content in the carbonation medium can improve CO2 uptake, as described in the '336 publication. In some embodiments, water can adhere the carbonation medium together to create a permeable crust. In some embodiments, water can be added to the carbonation medium at the filling station 110. In some embodiments, water can be added to the carbonation medium after the carbonation medium has left the filling station 110. The adhering can aid in keeping the carbonation medium on the trays and setting the carbonation medium in place. In some embodiments, the filling station 110 can include an agitator. The agitator can be located inside the filling station 110 and can aid in keeping the carbonation medium fluid as it is dispensed (e.g., from a hopper). In other words, the agitator prevents clumping of carbonation medium inside the filling station 110. In some embodiments, the filling station 110 can include humidity and/or temperature monitoring and control instruments. In some embodiments, the filling station 110 can include cleaning and/or drying instruments to clean the trays before filling.|[0043] Carbonated medium is collected at the collection station 120. In some embodiments, the collection station 120 can include a trough to catch the carbonated medium. In some embodiments, the collection station 120 can include a rotating arm to grip and turn over the trays to empty the trays into the trough. In some embodiments, the collection station 120 can include a hopper for collection of the carbonated medium. In some embodiments, the hopper can be cylindrical, pyramidal, wedge-shaped, or chisel-shaped. In some embodiments, the collection station 120 can include a vibration motor or agitator to vibrate the trays and aid the carbonation medium in falling from the trays. In some embodiments, the carbonated medium can be transferred from the collection station 120 to a calciner. In some embodiments, the carbonated medium can be transferred from the collection station 120 to a storage area via an conveyor. In some embodiments, the conveyor can include an auger. In some embodiments, the storage area can include a silo. In some embodiments, the carbonated medium can be transferred from the collection station 120 to the storage area pneumatically. In some embodiments, the collection station 120 can include a tray enclosure that manipulates the trays. In some embodiments, manipulating the trays can include touching the trays (e.g., via the rotating arm). In some embodiments, the manipulation can exclude direct touching of the trays. In some embodiments, the manipulation can include rotating the trays, vibrating the trays, applying a vacuum to the trays, stirring the contents of the trays, and/or applying ultrasonic waves to the trays.|[0044] The tray movers 130 transfer trays between sections of the TPU 100. In some embodiments, the tray movers 130 can include conveyors. In some embodiments, the tray movers 130 can include screw drives. In some embodiments, the tray movers 130 can include actuated end effector pins to move the trays via grommets. In some embodiments, the tray movers 130 can enable two-direction translation. In some embodiments, the tray movers 130 can enable tray velocity profile control. In some embodiments, the tray movers 130 can include belt conveyors. In some embodiments, the tray movers 130 can include a belt drive. In some embodiments, the tray movers 130 can include chain conveyors. In some embodiments, the tray movers 130 can include aero-mechanical conveyors. In some embodiments, the tray movers 130 can include bucket conveyors. In some embodiments, the tray movers 130 can include distributors and effectors.|[0045] In some embodiments, the distributors and effectors can be positioned beneath conveyors. In some embodiments, the distributors and effectors can be positioned at either end of the conveyors for hand-off. In some embodiments, the conveyor can include a 2-direction roller belt. In some embodiments, the conveyor can include lead-in movement paths (analogous to airport luggage conveyors). In some embodiments, the conveyor can include a roller conveyor with retractable index pins. The pins can engage with the trays and secure the trays to the conveyor. In some embodiments, the conveyor can include various end effector configurations. In some embodiments, the conveyor can include pegs that automatically engage, move, and disengage the trays. In some embodiments, the conveyor can include end effectors on an X-Y gantry. In some embodiments, the conveyor can include end effectors on a rack, driven by a pinion.|[0046] In some embodiments, the tray movers 130 can be fastened to walls via angle brackets. In some embodiments, the tray movers 130 can include end stops to limit tray travel. In some embodiments, the tray movers 130 include powered rail cars, such that a tray rides on a moving carriage with rails. In some embodiments, the tray movers 130 can include a conveyor and a distributor actuator. In some embodiments, the tray movers 130 can include a pinch roller on the tray edge. In some embodiments, the tray movers 130 can include holes along the edge of the tray engaged by sprockets. In some embodiments, the tray movers 130 can include removable handles added to the tray during conveyance. In some embodiments, the tray movers 130 can include a hitch feed with end effectors to move two or more trays at once. In some embodiments, the tray movers 130 can include an expanding pin to reduce clearance with the grommet. In some embodiments, the tray movers 130 can include a fan with small holes (analogous to an air hockey table) with a downward bearing to facilitate smooth movement of the trays along the tray movers 130. In some embodiments, the tray movers 130 can include a retractable guide rail for 2-direction travel. In some embodiments, the tray movers 130 can include an automated guide vehicle (AGV) to move the trays. In some embodiments, the tray movers 130 can include an arm to push the trays. In some embodiments, the tray movers 130 can include a carriage driven by a cable cylinder. In some embodiments, the tray movers 130 can include a mecanum wheel under the tray. In some embodiments, the tray movers 130 can include a shuttling system that conveys multiple trays at a time, each in various phases of the transport process.|[0047] The loader 140a is optional and can move the trays to a vertical position (e.g., for placement in a caddy). In some embodiments, the loader 140a can include one or more stackers and the unloader 140b can include one or more destackers. In some embodiments, the stackers can include vertically-mobile instruments that elevate trays upward and place the trays in a desired vertical position (e.g., in a caddy). The placement of the trays in the desired vertical position can include horizontal movement of the trays (e.g., via wheels, actuators, conveyors) onto the caddies. In some embodiments, the destackers can include vertically-mobile instruments that retrieve trays from their vertical position (e.g., via horizontal motion) and place the trays in tray movers 130 and/or the collection station 120. In some embodiments, the loader 140a and/or the unloader 140b can include any of the properties of the distributors described in the '602 application. In some embodiments, the loader 140a and/or the unloader 140b can include a stationary caddy and use common distributor mechanisms for horizontal motion. In some embodiments, the loader 140a and/or the unloader 140b can include a belt drive and/or a screw drive. In some embodiments, the loader 140a and/or the unloader 140b can include a z-motion platform. Actuators can use a lead screw drive (e.g., a direct drive or scissor lift). In some embodiments, caddies can be moved up and down via a pulley system and/or a hydraulic/pneumatic bed. In some embodiments, the loader 140a and/or the unloader 140b can include a stationary caddy and a moving conveyance/elevation mechanism. In some embodiments, the loader 140a and/or the unloader 140b can include a scissor lift and a conveyor. In some embodiments, the loader 140a and/or the unloader 140b can include a mini distributor. In some embodiments, the mini distributor can have any of the properties of the distributors described in the '602 application. In some embodiments, the mini distributor can distribute trays without additional functionality. In other words, functional components such as sprayers and/or mass measurement devices are optional in the mini distributor and can be absent from the mini distributor. In some embodiments, the loader 140a and/or the unloader 140b can include an AGV to raise and lower caddies. In some embodiments, the loader 140a and/or the unloader 140b can include hinge tilts to move the trays to different tray levels.|[0048] In some embodiments, the loader 140a can include both a vertical and a horizontal movement mechanism. In some embodiments, the vertical movement mechanism and the horizontal movement mechanism can be part of the same apparatus. In other words, the vertical movement mechanism (e.g., elevator or lift) can be physically coupled to the horizontal movement mechanism (e.g., conveyor, stacker). In some embodiments, the vertical and horizontal movement mechanism can be de-coupled from each other.|[0049] In some embodiments, the unloader 140b can include both a vertical and a horizontal movement mechanism. In some embodiments, the vertical movement mechanism and the horizontal movement mechanism can be part of the same apparatus. In other words, the vertical movement mechanism (e.g., elevator or lift) can be physically coupled to the horizontal movement mechanism (e.g., conveyor, destacker). In some embodiments, the vertical and horizontal movement mechanism can be de-coupled from each other.|[0050] In some embodiments, z-motion platform actuators in the loader 140a and/or the unloader 140b can include a screw actuator, pulleys, cables, a scissor lift, a pneumatic cylinder, and/or a belt drive. In some embodiments, the loader 140a and/or the unloader 140b can include end effectors for horizontal movement and a single actuator for both end effectors. In some embodiments, the loader 140a and/or the unloader 140b can grab and pull trays via a lip and/or edge. In some embodiments, the trays can be flat (i.e., without a lip or edge). In embodiments with flat trays, the loader 140a and/or the unloader 140b can grab the trays via grabbing arms and/or holes on the edges of the trays. In some embodiments, the loader 140a and/or the unloader 140b can reach behind the tray lip to drag the tray. In some embodiments, the loader 140a and/or the unloader 140b can include a short stroke end effector and conveyor. In some embodiments, the loader 140a and/or the unloader 140b can include a belt drive. In some embodiments, any of the loader 140a, the unloader 140b and/or the tray movers 130 can be part of the same structure. In some embodiments, the structure can include a vertical mover that collects trays at different portions in either of the caddies in the TPU 100 (e.g., a caddy supported by a loading station and/or an unloading station of the caddy docking station 150).|[0051] In some embodiments, the loader 140a and/or the unloader 140b can include pegs on conveyors that automatically engage, move, and disengage trays. In some embodiments, the loader 140a and/or the unloader 140b can include an elevator bed in a box with a counterweight. In some embodiments, the loader 140a and/or the unloader 140b can include a stepper motor. The loader 140a and/or the unloader 140b can include an air actuator. In some embodiments, the loader 140a and/or the unloader 140b can include a tray sensor with a z stage to determine the tray level. In some embodiments, the loader 140a and/or the unloader 140b can include mechanisms within the caddy, such as a movable shelf or a tray carousel.|[0052] The docking station 150 provides an area for delivery and retrieval of caddies with trays. In some embodiments, the docking station 150 can include a loading station and an unloading station. In some embodiments, caddies can be aligned in the docking station 150 via retractable tapered pins. In some embodiments, the caddies can be aligned via kinematic coupling using a magnet or pneumatic actuators. In some embodiments, caddies can be conveyed through the caddy docking station 150 via a roller conveyor or rollers on wrap-around chains pushing on carry wheels. In some embodiments, the roller conveyors can include retractable alignment pins between rollers. In some embodiments, the docking station 150 can include vision cameras for detection of a tag on a side of a caddy.|[0053] In some embodiments, the docking station 150 can include locating features. In some embodiments, the locating features can include cone-shaped pins, diamond shaped pins, holes, and/or slots. In some embodiments, the docking station 150 can include a vertical lift mechanism to dock and undock caddies. In some embodiments, the docking station 150 can include a belt drive to move the caddies on and off the AGV. In some embodiments, the caddy can have wheels that ride on rails. In some embodiments, the caddy can include a wheel that moves through tracks in the docking station 150 (analogous to a cabinet drawer rail/wheel combination). In some embodiments, the docking station can include rollers on chains that push wheels of the caddies (analogous to a car wash).|[0054] In some embodiments, the docking station 150 can include an overhead conveyor that moves the caddy along. In some embodiments, the docking station 150 can include pegs on a belt or chain conveyor. In some embodiments, the docking station 150 can include a carriage with index pins. In some embodiments, the carriage can include a reciprocating X-Z stage carriage. In some embodiments, the carriage can include a lead screw carriage. In some embodiments, the carriage can include a linear motor carriage. In some embodiments, the docking station 150 can include a lift-up conveyor at its center. This can work with a forklift AGV. In some embodiments, the docking station 150 can include a hitch feed, such that caddies can latch onto each other. In some embodiments, the docking station 150 can include an electromagnet contactor for alignment. In some embodiments, the caddy can be fed to the docking station 150 via an automatic feed system using springs. In some embodiments, the docking station 150 can include side rollers and/or brushes to keep caddies aligned during motion. In some embodiments, the docking station 150 can include an omni-directional wheels platform. In some embodiments, the docking station 150 can include a tool changer magnetic coupler. In some embodiments, the docking station 150 can include a pneumatic powered kinematic coupler.|[0055] In some embodiments, the TPU 100 can process at least about 10 kg/hr, at least about 20 kg/hr, at least about 30 kg/hr, at least about 40 kg/hr, at least about 50 kg/hr, at least about 60 kg/hr, at least about 70 kg/hr, at least about 80 kg/hr, at least about 90 kg/hr, at least about 100 kg/hr, at least about 200 kg/hr, at least about 300 kg/hr, at least about 400 kg/hr, at least about 500 kg/hr, at least about 600 kg/hr, at least about 700 kg/hr, at least about 800 kg/hr, at least about 900 kg/hr, at least about 1 tonne (metric ton)/hr, at least about 2 tonnes/hr, at least about 3 tonnes/hr, at least about 4 tonnes/hr, at least about 5 tonnes/hr, at least about 6 tonnes/hr, at least about 7 tonnes/hr, at least about 8 tonnes/hr, at least about 9 tonnes/hr, at least about 10 tonnes/hr, at least about 20 tonnes/hr, at least about 30 tonnes/hr, at least about 40 tonnes/hr, at least about 50 tonnes/hr, at least about 60 tonnes/hr, at least about 70 tonnes/hr, at least about 80 tonnes/hr, at least about 90 tonnes/hr, at least about 100 tonnes/hr, at least about 200 tonnes/hr, at least about 300 tonnes/hr, at least about 400 tonnes/hr, at least about 500 tonnes/hr, at least about 600 tonnes/hr, at least about 700 tonnes/hr, at least about 800 tonnes/hr, at least about 900 tonnes/hr, at least about 1,000 tonnes/hr, at least about 2,000 tonnes/hr, at least about 3,000 tonnes/hr, at least about 4,000 tonnes/hr, at least at least about 5,000 tonnes/hr, at least at least about 6,000 tonnes/hr, at least at least about 7,000 tonnes/hr, at least at least about 8,000 tonnes/hr, or at least about 9,000 tonnes/hr of carbonated medium. In some embodiments, the TPU 100 can process no more than about 10,000 tonnes/hr, no more than about 9,000 tonnes/hr, no more than about 8,000 tonnes/hr, no more than about 7,000 tonnes/hr, no more than about 6,000 tonnes/hr, no more than about 5,000 tonnes/hr, no more than about 4,000 tonnes/hr, no more than about 3,000 tonnes/hr, no more than about 2,000 tonnes/hr, no more than about 1,000 tonnes/hr, no more than about 900 tonnes/hr, no more than about 800 tonnes/hr, no more than about 700 tonnes/hr, no more than about 600 tonnes/hr, no more than about 500 tonnes/hr, no more than about 400 tonnes/hr, no more than about 300 tonnes/hr, no more than about 200 tonnes/hr, no more than about 100 tonnes/hr, no more than about 90 tonnes/hr, no more than about 80 tonnes/hr, no more than about 70 tonnes/hr, no more than about 60 tonnes/hr, no more than about 50 tonnes/hr, no more than about 40 tonnes/hr, no more than about 30 tonnes/hr, no more than about 20 tonnes/hr, no more than about 10 tonnes/hr, no more than about 9 tonnes/hr, no more than about 8 tonnes/hr, no more than about 7 tonnes/hr, no more than about 6 tonnes/hr, no more than about 5 tonnes/hr, no more than about 4 tonnes/hr, no more than about 3 tonnes/hr, no more than about 2 tonnes/hr, no more than about 1 tonne/hr, no more than about 900 kg/hr, no more than about 800 kg/hr, no more than about 700 kg/hr, no more than about 600 kg/hr, no more than about 500 kg/hr, no more than about 400 kg/hr, no more than about 300 kg/hr, no more than about 200 kg/hr, no more than about 100 kg/hr, no more than about 90 kg/hr, no more than about 80 kg/hr, no more than about 70 kg/hr, no more than about 60 kg/hr, no more than about 50 kg/hr, no more than about 40 kg/hr, no more than about 30 kg/hr, or no more than about 20 kg/hr of carbonated medium. Combinations of the above-referenced throughput values are also possible (e.g., at least about 10 kg/hr and no more than about 10,000 tonnes/hr or at least about 50 kg/hr and no more than about 5,000 kg/hr), inclusive of all values and ranges therebetween. In some embodiments, the TPU 100 can process about 10 kg/hr, about 20 kg/hr, about 30 kg/hr, about 40 kg/hr, about 50 kg/hr, about 60 kg/hr, about 70 kg/hr, about 80 kg/hr, about 90 kg/hr, about 100 kg/hr, about 200 kg/hr, about 300 kg/hr, about 400 kg/hr, about 500 kg/hr, about 600 kg/hr, about 700 kg/hr, about 800 kg/hr, about 900 kg/hr, about 1 tonne/hr, about 2 tonnes/hr, about 3 tonnes/hr, about 4 tonnes/hr, about 5 tonnes/hr, about 6 tonnes/hr, about 7 tonnes/hr, about 8 tonnes/hr, about 9 tonnes/hr, about 10 tonnes/hr, about 20 tonnes/hr, about 30 tonnes/hr, about 40 tonnes/hr, about 50 tonnes/hr, about 60 tonnes/hr, about 70 tonnes/hr, about 80 tonnes/hr, about 90 tonnes/hr, about 100 tonnes/hr, about 200 tonnes/hr, about 300 tonnes/hr, about 400 tonnes/hr, about 500 tonnes/hr, about 600 tonnes/hr, about 700 tonnes/hr, about 800 tonnes/hr, about 900 tonnes/hr, about 1,000 tonnes/hr, about 2,000 tonnes/hr, about 3,000 tonnes/hr, about 4,000 tonnes/hr, about 5,000 tonnes/hr, about 6,000 tonnes/hr, about 7,000 tonnes/hr, about 8,000 tonnes/hr, about 9,000 tonnes/hr, or about 10,000 tonnes/hr, of carbonated medium.|[0056] In some embodiments, the TPU 100 can process at least about 10 kg/hr, at least about 20 kg/hr, at least about 30 kg/hr, at least about 40 kg/hr, at least about 50 kg/hr, at least about 60 kg/hr, at least about 70 kg/hr, at least about 80 kg/hr, at least about 90 kg/hr, at least about 100 kg/hr, at least about 200 kg/hr, at least about 300 kg/hr, at least about 400 kg/hr, at least about 500 kg/hr, at least about 600 kg/hr, at least about 700 kg/hr, at least about 800 kg/hr, at least about 900 kg/hr, at least about 1 tonne/hr, at least about 2 tonnes/hr, at least about 3 tonnes/hr, at least about 4 tonnes/hr, at least about 5 tonnes/hr, at least about 6 tonnes/hr, at least about 7 tonnes/hr, at least about 8 tonnes/hr, at least about 9 tonnes/hr, at least about 10 tonnes/hr, at least about 20 tonnes/hr, at least about 30 tonnes/hr, at least about 40 tonnes/hr, at least about 50 tonnes/hr, at least about 60 tonnes/hr, at least about 70 tonnes/hr, at least about 80 tonnes/hr, at least about 90 tonnes/hr, at least about 100 tonnes/hr, at least about 200 tonnes/hr, at least about 300 tonnes/hr, at least about 400 tonnes/hr, at least about 500 tonnes/hr, at least about 600 tonnes/hr, at least about 700 tonnes/hr, at least about 800 tonnes/hr, at least about 900 tonnes/hr, at least about 1,000 tonnes/hr, at least about 2,000 tonnes/hr, at least about 3,000 tonnes/hr, at least about 4,000 tonnes/hr, at least at least about 5,000 tonnes/hr, at least at least about 6,000 tonnes/hr, at least at least about 7,000 tonnes/hr, at least at least about 8,000 tonnes/hr, or at least about 9,000 tonnes/hr of carbonation medium. In some embodiments, the TPU 100 can process no more than about 10,000 tonnes/hr, no more than about 9,000 tonnes/hr, no more than about 8,000 tonnes/hr, no more than about 7,000 tonnes/hr, no more than about 6,000 tonnes/hr, no more than about 5,000 tonnes/hr, no more than about 4,000 tonnes/hr, no more than about 3,000 tonnes/hr, no more than about 2,000 tonnes/hr, no more than about 1,000 tonnes/hr, no more than about 900 tonnes/hr, no more than about 800 tonnes/hr, no more than about 700 tonnes/hr, no more than about 600 tonnes/hr, no more than about 500 tonnes/hr, no more than about 400 tonnes/hr, no more than about 300 tonnes/hr, no more than about 200 tonnes/hr, no more than about 100 tonnes/hr, no more than about 90 tonnes/hr, no more than about 80 tonnes/hr, no more than about 70 tonnes/hr, no more than about 60 tonnes/hr, no more than about 50 tonnes/hr, no more than about 40 tonnes/hr, no more than about 30 tonnes/hr, no more than about 20 tonnes/hr, no more than about 10 tonnes/hr, no more than about 9 tonnes/hr, no more than about 8 tonnes/hr, no more than about 7 tonnes/hr, no more than about 6 tonnes/hr, no more than about 5 tonnes/hr, no more than about 4 tonnes/hr, no more than about 3 tonnes/hr, no more than about 2 tonnes/hr, no more than about 1 tonne/hr, no more than about 900 kg/hr, no more than about 800 kg/hr, no more than about 700 kg/hr, no more than about 600 kg/hr, no more than about 500 kg/hr, no more than about 400 kg/hr, no more than about 300 kg/hr, no more than about 200 kg/hr, no more than about 100 kg/hr, no more than about 90 kg/hr, no more than about 80 kg/hr, no more than about 70 kg/hr, no more than about 60 kg/hr, no more than about 50 kg/hr, no more than about 40 kg/hr, no more than about 30 kg/hr, or no more than about 20 kg/hr of carbonation medium. Combinations of the above-referenced throughput values are also possible (e.g., at least about 10 kg/hr and no more than about 10,000 tonnes/hr or at least about 50 kg/hr and no more than about 5,000 kg/hr), inclusive of all values and ranges therebetween. In some embodiments, the TPU 100 can process about 10 kg/hr, about 20 kg/hr, about 30 kg/hr, about 40 kg/hr, about 50 kg/hr, about 60 kg/hr, about 70 kg/hr, about 80 kg/hr, about 90 kg/hr, about 100 kg/hr, about 200 kg/hr, about 300 kg/hr, about 400 kg/hr, about 500 kg/hr, about 600 kg/hr, about 700 kg/hr, about 800 kg/hr, about 900 kg/hr, about 1 tonne/hr, about 2 tonnes/hr, about 3 tonnes/hr, about 4 tonnes/hr, about 5 tonnes/hr, about 6 tonnes/hr, about 7 tonnes/hr, about 8 tonnes/hr, about 9 tonnes/hr, about 10 tonnes/hr, about 20 tonnes/hr, about 30 tonnes/hr, about 40 tonnes/hr, about 50 tonnes/hr, about 60 tonnes/hr, about 70 tonnes/hr, about 80 tonnes/hr, about 90 tonnes/hr, about 100 tonnes/hr, about 200 tonnes/hr, about 300 tonnes/hr, about 400 tonnes/hr, about 500 tonnes/hr, about 600 tonnes/hr, about 700 tonnes/hr, about 800 tonnes/hr, about 900 tonnes/hr, about 1,000 tonnes/hr, about 2,000 tonnes/hr, about 3,000 tonnes/hr, about 4,000 tonnes/hr, about 5,000 tonnes/hr, about 6,000 tonnes/hr, about 7,000 tonnes/hr, about 8,000 tonnes/hr, about 9,000 tonnes/hr, or about 10,000 tonnes/hr, of carbonation medium.|[0057] In some embodiments, the TPU 100 can process at least about 50 trays/hr, at least about 60 trays/hr, at least about 70 trays/hr, at least about 80 trays/hr, at least about 90 trays/hr, at least about 100 trays/hr, at least about 200 trays/hr, at least about 300 trays/hr, at least about 400 trays/hr, at least about 500 trays/hr, at least about 600 trays/hr, at least about 700 trays/hr, at least about 800 trays/hr, at least about 900 trays/hr, at least about 1,000 trays/hr, at least about 2,000 trays/hr, at least about 3,000 trays/hr, at least about 4,000 trays/hr, at least about 5,000 trays/hr, at least about 6,000 trays/hr, at least about 7,000 trays/hr, at least about 8,000 trays/hr, at least about 9,000 trays/hr, at least about 10,000 trays/hr, at least about 20,000 trays/hr, at least about 30,000 trays/hr, at least about 40,000 trays/hr, at least about 50,000 trays/hr, at least about 60,000 trays/hr, at least about 70,000 trays/hr, at least about 80,000 trays/hr, or at least about 90,000 trays/hr of carbonated medium. In some embodiments, the TPU 100 can process no more than about 100,000 trays/hr, no more than about 90,000 trays/hr, no more than about 80,000 trays/hr, no more than about 70,000 trays/hr, no more than about 60,000 trays/hr, no more than about 50,000 trays/hr, no more than about 40,000 trays/hr, no more than about 30,000 trays/hr, no more than about 20,000 trays/hr, no more than about 10,000 trays/hr, no more than about 9,000 trays/hr, no more than about 8,000 trays/hr, no more than about 7,000 trays/hr, no more than about 6,000 trays/hr, no more than about 5,000 trays/hr, no more than about 4,000 trays/hr, no more than about 3,000 trays/hr, no more than about 2,000 trays/hr, no more than about 1,000 trays/hr, no more than about 900 trays/hr, no more than about 800 trays/hr, no more than about 700 trays/hr, no more than about 600 trays/hr, no more than about 500 trays/hr, no more than about 400 trays/hr, no more than about 300 trays/hr, no more than about 200 trays/hr, no more than about 100 trays/hr, no more than about 90 trays/hr, no more than about 80 trays/hr, no more than about 70 trays/hr, or no more than about 60 trays/hr of carbonated medium. Combinations of the above-referenced numbers of trays are also possible (e.g., at least about 50 trays/hr and no more than about 100,000 trays/hr or at least about 1,000 trays/hr and no more than about 10,000 trays/hr), inclusive of all values and ranges therebetween. In some embodiments, the TPU 100 can process about 50 trays/hr, about 60 trays/hr, about 70 trays/hr, about 80 trays/hr, about 90 trays/hr, about 100 trays/hr, about 200 trays/hr, about 300 trays/hr, about 400 trays/hr, about 500 trays/hr, about 600 trays/hr, about 700 trays/hr, about 800 trays/hr, about 900 trays/hr, about 1,000 trays/hr, about 2,000 trays/hr, about 3,000 trays/hr, about 4,000 trays/hr, about 5,000 trays/hr, about 6,000 trays/hr, about 7,000 trays/hr, about 8,000 trays/hr, about 9,000 trays/hr, about 10,000 trays/hr, about 20,000 trays/hr, about 30,000 trays/hr, about 40,000 trays/hr, about 50,000 trays/hr, about 60,000 trays/hr, about 70,000 trays/hr, about 80,000 trays/hr, about 90,000 trays/hr, or about 100,000 trays/hr of carbonated medium.|[0058] In some embodiments, one or more weigh stations can be placed at various locations throughout the TPU 100. In some embodiments, the weigh station(s) can include scales. In some embodiments, a weigh station can be incorporated into the tray mover 130a and/or the tray mover 130b. In some embodiments, a weigh station can be incorporated into the loader 140a and/or the unloader 140b. In some embodiments, a weigh station can be incorporated into the collection station 120. In some embodiments, a weigh station can be incorporated into the filling station 110. In some embodiments, a weigh station can be placed at any location between the aforementioned process units.|[0059] In some embodiments, one or more quality inspection stations can be placed at various locations throughout the TPU 100. In some embodiments, the quality inspection station(s) can include an inspection tool. In some embodiments, the quality inspection station(s) can include an optical measurement device. In some embodiments, the optical measurement device can measure the level and/or uniformity (i.e., evenness) of carbonation medium or carbonated medium in a tray. In some embodiments, a quality inspection station can be incorporated into the tray mover 130a and/or the tray mover 130b. In some embodiments, a quality inspection station can be incorporated into the loader 140a and/or the unloader 140b. In some embodiments, a quality inspection station can be incorporated into the collection station 120. In some embodiments, a quality inspection station can be incorporated into the filling station 110. In some embodiments, a quality inspection station can be placed at any location between the aforementioned process units.|[0060] FIG. 2 is a block diagram of a carbonation system 1000, according to an embodiment. FIG. 2 shows how the TPU 100 incorporates into a larger scheme. As shown, the carbonation system 1000 includes a contactor network 1001, a vehicle network, the TPU 100, a calciner 1003, a gas separation skid 1004, a CO2 processor 1005, and CO2 storage 1006.|[0061] The contactor network 1001 includes an array of contactors. In some embodiments, the contactors can have any of the properties of the contactors described in the '602 application. The vehicle network 1002 aids in transporting carbonation medium and carbonated medium between the contactor network 1001 and the TPU 100. In some embodiments, the vehicle network 1002 can include one or more AGV's. In some embodiments, the vehicle network 1002 can include a first vehicle and a second vehicle. In some embodiments, the first vehicle can transport caddies while the second vehicle is charging at a charging station. In some embodiments, the second vehicle can transport caddies while the first vehicle is charging at the charging station. In some embodiments, the vehicle network 1002 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, or about 1,000 vehicles, inclusive of all values and ranges therebetween. In some embodiments, any of the vehicles can include a lifter module configured to dock and undock caddies (i.e., from a loading dock and/or an unloading dock). The calciner 1003 converts carbonated medium to carbonation medium. In some embodiments, the calciner 1003 can have any of the properties of the calciners described in the '896 application.|[0062] The gas separation skid 1004 separates CO2 in the exhaust from the calciner 1003 from other gases. In some embodiments, the gas separation skid 1004 can include a condenser to remove water. The CO2 processer 1005 further separates gases to purify the CO2. In some embodiments, the CO2 processor 1005 can include a compressor to pressurize the CO2. The CO2 storage 1006 includes a volume for storage and sequestration of CO2. In some embodiments, the CO2 storage 1006 can have any of the properties described in the '896 application.|[0063] FIG. 2 depicts the movement of chemicals from one process block to another. The chemicals shown in FIG. 2 are intended as examples and not intended to limit the scope of this application. As shown, CaCO3 is transported from the contactor network 1001 to the TPU 100 via the vehicle network 1002 and Ca(OH)2 is transported from the TPU 100 to the contactor network 1001 via the vehicle network 1002. CaCO3 is transported from the TPU 100 to the calciner 1003 and a mixed stream of gases move from the calciner 1003 to the gas separation skid 1004. A high purity CO2 stream moves from the gas separation skid 1004 to the CO2 processor 1005 and a higher purity CO2 stream moves from the CO2 processor 1005 to the CO2 storage 1006. A stream of CaO moves from the calciner 1003 to the hydrator 1007, where the CaO is hydrated to become Ca(OH)2. The Ca(OH)2 is then fed to the TPU 100.|[0064] FIGS. 3A-3B show the layout of a TPU 200, according to an embodiment. FIG. 3A shows a perspective view of the TPU 200, while FIG. 3B shows an overhead view of the TPU 200. Axes are shown for structural clarity. As shown, the TPU 200 includes a filling station 210, a collection station 220, tray movers 230a, 230b (collectively referred to as tray movers 230), a loader 240a, an unloader 240b (collectively referred to as distributors 240), docking stations 250a, 250b, 250c (collectively referred to as docking stations 250), caddies 252a, 252b, 252c (collectively referred to as caddies 250), and a vehicle 255. In some embodiments, the filling station 210, the collection station 220, the tray movers 230, the distributors 240, and the docking stations 250 can be the same or substantially similar to the filling station 110, the collection station 120, the tray movers 130, the loader 140a, the unloader 140b, and the docking station 150, as described above with reference to FIG. 1. Thus, certain aspects of the filling station 210, the collection station 220, the tray movers 230, the loader 240a, the unloader 240b, and the docking stations 250 are not described in greater detail herein.|[0065] In use, the docking station 250c can act as a loading station, while the docking station 250a can act as an unloading station for trays. Trays can be loaded or unloaded from docking station 250b. In some embodiments, the docking station 250b can act as a buffer station. In some embodiments, the docking station 250b can be used for loading and/or unloading of trays. In some embodiments, either of the docking stations 250 can be used for loading or unloading of trays and conveyors in the docking stations 250 can aid in moving the trays to an appropriate location. As shown, the TPU 200 includes 3 docking stations 250. In some embodiments, the TPU 200 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, or about 100 docking stations, inclusive of all values and ranges therebetween.|[0066] In use, the vehicle 255 delivers the caddy 252c to the docking station 250c. The unloader 240b then transfers trays from the caddy 252c to the collection station 220 where the carbonated medium is collected. The tray mover 230b then transfers the empty or nearly empty trays from the collection station 220 to the filling station 210 where carbonation medium is dispensed into the trays. The tray mover 230a then transfers the trays to the loader 240a, which delivers the trays to the caddy 252a. Another vehicle (not shown) then delivers the caddy 252a to a contactor system. In some embodiments, the same vehicle 255 can deliver and collect the caddies 252. In some embodiments, the docking stations 250 can include rollers or conveyors to move the caddies 252 between the docking stations 250.|[0067] FIG. 4 is an overhead depiction of movement of trays T throughout the TPU 200. Axes are shown for structural clarity. In step 1, 10 trays T are included in the docking station 250c while additional trays T are scattered throughout the TPU 200. In step 2, a tray T1 has migrated from the docking station 250c to the unloader 240b. In step 3, the same tray T1 that migrated to the unloader 240b in step 2 has now migrated to the collection station 220. In step 4, the same tray T1 that migrated to the collection station 220 at step 3 has migrated to the tray mover 230b and an additional tray T2 has now migrated from the docking station 250c to the unloader 240b. |[0068] FIG. 5 shows movement of the vehicle 255 between the TPU 200 and a contactor system 2001. In some embodiments, the contactor system 2001 can be the same or substantially similar to the contactor system 1001, as described above with reference to FIG. 2. Thus, certain aspects of the contactor system 2001 are not described in greater detail herein. As shown, the contactor system 2001 includes rows of contactor units. Pathways P define movement paths of the vehicle 255 between the TPU 200 and the contactor system 2001. The pathways are positioned between the rows of contactors. As shown, the TPU 200 includes silos 223a, 223b (collectively referred to as silos 223). Carbonated medium is transferred from the silo 223a to the filling station 210. In some embodiments, carbonated medium can be transferred from the silo 223a to the filling station 210 via a vacuum installed at the filling station 210. In some embodiments, carbonated medium can be transferred from the silo 223a to the filling station 210 via an auger. In some embodiments, the carbonation medium can be transferred from the silo 223a to the filling station 210 via pneumatic conveyance (i.e., positive pressure conveyance). Carbonation medium is transferred from the collection station 220 to the silo 223b for storage. In some embodiments, the vehicle 255 can be powered via solar power, wind power, nuclear power, geothermal power, and/or any other suitable renewable or low carbon energy source or combinations thereof.|[0069] FIG. 6 shows interactions between a contactor tower 353, caddies 352a, 352b (collectively referred to as caddies 352), and a vehicle 355, according to an embodiment. Axes are shown for structural clarity. In some embodiments, the contactor tower 353 can be the same or substantially similar to the contactor towers described in the '602 application. In some embodiments, the caddies 352 and the vehicle 355 can be the same or substantially similar to the caddies 252 and the vehicle 255 as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the caddies 352, the contactor tower 353, and the vehicle 355 are not described in greater detail herein.|[0070] In use, the vehicle 355 moves to a position under the contactor tower 353 and retrieves the caddies 352. The vehicle 355 can also transport the caddies 352 and move to place the caddies 352 in a desired vertical position on the contactor tower 353. In some embodiments, multiple caddies 352 can be stacked upon each other in the contactor tower 353. In some embodiments, the contactor tower 353 can include an elevator to elevate and move caddies 352 to a desired vertical position. As shown, trays T are stacked within the caddies 352. In some embodiments, the trays T can be positioned in the contactor tower 353 while dissociated from the caddies 352.|[0071] FIGS. 7A-7B show a caddy 452, according to an embodiment. FIG. 7A shows an overhead perspective view of the caddy 452, while FIG. 7B shows a perspective view from an underside of the caddy 452. Axes are shown for structural clarity. As shown, the caddy 452 includes a caddy-vehicle interface 457 and support structures 458.|[0072] The caddy-vehicle interface 457 provides a surface for lifting the caddy along the height of the contactor tower 453. In some embodiments, the caddy-vehicle interface 457 can include a platform that can be contacted by an arm or lifting device. As shown, the caddy-vehicle interface 457 includes fastener holes 459 for securing or attachment of the caddy 452 to pieces of process equipment. The support structure 458 keeps trays T in a proper alignment along the height of the contactor tower 453. In some embodiments, the support structure 458 can include a series of beams or poles that prevent movement of the trays T along the x- and y-axes.|[0073] As shown, 10 trays T are stacked on the caddy 452. In some embodiments, at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, or at least about 900 trays T can be stacked on the caddy 452. In some embodiments, no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, or no more than about 2 trays T can be stacked on the caddy 452. Combinations of the above-referenced numbers of trays T are also possible (e.g., at least about 1 and no more than about 1,000 or at least about 5 and no more than about 50), inclusive of all values and ranges therebetween. In some embodiments, about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, or about 1,000, trays T can be stacked on the caddy 452.|[0074] FIG. 8 shows a collection station 520, according to an embodiment. As shown, the collection station 520 includes an enclosure 521, a trough 523, and an auger 526. The enclosure 521 can house a tray T. In some embodiments, the enclosure 521 can include openings for outflow of carbonated medium. In some embodiments, the enclosure 521 can include a long, narrow opening on a narrow side of the enclosure 521. The tray T is held to prevent the tray T from falling through the opening and the carbonated medium is allowed to fall from the tray T into the trough 523. In some embodiments, the enclosure 521 can include an arm to hold the tray T. In some embodiments, the enclosure 521 can rotate. In some embodiments, the collection station 520 can include a robotic arm that rotates the enclosure 521. In some embodiments, the collection station 520 can include an agitator to vibrate the enclosure 521 and the tray T to facilitate falling out of the carbonated medium.|[0075] In some embodiments, the enclosure 521 can rotate by at least about 30 degrees, at least about 30 degrees, at least about 30 degrees, at least about 40 degrees, at least about 50 degrees, at least about 60 degrees, at least about 70 degrees, at least about 80 degrees, at least about 90 degrees, at least about 100 degrees, at least about 110 degrees, at least about 120 degrees, at least about 130 degrees, at least about 140 degrees, at least about 150 degrees, at least about 160 degrees, or at least about 170 degrees. In some embodiments, the enclosure 521 can rotate by no more than about 180 degrees, no more than about 170 degrees, no more than about 160 degrees, no more than about 150 degrees, no more than about 140 degrees, no more than about 130 degrees, no more than about 120 degrees, no more than about 110 degrees, no more than about 100 degrees, no more than about 90 degrees, no more than about 80 degrees, no more than about 70 degrees, no more than about 60 degrees, no more than about 50 degrees, or no more than about 40 degrees. Combinations of the above-referenced angles are also possible (e.g., at least about 30 degrees and no more than about 180 degrees or at least about 80 degrees and no more than about 120 degrees), inclusive of all values and ranges therebetween. In some embodiments, the enclosure 521 can rotate by about 30 degrees, about 30 degrees, about 30 degrees, about 40 degrees, about 50 degrees, about 60 degrees, about 70 degrees, about 80 degrees, about 90 degrees, about 100 degrees, about 110 degrees, about 120 degrees, about 130 degrees, about 140 degrees, about 150 degrees, about 160 degrees, about 170 degrees, or about 180 degrees.|[0076] The trough 523 provides a volume where the carbonated medium can collect after falling from the tray T. In some embodiments, the trough 523 can include a hopper. The auger 526 facilitates movement of the carbonated medium out of the trough 523. In some embodiments, the auger 526 can deliver the carbonated medium directly to a calciner. In some embodiments, the auger 526 can deliver the carbonated medium to a storage area (e.g., a silo).|[0077] FIG. 9 shows an overhead view of a filling station 610, according to an embodiment. Axes are shown for structural clarity. As shown, the filling station 610 includes a tray filler 614 and a water dispenser 615. Carbonation medium is dispensed into a tray as the tray moves into the filling station 610. The water dispenser 615 delivers water to the tray. In some embodiments, the water can be delivered to the tray after the carbonation medium is dispensed into the tray. In some embodiments, the water can be delivered to the tray before the carbonation medium is dispensed into the tray. In some embodiments, the water can be delivered to the tray as the carbonation medium is being dispensed into the tray. As described above, the water can improve uptake of the carbonation medium and can adhere the carbonation medium together, creating a crust-like material. In some embodiments, the water dispenser 615 can include a spray nozzle.|[0078] FIG. 10 shows a water dispenser 715, according to an embodiment. In some embodiments, the water dispenser 715 can be the same or substantially similar to the water dispenser 615, as described above with reference to FIG. 9. Thus, certain aspects of the water dispenser 715 are not described in greater detail herein. As shown, the water dispenser 715 includes spray nozzles 717. As shown, the spray nozzles 717 are arranged in a single file. In some embodiments, the spray nozzles can be arranged in a 2-dimensional n x m array, where n and m are both integers. In some embodiments, n and/or m can be about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, or about 20, inclusive of all values and ranges therebetween.|[0079] FIG. 11 shows a tray filler 814, according to an embodiment. As shown, the tray filler 814 includes a carbonation medium reservoir 816 and a dispensing nozzle 819. The carbonation medium reservoir 816 stores carbonation medium. In some embodiments, the carbonation medium reservoir 816 can include an auger for movement of carbonation medium through the carbonation medium reservoir 816. The dispensing nozzle 819 dispenses carbonation medium. In some embodiments, the dispensing nozzle 819 can include one or more valves to regulate outflow of carbonation medium.|[0080] FIG. 12 shows a tray mover 930, according to an embodiment. In some embodiments, the tray mover 930 can be the same or substantially similar to the tray mover 130, as described above with reference to FIG. 1. As shown, the tray mover includes an actuator 932 and grommets 934. The actuator 932 propels horizontal movement of trays along the tray mover 930. In some embodiments, the actuator 932 can include a linear actuator. The grommets 934 provide a location for placement of trays on top of the tray mover 930. In some embodiments, the grommets 934 can be moved via effector pins. In some embodiments, the grommets 934 can be combined with passive rollers or active roller conveyors. In some embodiments, the grommets 934 can enable 2-direction translation. In some embodiments, the grommets 934 can enable tray velocity profile control.|[0081] FIG. 13 shows a tray movement scheme, according to an embodiment. FIG. 13 shows an overhead view of a filling station 1010, a collection station 1020, and tray movers 1030a, 1030b (collectively referred to as tray movers 1030). Axes are shown for structural clarity. As shown, the filling station 1010, the collection station 1020, and the tray movers 1030 can be the same or substantially similar to the filling station 210, the collection station 220, and the tray movers 230, as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the filling station 1010, the collection station 1020, and the tray movers 1030 are not described in greater detail herein. As shown, empty trays exit the collection station moving along two platforms of the tray mover 1030a in the positive x-direction. A next platform of the tray mover 1030a moves the tray in the negative y-direction. A next platform of the tray mover 1030a moves the tray in the negative x-direction toward the filling station 1010. Two more platforms of the tray mover 1030b then move the tray in the negative x-direction toward a loading dock (not shown).|[0082] FIG. 14 shows a tray distributor 1140, according to an embodiment. In some embodiments, the tray distributor 1140 can be the same or substantially similar to the loader 240a and/or the unloader 240b, as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the tray distributor 1140 are not described in greater detail. Axes are shown for structural clarity. In some embodiments, the tray distributor 1140 can function as a tray loader. In some embodiments, the tray distributor 1140 can function as a tray unloader. The distributor 1140 moves the trays vertically along the z-axis. As shown, the distributor 1140 includes a housing 1142 and a platform 1144. The platform 1144 moves into and out of the housing 1142 (i.e., along x-axis). A tray can be placed upon the platform 1144. In some embodiments, the movement of the platform 1144 into and out of the housing 1142 can be via wheels. In some embodiments, the wheels can move through a track. In some embodiments, the movement of the platform 1144 can be automated. In some embodiments, the platform 1144 can be the same or substantially similar to the platforms described with respect to the contactors in the '602 application.|[0083] FIGS. 15A-15B show a caddy 1252, according to an embodiment. FIG. 15A shows a perspective view of the caddy 1252, while FIG. 15B shows a side view of the caddy 1252. Axes are shown for structural clarity. As shown, the caddy 1252 includes support structures 1258 and bars 1248. The support structures 1258 act as shelves for the placement of trays. The support structures 1258 are placed on top of the bars 1248. The bars 1248 extend lengthwise along the caddy 1252.|[0084] FIGS. 16A-16B show interaction between a docking station 1350, a caddy 1352, and a vehicle 1355, according to an embodiment. FIG. 16A shows a front view of the components, while FIG. 16B shows a side view of the components. Axes are shown for structural clarity. In some embodiments, the docking station 1350, the caddy 1352, and the vehicle 1355 can be the same or substantially similar to the docking station 250, the caddy 252, and the vehicle 255, as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the docking station 1350, the caddy 1352, and the vehicle 1355 are not described in greater detail herein.|[0085] As shown, the docking station 1350 includes a detector 1371, a label 1372, rollers 1373a, 1373b, 1373c, 1373d, 1373e (collectively referred to as rollers 1373), and locating pins 1374a, 1374b (collectively referred to as locating pins 1374). The rollers 1373 facilitate movement of the caddy 1352 into and out of the docking station 1350. The locating pins 1374 lock the caddy 1352 in place when the caddy 1352 moves into position on the docking station 1350. In some embodiments, the locating pins 1374 can be spring loaded. In some embodiments, the locating pins 1374 can be automated. The label 1372 provides an identifying mark for the caddy 1352. In some embodiments, the label 1372 can include data stored in a central database. The detector 1371 detects the label 1372. In some embodiments, the detector 1371 can send information to a central computer for tracking. As shown, the caddy 1352 includes a stack of trays T disposed therein.|[0086] As shown, the vehicle 1355 includes wheels 1375a, 1375b (collectively referred to as wheels 1375) and a locating pin 1376. The wheels 1375 allow the vehicle 1355 to move around the floor of the facility. The locating pin 1376 locks the vehicle 1355 to the caddy 1352. In some embodiments, the vehicle 1355 can include a spring. In some embodiments, the vehicle 1355 can be automated.|[0087] FIG. 17 is an overhead view of a TPU 1400 and a contactor network 14001. Axes are shown for structural clarity. As shown, the TPU 1400 includes a filling station 1410, a collection station 1420, silos 1423a, 1423b (collectively referred to as silos 1423), tray movers 1430a, 1430b (collectively referred to as tray movers 1430), a loader 1440a, an unloader 1440b, a docking station 1450, caddies 1452a, 1452b, 1452c (collectively referred to as caddies 1452), and a vehicle 1455. In some embodiments, the TPU 1400, the contactor network 14001, the filling station 1410, the collection station 1420, the silos 1423, the tray movers 1430, the loader 1440a, the unloader 1440b, the docking station 1450, the caddies 1452, and the vehicle 1455 can be the same or substantially similar to the TPU 200, the contactor network 2001, the filling station 210, the collection station 220, the silos 223, the tray movers 230, the loader 240a, the unloader 240b, the docking station 250, the caddies 252, and the vehicles 255, as described above with reference to FIG. 5. Thus, certain aspects of the TPU 1400, the contactor network 14001, the filling station 1410, the collection station 1420, the silos 1423, the tray movers 1430, the loader 1440a, the unloader 1440b, the docking station 1450, the caddies 1452, and the vehicle 1455 are not described in greater detail herein.|[0088] As shown, pathways P between the contactors of the contactor network 14001 allow for one-way movement between the contractors. This allows the vehicle 1455 to weave through arrays of contactors of the contactor network 14001. The vehicle 1455 moves in a first direction through a first lane and a second direction in a second lane adjacent to the first lane, the second direction opposite the first direction.|[0089] FIG. 17 shows a single TPU 1400 in a facility. In some embodiments, multiple TPU's can be included in a single facility. In some embodiments, a facility can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, or about 100 TPU's, inclusive of all values and ranges therebetween.|[0090] FIG. 18 is an overhead view of a TPU 1500 and a contactor network 15001. Axes are shown for structural clarity. As shown, the TPU 1500 includes a filling station 1510, a collection station 1520, silos 1523a, 1523b (collectively referred to as silos 1523), tray movers 1530a, 1530b (collectively referred to as tray movers 1530), a loader 1540a, an unloader 1540b, a docking station 1550, caddies 1552a, 1552b, 1552c (collectively referred to as caddies 1552), and vehicles 1555a, 1555b (collectively referred to as vehicles 1555). In some embodiments, the TPU 1500, the contactor network 15001, the filling station 1510, the collection station 1520, the silos 1523, the tray movers 1530, the loader 1540a, the unloader 1540b, the docking station 1550, the caddies 1552, and the vehicles 1555 can be the same or substantially similar to the TPU 200, the contactor network 2001, the filling station 210, the collection station 220, the silos 223, the tray movers 230, the loader 1540a, the unloader 1540b, the docking station 250, the caddies 252, and the vehicle 255, as described above with reference to FIG. 5. Thus, certain aspects of the TPU 1500, the contactor network 15001, the filling station 1510, the collection station 1520, the silos 1523, the tray movers 1530, the loader 1540a, the unloader 1540b, the docking station 1550, the caddies 1552, and the vehicles 1555 are not described in greater detail herein.|[0091] As shown, pathways P between the contactors of the contactor network 15001 allow for two-way movement between the contractors. This allows the vehicles 1555 to move in either direction between the contactors. In some embodiments, the vehicles 1555 can drive on the right side of the lanes between the contactors, from the perspective of the vehicles 1555 (i.e., American driving scheme). In some embodiments, the vehicles 1555 can drive on the left side of the lanes between the contactors, from the perspective of the vehicles 1555 (i.e., British driving scheme).|[0092] FIG. 19 shows a flow diagram of a method 10 of processing trays in a carbonation system, according to an embodiment. As shown, the method 10 includes loading a first caddy onto a loading dock at step 11, transporting a tray from the first caddy at the loading dock to a collection station at step 12, at least partially removing a carbonated medium from the tray at step 13, transporting the tray from the collection station to a filling station at step 14, at least partially filling the tray with a carbonation medium 15, transporting the tray with carbonation medium to a second caddy at an unloading dock at step 16, and optionally an amount of carbonation medium in a tray at step 17.|[0093] Step 11 includes loading the first caddy onto the loading dock. In some embodiments, loading the first caddy onto the loading dock can be via a vehicle. The first caddy can be transported from a contactor system including an array of contactors. Step 12 includes transporting the tray from the first caddy at the loading dock to the collection station. In some embodiments, step 12 can include elevating or lowering the tray via a distributor. In some embodiments, step 12 can include conveying the tray (e.g., via a belt conveyor).|[0094] Step 13 includes at least partially removing the carbonated medium from the tray. In some embodiments, step 13 can include removing all or substantially all of the carbonated medium from the tray. In some embodiments, the carbonated medium can be collected in a trough or a hopper. In some embodiments, the carbonated medium can be transported from the collection station to a silo. In some embodiments, transporting the carbonated medium from the collection station to the silo can be via a conveyor. In some embodiments, the conveyor can include an auger.|[0095] Step 14 transporting the tray from the collection station to the filling station. In some embodiments, step 14 can include elevating or lowering the tray via a distributor. In some embodiments, step 14 can include conveying the tray (e.g., via a belt conveyor). Step 15 includes at least partially filling the tray with a carbonation medium. In some embodiments, the carbonation medium can be dispensed via a dispensation device. In some embodiments, water can be added to the carbonation medium. In some embodiments, water can be added to the carbonation medium at the filling station. In some embodiments, water can be added to the carbonation medium after the tray has left the filling station. In some embodiments, the carbonation medium can be transported to the dispensation device from an auger. In some embodiments, the transportation of the carbonation medium can be via an auger. After the addition of carbonation medium and/or water to the tray, the tray and the carbonation medium can be inspected. The tray can then be accepted and advanced in the process or rejected for recycling or further processing.|[0096] Step 16 includes transporting the tray with the carbonation medium to a second caddy at the unloading dock. In some embodiments, the second caddy can a different caddy from the first caddy. In some embodiments, the second caddy can be the same caddy as the first caddy. In some embodiments, the loading dock can be part of the same structure as the unloading dock. In some embodiments, the loading dock and the unloading dock can be in separate structures.|[0097] Step 17 is optional and includes monitoring the amount of carbonation medium in a tray. In some embodiments, determination of the amount of carbonation medium in a tray can be via weighting the tray. The tray can be weight at a weigh station. In some embodiments, the weigh station can be disposed on a caddy. In some embodiments, the weigh station can be disposed on a tray mover, such that the weight can be determined while the tray is in motion. In some embodiments, the amount of carbonation medium in a tray can be monitored via a visual inspection tool. In some embodiments, the visual inspection tool can be used to measure the fill level and/or the fill uniformity of the carbonation medium in the tray.|[0098] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0099] In addition, the disclosure may include other innovations not presently described.|[0100] Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0101] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0102] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0103] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0104] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0105] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0106] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0107] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0108] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | (US20240336446)|RELATED APPLICATIONS|[0001] This application claims priority and the benefit of U.S. Provisional Application No. 63/494,285, filed Apr. 5, 2023 and titled, “Central Tray Processing Units for Carbon Capture and Removal Systems, and Methods of Operating the Same” the disclosure of which is hereby incorporated by reference in its entirety.|(US20240336446)|TECHNICAL FIELD|[0002] Embodiments described herein relate to control systems and methods for processing CO2 capture media.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 420 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's average surface temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. State of the art DACS systems rely on media to capture CO2 from the atmosphere. Once the media has been exhausted, in some systems it must be transported for further processing and recycling. The turnover of the carbon capture medium can be a rate limiting step in the overall carbon capture process. By minimizing the turnover and processing time of the carbon capture medium, the efficiency of a carbon capture system can be improved.|SUMMARY|[0004] Embodiments described herein relate to tray processing units for processing CO2 capture media. In some aspects a tray processing unit can include a loading dock configured to receive a caddy including trays disposed thereon, a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays, a filling station configured to transfer a carbonation medium to the trays, a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station, an unloading dock configured to support the caddy while loading the caddy with trays, a second tray mover configured to transport trays from the collection station to the filling station, and a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock. In some embodiments, the tray processing unit can further include an unloader configured to transport trays from the loading dock to the collection station, the unloader configured to move vertically to select a vertical placement position of the trays in the caddy. In some embodiments, the unloader and the first tray mover can be part of the same structure and the structure can include a vertical mover configured to collect trays at different positions in the caddy supported by the loading dock. In some embodiments, the tray processing unit can further include a loader that transport trays from the second tray mover to the caddy at the unloading dock.|(US20240336446)|BRIEF DESCRIPTION OF THE DRAWINGS|[0005] FIG. 1 is a block diagram of a tray processing unit, according to an embodiment.|[0006] FIG. 2 is a block diagram of a carbon capture system, according to an embodiment.|[0007] FIGS. 3A-3B are schematic diagrams of a tray processing unit, according to an embodiment.|[0008] FIG. 4 illustrates a tray processing scheme in a tray processing unit, according to an embodiment.|[0009] FIG. 5 is an overhead diagram of a tray processing unit in relation to a contactor system, according to an embodiment.|[0010] FIG. 6 shows the transportation of a caddy to a carbonation contactor, according to an embodiment.|[0011] FIGS. 7A-7B show a caddy with trays thereon, according to an embodiment.|[0012] FIG. 8 shows a collection station, according to an embodiment.|[0013] FIG. 9 shows a filling station, according to an embodiment.|[0014] FIG. 10 shows a spraying apparatus, according to an embodiment.|[0015] FIG. 11 shows a carbonation medium dispenser, according to an embodiment.|[0016] FIG. 12 shows a tray mover, according to an embodiment.|[0017] FIG. 13 shows a tray movement scheme, according to an embodiment.|[0018] FIG. 14 shows a tray distributor, according to an embodiment.|[0019] FIGS. 15A-15B show a tray stacking scheme, according to an embodiment.|[0020] FIGS. 16A-16B show an engagement between a vehicle, a caddy, and a docking station, according to an embodiment.|[0021] FIG. 17 shows an overhead view of a carbonation medium delivery scheme, according to an embodiment.|[0022] FIG. 18 shows an overhead view of a carbonation medium delivery scheme, according to an embodiment.|[0023] FIG. 19 shows a flow diagram of a method of processing trays in a carbonation system, according to an embodiment.|(US20240336446)|DETAILED DESCRIPTION|[0024] Embodiments described herein relate to tray processing unit (TPU) for incorporation into carbon capture systems. TPU systems provide a centralized location for collection of material to undergo regeneration into a carbonation medium. Fresh or regenerated carbonation medium (i.e., material that has been processed in a system that removes CO2 from CaCO3) is distributed onto trays. The carbonation medium can then be processed via the addition of water. The carbon medium is then sent to carbonation plots via a distribution vehicle. Once the carbonation medium has taken up CO2 from ambient air, the trays including the now carbonated medium can be collected by a collection vehicle and sent back to the TPU. In some embodiments, the trays can be selected and placed into the vehicle to achieve a desired condition (e.g., carbonation extent). In some embodiments, the collection vehicle can be the same vehicle as the distribution vehicle. The carbonated medium can then be sent back to a regeneration system, where the carbonated medium is transformed back to a carbonation medium. In some embodiments, the regeneration system can include a calciner, a dissolution/precipitation-based system, and/or an electrochemical system for conversion of the carbonated medium to the carbonation medium.|[0025] Embodiments described herein can reduce capital expenses and operating expenses by centralizing two important components of the carbon capture process: (1) filling (i.e., placing carbonation medium onto a tray) and (2) collection (i.e., removing carbonated material from a tray). Embodiments described herein can resolve throughput mismatches in carbon capture and carbon regeneration equipment. Previously, tray distributors (i.e., components that deliver and collect trays of material in a contactor or carbonation plot) and trays were bottlenecks for throughput. The trays are bottlenecks due to the carbonation time of the material. Filling and collection stations are often under-utilized.|[0026] Embodiments described herein work to maintain process-sensitive equipment. Filling and collection processes are sensitive to parameter changes. By reducing the number of components involved in the process, there is less need for equipment maintenance and labor costs associated with operating the process are also reduced.|[0027] In some embodiments, trays and contactor units described herein can be the same or substantially similar to those described in U.S. Provisional Patent Application No. 63/358,602 (“the '602 application”), filed Jul. 6, 2022, and titled, “Direct Air Capture Contactor for Carbon Uptake, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, calciners or other processing equipment described herein can be the same or substantially similar to equipment described in U.S. patent application Ser. No. 18/067,896 (“the '896 application), filed Dec. 19, 2022 and titled “Systems and Methods of Carbon Capture from Cement Production Process,” the disclosure of which is hereby incorporated by reference in its entirety.|[0028] In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2020/263910 (“the '910 publication”), filed Jun. 24, 2020, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2022/187336 (“the '336 publication”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. Benefits of interactions between water and carbonation medium are described in greater detail in the '910 publication and the '336 publication.|[0029] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions.|[0030] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0031] As used herein, “carbonation medium” refers to a medium that can take on carbon dioxide when exposed to ambient air. This can include but is not limited to calcium oxide (CaO), calcium hydroxide (Ca(OH)2), magnesium oxide (MgO), magnesium hydroxide (MgOH), sodium oxide (Na2O), sodium hydroxide (NaOH), and/or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation medium can originate from a natural source (e.g., limestone). Carbonation medium can also be regenerated or recycled (i.e., a regenerated carbonated medium from a calciner).|[0032] As used herein, “carbonated medium” refers to a carbonation medium that has taken up carbon dioxide from ambient air. This can include but is not limited to calcium carbonate (CaCO3), magnesium carbonate (MgCO3), sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), mixed calcium-magnesium carbonate phases ((Ca,Mg)CO3). Carbonated medium can be converted back to a carbonation medium (e.g., via the use of a calciner, a dissolution/precipitation-based system, and/or an electrochemical system).|[0033] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0034] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0035] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0036] As used herein, a “caddy” can refer to a movable storage container. In some embodiments, movement of a caddy can be automated. In some embodiments, movement of a caddy can be controlled by an algorithm. In some embodiments, movement of a caddy can be controlled by user inputs. In some embodiments, movement of a caddy can be via physical pushing or pulling by a user. In some embodiments, a caddy can move along the ground via wheels. In some embodiments, a caddy can slide along the ground. In some embodiments, a caddy can include a mobile storage container that holds a multitude of carbonation medium and/or carbonated medium in contact with air.|[0037] As used herein, the term “about” and “approximately” generally means plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0038] FIG. 1 is a block diagram of a tray processing unit (TPU) 100, according to an embodiment. As shown, the TPU 100 includes a filling station 110, a collection station 120, tray movers 130a, 130b, optional loader 140a, unloader 140b, and a caddy docking station 150. In some embodiments, the TPU 100 can include a tray mover 130c that transports trays from the caddy docking station 150 to the collection station 120 and/or the loader 140a. The tray movers 130a, 130b, 130c are collectively referred to herein as tray movers 130. In some embodiments, the TPU 100 can include a conveyor (not shown) that transports caddies between a loading dock of the caddy docking station 150 and an unloading dock of the caddy docking station 150.|[0039] Carbonation medium is placed into trays at the filling station 110. In some embodiments, the filling station 110 can include an assembly line of trays that are filled with carbonation medium. In some embodiments, the filling of the trays can be via a dispensation device. In some embodiments, the carbonation medium can be stored in one or more silos and dispensed from the silos to the trays via the dispensation device. In some embodiments, the carbonation medium can include CaO, MgO, Na2O, Ca(OH)2, Mg(OH)2, NaOH, dolomitic lime, or any combination thereof. In some embodiments, the trays can be dual-sided and/or include multiple compartments, such that multiple dispensations can be fed to a single tray.|[0040] In some embodiments, at least about 0.5 kg, at least about 1 kg, at least about 2 kg, at least about 3 kg, at least about 4 kg, at least about 5 kg, at least about 6 kg, at least about 7 kg, at least about 8 kg, at least about 9 kg, at least about 10 kg, at least about 11 kg, at least about 12 kg, at least about 13 kg, at least about 14 kg, at least about 15 kg, at least about 16 kg, at least about 17 kg, at least about 18 kg, or at least about 19 kg of carbonation medium can be dispensed into each tray. In some embodiments, no more than about 20 kg, no more than about 19 kg, no more than about 18 kg, no more than about 17 kg, no more than about 16 kg, no more than about 15 kg, no more than about 14 kg, no more than about 13 kg, no more than about 12 kg, no more than about 11 kg, no more than about 10 kg, no more than about 9 kg, no more than about 8 kg, no more than about 7 kg, no more than about 6 kg, no more than about 5 kg, no more than about 4 kg, no more than about 3 kg, no more than about 2 kg, or no more than about 1 kg of carbonation medium can be dispensed into each tray. Combinations of the above-referenced amounts of carbonation medium are also possible (e.g., at least about 0.5 kg and no more than about 10 kg or at least about 1 kg and no more than about 5 kg), inclusive of all values and ranges therebetween. In some embodiments, about 0.5 kg, about 1 kg, about 2 kg, about 3 kg, about 4 kg, about 5 kg, about 6 kg, about 7 kg, about 8 kg, about 9 kg, about 10 kg, about 11 kg, about 12 kg, about 13 kg, about 14 kg, about 15 kg, about 16 kg, about 17 kg, about 18 kg, about 19 kg, or about 20 kg of carbonation medium can be dispensed into each tray.|[0041] In some embodiments, the carbonation medium can be dispensed into each tray at a thickness of at least about 0.5 mm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm. In some embodiments, the carbonation medium can be dispensed into each tray at a thickness of no more than about 10 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, or no more than about 1 mm. Combinations of the above-referenced thicknesses of the carbonation medium are also possible (e.g., at least about 0.5 mm and no more than about 10 cm or at least about 5 mm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be dispensed into each tray at a thickness of about 0.5 mm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, or about 10 cm.|[0042] In some embodiments, the filling station 110 can include a water addition station (not shown). At the water addition station, water can be added to the carbonation medium. The water content in the carbonation medium can improve CO2 uptake, as described in the '336 publication. In some embodiments, water can adhere the carbonation medium together to create a permeable crust. In some embodiments, water can be added to the carbonation medium at the filling station 110. In some embodiments, water can be added to the carbonation medium after the carbonation medium has left the filling station 110. The adhering can aid in keeping the carbonation medium on the trays and setting the carbonation medium in place. In some embodiments, the filling station 110 can include an agitator. The agitator can be located inside the filling station 110 and can aid in keeping the carbonation medium fluid as it is dispensed (e.g., from a hopper). In other words, the agitator prevents clumping of carbonation medium inside the filling station 110. In some embodiments, the filling station 110 can include humidity and/or temperature monitoring and control instruments. In some embodiments, the filling station 110 can include cleaning and/or drying instruments to clean the trays before filling.|[0043] Carbonated medium is collected at the collection station 120. In some embodiments, the collection station 120 can include a trough to catch the carbonated medium. In some embodiments, the collection station 120 can include a rotating arm to grip and turn over the trays to empty the trays into the trough. In some embodiments, the collection station 120 can include a hopper for collection of the carbonated medium. In some embodiments, the hopper can be cylindrical, pyramidal, wedge-shaped, or chisel-shaped. In some embodiments, the collection station 120 can include a vibration motor or agitator to vibrate the trays and aid the carbonation medium in falling from the trays. In some embodiments, the carbonated medium can be transferred from the collection station 120 to a calciner. In some embodiments, the carbonated medium can be transferred from the collection station 120 to a storage area via an conveyor. In some embodiments, the conveyor can include an auger. In some embodiments, the storage area can include a silo. In some embodiments, the carbonated medium can be transferred from the collection station 120 to the storage area pneumatically. In some embodiments, the collection station 120 can include a tray enclosure that manipulates the trays. In some embodiments, manipulating the trays can include touching the trays (e.g., via the rotating arm). In some embodiments, the manipulation can exclude direct touching of the trays. In some embodiments, the manipulation can include rotating the trays, vibrating the trays, applying a vacuum to the trays, stirring the contents of the trays, and/or applying ultrasonic waves to the trays.|[0044] The tray movers 130 transfer trays between sections of the TPU 100. In some embodiments, the tray movers 130 can include conveyors. In some embodiments, the tray movers 130 can include screw drives. In some embodiments, the tray movers 130 can include actuated end effector pins to move the trays via grommets. In some embodiments, the tray movers 130 can enable two-direction translation. In some embodiments, the tray movers 130 can enable tray velocity profile control. In some embodiments, the tray movers 130 can include belt conveyors. In some embodiments, the tray movers 130 can include a belt drive. In some embodiments, the tray movers 130 can include chain conveyors. In some embodiments, the tray movers 130 can include aero-mechanical conveyors. In some embodiments, the tray movers 130 can include bucket conveyors. In some embodiments, the tray movers 130 can include distributors and effectors.|[0045] In some embodiments, the distributors and effectors can be positioned beneath conveyors. In some embodiments, the distributors and effectors can be positioned at either end of the conveyors for hand-off. In some embodiments, the conveyor can include a 2-direction roller belt. In some embodiments, the conveyor can include lead-in movement paths (analogous to airport luggage conveyors). In some embodiments, the conveyor can include a roller conveyor with retractable index pins. The pins can engage with the trays and secure the trays to the conveyor. In some embodiments, the conveyor can include various end effector configurations. In some embodiments, the conveyor can include pegs that automatically engage, move, and disengage the trays. In some embodiments, the conveyor can include end effectors on an X-Y gantry. In some embodiments, the conveyor can include end effectors on a rack, driven by a pinion.|[0046] In some embodiments, the tray movers 130 can be fastened to walls via angle brackets. In some embodiments, the tray movers 130 can include end stops to limit tray travel. In some embodiments, the tray movers 130 include powered rail cars, such that a tray rides on a moving carriage with rails. In some embodiments, the tray movers 130 can include a conveyor and a distributor actuator. In some embodiments, the tray movers 130 can include a pinch roller on the tray edge. In some embodiments, the tray movers 130 can include holes along the edge of the tray engaged by sprockets. In some embodiments, the tray movers 130 can include removable handles added to the tray during conveyance. In some embodiments, the tray movers 130 can include a hitch feed with end effectors to move two or more trays at once. In some embodiments, the tray movers 130 can include an expanding pin to reduce clearance with the grommet. In some embodiments, the tray movers 130 can include a fan with small holes (analogous to an air hockey table) with a downward bearing to facilitate smooth movement of the trays along the tray movers 130. In some embodiments, the tray movers 130 can include a retractable guide rail for 2-direction travel. In some embodiments, the tray movers 130 can include an automated guide vehicle (AGV) to move the trays. In some embodiments, the tray movers 130 can include an arm to push the trays. In some embodiments, the tray movers 130 can include a carriage driven by a cable cylinder. In some embodiments, the tray movers 130 can include a mecanum wheel under the tray. In some embodiments, the tray movers 130 can include a shuttling system that conveys multiple trays at a time, each in various phases of the transport process.|[0047] The loader 140a is optional and can move the trays to a vertical position (e.g., for placement in a caddy). In some embodiments, the loader 140a can include one or more stackers and the unloader 140b can include one or more destackers. In some embodiments, the stackers can include vertically-mobile instruments that elevate trays upward and place the trays in a desired vertical position (e.g., in a caddy). The placement of the trays in the desired vertical position can include horizontal movement of the trays (e.g., via wheels, actuators, conveyors) onto the caddies. In some embodiments, the destackers can include vertically-mobile instruments that retrieve trays from their vertical position (e.g., via horizontal motion) and place the trays in tray movers 130 and/or the collection station 120. In some embodiments, the loader 140a and/or the unloader 140b can include any of the properties of the distributors described in the '602 application. In some embodiments, the loader 140a and/or the unloader 140b can include a stationary caddy and use common distributor mechanisms for horizontal motion. In some embodiments, the loader 140a and/or the unloader 140b can include a belt drive and/or a screw drive. In some embodiments, the loader 140a and/or the unloader 140b can include a z-motion platform. Actuators can use a lead screw drive (e.g., a direct drive or scissor lift). In some embodiments, caddies can be moved up and down via a pulley system and/or a hydraulic/pneumatic bed. In some embodiments, the loader 140a and/or the unloader 140b can include a stationary caddy and a moving conveyance/elevation mechanism. In some embodiments, the loader 140a and/or the unloader 140b can include a scissor lift and a conveyor. In some embodiments, the loader 140a and/or the unloader 140b can include a mini distributor. In some embodiments, the mini distributor can have any of the properties of the distributors described in the '602 application. In some embodiments, the mini distributor can distribute trays without additional functionality. In other words, functional components such as sprayers and/or mass measurement devices are optional in the mini distributor and can be absent from the mini distributor. In some embodiments, the loader 140a and/or the unloader 140b can include an AGV to raise and lower caddies. In some embodiments, the loader 140a and/or the unloader 140b can include hinge tilts to move the trays to different tray levels.|[0048] In some embodiments, the loader 140a can include both a vertical and a horizontal movement mechanism. In some embodiments, the vertical movement mechanism and the horizontal movement mechanism can be part of the same apparatus. In other words, the vertical movement mechanism (e.g., elevator or lift) can be physically coupled to the horizontal movement mechanism (e.g., conveyor, stacker). In some embodiments, the vertical and horizontal movement mechanism can be de-coupled from each other.|[0049] In some embodiments, the unloader 140b can include both a vertical and a horizontal movement mechanism. In some embodiments, the vertical movement mechanism and the horizontal movement mechanism can be part of the same apparatus. In other words, the vertical movement mechanism (e.g., elevator or lift) can be physically coupled to the horizontal movement mechanism (e.g., conveyor, destacker). In some embodiments, the vertical and horizontal movement mechanism can be de-coupled from each other.|[0050] In some embodiments, z-motion platform actuators in the loader 140a and/or the unloader 140b can include a screw actuator, pulleys, cables, a scissor lift, a pneumatic cylinder, and/or a belt drive. In some embodiments, the loader 140a and/or the unloader 140b can include end effectors for horizontal movement and a single actuator for both end effectors. In some embodiments, the loader 140a and/or the unloader 140b can grab and pull trays via a lip and/or edge. In some embodiments, the trays can be flat (i.e., without a lip or edge). In embodiments with flat trays, the loader 140a and/or the unloader 140b can grab the trays via grabbing arms and/or holes on the edges of the trays. In some embodiments, the loader 140a and/or the unloader 140b can reach behind the tray lip to drag the tray. In some embodiments, the loader 140a and/or the unloader 140b can include a short stroke end effector and conveyor. In some embodiments, the loader 140a and/or the unloader 140b can include a belt drive. In some embodiments, any of the loader 140a, the unloader 140b and/or the tray movers 130 can be part of the same structure. In some embodiments, the structure can include a vertical mover that collects trays at different portions in either of the caddies in the TPU 100 (e.g., a caddy supported by a loading station and/or an unloading station of the caddy docking station 150).|[0051] In some embodiments, the loader 140a and/or the unloader 140b can include pegs on conveyors that automatically engage, move, and disengage trays. In some embodiments, the loader 140a and/or the unloader 140b can include an elevator bed in a box with a counterweight. In some embodiments, the loader 140a and/or the unloader 140b can include a stepper motor. The loader 140a and/or the unloader 140b can include an air actuator. In some embodiments, the loader 140a and/or the unloader 140b can include a tray sensor with a z stage to determine the tray level. In some embodiments, the loader 140a and/or the unloader 140b can include mechanisms within the caddy, such as a movable shelf or a tray carousel.|[0052] The docking station 150 provides an area for delivery and retrieval of caddies with trays. In some embodiments, the docking station 150 can include a loading station and an unloading station. In some embodiments, caddies can be aligned in the docking station 150 via retractable tapered pins. In some embodiments, the caddies can be aligned via kinematic coupling using a magnet or pneumatic actuators. In some embodiments, caddies can be conveyed through the caddy docking station 150 via a roller conveyor or rollers on wrap-around chains pushing on carry wheels. In some embodiments, the roller conveyors can include retractable alignment pins between rollers. In some embodiments, the docking station 150 can include vision cameras for detection of a tag on a side of a caddy.|[0053] In some embodiments, the docking station 150 can include locating features. In some embodiments, the locating features can include cone-shaped pins, diamond shaped pins, holes, and/or slots. In some embodiments, the docking station 150 can include a vertical lift mechanism to dock and undock caddies. In some embodiments, the docking station 150 can include a belt drive to move the caddies on and off the AGV. In some embodiments, the caddy can have wheels that ride on rails. In some embodiments, the caddy can include a wheel that moves through tracks in the docking station 150 (analogous to a cabinet drawer rail/wheel combination). In some embodiments, the docking station can include rollers on chains that push wheels of the caddies (analogous to a car wash).|[0054] In some embodiments, the docking station 150 can include an overhead conveyor that moves the caddy along. In some embodiments, the docking station 150 can include pegs on a belt or chain conveyor. In some embodiments, the docking station 150 can include a carriage with index pins. In some embodiments, the carriage can include a reciprocating X-Z stage carriage. In some embodiments, the carriage can include a lead screw carriage. In some embodiments, the carriage can include a linear motor carriage. In some embodiments, the docking station 150 can include a lift-up conveyor at its center. This can work with a forklift AGV. In some embodiments, the docking station 150 can include a hitch feed, such that caddies can latch onto each other. In some embodiments, the docking station 150 can include an electromagnet contactor for alignment. In some embodiments, the caddy can be fed to the docking station 150 via an automatic feed system using springs. In some embodiments, the docking station 150 can include side rollers and/or brushes to keep caddies aligned during motion. In some embodiments, the docking station 150 can include an omni-directional wheels platform. In some embodiments, the docking station 150 can include a tool changer magnetic coupler. In some embodiments, the docking station 150 can include a pneumatic powered kinematic coupler.|[0055] In some embodiments, the TPU 100 can process at least about 10 kg/hr, at least about 20 kg/hr, at least about 30 kg/hr, at least about 40 kg/hr, at least about 50 kg/hr, at least about 60 kg/hr, at least about 70 kg/hr, at least about 80 kg/hr, at least about 90 kg/hr, at least about 100 kg/hr, at least about 200 kg/hr, at least about 300 kg/hr, at least about 400 kg/hr, at least about 500 kg/hr, at least about 600 kg/hr, at least about 700 kg/hr, at least about 800 kg/hr, at least about 900 kg/hr, at least about 1 tonne (metric ton)/hr, at least about 2 tonnes/hr, at least about 3 tonnes/hr, at least about 4 tonnes/hr, at least about 5 tonnes/hr, at least about 6 tonnes/hr, at least about 7 tonnes/hr, at least about 8 tonnes/hr, at least about 9 tonnes/hr, at least about 10 tonnes/hr, at least about 20 tonnes/hr, at least about 30 tonnes/hr, at least about 40 tonnes/hr, at least about 50 tonnes/hr, at least about 60 tonnes/hr, at least about 70 tonnes/hr, at least about 80 tonnes/hr, at least about 90 tonnes/hr, at least about 100 tonnes/hr, at least about 200 tonnes/hr, at least about 300 tonnes/hr, at least about 400 tonnes/hr, at least about 500 tonnes/hr, at least about 600 tonnes/hr, at least about 700 tonnes/hr, at least about 800 tonnes/hr, at least about 900 tonnes/hr, at least about 1,000 tonnes/hr, at least about 2,000 tonnes/hr, at least about 3,000 tonnes/hr, at least about 4,000 tonnes/hr, at least at least about 5,000 tonnes/hr, at least at least about 6,000 tonnes/hr, at least at least about 7,000 tonnes/hr, at least at least about 8,000 tonnes/hr, or at least about 9,000 tonnes/hr of carbonated medium. In some embodiments, the TPU 100 can process no more than about 10,000 tonnes/hr, no more than about 9,000 tonnes/hr, no more than about 8,000 tonnes/hr, no more than about 7,000 tonnes/hr, no more than about 6,000 tonnes/hr, no more than about 5,000 tonnes/hr, no more than about 4,000 tonnes/hr, no more than about 3,000 tonnes/hr, no more than about 2,000 tonnes/hr, no more than about 1,000 tonnes/hr, no more than about 900 tonnes/hr, no more than about 800 tonnes/hr, no more than about 700 tonnes/hr, no more than about 600 tonnes/hr, no more than about 500 tonnes/hr, no more than about 400 tonnes/hr, no more than about 300 tonnes/hr, no more than about 200 tonnes/hr, no more than about 100 tonnes/hr, no more than about 90 tonnes/hr, no more than about 80 tonnes/hr, no more than about 70 tonnes/hr, no more than about 60 tonnes/hr, no more than about 50 tonnes/hr, no more than about 40 tonnes/hr, no more than about 30 tonnes/hr, no more than about 20 tonnes/hr, no more than about 10 tonnes/hr, no more than about 9 tonnes/hr, no more than about 8 tonnes/hr, no more than about 7 tonnes/hr, no more than about 6 tonnes/hr, no more than about 5 tonnes/hr, no more than about 4 tonnes/hr, no more than about 3 tonnes/hr, no more than about 2 tonnes/hr, no more than about 1 tonne/hr, no more than about 900 kg/hr, no more than about 800 kg/hr, no more than about 700 kg/hr, no more than about 600 kg/hr, no more than about 500 kg/hr, no more than about 400 kg/hr, no more than about 300 kg/hr, no more than about 200 kg/hr, no more than about 100 kg/hr, no more than about 90 kg/hr, no more than about 80 kg/hr, no more than about 70 kg/hr, no more than about 60 kg/hr, no more than about 50 kg/hr, no more than about 40 kg/hr, no more than about 30 kg/hr, or no more than about 20 kg/hr of carbonated medium. Combinations of the above-referenced throughput values are also possible (e.g., at least about 10 kg/hr and no more than about 10,000 tonnes/hr or at least about 50 kg/hr and no more than about 5,000 kg/hr), inclusive of all values and ranges therebetween. In some embodiments, the TPU 100 can process about 10 kg/hr, about 20 kg/hr, about 30 kg/hr, about 40 kg/hr, about 50 kg/hr, about 60 kg/hr, about 70 kg/hr, about 80 kg/hr, about 90 kg/hr, about 100 kg/hr, about 200 kg/hr, about 300 kg/hr, about 400 kg/hr, about 500 kg/hr, about 600 kg/hr, about 700 kg/hr, about 800 kg/hr, about 900 kg/hr, about 1 tonne/hr, about 2 tonnes/hr, about 3 tonnes/hr, about 4 tonnes/hr, about 5 tonnes/hr, about 6 tonnes/hr, about 7 tonnes/hr, about 8 tonnes/hr, about 9 tonnes/hr, about 10 tonnes/hr, about 20 tonnes/hr, about 30 tonnes/hr, about 40 tonnes/hr, about 50 tonnes/hr, about 60 tonnes/hr, about 70 tonnes/hr, about 80 tonnes/hr, about 90 tonnes/hr, about 100 tonnes/hr, about 200 tonnes/hr, about 300 tonnes/hr, about 400 tonnes/hr, about 500 tonnes/hr, about 600 tonnes/hr, about 700 tonnes/hr, about 800 tonnes/hr, about 900 tonnes/hr, about 1,000 tonnes/hr, about 2,000 tonnes/hr, about 3,000 tonnes/hr, about 4,000 tonnes/hr, about 5,000 tonnes/hr, about 6,000 tonnes/hr, about 7,000 tonnes/hr, about 8,000 tonnes/hr, about 9,000 tonnes/hr, or about 10,000 tonnes/hr, of carbonated medium.|[0056] In some embodiments, the TPU 100 can process at least about 10 kg/hr, at least about 20 kg/hr, at least about 30 kg/hr, at least about 40 kg/hr, at least about 50 kg/hr, at least about 60 kg/hr, at least about 70 kg/hr, at least about 80 kg/hr, at least about 90 kg/hr, at least about 100 kg/hr, at least about 200 kg/hr, at least about 300 kg/hr, at least about 400 kg/hr, at least about 500 kg/hr, at least about 600 kg/hr, at least about 700 kg/hr, at least about 800 kg/hr, at least about 900 kg/hr, at least about 1 tonne/hr, at least about 2 tonnes/hr, at least about 3 tonnes/hr, at least about 4 tonnes/hr, at least about 5 tonnes/hr, at least about 6 tonnes/hr, at least about 7 tonnes/hr, at least about 8 tonnes/hr, at least about 9 tonnes/hr, at least about 10 tonnes/hr, at least about 20 tonnes/hr, at least about 30 tonnes/hr, at least about 40 tonnes/hr, at least about 50 tonnes/hr, at least about 60 tonnes/hr, at least about 70 tonnes/hr, at least about 80 tonnes/hr, at least about 90 tonnes/hr, at least about 100 tonnes/hr, at least about 200 tonnes/hr, at least about 300 tonnes/hr, at least about 400 tonnes/hr, at least about 500 tonnes/hr, at least about 600 tonnes/hr, at least about 700 tonnes/hr, at least about 800 tonnes/hr, at least about 900 tonnes/hr, at least about 1,000 tonnes/hr, at least about 2,000 tonnes/hr, at least about 3,000 tonnes/hr, at least about 4,000 tonnes/hr, at least at least about 5,000 tonnes/hr, at least at least about 6,000 tonnes/hr, at least at least about 7,000 tonnes/hr, at least at least about 8,000 tonnes/hr, or at least about 9,000 tonnes/hr of carbonation medium. In some embodiments, the TPU 100 can process no more than about 10,000 tonnes/hr, no more than about 9,000 tonnes/hr, no more than about 8,000 tonnes/hr, no more than about 7,000 tonnes/hr, no more than about 6,000 tonnes/hr, no more than about 5,000 tonnes/hr, no more than about 4,000 tonnes/hr, no more than about 3,000 tonnes/hr, no more than about 2,000 tonnes/hr, no more than about 1,000 tonnes/hr, no more than about 900 tonnes/hr, no more than about 800 tonnes/hr, no more than about 700 tonnes/hr, no more than about 600 tonnes/hr, no more than about 500 tonnes/hr, no more than about 400 tonnes/hr, no more than about 300 tonnes/hr, no more than about 200 tonnes/hr, no more than about 100 tonnes/hr, no more than about 90 tonnes/hr, no more than about 80 tonnes/hr, no more than about 70 tonnes/hr, no more than about 60 tonnes/hr, no more than about 50 tonnes/hr, no more than about 40 tonnes/hr, no more than about 30 tonnes/hr, no more than about 20 tonnes/hr, no more than about 10 tonnes/hr, no more than about 9 tonnes/hr, no more than about 8 tonnes/hr, no more than about 7 tonnes/hr, no more than about 6 tonnes/hr, no more than about 5 tonnes/hr, no more than about 4 tonnes/hr, no more than about 3 tonnes/hr, no more than about 2 tonnes/hr, no more than about 1 tonne/hr, no more than about 900 kg/hr, no more than about 800 kg/hr, no more than about 700 kg/hr, no more than about 600 kg/hr, no more than about 500 kg/hr, no more than about 400 kg/hr, no more than about 300 kg/hr, no more than about 200 kg/hr, no more than about 100 kg/hr, no more than about 90 kg/hr, no more than about 80 kg/hr, no more than about 70 kg/hr, no more than about 60 kg/hr, no more than about 50 kg/hr, no more than about 40 kg/hr, no more than about 30 kg/hr, or no more than about 20 kg/hr of carbonation medium. Combinations of the above-referenced throughput values are also possible (e.g., at least about 10 kg/hr and no more than about 10,000 tonnes/hr or at least about 50 kg/hr and no more than about 5,000 kg/hr), inclusive of all values and ranges therebetween. In some embodiments, the TPU 100 can process about 10 kg/hr, about 20 kg/hr, about 30 kg/hr, about 40 kg/hr, about 50 kg/hr, about 60 kg/hr, about 70 kg/hr, about 80 kg/hr, about 90 kg/hr, about 100 kg/hr, about 200 kg/hr, about 300 kg/hr, about 400 kg/hr, about 500 kg/hr, about 600 kg/hr, about 700 kg/hr, about 800 kg/hr, about 900 kg/hr, about 1 tonne/hr, about 2 tonnes/hr, about 3 tonnes/hr, about 4 tonnes/hr, about 5 tonnes/hr, about 6 tonnes/hr, about 7 tonnes/hr, about 8 tonnes/hr, about 9 tonnes/hr, about 10 tonnes/hr, about 20 tonnes/hr, about 30 tonnes/hr, about 40 tonnes/hr, about 50 tonnes/hr, about 60 tonnes/hr, about 70 tonnes/hr, about 80 tonnes/hr, about 90 tonnes/hr, about 100 tonnes/hr, about 200 tonnes/hr, about 300 tonnes/hr, about 400 tonnes/hr, about 500 tonnes/hr, about 600 tonnes/hr, about 700 tonnes/hr, about 800 tonnes/hr, about 900 tonnes/hr, about 1,000 tonnes/hr, about 2,000 tonnes/hr, about 3,000 tonnes/hr, about 4,000 tonnes/hr, about 5,000 tonnes/hr, about 6,000 tonnes/hr, about 7,000 tonnes/hr, about 8,000 tonnes/hr, about 9,000 tonnes/hr, or about 10,000 tonnes/hr, of carbonation medium.|[0057] In some embodiments, the TPU 100 can process at least about 50 trays/hr, at least about 60 trays/hr, at least about 70 trays/hr, at least about 80 trays/hr, at least about 90 trays/hr, at least about 100 trays/hr, at least about 200 trays/hr, at least about 300 trays/hr, at least about 400 trays/hr, at least about 500 trays/hr, at least about 600 trays/hr, at least about 700 trays/hr, at least about 800 trays/hr, at least about 900 trays/hr, at least about 1,000 trays/hr, at least about 2,000 trays/hr, at least about 3,000 trays/hr, at least about 4,000 trays/hr, at least about 5,000 trays/hr, at least about 6,000 trays/hr, at least about 7,000 trays/hr, at least about 8,000 trays/hr, at least about 9,000 trays/hr, at least about 10,000 trays/hr, at least about 20,000 trays/hr, at least about 30,000 trays/hr, at least about 40,000 trays/hr, at least about 50,000 trays/hr, at least about 60,000 trays/hr, at least about 70,000 trays/hr, at least about 80,000 trays/hr, or at least about 90,000 trays/hr of carbonated medium. In some embodiments, the TPU 100 can process no more than about 100,000 trays/hr, no more than about 90,000 trays/hr, no more than about 80,000 trays/hr, no more than about 70,000 trays/hr, no more than about 60,000 trays/hr, no more than about 50,000 trays/hr, no more than about 40,000 trays/hr, no more than about 30,000 trays/hr, no more than about 20,000 trays/hr, no more than about 10,000 trays/hr, no more than about 9,000 trays/hr, no more than about 8,000 trays/hr, no more than about 7,000 trays/hr, no more than about 6,000 trays/hr, no more than about 5,000 trays/hr, no more than about 4,000 trays/hr, no more than about 3,000 trays/hr, no more than about 2,000 trays/hr, no more than about 1,000 trays/hr, no more than about 900 trays/hr, no more than about 800 trays/hr, no more than about 700 trays/hr, no more than about 600 trays/hr, no more than about 500 trays/hr, no more than about 400 trays/hr, no more than about 300 trays/hr, no more than about 200 trays/hr, no more than about 100 trays/hr, no more than about 90 trays/hr, no more than about 80 trays/hr, no more than about 70 trays/hr, or no more than about 60 trays/hr of carbonated medium. Combinations of the above-referenced numbers of trays are also possible (e.g., at least about 50 trays/hr and no more than about 100,000 trays/hr or at least about 1,000 trays/hr and no more than about 10,000 trays/hr), inclusive of all values and ranges therebetween. In some embodiments, the TPU 100 can process about 50 trays/hr, about 60 trays/hr, about 70 trays/hr, about 80 trays/hr, about 90 trays/hr, about 100 trays/hr, about 200 trays/hr, about 300 trays/hr, about 400 trays/hr, about 500 trays/hr, about 600 trays/hr, about 700 trays/hr, about 800 trays/hr, about 900 trays/hr, about 1,000 trays/hr, about 2,000 trays/hr, about 3,000 trays/hr, about 4,000 trays/hr, about 5,000 trays/hr, about 6,000 trays/hr, about 7,000 trays/hr, about 8,000 trays/hr, about 9,000 trays/hr, about 10,000 trays/hr, about 20,000 trays/hr, about 30,000 trays/hr, about 40,000 trays/hr, about 50,000 trays/hr, about 60,000 trays/hr, about 70,000 trays/hr, about 80,000 trays/hr, about 90,000 trays/hr, or about 100,000 trays/hr of carbonated medium.|[0058] In some embodiments, one or more weigh stations can be placed at various locations throughout the TPU 100. In some embodiments, the weigh station(s) can include scales. In some embodiments, a weigh station can be incorporated into the tray mover 130a and/or the tray mover 130b. In some embodiments, a weigh station can be incorporated into the loader 140a and/or the unloader 140b. In some embodiments, a weigh station can be incorporated into the collection station 120. In some embodiments, a weigh station can be incorporated into the filling station 110. In some embodiments, a weigh station can be placed at any location between the aforementioned process units.|[0059] In some embodiments, one or more quality inspection stations can be placed at various locations throughout the TPU 100. In some embodiments, the quality inspection station(s) can include an inspection tool. In some embodiments, the quality inspection station(s) can include an optical measurement device. In some embodiments, the optical measurement device can measure the level and/or uniformity (i.e., evenness) of carbonation medium or carbonated medium in a tray. In some embodiments, a quality inspection station can be incorporated into the tray mover 130a and/or the tray mover 130b. In some embodiments, a quality inspection station can be incorporated into the loader 140a and/or the unloader 140b. In some embodiments, a quality inspection station can be incorporated into the collection station 120. In some embodiments, a quality inspection station can be incorporated into the filling station 110. In some embodiments, a quality inspection station can be placed at any location between the aforementioned process units.|[0060] FIG. 2 is a block diagram of a carbonation system 1000, according to an embodiment. FIG. 2 shows how the TPU 100 incorporates into a larger scheme. As shown, the carbonation system 1000 includes a contactor network 1001, a vehicle network, the TPU 100, a calciner 1003, a gas separation skid 1004, a CO2 processor 1005, and CO2 storage 1006.|[0061] The contactor network 1001 includes an array of contactors. In some embodiments, the contactors can have any of the properties of the contactors described in the '602 application. The vehicle network 1002 aids in transporting carbonation medium and carbonated medium between the contactor network 1001 and the TPU 100. In some embodiments, the vehicle network 1002 can include one or more AGV's. In some embodiments, the vehicle network 1002 can include a first vehicle and a second vehicle. In some embodiments, the first vehicle can transport caddies while the second vehicle is charging at a charging station. In some embodiments, the second vehicle can transport caddies while the first vehicle is charging at the charging station. In some embodiments, the vehicle network 1002 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, or about 1,000 vehicles, inclusive of all values and ranges therebetween. In some embodiments, any of the vehicles can include a lifter module configured to dock and undock caddies (i.e., from a loading dock and/or an unloading dock). The calciner 1003 converts carbonated medium to carbonation medium. In some embodiments, the calciner 1003 can have any of the properties of the calciners described in the '896 application.|[0062] The gas separation skid 1004 separates CO2 in the exhaust from the calciner 1003 from other gases. In some embodiments, the gas separation skid 1004 can include a condenser to remove water. The CO2 processer 1005 further separates gases to purify the CO2. In some embodiments, the CO2 processor 1005 can include a compressor to pressurize the CO2. The CO2 storage 1006 includes a volume for storage and sequestration of CO2. In some embodiments, the CO2 storage 1006 can have any of the properties described in the '896 application.|[0063] FIG. 2 depicts the movement of chemicals from one process block to another. The chemicals shown in FIG. 2 are intended as examples and not intended to limit the scope of this application. As shown, CaCO3 is transported from the contactor network 1001 to the TPU 100 via the vehicle network 1002 and Ca(OH)2 is transported from the TPU 100 to the contactor network 1001 via the vehicle network 1002. CaCO3 is transported from the TPU 100 to the calciner 1003 and a mixed stream of gases move from the calciner 1003 to the gas separation skid 1004. A high purity CO2 stream moves from the gas separation skid 1004 to the CO2 processor 1005 and a higher purity CO2 stream moves from the CO2 processor 1005 to the CO2 storage 1006. A stream of CaO moves from the calciner 1003 to the hydrator 1007, where the CaO is hydrated to become Ca(OH)2. The Ca(OH)2 is then fed to the TPU 100.|[0064] FIGS. 3A-3B show the layout of a TPU 200, according to an embodiment. FIG. 3A shows a perspective view of the TPU 200, while FIG. 3B shows an overhead view of the TPU 200. Axes are shown for structural clarity. As shown, the TPU 200 includes a filling station 210, a collection station 220, tray movers 230a, 230b (collectively referred to as tray movers 230), a loader 240a, an unloader 240b (collectively referred to as distributors 240), docking stations 250a, 250b, 250c (collectively referred to as docking stations 250), caddies 252a, 252b, 252c (collectively referred to as caddies 250), and a vehicle 255. In some embodiments, the filling station 210, the collection station 220, the tray movers 230, the distributors 240, and the docking stations 250 can be the same or substantially similar to the filling station 110, the collection station 120, the tray movers 130, the loader 140a, the unloader 140b, and the docking station 150, as described above with reference to FIG. 1. Thus, certain aspects of the filling station 210, the collection station 220, the tray movers 230, the loader 240a, the unloader 240b, and the docking stations 250 are not described in greater detail herein.|[0065] In use, the docking station 250c can act as a loading station, while the docking station 250a can act as an unloading station for trays. Trays can be loaded or unloaded from docking station 250b. In some embodiments, the docking station 250b can act as a buffer station. In some embodiments, the docking station 250b can be used for loading and/or unloading of trays. In some embodiments, either of the docking stations 250 can be used for loading or unloading of trays and conveyors in the docking stations 250 can aid in moving the trays to an appropriate location. As shown, the TPU 200 includes 3 docking stations 250. In some embodiments, the TPU 200 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, or about 100 docking stations, inclusive of all values and ranges therebetween.|[0066] In use, the vehicle 255 delivers the caddy 252c to the docking station 250c. The unloader 240b then transfers trays from the caddy 252c to the collection station 220 where the carbonated medium is collected. The tray mover 230b then transfers the empty or nearly empty trays from the collection station 220 to the filling station 210 where carbonation medium is dispensed into the trays. The tray mover 230a then transfers the trays to the loader 240a, which delivers the trays to the caddy 252a. Another vehicle (not shown) then delivers the caddy 252a to a contactor system. In some embodiments, the same vehicle 255 can deliver and collect the caddies 252. In some embodiments, the docking stations 250 can include rollers or conveyors to move the caddies 252 between the docking stations 250.|[0067] FIG. 4 is an overhead depiction of movement of trays T throughout the TPU 200. Axes are shown for structural clarity. In step 1, 10 trays T are included in the docking station 250c while additional trays T are scattered throughout the TPU 200. In step 2, a tray T1 has migrated from the docking station 250c to the unloader 240b. In step 3, the same tray T1 that migrated to the unloader 240b in step 2 has now migrated to the collection station 220. In step 4, the same tray T1 that migrated to the collection station 220 at step 3 has migrated to the tray mover 230b and an additional tray T2 has now migrated from the docking station 250c to the unloader 240b. |[0068] FIG. 5 shows movement of the vehicle 255 between the TPU 200 and a contactor system 2001. In some embodiments, the contactor system 2001 can be the same or substantially similar to the contactor system 1001, as described above with reference to FIG. 2. Thus, certain aspects of the contactor system 2001 are not described in greater detail herein. As shown, the contactor system 2001 includes rows of contactor units. Pathways P define movement paths of the vehicle 255 between the TPU 200 and the contactor system 2001. The pathways are positioned between the rows of contactors. As shown, the TPU 200 includes silos 223a, 223b (collectively referred to as silos 223). Carbonated medium is transferred from the silo 223a to the filling station 210. In some embodiments, carbonated medium can be transferred from the silo 223a to the filling station 210 via a vacuum installed at the filling station 210. In some embodiments, carbonated medium can be transferred from the silo 223a to the filling station 210 via an auger. In some embodiments, the carbonation medium can be transferred from the silo 223a to the filling station 210 via pneumatic conveyance (i.e., positive pressure conveyance). Carbonation medium is transferred from the collection station 220 to the silo 223b for storage. In some embodiments, the vehicle 255 can be powered via solar power, wind power, nuclear power, geothermal power, and/or any other suitable renewable or low carbon energy source or combinations thereof.|[0069] FIG. 6 shows interactions between a contactor tower 353, caddies 352a, 352b (collectively referred to as caddies 352), and a vehicle 355, according to an embodiment. Axes are shown for structural clarity. In some embodiments, the contactor tower 353 can be the same or substantially similar to the contactor towers described in the '602 application. In some embodiments, the caddies 352 and the vehicle 355 can be the same or substantially similar to the caddies 252 and the vehicle 255 as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the caddies 352, the contactor tower 353, and the vehicle 355 are not described in greater detail herein.|[0070] In use, the vehicle 355 moves to a position under the contactor tower 353 and retrieves the caddies 352. The vehicle 355 can also transport the caddies 352 and move to place the caddies 352 in a desired vertical position on the contactor tower 353. In some embodiments, multiple caddies 352 can be stacked upon each other in the contactor tower 353. In some embodiments, the contactor tower 353 can include an elevator to elevate and move caddies 352 to a desired vertical position. As shown, trays T are stacked within the caddies 352. In some embodiments, the trays T can be positioned in the contactor tower 353 while dissociated from the caddies 352.|[0071] FIGS. 7A-7B show a caddy 452, according to an embodiment. FIG. 7A shows an overhead perspective view of the caddy 452, while FIG. 7B shows a perspective view from an underside of the caddy 452. Axes are shown for structural clarity. As shown, the caddy 452 includes a caddy-vehicle interface 457 and support structures 458.|[0072] The caddy-vehicle interface 457 provides a surface for lifting the caddy along the height of the contactor tower 453. In some embodiments, the caddy-vehicle interface 457 can include a platform that can be contacted by an arm or lifting device. As shown, the caddy-vehicle interface 457 includes fastener holes 459 for securing or attachment of the caddy 452 to pieces of process equipment. The support structure 458 keeps trays T in a proper alignment along the height of the contactor tower 453. In some embodiments, the support structure 458 can include a series of beams or poles that prevent movement of the trays T along the x- and y-axes.|[0073] As shown, 10 trays T are stacked on the caddy 452. In some embodiments, at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, or at least about 900 trays T can be stacked on the caddy 452. In some embodiments, no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, or no more than about 2 trays T can be stacked on the caddy 452. Combinations of the above-referenced numbers of trays T are also possible (e.g., at least about 1 and no more than about 1,000 or at least about 5 and no more than about 50), inclusive of all values and ranges therebetween. In some embodiments, about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, or about 1,000, trays T can be stacked on the caddy 452.|[0074] FIG. 8 shows a collection station 520, according to an embodiment. As shown, the collection station 520 includes an enclosure 521, a trough 523, and an auger 526. The enclosure 521 can house a tray T. In some embodiments, the enclosure 521 can include openings for outflow of carbonated medium. In some embodiments, the enclosure 521 can include a long, narrow opening on a narrow side of the enclosure 521. The tray T is held to prevent the tray T from falling through the opening and the carbonated medium is allowed to fall from the tray T into the trough 523. In some embodiments, the enclosure 521 can include an arm to hold the tray T. In some embodiments, the enclosure 521 can rotate. In some embodiments, the collection station 520 can include a robotic arm that rotates the enclosure 521. In some embodiments, the collection station 520 can include an agitator to vibrate the enclosure 521 and the tray T to facilitate falling out of the carbonated medium.|[0075] In some embodiments, the enclosure 521 can rotate by at least about 30 degrees, at least about 30 degrees, at least about 30 degrees, at least about 40 degrees, at least about 50 degrees, at least about 60 degrees, at least about 70 degrees, at least about 80 degrees, at least about 90 degrees, at least about 100 degrees, at least about 110 degrees, at least about 120 degrees, at least about 130 degrees, at least about 140 degrees, at least about 150 degrees, at least about 160 degrees, or at least about 170 degrees. In some embodiments, the enclosure 521 can rotate by no more than about 180 degrees, no more than about 170 degrees, no more than about 160 degrees, no more than about 150 degrees, no more than about 140 degrees, no more than about 130 degrees, no more than about 120 degrees, no more than about 110 degrees, no more than about 100 degrees, no more than about 90 degrees, no more than about 80 degrees, no more than about 70 degrees, no more than about 60 degrees, no more than about 50 degrees, or no more than about 40 degrees. Combinations of the above-referenced angles are also possible (e.g., at least about 30 degrees and no more than about 180 degrees or at least about 80 degrees and no more than about 120 degrees), inclusive of all values and ranges therebetween. In some embodiments, the enclosure 521 can rotate by about 30 degrees, about 30 degrees, about 30 degrees, about 40 degrees, about 50 degrees, about 60 degrees, about 70 degrees, about 80 degrees, about 90 degrees, about 100 degrees, about 110 degrees, about 120 degrees, about 130 degrees, about 140 degrees, about 150 degrees, about 160 degrees, about 170 degrees, or about 180 degrees.|[0076] The trough 523 provides a volume where the carbonated medium can collect after falling from the tray T. In some embodiments, the trough 523 can include a hopper. The auger 526 facilitates movement of the carbonated medium out of the trough 523. In some embodiments, the auger 526 can deliver the carbonated medium directly to a calciner. In some embodiments, the auger 526 can deliver the carbonated medium to a storage area (e.g., a silo).|[0077] FIG. 9 shows an overhead view of a filling station 610, according to an embodiment. Axes are shown for structural clarity. As shown, the filling station 610 includes a tray filler 614 and a water dispenser 615. Carbonation medium is dispensed into a tray as the tray moves into the filling station 610. The water dispenser 615 delivers water to the tray. In some embodiments, the water can be delivered to the tray after the carbonation medium is dispensed into the tray. In some embodiments, the water can be delivered to the tray before the carbonation medium is dispensed into the tray. In some embodiments, the water can be delivered to the tray as the carbonation medium is being dispensed into the tray. As described above, the water can improve uptake of the carbonation medium and can adhere the carbonation medium together, creating a crust-like material. In some embodiments, the water dispenser 615 can include a spray nozzle.|[0078] FIG. 10 shows a water dispenser 715, according to an embodiment. In some embodiments, the water dispenser 715 can be the same or substantially similar to the water dispenser 615, as described above with reference to FIG. 9. Thus, certain aspects of the water dispenser 715 are not described in greater detail herein. As shown, the water dispenser 715 includes spray nozzles 717. As shown, the spray nozzles 717 are arranged in a single file. In some embodiments, the spray nozzles can be arranged in a 2-dimensional n x m array, where n and m are both integers. In some embodiments, n and/or m can be about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, or about 20, inclusive of all values and ranges therebetween.|[0079] FIG. 11 shows a tray filler 814, according to an embodiment. As shown, the tray filler 814 includes a carbonation medium reservoir 816 and a dispensing nozzle 819. The carbonation medium reservoir 816 stores carbonation medium. In some embodiments, the carbonation medium reservoir 816 can include an auger for movement of carbonation medium through the carbonation medium reservoir 816. The dispensing nozzle 819 dispenses carbonation medium. In some embodiments, the dispensing nozzle 819 can include one or more valves to regulate outflow of carbonation medium.|[0080] FIG. 12 shows a tray mover 930, according to an embodiment. In some embodiments, the tray mover 930 can be the same or substantially similar to the tray mover 130, as described above with reference to FIG. 1. As shown, the tray mover includes an actuator 932 and grommets 934. The actuator 932 propels horizontal movement of trays along the tray mover 930. In some embodiments, the actuator 932 can include a linear actuator. The grommets 934 provide a location for placement of trays on top of the tray mover 930. In some embodiments, the grommets 934 can be moved via effector pins. In some embodiments, the grommets 934 can be combined with passive rollers or active roller conveyors. In some embodiments, the grommets 934 can enable 2-direction translation. In some embodiments, the grommets 934 can enable tray velocity profile control.|[0081] FIG. 13 shows a tray movement scheme, according to an embodiment. FIG. 13 shows an overhead view of a filling station 1010, a collection station 1020, and tray movers 1030a, 1030b (collectively referred to as tray movers 1030). Axes are shown for structural clarity. As shown, the filling station 1010, the collection station 1020, and the tray movers 1030 can be the same or substantially similar to the filling station 210, the collection station 220, and the tray movers 230, as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the filling station 1010, the collection station 1020, and the tray movers 1030 are not described in greater detail herein. As shown, empty trays exit the collection station moving along two platforms of the tray mover 1030a in the positive x-direction. A next platform of the tray mover 1030a moves the tray in the negative y-direction. A next platform of the tray mover 1030a moves the tray in the negative x-direction toward the filling station 1010. Two more platforms of the tray mover 1030b then move the tray in the negative x-direction toward a loading dock (not shown).|[0082] FIG. 14 shows a tray distributor 1140, according to an embodiment. In some embodiments, the tray distributor 1140 can be the same or substantially similar to the loader 240a and/or the unloader 240b, as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the tray distributor 1140 are not described in greater detail. Axes are shown for structural clarity. In some embodiments, the tray distributor 1140 can function as a tray loader. In some embodiments, the tray distributor 1140 can function as a tray unloader. The distributor 1140 moves the trays vertically along the z-axis. As shown, the distributor 1140 includes a housing 1142 and a platform 1144. The platform 1144 moves into and out of the housing 1142 (i.e., along x-axis). A tray can be placed upon the platform 1144. In some embodiments, the movement of the platform 1144 into and out of the housing 1142 can be via wheels. In some embodiments, the wheels can move through a track. In some embodiments, the movement of the platform 1144 can be automated. In some embodiments, the platform 1144 can be the same or substantially similar to the platforms described with respect to the contactors in the '602 application.|[0083] FIGS. 15A-15B show a caddy 1252, according to an embodiment. FIG. 15A shows a perspective view of the caddy 1252, while FIG. 15B shows a side view of the caddy 1252. Axes are shown for structural clarity. As shown, the caddy 1252 includes support structures 1258 and bars 1248. The support structures 1258 act as shelves for the placement of trays. The support structures 1258 are placed on top of the bars 1248. The bars 1248 extend lengthwise along the caddy 1252.|[0084] FIGS. 16A-16B show interaction between a docking station 1350, a caddy 1352, and a vehicle 1355, according to an embodiment. FIG. 16A shows a front view of the components, while FIG. 16B shows a side view of the components. Axes are shown for structural clarity. In some embodiments, the docking station 1350, the caddy 1352, and the vehicle 1355 can be the same or substantially similar to the docking station 250, the caddy 252, and the vehicle 255, as described above with reference to FIGS. 3A-3B. Thus, certain aspects of the docking station 1350, the caddy 1352, and the vehicle 1355 are not described in greater detail herein.|[0085] As shown, the docking station 1350 includes a detector 1371, a label 1372, rollers 1373a, 1373b, 1373c, 1373d, 1373e (collectively referred to as rollers 1373), and locating pins 1374a, 1374b (collectively referred to as locating pins 1374). The rollers 1373 facilitate movement of the caddy 1352 into and out of the docking station 1350. The locating pins 1374 lock the caddy 1352 in place when the caddy 1352 moves into position on the docking station 1350. In some embodiments, the locating pins 1374 can be spring loaded. In some embodiments, the locating pins 1374 can be automated. The label 1372 provides an identifying mark for the caddy 1352. In some embodiments, the label 1372 can include data stored in a central database. The detector 1371 detects the label 1372. In some embodiments, the detector 1371 can send information to a central computer for tracking. As shown, the caddy 1352 includes a stack of trays T disposed therein.|[0086] As shown, the vehicle 1355 includes wheels 1375a, 1375b (collectively referred to as wheels 1375) and a locating pin 1376. The wheels 1375 allow the vehicle 1355 to move around the floor of the facility. The locating pin 1376 locks the vehicle 1355 to the caddy 1352. In some embodiments, the vehicle 1355 can include a spring. In some embodiments, the vehicle 1355 can be automated.|[0087] FIG. 17 is an overhead view of a TPU 1400 and a contactor network 14001. Axes are shown for structural clarity. As shown, the TPU 1400 includes a filling station 1410, a collection station 1420, silos 1423a, 1423b (collectively referred to as silos 1423), tray movers 1430a, 1430b (collectively referred to as tray movers 1430), a loader 1440a, an unloader 1440b, a docking station 1450, caddies 1452a, 1452b, 1452c (collectively referred to as caddies 1452), and a vehicle 1455. In some embodiments, the TPU 1400, the contactor network 14001, the filling station 1410, the collection station 1420, the silos 1423, the tray movers 1430, the loader 1440a, the unloader 1440b, the docking station 1450, the caddies 1452, and the vehicle 1455 can be the same or substantially similar to the TPU 200, the contactor network 2001, the filling station 210, the collection station 220, the silos 223, the tray movers 230, the loader 240a, the unloader 240b, the docking station 250, the caddies 252, and the vehicles 255, as described above with reference to FIG. 5. Thus, certain aspects of the TPU 1400, the contactor network 14001, the filling station 1410, the collection station 1420, the silos 1423, the tray movers 1430, the loader 1440a, the unloader 1440b, the docking station 1450, the caddies 1452, and the vehicle 1455 are not described in greater detail herein.|[0088] As shown, pathways P between the contactors of the contactor network 14001 allow for one-way movement between the contractors. This allows the vehicle 1455 to weave through arrays of contactors of the contactor network 14001. The vehicle 1455 moves in a first direction through a first lane and a second direction in a second lane adjacent to the first lane, the second direction opposite the first direction.|[0089] FIG. 17 shows a single TPU 1400 in a facility. In some embodiments, multiple TPU's can be included in a single facility. In some embodiments, a facility can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, or about 100 TPU's, inclusive of all values and ranges therebetween.|[0090] FIG. 18 is an overhead view of a TPU 1500 and a contactor network 15001. Axes are shown for structural clarity. As shown, the TPU 1500 includes a filling station 1510, a collection station 1520, silos 1523a, 1523b (collectively referred to as silos 1523), tray movers 1530a, 1530b (collectively referred to as tray movers 1530), a loader 1540a, an unloader 1540b, a docking station 1550, caddies 1552a, 1552b, 1552c (collectively referred to as caddies 1552), and vehicles 1555a, 1555b (collectively referred to as vehicles 1555). In some embodiments, the TPU 1500, the contactor network 15001, the filling station 1510, the collection station 1520, the silos 1523, the tray movers 1530, the loader 1540a, the unloader 1540b, the docking station 1550, the caddies 1552, and the vehicles 1555 can be the same or substantially similar to the TPU 200, the contactor network 2001, the filling station 210, the collection station 220, the silos 223, the tray movers 230, the loader 1540a, the unloader 1540b, the docking station 250, the caddies 252, and the vehicle 255, as described above with reference to FIG. 5. Thus, certain aspects of the TPU 1500, the contactor network 15001, the filling station 1510, the collection station 1520, the silos 1523, the tray movers 1530, the loader 1540a, the unloader 1540b, the docking station 1550, the caddies 1552, and the vehicles 1555 are not described in greater detail herein.|[0091] As shown, pathways P between the contactors of the contactor network 15001 allow for two-way movement between the contractors. This allows the vehicles 1555 to move in either direction between the contactors. In some embodiments, the vehicles 1555 can drive on the right side of the lanes between the contactors, from the perspective of the vehicles 1555 (i.e., American driving scheme). In some embodiments, the vehicles 1555 can drive on the left side of the lanes between the contactors, from the perspective of the vehicles 1555 (i.e., British driving scheme).|[0092] FIG. 19 shows a flow diagram of a method 10 of processing trays in a carbonation system, according to an embodiment. As shown, the method 10 includes loading a first caddy onto a loading dock at step 11, transporting a tray from the first caddy at the loading dock to a collection station at step 12, at least partially removing a carbonated medium from the tray at step 13, transporting the tray from the collection station to a filling station at step 14, at least partially filling the tray with a carbonation medium 15, transporting the tray with carbonation medium to a second caddy at an unloading dock at step 16, and optionally an amount of carbonation medium in a tray at step 17.|[0093] Step 11 includes loading the first caddy onto the loading dock. In some embodiments, loading the first caddy onto the loading dock can be via a vehicle. The first caddy can be transported from a contactor system including an array of contactors. Step 12 includes transporting the tray from the first caddy at the loading dock to the collection station. In some embodiments, step 12 can include elevating or lowering the tray via a distributor. In some embodiments, step 12 can include conveying the tray (e.g., via a belt conveyor).|[0094] Step 13 includes at least partially removing the carbonated medium from the tray. In some embodiments, step 13 can include removing all or substantially all of the carbonated medium from the tray. In some embodiments, the carbonated medium can be collected in a trough or a hopper. In some embodiments, the carbonated medium can be transported from the collection station to a silo. In some embodiments, transporting the carbonated medium from the collection station to the silo can be via a conveyor. In some embodiments, the conveyor can include an auger.|[0095] Step 14 transporting the tray from the collection station to the filling station. In some embodiments, step 14 can include elevating or lowering the tray via a distributor. In some embodiments, step 14 can include conveying the tray (e.g., via a belt conveyor). Step 15 includes at least partially filling the tray with a carbonation medium. In some embodiments, the carbonation medium can be dispensed via a dispensation device. In some embodiments, water can be added to the carbonation medium. In some embodiments, water can be added to the carbonation medium at the filling station. In some embodiments, water can be added to the carbonation medium after the tray has left the filling station. In some embodiments, the carbonation medium can be transported to the dispensation device from an auger. In some embodiments, the transportation of the carbonation medium can be via an auger. After the addition of carbonation medium and/or water to the tray, the tray and the carbonation medium can be inspected. The tray can then be accepted and advanced in the process or rejected for recycling or further processing.|[0096] Step 16 includes transporting the tray with the carbonation medium to a second caddy at the unloading dock. In some embodiments, the second caddy can a different caddy from the first caddy. In some embodiments, the second caddy can be the same caddy as the first caddy. In some embodiments, the loading dock can be part of the same structure as the unloading dock. In some embodiments, the loading dock and the unloading dock can be in separate structures.|[0097] Step 17 is optional and includes monitoring the amount of carbonation medium in a tray. In some embodiments, determination of the amount of carbonation medium in a tray can be via weighting the tray. The tray can be weight at a weigh station. In some embodiments, the weigh station can be disposed on a caddy. In some embodiments, the weigh station can be disposed on a tray mover, such that the weight can be determined while the tray is in motion. In some embodiments, the amount of carbonation medium in a tray can be monitored via a visual inspection tool. In some embodiments, the visual inspection tool can be used to measure the fill level and/or the fill uniformity of the carbonation medium in the tray.|[0098] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0099] In addition, the disclosure may include other innovations not presently described.|[0100] Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0101] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0102] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0103] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0104] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0105] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0106] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0107] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0108] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | Family Number|(111695406)|111695406|Advantages / Prev. Drawbacks|(US20240336446 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(WO2024211540 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | Chemical engineering|Civil engineering|Environmental technology|Handling|Other special machines | B01D-053/62|B01D-053/81|B01D-053/96|B01D-2251/402|B01D-2251/404|B01D-2257/504|B65G-065/02|B65G-069/18|F23J-2215/50 | 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(EP4688224)|PENDING|(US20240336446)|PENDING|(WO2024/211540)|PENDING|(CA3288230)|PENDING | ALIVE | (EP4688224)|ALIVE|(US20240336446)|ALIVE|(WO2024/211540)|ALIVE|(CA3288230)|ALIVE | (EP4688224)|LEGAL DETAILS FOR EP4688224|Actual or expected expiration date=2044-04-04|Legal state=ALIVE|Status=PENDING|Event publication date=2024-04-04|Event code=EP/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=EP EP24724340|Application date=2024-04-04|Standardized application number=2024EP-0724340|Event publication date=2024-05-15|Event code=EP/STAAUK|Event group=Administrative notifications|Unknown|Original code: STAA|Event publication date=2024-10-12|Event code=EP/STAAPCT|Event group=Examination events Entry into national phase|The international publication has been made|Original code: STAA|Event publication date=2026-01-09|Event code=EP/PUAI|Event group=Administrative notifications|PUBLIC REFERENCE MADE UNDER ARTICLE 153(3) EPC TO A PUBLISHED 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events|Case Docketed to Examiner|(WO2024/211540)|LEGAL DETAILS FOR WO2024/211540|Actual or expected expiration date=2026-10-05|Legal state=ALIVE|Status=PENDING|Event publication date=2024-04-04|Event code=WO/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=WO WOUS2024/023029|Application date=2024-04-04|Standardized application number=2024WO-US23029|Event publication date=2024-10-10|Event code=WO/A1|Event group=Examination events|Published application with search report|Publication country=WO|Publication number=WO2024/211540|Publication stage code=A1|Publication date=2024-10-10|Standardized publication number=WO2024211540|MEMBER STATE LEGAL DETAILS FOR CA3288230|Actual or expected expiration date=2044-04-04|Legal state=ALIVE|Status=PENDING|Corresponding cc:|Designated or member state=CA Corresponding appl: CA3288230|Application date in the designated or member state=2024-04-04|Application number in the designated or member state=2024CA-3288230|Corresponding cc:|Designated or member state=CA Corresponding pat: CA3288230|Publication stage code in the designated or member state=A1|Publication date in the designated or member state=2024-10-10|Publication number in the designated or member state=CA3288230|MEMBER STATE LEGAL DETAILS FOR DE|Actual or expected expiration date=2025-11-06|Legal state=DEAD|Status=LAPSED|Corresponding cc:|Designated or member state=DE|Event publication date=2025-11-06|Event code=WO/NENP|Event group=Event indicating Not In Force|Non-entry into the national phase|Corresponding cc:|Designated or member state=DE|MEMBER STATE LEGAL DETAILS FOR EP4688224|Actual or expected expiration date=2044-04-04|Legal state=ALIVE|Status=PENDING|Corresponding cc:|Designated or member state=EP Corresponding appl: EP24724340|Application date in the designated or member state=2024-04-04|Application number in the designated or member state=2024EP-0724340|Corresponding cc:|Designated or member state=EP Corresponding pat: EP4688224|Publication stage code in the designated or member state=A1|Publication date in the designated or member state=2026-02-11|Publication number in the designated or member state=EP4688224|Event publication date=2024-11-20|Event code=WO/121|Event group=Designated states|EP: The EPO has been informed by wipo that ep was designated in this application|Corresponding cc:|Designated or member state=EP|Event publication date=2025-11-05|Event code=WO/WWE|Event indicator=Pos|Event group=Entry into national phase|Wipo information: entry into national phase|Corresponding cc:|Designated or member state=EP|Event publication date=2025-11-16|Event code=WO/ENP|Event group=Entry into national phase|Entry into the national phase|Effective date of the event=2025-11-05|Corresponding cc:|Designated or member state=EP|Event publication date=2025-11-23|Event code=WO/ENP|Event group=Entry into national phase|Entry into the national phase|Effective date of the 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national phase|Effective date of the event=2025-11-05|Corresponding cc:|Designated or member state=EP|Event publication date=2026-01-04|Event code=WO/ENP|Event group=Entry into national phase|Entry into the national phase|Effective date of the event=2025-11-05|Corresponding cc:|Designated or member state=EP|Event publication date=2026-02-11|Event code=WO/WWP|Event indicator=Pos|Event group=Examination events|Wipo information: published in national office|Corresponding cc:|Designated or member state=EP|(CA3288230)|LEGAL DETAILS FOR CA3288230|Actual or expected expiration date=2044-04-04|Legal state=ALIVE|Status=PENDING|Event publication date=2024-04-04|Event code=CA/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CA CA3288230|Application date=2024-04-04|Standardized application number=2024CA-3288230|Event publication date=2024-10-10|Event code=CA/A1|Event group=Examination events|Application laid open|Publication country=CA|Publication number=CA3288230|Publication stage code=A1|Publication date=2024-10-10|Standardized publication number=CA3288230 | (EP4688224)|Contracting States: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, ME, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, LI, RO, NL, TR|(EP4688224)|Extension States: BA|(EP4688224)|Validation States: MA, MD, TN, KH, GE|(WO2024/211540)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2024/211540)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2024/211540)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, ME, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2024/211540)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2024/211540)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IQ, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, JM, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, CV, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, MG, EC, MK, US, EE, MN, EG, UZ, MU, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4688224)|EP|(US20240336446)|US|(WO2024/211540)|WO; CA; EP|(CA3288230)|CA | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=iCBy9VOVqJWOI4yZSKYV2qCa4vFyxJplNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000022268085&ekey=2305&xpn=EP4688224&kind=A1 | https://register.epo.org/application?number=EP24724340 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=Ytdr8geZxpL4%252BC%252F5M6pym3fDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2024/211540)|US|(US20240336446)|US | (WO2024/211540)|NAME=HEIRLOOM CARBON TECHNOLOGIES, INC. 125 Valley Drive Brisbane, California 94005 , COUNTRY=US|(US20240336446)|NAME=Heirloom Carbon Technologies, Inc. , CITY=Brisbane , STATE=CA , COUNTRY=US | (EP4688224)|GB|(WO2024/211540)|US|(CA3288230)|CA | (EP4688224)|NAME=Cooley (UK) LLP 22 Bishopsgate , CITY=London EC2N 4BQ , COUNTRY=GB , REG=101544956|(WO2024/211540)|NAME=HILTON, Ramsey Mitchell et al. Cooley LLP ATTN: IP Docketing Department 1299 Pennsylvania Avenue NW Suite 700 Washington, District of Columbia 20004 , POSTCODE=20004 , COUNTRY=US|(CA3288230)|NAME=Borden Ladner Gervais LLP 100 Queen Street, Suite 1300 , CITY=ottawa , POSTCODE=K1P 1J9 , COUNTRY=CA | (EP4688224)|US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US|(US20240336446)|US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US|(WO2024/211540)|US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US|(CA3288230)|US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US; US | (EP4688224)|NAME=MAI, Rocky, CITY=San Mateo, California 94402, COUNTRY=US |NAME=GARNIER, Hunter, CITY=San Bruno, California 94066, COUNTRY=US |NAME=GUEBLE, Isabel, CITY=Sunnyvale, California 94089, COUNTRY=US |NAME=KARR, Charles, CITY=San Francisco, California 94127, COUNTRY=US |NAME=PEDERSEN, Kristen, CITY=San Francisco, California 94122, COUNTRY=US |NAME=PAUL-GIN, Noah, CITY=San Francisco, California 94122, COUNTRY=US |NAME=LIU, Roufei, CITY=San Jose, California 95133, COUNTRY=US |NAME=NASSAR, Maryam, CITY=Sacramento, California 95835, COUNTRY=US |NAME=ELAHI, Shazib, CITY=Fremont, California 94539, COUNTRY=US |NAME=DRENNAN, David, CITY=Springfield, New Hampshire 03284, COUNTRY=US |NAME=MANEM, Tejas, CITY=San Bruno, California 94066, COUNTRY=US |NAME=SANCHEZ, Hugo, CITY=San Bruno, California 94066, COUNTRY=US |NAME=MILLS, Jennifer, CITY=San Leandro, California 94577, COUNTRY=US |NAME=DUNCAN, Robert, CITY=San Francisco, California 94110, COUNTRY=US |NAME=KANE, Margaret, CITY=Mountain View, California 94043, COUNTRY=US |NAME=DUBEL, Andrew, CITY=Moss Beach, California 94038, COUNTRY=US |NAME=MCQUEEN, Noah, CITY=San Francisco, California 94107, COUNTRY=US |NAME=CUSON, Mark, CITY=Brisbane, California 94005, COUNTRY=US|(US20240336446)|NAME=MAI Rocky, CITY=San Mateo, STATE=CA , COUNTRY=US |NAME=GARNIER Hunter, CITY=San Bruno, STATE=CA , COUNTRY=US |NAME=GUEBLE Isabel, CITY=Sunnyvale, STATE=CA , COUNTRY=US |NAME=KARR Charlie, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=PEDERSEN Kristen, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=PAUL-GIN Noah, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=LIU Ruofei, CITY=San Jose, STATE=CA , COUNTRY=US |NAME=NASSAR Maryam, CITY=Sacramento, STATE=CA , COUNTRY=US |NAME=ELAHI Shazib, CITY=Fremont, STATE=CA , COUNTRY=US |NAME=DRENNAN David, CITY=Springfield, STATE=NH , COUNTRY=US |NAME=MANEM Tejas, CITY=San Bruno, STATE=CA , COUNTRY=US |NAME=SANCHEZ Hugo, CITY=San Bruno, STATE=CA , COUNTRY=US |NAME=MILLS Jennifer, CITY=San Leandro, STATE=CA , COUNTRY=US |NAME=DUNCAN Robert, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=KANE Margaret, CITY=Mountain View, STATE=CA , COUNTRY=US |NAME=DUBEL Andy, CITY=Moss Beach, STATE=CA , COUNTRY=US |NAME=MCQUEEN Noah, CITY=San Francisco, STATE=CA , COUNTRY=US|(WO2024/211540)|NAME=MAI, Rocky 636 Birch Ave San Mateo, California 94402, POSTCODE=94402, COUNTRY=US |NAME=GARNIER, Hunter 5 Pacific Bay Cir, Apt 102 San Bruno, California 94066, POSTCODE=94066, COUNTRY=US |NAME=GUEBLE, Isabel 416 Paria Ter Sunnyvale, California 94089, POSTCODE=94089, COUNTRY=US |NAME=KARR, Charlie 189 Marietta Dr. San Francisco, California 94127, POSTCODE=94127, COUNTRY=US |NAME=PEDERSEN, Kristen 1279 8th Ave, Apt 206 San Francisco, California 94122, POSTCODE=94122, COUNTRY=US |NAME=PAUL-GIN, Noah 1458 Funston Ave San Francisco, California 94122, POSTCODE=94122, COUNTRY=US |NAME=LIU, Roufei 1056 Vanilla Walkway San Jose, California 95133, POSTCODE=95133, COUNTRY=US |NAME=NASSAR, Maryam 2517 Cantara Way Sacramento, California 95835, POSTCODE=95835, COUNTRY=US |NAME=ELAHI, Shazib 2265 Ocaso Camino Fremont, California 94539, POSTCODE=94539, COUNTRY=US |NAME=DRENNAN, David 94 Shore Dr. Springfield, New Hampshire 03284, POSTCODE=03284, COUNTRY=US |NAME=MANEM, Tejas 2681 Rollingwood Dr San Bruno, California 94066, POSTCODE=94066, COUNTRY=US |NAME=SANCHEZ, Hugo 3815 Susan Dr., Apt E4 San Bruno, California 94066, POSTCODE=94066, COUNTRY=US |NAME=MILLS, Jennifer 270 Oakes Blvd San Leandro, California 94577, POSTCODE=94577, COUNTRY=US |NAME=DUNCAN, Robert 319 Banks St San Francisco, California 94110, POSTCODE=94110, COUNTRY=US |NAME=KANE, Margaret 165 Sherland Ave Mountain View, California 94043, POSTCODE=94043, COUNTRY=US |NAME=DUBEL, Andy 633 Lancaster Blvd Moss Beach, California 94038, POSTCODE=94038, COUNTRY=US |NAME=MCQUEEN, Noah 2660 3rd St., Unit 426 San Francisco, California 94107, POSTCODE=94107, COUNTRY=US|(CA3288230)|NAME=MAI Rocky 636 Birch Ave, CITY=San Mateo, POSTCODE=94402, STATE=CA , COUNTRY=US |NAME=GARNIER Hunter 5 Pacific Bay Cir, Apt 102 San Bruno, California 94066, POSTCODE=94066, COUNTRY=US |NAME=GUEBLE Isabel 416 Paria Ter Sunnyvale, California 94089, POSTCODE=94089, COUNTRY=US |NAME=KARR Charles 189 Marietta Dr. San Francisco, California 94127, POSTCODE=94127, COUNTRY=US |NAME=PEDERSEN Kristen 1279 8th Ave, Apt 206 San Francisco, California 94122, POSTCODE=94122, COUNTRY=US |NAME=PAUL-GIN Noah 1458 Funston Ave San Francisco, California 94122, POSTCODE=94122, COUNTRY=US |NAME=LIU Roufei 1056 Vanilla Walkway San Jose, California 95133, POSTCODE=95133, COUNTRY=US |NAME=NASSAR Maryam 2517 Cantara Way Sacramento, California 95835, POSTCODE=95835, COUNTRY=US |NAME=ELAHI Shazib 2265 Ocaso Camino Fremont, California 94539, POSTCODE=94539, COUNTRY=US |NAME=DRENNAN David 94 Shore Dr. Springfield, New Hampshire 03284, POSTCODE=03284, COUNTRY=US |NAME=MANEM Tejas 2681 Rollingwood Dr San Bruno, California 94066, POSTCODE=94066, COUNTRY=US |NAME=SANCHEZ Hugo 3815 Susan Dr., Apt E4 San Bruno, California 94066, POSTCODE=94066, COUNTRY=US |NAME=MILLS Jennifer 270 Oakes Blvd San Leandro, California 94577, POSTCODE=94577, COUNTRY=US |NAME=DUNCAN Robert 319 Banks St San Francisco, California 94110, POSTCODE=94110, COUNTRY=US |NAME=KANE Margaret 165 Sherland Ave Mountain View, California 94043, POSTCODE=94043, COUNTRY=US |NAME=DUBEL Andrew 633 Lancaster Blvd Moss Beach, California 94038, POSTCODE=94038, COUNTRY=US |NAME=MCQUEEN Noah 2660 3rd St., Unit 426 San Francisco, California 94107, POSTCODE=94107, COUNTRY=US |NAME=CUSON Mark c/o Heirloom Carbon Technologies, Inc. 125 Valley Drive Brisbane, California 94005, COUNTRY=US | (WO2024/211540)|19|(US20240336446)|19 | 3 | 4 | (EP4688224)|WO2024/211540|(CA3288230)|WO2024/211540 | (US20240336446)|Number of Claims: NCL=22|Number of Drawings: NDR=23|Number of Figures: NFG=23|Independent Claim Number: ICL=35,51|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=35||(WO2024/211540)|Number of Claims: NCL=34|Extended kind: EXTK=x| | (US20240336446)|Provisional Appl: US63/494,285 FDD=2023-04-05 [2023US-63494285] | (EP4688224)|ENGLISH (ENG) | (EP4688224)|Patent|(CA3288230)|Patent|(US20240336446)|Patent|(WO2024211540)|Patent | Titre: (EP4688224)|Tray processing units for carbon capture and removal systems, and methods of operating the same Résumé: (EP4688224)|Embodiments described herein relate to tray processing units for processing CO2 capture media. In some aspects a tray processing unit can include a loading dock configured to receive a caddy including trays disposed thereon, a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays, a filling station configured to transfer a carbonation medium to the trays, a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station, an unloading dock configured to support the caddy while loading the caddy with trays, a second tray mover configured to transport trays from the collection station to the filling station, and a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock. Autre: (US20240336446)|1-34. (canceled)|35. A tray processing unit (TPU), comprising:| a loading dock configured to receive a caddy including trays disposed thereon;| a collection station configured to receive trays from the loading dock and collect a carbonated medium from the trays;| a filling station configured to transfer a carbonation medium to the trays;| a first tray mover configured to transport the trays from the caddy at the loading dock to the collection station;| an unloading dock configured to support the caddy while loading the caddy with trays;| a second tray mover configured to transport trays from the collection station to the filling station; and| a third tray mover configured to transport trays from the filling station to the caddy supported by the unloading dock.|36. The TPU of claim 35, further comprising:| an unloader configured to transport trays from the loading dock to the collection station, the unloader configured to move vertically to select a vertical placement position of the trays in the caddy.|37. The TPU of claim 36, further comprising:| a loader configured to transport trays from the second tray mover to the caddy at the unloading dock.|38. The TPU of claim 35, further comprising:| a first vehicle configured to transport the caddy between the unloading dock and a carbonation contactor.|39. The TPU of claim 35, wherein the collection station includes a tray enclosure and a trough, the tray enclosure configured to manipulate the trays, such that the carbonated medium falls from the tray to the trough.|40. The TPU of claim 39, wherein manipulating the trays includes at least one of rotating, applying a vacuum, vibrating, stirring, or applying ultrasonic waves to the trays.|41. The TPU of claim 39, further comprising:| a silo in communication with the trough;| a conveyor configured to transport carbonated medium from the trough to the silo; and| a vacuum configured to reduce pressure inside the silo and draw carbonated medium into the silo.|42. The TPU of claim 41, wherein the conveyor includes an auger.|43. The TPU of claim 41, wherein the conveyor includes a pneumatic conveyor.|44. The TPU of claim 35, wherein the filling station includes a spraying apparatus configured to wet the carbonation medium.|45. The TPU of claim 35, wherein the first tray mover and the second tray mover include actuated end effector pins configured to move the trays.|46. The TPU of claim 35, wherein the unloading dock includes a roller configured to transfer the caddy from the unloading dock to a vehicle.|47. The TPU of claim 38, wherein the first vehicle includes a lifter module configured to dock and undock caddies to the loading dock and from the unloading dock.|48. The TPU of claim 47, wherein the unloading dock includes a locating pin configured to actuate to lock the caddy in place.|49. The TPU of claim 35, further comprising:| a weigh station configured to weigh the trays.|50. The TPU of claim 35, further comprising:| an inspection tool configured to measure an amount of at least one of carbonation medium or carbonated medium in a tray.|51. A method, comprising:| loading a first caddy onto a loading dock, the first caddy including a tray, the tray including a carbonated medium;| transporting the tray from the first caddy at the loading dock to a collection station;| at the collection station, at least partially removing the carbonated medium from the tray;| transporting the tray from the collection station to a filling station;| at the filling station, at least partially filling the tray with a carbonation medium; and| transporting the tray with the carbonation medium to a second caddy at an unloading dock.|52. The method of claim 51, wherein the tray is selected based on the carbonation extent of the carbonated medium included therein.|53. The method of claim 51, further comprising:| transporting the second caddy from the unloading dock to a carbonation contactor via a vehicle.|54. The method of claim 51, further comprising:| transporting the first caddy from a carbonation contactor to the loading dock.|55. The method of claim 51, further comprising:| spraying water onto the carbonation medium at the filling station and/or after the tray has exited the filling station.|56. The method of claim 51, further comprising:| vertically translating the tray to place the tray in the second caddy. | 11 | Abstract | gpt-4o-mini | no | The article focuses on tray processing units for CO2 capture media, without any mention of biomass energy production or carbon storage, which are central to BECCS. | |||||||||||||||||
| 12 | KR20230037657 | KR10-2023-0037657 | KR10-2769477|KR10-2024-0142963 | 111691506 | KR10-2769477 B1 2025-02-17 [KR102769477]|KR10-2024-0142963 A 2024-10-02 [KR20240142963] | 2023-03-23 | 2023-03-23 | 2025-02-17|2024-10-02 | (KR102769477)|2025-02-17 | (KR10-2769477)|2043-03-23 | (KR10-2769477)|Transaction service system and method using carbon reduction information | (KR10-2769477)|Disclosed are a transaction service system using carbon reduction information and a method thereof. The present invention connects a purchaser and a low carbon emission seller who sells an environmental product to share information and knowledge based on carbon reduction activities, and converts points of the purchaser generated according to the transaction of the environmental product into stocks of the low carbon emission seller to perform the transaction.COPYRIGHT MOIP 2025 | MOON, Yoo Jung | (KR10-2769477)|MOON, Yoo Jung ([KR])|(KR10-2024-0142963)|MOON, Yoo Jung ([KR]) | MOON YU JUNG|SEO JAE KWAN | (KR10-2769477)|MOON, Yoo Jung|SEO, Jaekwan|(KR10-2024-0142963)|MOON, YU JUNG|SEO JAE KWAN | (KR10-2769477)|WOO, KWANG-JE | (KR10-2769477)|The present invention has the advantage of sharing information and knowledge based on a carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and converting the point of the buyer generated according to the transaction of the environmental product into the stock of the low-carbon emission seller to transact.In addition, the present invention has the advantage of increasing carbon emission reduction activities through the environmental product transaction in the corresponding area by managing the environmental product transaction between the buyer and the seller in the same area.|Here, the activity information and knowledge information related to low carbon emission and carbon reduction may include ESG management report information, and may be ESG management effort introduced or promoted in a production facility of a seller or a listed company in stages, selection information on green consumers, assembly business information for greenhouse gas reduction, bioenergy with carbon capture and storage (BECCS), and technology information related to Carbon Dioide Removal (CDR.).|However, there is a problem in that individuals or general consumers cannot voluntarily enter the carbon transaction market of eco-friendly product development companies or low-carbon emission companies due to lack of connectivity with eco-friendly product development companies.| | (KR10-2769477)|1. A seller terminal (210) comprising: a buyer management unit (210) for managing subscription information including local information of a buyer, authentication information, transaction information of an environmental product, purchaser points accumulation according to transactions of the environmental product, and accumulated transactions of the purchaser points, while forming communication between the buyers and sellers who need carbon emission trading and setting the purchaser points as investment money to perform stock investment trading based on low-carbon emission seller information inputted from each purchaser terminal (100, 100a, 100n); a seller management unit (220) for managing environmental product information including local information of a low-carbon emission seller inputted from each seller terminal (300, 300a, 300n), authentication information, and storytelling information of the seller, wherein the storytelling information is information for the seller to deliver a process for production, sale, management, and distribution of the environmental product to the buyer; transaction information of the environmental product; carbon reduction activity information and carbon knowledge reduction information of the low-carbon emission seller; and a seller terminal (300, 300a, 300n) for managing transactions of the environmental product between the purchaser terminal (100, 100a, 100n) and the seller terminal (300, 100a, 100n), and having the same local information of the buyer terminal (100, 100a, 100n, 300a, 30, 300n) A transaction service system using carbon reduction information, comprising: a shopping mall management unit 230 configured to first provide an environmental product of the terminal 300 (300a to 300n) to the buyer terminal 100 (100a to 100n) to manage carbon emissions reduction through the environmental product transaction of a corresponding region; a community management unit 240 configured to collect activity information and knowledge information of a seller related to low carbon emissions and carbon reductions from the seller terminal 300 (300a to 300n), analyze the collected activity information and knowledge information for each low carbon emission seller and carbon reduction technology based on the carbon reduction-related activity information and knowledge information of the seller, and manage the analyzed information to be shared with the buyer terminal 100 (100a to 100n); and a management server 200 including a database 250 configured to store management information of the buyer management unit 210, the seller management unit 220, the shopping mall management unit 230, and the community management unit 240.|2. AMENDSTATUS: Delete|3. AMENDSTATUS: Delete|6. AMENDSTATUS: Delete|8. A) a step in which the management server 200 collects activity information and knowledge information of a seller related to low carbon emission and carbon reduction from the seller terminals 300, 100a, and 100n, collects activity information and knowledge information of the seller related to the low carbon emission and carbon reduction from the seller terminals 300, 300a, and 300n, and analyzes the collected activity information and knowledge information related to carbon reduction of the seller for each low carbon emission seller and carbon reduction technology on the basis of the collected activity information and knowledge information related to carbon reduction of the seller to manage the low carbon emission seller and the low carbon reduction technology to be shared with the buyer terminals 100, 300a, and 300n, and b) a step in which the management server 200 manages an environmental transaction between the buyer terminals 100, 100a, and 100n and the seller terminals 300, 100a, and 100n, searches for a seller terminal 300, 300a, and 300n having the same regional information on the basis of regional information of the buyer terminals 100, 100a, and 100n, and provides the searched environmental product to the buyer terminals 100, 300a, 300n, 300a, and 300n to preferentially manage the environmental transaction between the buyer terminals 100, 300, and 100a A transaction service method using carbon reduction information, comprising: managing so that carbon emissions are reduced through local environmental product transactions and determining whether a buyer point is generated by a certain buyer terminal 100(100n to 100a) performing a transaction of an environmental product with one or more seller terminals 300(100n to 300a); and managing so that individual buyer points generated by the management server 200 according to generation of a buyer point through the transaction of the environmental product are accumulated, the accumulated buyer points are set as investments to form communication between buyers and sellers who need a carbon emission right transaction, and stock investment transactions are performed based on low-carbon emission seller information input from each buyer terminal 100(300n to 100a 100n).|9. AMENDSTATUS: Delete|10. AMENDSTATUS: Delete|11. AMENDSTATUS: Delete|12. AMENDSTATUS: Delete|13. AMENDSTATUS: Delete| | (KR10-2769477)|In order to solve the above problems, the present invention is directed to providing a transaction service system and method using carbon reduction information, which may share information and knowledge based on carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and convert points of the buyer generated according to transactions of the environmental product into stocks of the low-carbon emission seller to perform transactions.|The present invention relates to a transaction service system and method using carbon reduction information, and more particularly, to a transaction service system and method using carbon reduction information, in which a buyer and a low-carbon emission seller who sells an environmental product are connected to share information and knowledge on the basis of carbon reduction activities, and points of the buyer generated by transactions of the environmental product are converted into shares of the low-carbon emission seller for transactions.| | (KR10-2769477)|MANAGEMENT SERVER(100,66)|SELLER(100,51)|BUYER TERMINAL(100,43)|CARBON REDUCTION(100,43)|LOW CARBON EMISSION SELLER(100,41)|SELLER TERMINAL(100,35)|LOW CARBON EMISSION(100,34)|CARBON REDUCTION INFORMATION(100,27)|KNOWLEDGE INFORMATION(100,24)|SELLER KNOWLEDGE INFORMATION(100,11)|INFORMATION REGION(100,10)|TRANSACTION(100,10)|AMENDSTATUS(100,8)|TRANSACTION SERVICE(100,8)|BUYER TERMINAL INFORMATION(100,4)|COLLECTION(100,4)|COLLECTION ACTIVITY INFORMATION(100,3)|SELLER CARBON REDUCTION(100,2)|LOW CARBON REDUCTION(100,1)|SEARCHED ENVIRONMENTAL PRODUCT(100,1)|SELLER MANAGEMENT(78,17)|BUYER MANAGEMENT(73,9)|BUYER(71,67)|STOCK INVESTMENT TRANSACTION(71,13)|SHOPPING MALL MANAGEMENT(64,11)|SELLER STORY TELLING INFORMATION(58,8)|STORY TELLING INFORMATION(56,13)|BUYER MANAGEMENT INFORMATION(50,1)|PURCHASER TERMINAL(49,14)|AUTHENTICATION INFORMATION(48,14)|TRANSACTION MANAGEMENT(47,3)|PURCHASER POINT ACCUMULATED TRANSACTION(47,1)|INVESTMENT MONEY(46,3)|TRANSACTION INFORMATION(45,14)|ACCUMULATED TRANSACTION(42,4)|GREEN CONSUMER(41,1)|MANAGEMENT EFFORT(41,1)|MANAGING SUBSCRIPTION INFORMATION(39,5)|CARBON TRANSACTION(38,1)|PURCHASE(35,11)|STOCK INVESTMENT(35,7)|KNOWLEDGE(35,6)|ACTIVITY INFORMATION(34,10)|ANALYZING INFORMATION(34,1)|COMMUNITY MANAGEMENT(33,14)|RIGHT TRANSACTION(33,1)|SELLER INFORMATION(32,16)|ESG MANAGEMENT REPORT INFORMATION(32,2)|ECO FRIENDLY PRODUCT DEVELOPMENT(30,2)|SHARING INFORMATION(30,1)|BUYER POINT(29,18)|ECO FRIENDLY(28,5)|BUYER POINT GENERATION(28,1)|CARBON EMISSION RIGHT TRANSACTION(28,1)|CONSUMER(28,1)|PRODUCT TRANSACTION(27,38)|SELLER PRODUCTION FACILITY(27,2)|BIOENERGY(27,1)|CARBON DIODE REMOVAL(27,1)|CONNECTIVITY(27,1)|INVESTMENT(26,6)|CARBON EMISSION(26,5)|CARBON KNOWLEDGE REDUCTION INFORMATION(26,1)|PURCHASE POINT(26,1)|STOCK INVESTMENT INFORMATION(25,2)|TRANSACTION SERVICE SYSTEM(23,14)|SELECTION INFORMATION(22,1)|ACCUMULATED BUYER POINT(21,7)|CARBON EMISSION REDUCTION(21,7)|SELLER INFORMATION INPUT(21,4)|MANAGEMENT REPORT INFORMATION(20,2)|TECHNOLOGY INFORMATION(19,2)|DATABASE(18,13)|SHARE(18,1)|SELLER AUTHENTICATION(17,4)|BUYER REGION INFORMATION(17,2)|BUYER INFORMATION MANAGEMENT(16,3)|SELLER INPUT(15,8)|SELLER INFORMATION MANAGEMENT(15,5)|SALE(15,3)|SHOPPING MALL WEBPAGE(15,3)|STOCK(15,3)|STOCK INVESTMENT PRODUCT(14,5)|BECCS(14,4)|DELIVER(14,2)|PRODUCT DEVELOPMENT(14,2)|BUYER STOCK INVESTMENT TRANSACTION(14,1)|CARBON CAPTURE(14,1)|CARBON REDUCTION KNOWLEDGE INFORMATION(13,17)|CARBON EMISSION TRADING(13,12)|MANAGING PURCHASE(13,3)|CARBON REDUCTION ACTIVITY INFORMATION(12,25)|COLLECTED CARBON REDUCTION INFORMATION(12,3)|LISTED COMPANY(12,3)|PRODUCTION FACILITY(12,2)|LOW CARBON EMISSION COMPANY(12,1)|PRODUCT INFORMATION MANAGEMENT(11,6)|ARBITRARY STORY TELLING INFORMATION(11,2)|ECO FRIENDLY COMMUNITY(11,2)|SEARCHED SELLER PRODUCT(11,2)|BUYER ACCUMULATED TRANSACTION(11,1)|PURCHASER ACCUMULATED TRANSACTION(11,1)|SELLER TERMINAL N(10,10)|BUYER TERMINAL N(10,9)|ANALYSIS INFORMATION MANAGEMENT(10,5)|MANAGEMENT INFORMATION(10,4)|BUYER POINT INFORMATION(10,2)|BUSINESS INFORMATION(9,4)|ENVIRONMENT PRODUCT TRANSACTION(9,4)|ESG MANAGEMENT EFFORT(9,1)|PURCHASER AUTHENTICATION TERMINAL(9,1)|SELLER VOLUNTARY(9,1)|SHOPPING MALL WEBSITE(9,1)|WEATHER ANOMALY(9,1)|BUYER COLLECTING INFORMATION(8,2)|FACILITY INVESTMENT INFORMATION(8,2)|VOLUNTARY CARBON EMISSION TRADING(7,3)|FINANCE COMPANY SERVER(7,1)|LIVESTOCK BUSINESS OPERATOR(7,1)|MANAGEMENT SERVER COLLECTION(7,1)|MANAGEMENT SERVER SEARCH(7,1)|MANDATORY COUNTRY(7,1)|PRODUCT STOCK INVESTMENT TRANSACTION(7,1)|PURCHASER ACCUMULATION(7,1)|GREENHOUSE GAS REDUCTION(6,4)|TECHNICAL GIST(6,2)|BUYER ACCUMULATION INFORMATION(6,1)|COLLECT BUYER(6,1)|PUBLIC INSTITUTION(6,1)|CARBON REDUCTION INFORMATION COLLECTION(5,6)|ELECTRONIC COMMERCE(5,5)|POINT INFORMATION MANAGEMENT(5,5)|RECYCLED PRODUCT(5,3)|STOCK INFORMATION(5,3)|PURCHASER INPUT(5,2)|ENTERPRISE LIST(5,1)|MANAGEMENT SERVER COLLECT INFORMATION(5,1)|PURCHASER USAGE INFORMATION(5,1)|SEARCHED SELLER ENVIRONMENT PRODUCT(5,1)|SEARCHED SELLER TERMINAL PRODUCT(5,1)|SELLER ACTIVITY INFORMATION(5,1)|SHOPPING MALL WEB PAGE(5,1)|CARBON REDUCTION INFORMATION ANALYSIS(4,6)|COMMISSION(4,2)|ECO FRIENDLY PRODUCT(4,2)|ESG MANAGEMENT INFORMATION(4,2)|LIVESTOCK PRODUCTION(4,2)|LOGIN INFORMATION INPUT(4,2)|PURCHASE INFORMATION MANAGEMENT(4,2)|PURCHASER TERMINAL N(4,2)|SINGULAR(4,2)|ACCUMULATED BUYER POINT TRANSACTION(4,1)|ACCUMULATED POINT ENCASHMENT(4,1)|ACCUMULATED PURCHASER POINT TRANSACTION(4,1)|BUYER POINT ACCUMULATED TRANSACTION(4,1)|BUYER REGIONAL INFORMATION INPUT(4,1)|CARBON CREDIT TRANSACTION(4,1)|CARBON EMISSION QUOTA(4,1)|ENVIRONMENT PROTECTION(4,1)|GREENHOUSE GAS EMISSION QUOTA(4,1)|NATURE DESTRUCTION(4,1)|RECEIVED STORY TELLING INFORMATION(4,1)|RELAYING CARBON EMISSIONS TRADING(4,1)||(KR10-2024-0142963)|MANAGEMENT SERVER(100,79)|CARBON REDUCTION INFORMATION(100,35)|TRANSACTION SERVICE SYSTEM(100,14)|TRANSACTION(100,10)|STOCK TRADING(100,2)|CARBON INVESTMENT TRANSACTION INFORMATION(100,1)|STOCK TRANSACTION(73,2)|SELLER MANAGEMENT(67,18)|PURCHASE(66,68)|STOCK INVESTMENT TRANSACTION(66,14)|PURCHASER TERMINAL(65,46)|STORY TELLING INFORMATION(65,16)|BUYER ACCUMULATION(62,1)|PURCHASER ACCUMULATED TRADING(60,1)|SELLER TERMINAL(57,32)|SELLER STORY TELLING INFORMATION(55,9)|BUYER(54,21)|TRANSACTION MANAGEMENT(48,2)|SELLER AUTHENTICATION(47,6)|SELLER(44,53)|LOW CARBON EMISSION SELLER(44,45)|SHOPPING MALL MANAGEMENT(43,11)|SEARCHED SELLER TERMINAL PRODUCT(43,2)|MANAGING PURCHASE(42,9)|SHOPPING MALL WEBPAGE(38,2)|AUTHENTICATION INFORMATION(36,14)|INFORMATION REGION(36,8)|PURCHASER AUTHENTICATION TERMINAL(36,2)|ACCUMULATING SUBSCRIPTION INFORMATION(35,1)|SELLER INFORMATION(34,16)|CARBON REDUCTION KNOWLEDGE INFORMATION(33,26)|PRODUCT TRADE(33,4)|PURCHASER REGION INFORMATION(31,4)|SELLER INPUT(30,10)|ECO FRIENDLY(30,3)|BUYER POINT(29,6)|ACCUMULATED ENVIRONMENTAL PRODUCT TRANSACTION(29,1)|ECO FRIENDLY PRODUCT DEVELOPMENT(28,2)|MANAGING SUBSCRIPTION INFORMATION(27,2)|CONSUMER(26,1)|PURCHASE POINT(25,19)|KNOWLEDGE(25,6)|TRADE INFORMATION(25,2)|ACCUMULATING INDIVIDUAL BUYER POINT(25,1)|CONNECTIVITY(25,1)|PURCHASER POINT ACCUMULATED TRADE(22,1)|CARBON REDUCTION ACTIVITY INFORMATION(21,31)|ACCUMULATED PURCHASER POINT(20,7)|COMMUNITY MANAGEMENT INFORMATION(20,1)|COMMUNITY MANAGEMENT(19,13)|INFORMATION INPUT(19,1)|CARBON TRADING(18,1)|CARBON REDUCTION(17,39)|LOGIN INFORMATION INPUT(17,1)|TRANSACT POINT(17,1)|SELLER KNOWLEDGE INFORMATION(14,7)|PURCHASE INFORMATION MANAGEMENT(14,5)|SELLER INFORMATION MANAGEMENT(14,5)|TRADING SERVICE SYSTEM(14,3)|LOW CARBON EMISSION(13,36)|DATABASE(13,13)|PURCHASE POINT INFORMATION(13,6)|SELLER INFORMATION INPUT(13,4)|STOCK INVESTMENT PRODUCT(13,4)|PRODUCT DEVELOPMENT(13,2)|BUYER STOCK INVESTMENT TRANSACTION(13,1)|COLLECTED CARBON REDUCTION INFORMATION(12,7)|CARBON EMISSION REDUCTION(12,6)|SETTING INFORMATION INPUT(12,4)|INVESTMENT MONEY(12,3)|SEARCHED SELLER PRODUCT(12,3)|ESG MANAGEMENT EFFORT(12,2)|LOW CARBON EMISSION COMPANY(11,1)|PURCHASER TERMINAL N(10,10)|BUYER TERMINAL(10,6)|ARBITRARY STORY TELLING INFORMATION(10,2)|ECO FRIENDLY COMMUNITY(10,2)|PURCHASER ACCUMULATED TRANSACTION(10,1)|SELLER TERMINAL N(9,9)|ANALYSIS INFORMATION MANAGEMENT(9,5)|INFORMATION RECEPTION(9,3)|SHOPPING MALL WEB PAGE(9,3)|ECO FRIENDLY EXPERIENCE(9,2)|ANALYZED RESULT(9,1)|SELLER VOLUNTARY(8,1)|SHOPPING MALL WEBSITE(8,1)|WEATHER ANOMALY(8,1)|PRODUCT TRANSACTION(7,31)|ESG MANAGEMENT REPORT INFORMATION(7,2)|FACILITY INVESTMENT INFORMATION(7,2)|PURCHASER COLLECTING INFORMATION(7,2)|FINANCE COMPANY SERVER(7,1)|LIVESTOCK BUSINESS OPERATOR(7,1)|MANDATORY COUNTRY(7,1)|NTH SELLER TERMINAL(7,1)|PRODUCT STOCK INVESTMENT TRANSACTION(7,1)|SELLER STOCK(7,1)|PRODUCT INFORMATION MANAGEMENT(6,7)|PURCHASER INPUT(6,3)|USER SETTING INFORMATION INPUT(6,3)|ENVIRONMENT PRODUCT TRANSACTION(6,2)|PURCHASER POINT ACCUMULATED TRANSACTION(6,2)|SELLER PRODUCTION FACILITY(6,2)|TECHNICAL GIST(6,2)|VOLUNTARY CARBON EMISSION TRADING(6,2)|ARBITRARY POWER PURCHASE TERMINAL(6,1)|CARBON CREDIT TRADING RELAY(6,1)|PUBLIC INSTITUTION(6,1)|PURCHASER ACCUMULATION INFORMATION(6,1)|PURCHASER SUBSCRIPTION INFORMATION(6,1)|ELECTRONIC COMMERCE(5,6)|RECYCLED PRODUCT(5,3)|STOCK INFORMATION(5,3)|BUY INSUFFICIENT CARBON CREDIT(5,1)|BUYER MANAGEMENT INFORMATION(5,1)|COLLECTING PURCHASER INFORMATION(5,1)|ENTERPRISE LIST(5,1)|GREEN CONSUMER(5,1)|PURCHASER USAGE INFORMATION(5,1)|SEARCHED SELLER ENVIRONMENT PRODUCT(5,1)|STOCK INVESTMENT INFORMATION(5,1)|CARBON REDUCTION INFORMATION ANALYSIS(4,6)|CARBON REDUCTION INFORMATION COLLECTION(4,6)|POINT INFORMATION MANAGEMENT(4,5)|BECCS(4,4)|PURCHASER USE INFORMATION(4,3)|COLLECT INFORMATION(4,2)|COMMISSION(4,2)|ECO FRIENDLY PRODUCT(4,2)|ESG MANAGEMENT INFORMATION(4,2)|LIVESTOCK PRODUCTION(4,2)|SINGULAR(4,2)|ACCUMULATED POINT ENCASHMENT(4,1)|ACCUMULATED PURCHASER POINT TRANSACTION(4,1)|BUYER POINT ACCUMULATED TRANSACTION(4,1)|CARBON EMISSION QUOTA(4,1)|CARBON SUPPRESSION(4,1)|ENVIRONMENT PRODUCT PURCHASE(4,1)|ENVIRONMENT PROTECTION(4,1)|GREENHOUSE GAS EMISSION QUOTA(4,1)|NATURE DESTRUCTION(4,1)|PURCHASER REGIONAL INFORMATION INPUT(4,1)|RECEIVED STORY TELLING INFORMATION(4,1)|SELLER SUBSCRIPTION INFORMATION INPUT(4,1)|SPONTANEOUS CARBON EMISSION TRADING(4,1)|STEADY PRODUCTION(4,1)|TECHNICAL IDEA(4,1)|SECURITY(3,2)| | (KR10-2769477)|1. A seller terminal (210) comprising: a buyer management unit (210) for managing subscription information including local information of a buyer, authentication information, transaction information of an environmental product, purchaser points accumulation according to transactions of the environmental product, and accumulated transactions of the purchaser points, while forming communication between the buyers and sellers who need carbon emission trading and setting the purchaser points as investment money to perform stock investment trading based on low-carbon emission seller information inputted from each purchaser terminal (100, 100a, 100n); a seller management unit (220) for managing environmental product information including local information of a low-carbon emission seller inputted from each seller terminal (300, 300a, 300n), authentication information, and storytelling information of the seller, wherein the storytelling information is information for the seller to deliver a process for production, sale, management, and distribution of the environmental product to the buyer; transaction information of the environmental product; carbon reduction activity information and carbon knowledge reduction information of the low-carbon emission seller; and a seller terminal (300, 300a, 300n) for managing transactions of the environmental product between the purchaser terminal (100, 100a, 100n) and the seller terminal (300, 100a, 100n), and having the same local information of the buyer terminal (100, 100a, 100n, 300a, 30, 300n) A transaction service system using carbon reduction information, comprising: a shopping mall management unit 230 configured to first provide an environmental product of the terminal 300 (300a to 300n) to the buyer terminal 100 (100a to 100n) to manage carbon emissions reduction through the environmental product transaction of a corresponding region; a community management unit 240 configured to collect activity information and knowledge information of a seller related to low carbon emissions and carbon reductions from the seller terminal 300 (300a to 300n), analyze the collected activity information and knowledge information for each low carbon emission seller and carbon reduction technology based on the carbon reduction-related activity information and knowledge information of the seller, and manage the analyzed information to be shared with the buyer terminal 100 (100a to 100n); and a management server 200 including a database 250 configured to store management information of the buyer management unit 210, the seller management unit 220, the shopping mall management unit 230, and the community management unit 240.|2. AMENDSTATUS: Delete|3. AMENDSTATUS: Delete|4. The transaction service system of claim 1, wherein the buyer management unit (210) comprises: a buyer information management unit (211) configured to accumulate subscription information including region information of a buyer inputted from the buyer terminal (100, 100a to 100n), authentication information, transaction information of an environmental product, and buyer point information according to a transaction of the environmental product; and a point information management unit (212) configured to set the accumulated buyer points as investments according to seller information inputted from the buyer terminal (100, 100a to 100n) to perform a stock investment transaction based on stock investment information or a stock investment product.|5. The transaction service system of claim 1, wherein the seller management unit (220) comprises: a seller information management unit (221) configured to manage subscription information including regional information of a low carbon emission seller inputted from the seller terminal (300, 300a to 300n), authentication information, carbon reduction activity information of the low carbon emission seller, and carbon reduction knowledge information; and a product information management unit (222) configured to manage the environmental product information and transaction information with the purchaser terminal (100, 100a to 100n).|6. AMENDSTATUS: Delete|7. The transaction service system of claim 1, wherein the community management unit 240 includes: a carbon reduction information collection unit 241 configured to collect carbon reduction activity information and carbon reduction knowledge information of a low carbon emission seller input to the seller management unit 220; a carbon reduction information analysis unit 242 configured to analyze the collected carbon reduction related information for each low carbon emission seller and carbon reduction technology based on the collected carbon reduction related information; and an analysis information management unit 243 configured to transmit the analysis result to the purchaser terminal 100 (100a to 100n) and manage the analysis result to be shared.|8. A) a step in which the management server 200 collects activity information and knowledge information of a seller related to low carbon emission and carbon reduction from the seller terminals 300, 100a, and 100n, collects activity information and knowledge information of the seller related to the low carbon emission and carbon reduction from the seller terminals 300, 300a, and 300n, and analyzes the collected activity information and knowledge information related to carbon reduction of the seller for each low carbon emission seller and carbon reduction technology on the basis of the collected activity information and knowledge information related to carbon reduction of the seller to manage the low carbon emission seller and the low carbon reduction technology to be shared with the buyer terminals 100, 300a, and 300n, and b) a step in which the management server 200 manages an environmental transaction between the buyer terminals 100, 100a, and 100n and the seller terminals 300, 100a, and 100n, searches for a seller terminal 300, 300a, and 300n having the same regional information on the basis of regional information of the buyer terminals 100, 100a, and 100n, and provides the searched environmental product to the buyer terminals 100, 300a, 300n, 300a, and 300n to preferentially manage the environmental transaction between the buyer terminals 100, 300, and 100a A transaction service method using carbon reduction information, comprising: managing so that carbon emissions are reduced through local environmental product transactions and determining whether a buyer point is generated by a certain buyer terminal 100(100n to 100a) performing a transaction of an environmental product with one or more seller terminals 300(100n to 300a); and managing so that individual buyer points generated by the management server 200 according to generation of a buyer point through the transaction of the environmental product are accumulated, the accumulated buyer points are set as investments to form communication between buyers and sellers who need a carbon emission right transaction, and stock investment transactions are performed based on low-carbon emission seller information input from each buyer terminal 100(300n to 100a 100n).|9. AMENDSTATUS: Delete|10. AMENDSTATUS: Delete|11. AMENDSTATUS: Delete|12. AMENDSTATUS: Delete|13. AMENDSTATUS: Delete | (KR10-2769477)|TECHNICAL FIELD|[0001] The present invention relates to a transaction service system and method using carbon reduction information, and more particularly, to a transaction service system and method using carbon reduction information, in which a buyer and a low-carbon emission seller who sells an environmental product are connected to share information and knowledge on the basis of carbon reduction activities, and points of the buyer generated by transactions of the environmental product are converted into shares of the low-carbon emission seller for transactions.|BACKGROUND ART|[0002] Industrial development has given convenience to mankind, but natural destruction due to industrial development has also been accompanied, and greenhouse gases derived and emitted as the primary and fourth industries develop are accelerating global warming.|[0003] In addition, as the temperature rises due to global warming, sea levels rise and unprecedented weather anomalies are encountered, opinions are being gathered to protect the environment before it is too late.|[0004] In recent years, advanced countries have led to an international agreement that greenhouse gases should be reduced by a certain percentage for a certain period of time, and in addition, a carbon emission trading system has been created that allows the purchase and sale of greenhouse gas emission rights.|[0005] The carbon emission trading system is a name given by carbon dioxide (CO₂), which has the largest emission among greenhouse gases, and if greenhouse gases are emitted below the quota given by each country (greenhouse gas emissions that can be emitted for a certain period of time), the surplus amount (carbon emission credits) can be sold to other countries, and in the opposite case, carbon emission credits can be purchased from other countries.|[0006] In the end, reducing carbon emissions to take the lead in protecting the environment will be a slight obstacle to industrial development, but by converting them into money so that they can benefit, it is inducing countries to voluntarily join in reducing carbon emissions.|[0007] Carbon emission quotas (greenhouse gas emission quotas) are assigned by country, but carbon credit transactions are mostly made between companies.|[0008] However, there is no adequate market yet for individuals or companies to sell surplus carbon credits through carbon emission reduction activities or to buy insufficient carbon credits.|[0009] Moreover, since there is a high concern that companies will naturally lack carbon credits if they engage in steady production activities, the need to form a passage through which carbon credits can be easily introduced is very increasing, and the need for a free carbon credit trading market is more urgently required when the state is designated as a mandatory country to reduce carbon emissions.|[0010] However, there is a problem in that individuals or general consumers cannot voluntarily enter the carbon transaction market of eco-friendly product development companies or low-carbon emission companies due to lack of connectivity with eco-friendly product development companies.|CITATION LIST|PATENT LITERATURE|[0011] Korean Patent Registration No. 10-1052789 (Title of Invention: Method and System for Relaying Carbon Emissions Trading)|SUMMARY OF INVENTION|TECH PROBLEM|[0012] In order to solve the above problems, the present invention is directed to providing a transaction service system and method using carbon reduction information, which may share information and knowledge based on carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and convert points of the buyer generated according to transactions of the environmental product into stocks of the low-carbon emission seller to perform transactions.|TECH SOLUTION|[0013] In order to achieve the above object, a transaction service system using carbon reduction information according to an embodiment of the present invention includes a management server for managing transactions of an environmental product between a buyer terminal and a seller terminal of a low carbon emission seller who sells the environmental product including arbitrary storytelling information, collecting carbon reduction activity information and carbon reduction knowledge information of the low carbon emission seller to share the information with the buyer terminal, accumulating and managing individual buyer points generated by the buyer terminal by performing transactions of the environmental product, and using the accumulated buyer points for transactions of other environmental products according to setting information input from each buyer terminal or managing stock investment transactions based on arbitrary low carbon emission seller information.|[0014] In addition, the management server according to the embodiment is characterized in managing the accumulated transaction of the buyer point to be used for a stock investment transaction of an environmental product traded in a predetermined shopping mall or a low-carbon emission seller selling the environmental product in the shopping mall.|[0015] In addition, the management server according to the embodiment includes: a buyer management unit for managing subscription information including local information of a buyer individually inputted from the buyer terminal, environmental product information including authentication information and storytelling information of a seller, transaction information of the environmental product, buyer point accumulation according to the transaction of the environmental product, and the accumulated transaction of the buyer point; a seller management unit for managing subscription information including local information of a low-carbon emission seller individually inputted from the seller terminal, environmental product information including authentication information and storytelling information of the seller, transaction information of the environmental product, and carbon reduction activity information and carbon reduction knowledge information of a low-carbon emission seller; a shopping mall management unit for managing the transaction of the environmental product between the buyer terminal and the seller terminal; a community management unit for collecting carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller inputted to the seller management unit, analyzing the collected carbon reduction activity information and carbon reduction knowledge information by low-carbon emission seller and carbon reduction technology based on the collected carbon reduction related information, and managing the analysis result to be transmitted and shared to the buyer terminal; and a database for storing management information of the buyer management unit, the seller management unit, the shopping mall management unit, and the community management unit.|[0016] In addition, the buyer management unit according to the embodiment may include: a buyer information management unit configured to accumulate subscription information and authentication information of a buyer, transaction information of an environmental product, and buyer point information according to the transaction of the environmental product, which are input from the buyer terminal; and a point information management unit configured to manage the environmental product transaction and stock investment transaction of the accumulated buyer point.|[0017] In addition, the seller management unit according to the embodiment includes: a seller information management unit configured to manage subscription information and authentication information of a low-carbon emission seller, carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller inputted from the seller terminal; and a product information management unit configured to manage the environmental product information and transaction information with a purchaser terminal.|[0018] In addition, the shopping mall management unit according to the embodiment may search for a seller terminal having the same regional information based on regional information of the buyer terminal, and preferentially provide an environmental product of the searched seller terminal to the buyer terminal.|[0019] In addition, the community management unit according to the embodiment may include: a carbon reduction information collection unit configured to collect carbon reduction activity information and carbon reduction knowledge information of a low-carbon emission seller input to the seller management unit in a shopping mall; a carbon reduction information analysis unit configured to analyze the collected carbon reduction-related information for each low-carbon emission seller and carbon reduction technology; and an analysis information management unit configured to transmit the analysis result to a purchaser terminal and manage the analysis result to be shared.|[0020] In addition, an embodiment of the present invention provides a transaction service method using carbon reduction information, including: a) a step in which a management server collects information on a buyer and a seller from a seller terminal of a low-carbon emission seller who sells an environmental product including arbitrary storytelling information and a buyer terminal connected through a network, and collects carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller to share the information in the buyer terminal; b) a step in which the management server manages transactions of the environmental product between the buyer terminal and the seller terminal, and determines whether buyer points are generated by random buyer terminals performing transactions of the environmental product with one or more seller terminals; and c) a step in which the management server accumulates individual buyer points generated by generating buyer points through the transactions of the environmental product, and manages the accumulated buyer points to be used for transactions of other environmental products or to perform stock investment transactions based on arbitrary low-carbon emission seller information according to setting information input from a corresponding buyer terminal.|[0021] In addition, step a) according to the embodiment may include: a-1) performing, by the management server, purchaser authentication based on subscription information including region information of a purchaser input from a purchaser terminal and login information; and a-2) searching, by the management server, for purchaser point information as the purchaser authentication is completed and setting usage information of the purchaser point based on user setting information input from an authenticated purchaser terminal.|[0022] In addition, in step a-2) according to the embodiment, the management server may receive any one of encashment or stock investment based on low-carbon emission seller information for use in the transaction of the environmental product from the buyer terminal, and when the stock investment is input, the management server may set a buyer point as investment money to perform stock investment in a stock investment product based on arbitrary low-carbon emission seller information input from the corresponding buyer terminal.|[0023] In addition, step a) according to the embodiment may include: a'-1) performing, by the management server, seller authentication based on subscription information including region information of the seller and login information input from the seller terminal; and a'-2) receiving, by the management server, environmental product information including storytelling information, carbon reduction activity information, and carbon reduction knowledge information from the seller terminal when the seller authentication is completed, and displaying the environmental product information, carbon reduction activity information, and carbon reduction knowledge information on the shopping mall webpage.|[0024] In addition, step b) according to the embodiment may include: b-1) searching and collecting, by a management server, carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller input in step a); b-2) analyzing, by the management server, each of the low-carbon emission seller and the carbon reduction technology based on the collected carbon reduction-related information; and b-3) transmitting, by the management server, the analysis result to a purchaser terminal to share the low-carbon emission seller information and the carbon reduction information.|[0025] In addition, step b) according to the embodiment is characterized in that the management server searches for a seller terminal having the same regional information based on regional information of the buyer terminal so that a transaction of an environmental product may be made between a buyer and a seller in the same region, and provides the environmental product of the searched seller terminal preferentially to the buyer terminal.|ADVANTAGEOUS EFFECTS|[0026] The present invention has the advantage of sharing information and knowledge based on a carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and converting the point of the buyer generated according to the transaction of the environmental product into the stock of the low-carbon emission seller to transact.|[0027] In addition, the present invention has the advantage of increasing carbon emission reduction activities through the environmental product transaction in the corresponding area by managing the environmental product transaction between the buyer and the seller in the same area.|DESCRIPTION OF DRAWINGS|[0028] FIG. 1 is a block diagram illustrating a configuration of a transaction service system using carbon reduction information according to an embodiment of the present disclosure. FIG. 2 is a block diagram illustrating a configuration of a management server of a transaction service system using carbon reduction information according to the embodiment of FIG. 1. FIG. 3 is a block diagram illustrating a configuration of a buyer management unit of a management server according to the embodiment of FIG. 2. FIG. 4 is a block diagram illustrating a configuration of a seller management unit of a management server according to the embodiment of FIG. 2. FIG. 5 is a block diagram illustrating a configuration of a community management unit of a management server according to the embodiment of FIG. 2. FIG. 6 is a flowchart illustrating a transaction service method using carbon reduction information according to an embodiment of the present disclosure. FIG. 7 is a flowchart illustrating a process of collecting information of a buyer and a seller in the transaction service method using carbon reduction information according to the embodiment of FIG. 6. FIG. 8 is a flowchart illustrating a point use information setting process of a purchaser information collection process according to the embodiment of FIG. 7. FIG. 9 is a flowchart illustrating a process of outputting carbon reductions information and investment product information of a transaction service method using carbon reductions information according to the embodiment of FIG. 6.|DESCRIPTION OF EMBODIMENTS|[0029] Hereinafter, the present invention will be described in detail with reference to preferred embodiments of the present invention and the accompanying drawings, on the premise that the same reference numerals in the drawings refer to the same components.|[0030] It should be noted that, prior to describing specific contents for the implementation of the present disclosure, configurations that are not directly related to the technical gist of the present disclosure are omitted within a range that does not obscure the technical gist of the present disclosure. |[0031] In addition, terms or words used in the present specification and claims should be interpreted as meanings and concepts conforming to the technical spirit of the present invention based on the principle that the inventor can define appropriate concepts of terms in order to describe his or her invention in the best way.|[0032] In this specification, the expression that a part "includes" a certain component means that the part may further include another component, rather than excluding another component.|[0033] In addition, terms such as "‥unit‥", "device", and "‥module" refer to a unit for processing at least one function or operation, and may be classified as hardware, software, or a combination thereof.|[0034] In addition, the term "at least one" is defined as a term including a singular number and a plural number, and it will be apparent that each component may exist in the singular or the plural number even if the term "at least one" does not exist, and may mean the singular or the plural number. |[0035] Hereinafter, preferred embodiments of a transaction service system and method using carbon reduction information according to an embodiment of the present disclosure will be described in detail with reference to the accompanying drawings.|[0036] FIG. 1 is a block diagram illustrating a configuration of a transaction service system using carbon reduction information according to an embodiment of the present disclosure, FIG. 2 is a block diagram illustrating a configuration of a management server of the transaction service system using carbon reduction information according to the embodiment of FIG. 1, FIG. 3 is a block diagram illustrating a configuration of a buyer management unit of the management server according to the embodiment of FIG. 2, FIG. 4 is a block diagram illustrating a configuration of a seller management unit of the management server according to the embodiment of FIG. 2, and FIG. 5 is a block diagram illustrating a configuration of a community management unit of the management server according to the embodiment of FIG. 2.|[0037] Referring to FIGS. 1 to 5, a transaction service system using carbon reduction information according to an embodiment of the present disclosure may include a plurality of buyer terminals 100, a management server 200, and a plurality of seller terminals 300 to connect a buyer and a low-carbon emission seller who sells an environmental product to share information and knowledge based on carbon reduction activities, and to convert points of the buyer generated according to transactions of the environmental product into stocks of the low-carbon emission seller to perform transactions.|[0038] The buyer terminal 100 is a component that accesses the management server 200 through a network to perform electronic commerce with the plurality of seller terminals 300, seller terminal 1 (300a) to seller terminal n (300n), and may be configured as a desktop PC, a notebook PC, a tablet PC, or a mobile terminal capable of installing any application program (app).|[0039] In addition, the buyer terminal 100 may transmit, to the management server 200, subscription information including the buyer's regional information input by the buyer, authentication information such as login, and transaction information related to orders such as environmental products, addresses, buyers, contacts, and payments for electronic commerce.|[0040] In addition, the buyer terminal 100 receives storytelling information related to the environmental product sold in the seller terminal 300 and the seller terminal 1 (300a) to the seller terminal n (300n) transmitted from the management server 200, and buyer point accumulation information generated according to the transaction of the environmental product, and displays the received storytelling information.|[0041] In addition, the buyer terminal 100 may receive setting information for use and transaction of the accumulated buyer point from the user and output the setting information to the management server 200.|[0042] In addition, the buyer terminal 100 may identify activity information and knowledge information of the seller related to low carbon emission, carbon reduction, and the like, and receive activity information and knowledge information related to low carbon emission, carbon reduction, and the like for each seller transmitted from the management server 200 so that the buyer may utilize a voluntary carbon emission trading market by sellers (or companies) requiring carbon emission trading through trading with the buyer and share the activity information and knowledge information with the buyer.|[0043] Here, the activity information and knowledge information related to low carbon emission and carbon reduction may include ESG management report information, and may be ESG management effort introduced or promoted in a production facility of a seller or a listed company in stages, selection information on green consumers, assembly business information for greenhouse gas reduction, bioenergy with carbon capture and storage (BECCS), and technology information related to Carbon Dioide Removal (CDR.).|[0044] In addition, the buyer terminal 100 may receive, from the buyer, one or more of use information of points to be used for the transaction of the environmental product, for example, stock investment based on the encashment of accumulated points and low-carbon emission seller information.|[0045] In addition, when stock investment is input for the buyer point, the buyer terminal 100 may set the buyer point as investment money, receive setting information so that at least a part of the buyer point is invested in the stock investment product provided by the management server 200 through the stock based on arbitrary low-carbon emission seller information set by the buyer, and output the setting information to the management server 200.|[0046] The management server 200 is a component that manages transactions of the environmental product to be performed among the plurality of buyer terminals 100, the buyer terminal 1 (100a) to the buyer terminal n (100n), the seller terminal 300 of the low-carbon emission seller who sells the environmental product, and the seller terminal 1 (300a) to the seller terminal n (300n), and may be configured as a server system.|[0047] In addition, the management server 200 may check activity information and knowledge information of the seller related to low carbon emission and carbon reductions of the buyer, and the seller may collect carbon reduction activity information and carbon reduction knowledge information of the low carbon emission seller and share the information with the buyer terminal 100, the buyer terminal 1 (100a), or the buyer terminal n (100n) so that the seller may utilize a voluntary carbon emission trading market by sellers (or companies) requiring carbon emission trading through trading with the buyer.|[0048] In addition, the management server 200 may manage so that buyer points generated by the buyer terminal 100, the buyer terminal 1 (100a) to the buyer terminal n (100n) by performing the transaction of the environmental goods with one or more seller terminals 300, the seller terminal 1 (300a) to the seller terminal n (300n) are accumulated for each individual buyer.|[0049] In addition, the management server 200 may set the accumulated buyer points to be used for transactions of other environment products according to setting information individually input from the buyer terminal 100, the buyer terminal 1 100a, or the buyer terminal n 100n.|[0050] In addition, the management server 200 may manage the buyer points accumulated according to the setting information individually input from the buyer terminal 100, the buyer terminal 1 (100a), or the buyer terminal n (100n) so that at least a part of the buyer points are invested as stocks in the stock investment product so that stock investment transactions based on arbitrary low-carbon emission seller information are made.|[0051] In addition, the management server 200 may manage the accumulated transaction of the purchaser point to be used for an environmental product traded in a predetermined shopping mall or a stock investment transaction of a low-carbon emission seller or a listed company selling the environmental product in the corresponding shopping mall.|[0052] To this end, the management server 200 may include a buyer management unit 210, a seller management unit 220, a shopping mall management unit 230, a community management unit 240, and a database 250.|[0053] The purchaser management unit 210 is a component for managing subscription information including area information of the purchaser input from the purchaser terminal 100 and the purchaser terminal 1 (100a) to the purchaser terminal n (100n), authentication information, and transaction information of the environmental product, accumulation of purchaser points according to the transaction of the environmental product, and transaction of the accumulated purchaser points, and may be configured to include a purchaser information management unit 211 and a point information management unit 212.|[0054] The buyer information management unit 211 receives subscription information and authentication information including region information of the buyer individually input from the buyer terminal 100 and the buyer terminal 1 (100a) to the buyer terminal n (100n), transaction information of the environmental product through each of the buyer terminals 100, 100a to 100n, accumulation information of the buyer point according to the transaction of the environmental product, use information, and the like, and stores the received information in the database 250.|[0055] The point information management unit 212 manages a stock investment transaction so that at least a part of the buyer points can be invested and used as stocks so that the accumulated buyer points can be used by subtracting the accumulated buyer points from a transaction related to the purchase of another environmental product according to a use method set by the buyer or used by being used in a stock investment transaction based on arbitrary low-carbon emission seller information input by the user.|[0056] Such a buyer's stock investment transaction may form a "green communication" between sellers (or companies) and buyers who need carbon emission trading, and may activate the seller's voluntary carbon emission trading market. |[0057] The seller management unit 220 is a component for managing subscription information including area information of a low-carbon emission seller individually input from the seller terminal 300 and the seller terminal 1 (300a) to the seller terminal n (300n), authentication information, environmental product information including storytelling information of the seller, transaction information of the environmental product, carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller, and may be configured to include a seller information management unit 221 and a product information management unit 222.|[0058] The seller information management unit 221 receives subscription information and authentication information of a low-carbon emission seller individually input from the seller terminal 300, the seller terminal 1 (300a) to the seller terminal n (300n), environmental product information including storytelling information of the seller, carbon reduction activity information for low-carbon emission of a seller who sells the environmental product, knowledge information for carbon reduction, and the like, and stores and manages the received information in the database 250.|[0059] The product information management unit 222 manages environmental product information individually input from the seller terminal 300, the seller terminal 1 300a, or the seller terminal n 300n, and transaction information with the individual buyer terminals 100, 100a, or 100n that purchases each environmental product information.|[0060] Here, the environmental product may include content information such as agricultural/fishery/livestock products, eco-friendly products, recycled products, and eco-friendly experience programs, application programs for forming and managing an eco-friendly community, and the like.|[0061] In addition, the storytelling information of the seller may be information for the seller to deliver a process of producing, selling, managing, distributing, and the like of the environmental product to the buyer.|[0062] The shopping mall management unit 230 manages the transaction of the environment product through the e-commerce between the buyer terminal 100, the buyer terminal 1 (100a) to the buyer terminal n (100n), the seller terminal 300, and the seller terminal 1 (300a) to the seller terminal n (300n), and stores the transaction result in the database 250.|[0063] In addition, the shopping mall management unit 230 may be configured to search for the seller terminal 300, 100a to 100n having the same regional information based on regional information of the buyer terminal 100, 300a to 300n when trading the environmental product, and display the environmental product of the searched seller terminal 300, 300a to 300n on the buyer terminal 100, 100a to 100n.|[0064] That is, the shopping mall management unit 230 manages the environmental product transaction between the buyer and the seller in the same area so that the carbon emission reduction activity can be performed through the environmental product transaction in the corresponding area.|[0065] The community management unit 240 may search and collect carbon reduction activity information and carbon reduction-related knowledge information for low carbon emission of the seller input from the seller management unit 220 through the database 250 or an external server connected through a network.|[0066] In addition, the community management unit 240 may analyze each of the low carbon emission seller and the carbon reduction technology based on the collected carbon reduction-related activity information and knowledge information of the seller, and individually transmit the analysis result to the purchaser terminal 100, the purchaser terminal 1 (100a), or the purchaser terminal n (100n) to manage the analysis result to be shared.|[0067] To this end, the community management unit 240 may include a carbon reduction information collection unit 241, a carbon reduction information analysis unit 242, and an analysis information management unit 243.|[0068] The carbon reduction information collection unit 241 is a component for collecting carbon reduction activity information and carbon reduction-related knowledge information of a seller for low carbon emission, and may collect carbon reduction activity information and carbon reduction-related knowledge information of the seller from the carbon reduction-related information of the seller input through the seller management unit 220 or an external public information providing server (e.g., the Korea Exchange, the U.S. Securities and Exchange Commission, etc.) accessed through a network.|[0069] The carbon reduction information analysis unit 142 may classify and analyze a seller for low carbon emission, ESG management information for carbon reduction, assembly business information for greenhouse gas reduction, BECCS, and carbon removal (CDR.) technologies based on the carbon reduction activity information and carbon reduction related knowledge information of the seller collected by the carbon reduction information collection unit 241.|[0070] The analysis information management unit 243 transmits the analysis result of the carbon reduction information analysis unit 142 to the individual buyer terminals 100, 100a to 100n to manage the analysis result to be shared, thereby allowing the individual buyer to check carbon reduction-related management information, facility investment information, and the like for low carbon emission for each seller.|[0071] The database 250 stores management information of the purchaser management unit 210, the seller management unit 220, the shopping mall management unit 230, and the community management unit 240.|[0072] The seller terminal 300 is a component that accesses the management server 200 through a network to perform electronic commerce with the plurality of buyer terminals 100, the buyer terminal 1 (100a) to the buyer terminal n (100n), and may be configured as a desktop PC, a notebook PC, a tablet PC, or a mobile terminal capable of installing any application program (app).|[0073] In addition, the seller terminal 300 may transmit, to the management server 200, seller's subscription information input by the seller, authentication information such as login, and transaction information related to orders such as environmental product information and payment for electronic commerce.|[0074] Here, the seller may include an agricultural/fisheries/livestock business operator or association, a general environment-related organization, an enterprise that produces and distributes eco-friendly or recycled products, a listed enterprise that needs to be traded in a voluntary carbon emission trading market, a public institution, and the like.|[0075] In addition, the seller terminal 300 may provide related information to the management server 200 so that the buyer can check the seller's activity information and knowledge information related to low carbon emission and carbon reduction, for example, ESG management report information, ESG management effort introduced or promoted in the production facilities of the seller or listed company in stages, assembly business information for greenhouse gas reduction, BECCS, and carbon removal (CDR.) related technology information.|[0077] Next, a transaction service method using carbon reduction information according to an embodiment of the present disclosure will be described.|[0078] FIG. 6 is a flowchart illustrating a transaction service method using carbon reduction information according to an embodiment of the present invention, FIG. 7 is a flowchart illustrating a process of collecting information of a buyer and a seller in the transaction service method using carbon reduction information according to the embodiment of FIG. 6, FIG. 8 is a flowchart illustrating a process of setting point use information in the process of collecting buyer information according to the embodiment of FIG. 7, and FIG. 9 is a flowchart illustrating a process of outputting carbon reduction information and investment product information in the transaction service method using carbon reduction information according to the embodiment of FIG. 6.|[0079] Referring to FIGS. 1 to 9, in the transaction service method using carbon reduction information according to an embodiment of the present disclosure, the management server 200 collects buyer information and seller information from a buyer terminal 100, a buyer terminal 1 (100a) to a buyer terminal n (100n), a seller terminal 300 of a low-carbon emission seller who sells environmental products, and a seller terminal 1 (300a) to a seller terminal n (300n) connected through a network (S100).|[0080] Describing step S100 in more detail, the management server 200 checks whether the input information is purchaser information or seller information.|[0081] As a result of the checking, if the purchaser information is the purchaser information, the management server 200 may perform purchaser authentication based on subscription information including the purchaser's region information and login information input from the individual purchaser terminals 100, 100a to 100n (S110).|[0082] In addition, the management server 200 may perform a process of searching for and displaying purchaser point information in the database 250 (S120) as the purchaser authentication in step S110 is completed, and setting use information of the purchaser point based on user setting information input from the purchaser terminal 100, 100a to 100n of the authenticated purchaser (S130).|[0083] In step S130, when any one of stock investment based on seller information for performing encashment or low carbon emission for using the use information of the buyer point set from each of the buyer terminals 100, 100a to 100n for the transaction of the environmental product is input (S131), the management server 200 may allow the buyer point to be used according to the input setting information.|[0084] In this case, when stock investment is input in step S131, the management server 200 sets buyer points as investments to set stock investment information or stock investment products based on seller information input from the corresponding buyer terminal 100, 100a to 100n (S132), and changes the buyer points into investments according to the set investment information to invest in the corresponding investment products or stocks of the seller (or company) (S133).|[0085] In addition, the management server 200 may search for and provide stock information or investment product information of a corresponding seller from a stock information providing server (not shown) linked through a network.|[0086] Meanwhile, although the encashment and stock investment by the buyer are described as being used for product payment of a seller or a company that sells environmental products in a shopping mall managed by the management server 200 or invested in stocks, the present disclosure is not limited thereto.|[0087] In addition, as a result of the checking in step S100, when the seller information is the seller information, the management server 200 performs seller authentication based on subscription information including regional information of the seller input from the individual seller terminals 300, 300a to 300n and login information (S110′). |[0088] In addition, when the seller authentication in step S110′ is completed, the management server 200 receives environmental product information including storytelling information of the seller for electronic commerce from the individual seller terminals 300, 300a to 300n (S120′) and stores the environmental product information in the database 150, and the environmental product information is disclosed in the shopping mall webpage.|[0089] In addition, the environmental product information in step S120′ may include content information such as agricultural/fishery/livestock products, eco-friendly products, recycled products, and eco-friendly experience programs, application programs for forming and managing an eco-friendly community, and the like.|[0090] In addition, in step S120′, the seller may additionally receive an input of the seller's storytelling information for delivering the seller's process of production, sale, management, distribution, and the like of the environmental product to the buyer.|[0091] In addition, the management server 200 receives carbon reduction activity information and carbon reduction-related knowledge information for low carbon emission input for each seller from the individual seller terminals 300, 300a to 300n (S130′) and stores the same in the database 150, and the carbon reduction activity information and the carbon reduction-related knowledge information are disclosed in the shopping mall webpage.|[0092] In addition, the management server 200 collects the carbon reduction activity information and the carbon reduction knowledge information for low carbon emission of the seller input in step S100, and transmits the collected information to the individual purchaser terminals 100, 100a to 100n to share the same (S200).|[0093] In step S200, the management server 200 may search for and collect the carbon reduction activity information and the carbon reduction knowledge information of the seller for low carbon emission input in step S100 (S210).|[0094] In step S210, the management server 200 may collect the carbon reduction-related information of the seller input from the individual seller terminals 300, 300a to 300n or the carbon reduction-related knowledge information and carbon reduction activity information of the seller from an external public information providing server (e.g., the Korea Exchange, the U.S. Securities and Exchange Commission, etc.) connected through a network.|[0095] In addition, the management server 200 may analyze and evaluate ESG management information for carbon reduction, assembly business information for greenhouse gas reduction, BECCS, carbon removal (CDR.), and the like for each technology based on the carbon reduction activity information and carbon reduction-related knowledge information of the seller collected in step S210 (S220), and may classify and extract the seller for low carbon emission according to the analyzed evaluation result (S230).|[0096] In addition, the management server 200 searches for seller information for low carbon emission and related investment product and stock information according to the carbon reduction information based on the analysis results of steps S220 and S230, and transmits the searched result together with the seller information and the carbon reduction information to the individual purchaser terminals 100, 100a to 100n to be disclosed and shared (S240), thereby allowing the individual purchaser to check carbon reduction-related management information, facility investment information, and the like for low carbon emission for each seller.|[0097] Subsequently, the management server 200 manages the transaction of the environmental product between the individual purchaser terminals 100, 100a to 100n and the seller terminals 300, 300a to 300n connected to the shopping mall website (S300).|[0098] In step S300, the management server 200 may search for the seller terminal 300, 100a, or 100n having the same area information based on the area information of the buyer terminal 100, 300a, or 300n so that the transaction of the environment product may be performed between the buyer and the seller in the same area, and preferentially provide the environment product of the searched seller terminal 300, 300a, or 300n to the buyer terminal 100, 100a, or 100n so that carbon emission reduction activities through the transaction of the environment product in the corresponding area may be performed.|[0099] In addition, the management server 200 determines whether a buyer point is generated by each of the buyer terminals 100, 100a to 100n performing a transaction of an environmental product with one or more seller terminals 300, 300a to 300n (S400).|[0100] As a result of the determination in step S400, when the buyer points are generated through the transaction of the environmental product, the management server 200 accumulates the generated buyer points as individual buyer points, and uses the accumulated buyer points for the transaction of another environmental product according to the setting information input from the corresponding buyer terminal 100, 100a to 100n, sets the stock investment transaction based on any low-carbon emission seller information to be performed, or manages the stock investment transaction to be performed in conjunction with a financial company server (not shown) so that some buyer points are used for the transaction of another environmental product and the rest are used for the stock investment transaction (S500).|[0101] Subsequently, the management server 200 may determine whether the access to the shopping mall web page is terminated after the e-commerce between the purchaser terminal 100, 100a to 100n and the seller terminal 300, 300a to 300n is terminated (S600).|[0102] As a result of the determination in step S600, when the connection termination is confirmed, the information set in steps S100 to S500 is stored in the database 250 (SS700).|[0103] Therefore, the present invention can share information and knowledge based on a carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and convert points of the buyer generated according to a transaction of the environmental product into stocks of the low-carbon emission seller to transact the same.|[0104] In addition, the buyer may share and confirm activity information and knowledge information of the seller related to low carbon emissions, carbon reductions, etc., and may utilize the voluntary carbon emission trading market by sellers who need carbon emission trading through trading with the buyer.|[0105] As described above, although it has been described with reference to preferred embodiments of the present disclosure, it will be understood by those skilled in the art that the present disclosure may be variously modified and changed without departing from the spirit and scope of the present disclosure described in the following claims.|[0106] In addition, the reference numerals described in the claims of the present disclosure are only described for clarity and convenience of description, and are not limited thereto, and in the process of describing the embodiments, the thicknesses of lines or the sizes of components shown in the drawings may be exaggerated for clarity and convenience of description.|[0107] In addition, the above-described terms are terms defined in consideration of functions in the present disclosure, which may vary depending on the intention or custom of a user or operator, and thus the interpretation of these terms should be made based on the contents throughout the present specification.|[0108] In addition, even if it is not explicitly shown or described, it is obvious that a person skilled in the art to which the present invention pertains can make various modifications including the technical idea of the present invention from the description of the present invention, and this still belongs to the scope of the present invention. |[0109] In addition, the embodiments described above with reference to the accompanying drawings are described for the purpose of describing the present disclosure, and the scope of the present disclosure is not limited to these embodiments.|REFERENCE SIGNS LIST|[0110] 100: purchaser terminal 100a: purchaser terminal 1 100n: purchaser terminal n 200: management server 210: purchaser management unit 211: purchaser information management unit 212: point information management unit 220: seller management unit 221: seller information management unit 222: product information management unit 230: shopping mall management unit 240: community management unit 241: carbon reduction information collection unit 242: carbon reduction information analysis unit 243: analysis information management unit 250: database 300: seller terminal 300a: seller terminal 1 300n: seller terminal n | (KR10-2769477)|TECHNICAL FIELD|[0001] The present invention relates to a transaction service system and method using carbon reduction information, and more particularly, to a transaction service system and method using carbon reduction information, in which a buyer and a low-carbon emission seller who sells an environmental product are connected to share information and knowledge on the basis of carbon reduction activities, and points of the buyer generated by transactions of the environmental product are converted into shares of the low-carbon emission seller for transactions.|BACKGROUND ART|[0002] Industrial development has given convenience to mankind, but natural destruction due to industrial development has also been accompanied, and greenhouse gases derived and emitted as the primary and fourth industries develop are accelerating global warming.|[0003] In addition, as the temperature rises due to global warming, sea levels rise and unprecedented weather anomalies are encountered, opinions are being gathered to protect the environment before it is too late.|[0004] In recent years, advanced countries have led to an international agreement that greenhouse gases should be reduced by a certain percentage for a certain period of time, and in addition, a carbon emission trading system has been created that allows the purchase and sale of greenhouse gas emission rights.|[0005] The carbon emission trading system is a name given by carbon dioxide (CO₂), which has the largest emission among greenhouse gases, and if greenhouse gases are emitted below the quota given by each country (greenhouse gas emissions that can be emitted for a certain period of time), the surplus amount (carbon emission credits) can be sold to other countries, and in the opposite case, carbon emission credits can be purchased from other countries.|[0006] In the end, reducing carbon emissions to take the lead in protecting the environment will be a slight obstacle to industrial development, but by converting them into money so that they can benefit, it is inducing countries to voluntarily join in reducing carbon emissions.|[0007] Carbon emission quotas (greenhouse gas emission quotas) are assigned by country, but carbon credit transactions are mostly made between companies.|[0008] However, there is no adequate market yet for individuals or companies to sell surplus carbon credits through carbon emission reduction activities or to buy insufficient carbon credits.|[0009] Moreover, since there is a high concern that companies will naturally lack carbon credits if they engage in steady production activities, the need to form a passage through which carbon credits can be easily introduced is very increasing, and the need for a free carbon credit trading market is more urgently required when the state is designated as a mandatory country to reduce carbon emissions.|[0010] However, there is a problem in that individuals or general consumers cannot voluntarily enter the carbon transaction market of eco-friendly product development companies or low-carbon emission companies due to lack of connectivity with eco-friendly product development companies.|CITATION LIST|PATENT LITERATURE|[0011] Korean Patent Registration No. 10-1052789 (Title of Invention: Method and System for Relaying Carbon Emissions Trading)|SUMMARY OF INVENTION|TECH PROBLEM|[0012] In order to solve the above problems, the present invention is directed to providing a transaction service system and method using carbon reduction information, which may share information and knowledge based on carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and convert points of the buyer generated according to transactions of the environmental product into stocks of the low-carbon emission seller to perform transactions.|TECH SOLUTION|[0013] In order to achieve the above object, a transaction service system using carbon reduction information according to an embodiment of the present invention includes a management server for managing transactions of an environmental product between a buyer terminal and a seller terminal of a low carbon emission seller who sells the environmental product including arbitrary storytelling information, collecting carbon reduction activity information and carbon reduction knowledge information of the low carbon emission seller to share the information with the buyer terminal, accumulating and managing individual buyer points generated by the buyer terminal by performing transactions of the environmental product, and using the accumulated buyer points for transactions of other environmental products according to setting information input from each buyer terminal or managing stock investment transactions based on arbitrary low carbon emission seller information.|[0014] In addition, the management server according to the embodiment is characterized in managing the accumulated transaction of the buyer point to be used for a stock investment transaction of an environmental product traded in a predetermined shopping mall or a low-carbon emission seller selling the environmental product in the shopping mall.|[0015] In addition, the management server according to the embodiment includes: a buyer management unit for managing subscription information including local information of a buyer individually inputted from the buyer terminal, environmental product information including authentication information and storytelling information of a seller, transaction information of the environmental product, buyer point accumulation according to the transaction of the environmental product, and the accumulated transaction of the buyer point; a seller management unit for managing subscription information including local information of a low-carbon emission seller individually inputted from the seller terminal, environmental product information including authentication information and storytelling information of the seller, transaction information of the environmental product, and carbon reduction activity information and carbon reduction knowledge information of a low-carbon emission seller; a shopping mall management unit for managing the transaction of the environmental product between the buyer terminal and the seller terminal; a community management unit for collecting carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller inputted to the seller management unit, analyzing the collected carbon reduction activity information and carbon reduction knowledge information by low-carbon emission seller and carbon reduction technology based on the collected carbon reduction related information, and managing the analysis result to be transmitted and shared to the buyer terminal; and a database for storing management information of the buyer management unit, the seller management unit, the shopping mall management unit, and the community management unit.|[0016] In addition, the buyer management unit according to the embodiment may include: a buyer information management unit configured to accumulate subscription information and authentication information of a buyer, transaction information of an environmental product, and buyer point information according to the transaction of the environmental product, which are input from the buyer terminal; and a point information management unit configured to manage the environmental product transaction and stock investment transaction of the accumulated buyer point.|[0017] In addition, the seller management unit according to the embodiment includes: a seller information management unit configured to manage subscription information and authentication information of a low-carbon emission seller, carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller inputted from the seller terminal; and a product information management unit configured to manage the environmental product information and transaction information with a purchaser terminal.|[0018] In addition, the shopping mall management unit according to the embodiment may search for a seller terminal having the same regional information based on regional information of the buyer terminal, and preferentially provide an environmental product of the searched seller terminal to the buyer terminal.|[0019] In addition, the community management unit according to the embodiment may include: a carbon reduction information collection unit configured to collect carbon reduction activity information and carbon reduction knowledge information of a low-carbon emission seller input to the seller management unit in a shopping mall; a carbon reduction information analysis unit configured to analyze the collected carbon reduction-related information for each low-carbon emission seller and carbon reduction technology; and an analysis information management unit configured to transmit the analysis result to a purchaser terminal and manage the analysis result to be shared.|[0020] In addition, an embodiment of the present invention provides a transaction service method using carbon reduction information, including: a) a step in which a management server collects information on a buyer and a seller from a seller terminal of a low-carbon emission seller who sells an environmental product including arbitrary storytelling information and a buyer terminal connected through a network, and collects carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller to share the information in the buyer terminal; b) a step in which the management server manages transactions of the environmental product between the buyer terminal and the seller terminal, and determines whether buyer points are generated by random buyer terminals performing transactions of the environmental product with one or more seller terminals; and c) a step in which the management server accumulates individual buyer points generated by generating buyer points through the transactions of the environmental product, and manages the accumulated buyer points to be used for transactions of other environmental products or to perform stock investment transactions based on arbitrary low-carbon emission seller information according to setting information input from a corresponding buyer terminal.|[0021] In addition, step a) according to the embodiment may include: a-1) performing, by the management server, purchaser authentication based on subscription information including region information of a purchaser input from a purchaser terminal and login information; and a-2) searching, by the management server, for purchaser point information as the purchaser authentication is completed and setting usage information of the purchaser point based on user setting information input from an authenticated purchaser terminal.|[0022] In addition, in step a-2) according to the embodiment, the management server may receive any one of encashment or stock investment based on low-carbon emission seller information for use in the transaction of the environmental product from the buyer terminal, and when the stock investment is input, the management server may set a buyer point as investment money to perform stock investment in a stock investment product based on arbitrary low-carbon emission seller information input from the corresponding buyer terminal.|[0023] In addition, step a) according to the embodiment may include: a'-1) performing, by the management server, seller authentication based on subscription information including region information of the seller and login information input from the seller terminal; and a'-2) receiving, by the management server, environmental product information including storytelling information, carbon reduction activity information, and carbon reduction knowledge information from the seller terminal when the seller authentication is completed, and displaying the environmental product information, carbon reduction activity information, and carbon reduction knowledge information on the shopping mall webpage.|[0024] In addition, step b) according to the embodiment may include: b-1) searching and collecting, by a management server, carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller input in step a); b-2) analyzing, by the management server, each of the low-carbon emission seller and the carbon reduction technology based on the collected carbon reduction-related information; and b-3) transmitting, by the management server, the analysis result to a purchaser terminal to share the low-carbon emission seller information and the carbon reduction information.|[0025] In addition, step b) according to the embodiment is characterized in that the management server searches for a seller terminal having the same regional information based on regional information of the buyer terminal so that a transaction of an environmental product may be made between a buyer and a seller in the same region, and provides the environmental product of the searched seller terminal preferentially to the buyer terminal.|ADVANTAGEOUS EFFECTS|[0026] The present invention has the advantage of sharing information and knowledge based on a carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and converting the point of the buyer generated according to the transaction of the environmental product into the stock of the low-carbon emission seller to transact.|[0027] In addition, the present invention has the advantage of increasing carbon emission reduction activities through the environmental product transaction in the corresponding area by managing the environmental product transaction between the buyer and the seller in the same area.|DESCRIPTION OF DRAWINGS|[0028] FIG. 1 is a block diagram illustrating a configuration of a transaction service system using carbon reduction information according to an embodiment of the present disclosure. FIG. 2 is a block diagram illustrating a configuration of a management server of a transaction service system using carbon reduction information according to the embodiment of FIG. 1. FIG. 3 is a block diagram illustrating a configuration of a buyer management unit of a management server according to the embodiment of FIG. 2. FIG. 4 is a block diagram illustrating a configuration of a seller management unit of a management server according to the embodiment of FIG. 2. FIG. 5 is a block diagram illustrating a configuration of a community management unit of a management server according to the embodiment of FIG. 2. FIG. 6 is a flowchart illustrating a transaction service method using carbon reduction information according to an embodiment of the present disclosure. FIG. 7 is a flowchart illustrating a process of collecting information of a buyer and a seller in the transaction service method using carbon reduction information according to the embodiment of FIG. 6. FIG. 8 is a flowchart illustrating a point use information setting process of a purchaser information collection process according to the embodiment of FIG. 7. FIG. 9 is a flowchart illustrating a process of outputting carbon reductions information and investment product information of a transaction service method using carbon reductions information according to the embodiment of FIG. 6.|DESCRIPTION OF EMBODIMENTS|[0029] Hereinafter, the present invention will be described in detail with reference to preferred embodiments of the present invention and the accompanying drawings, on the premise that the same reference numerals in the drawings refer to the same components.|[0030] It should be noted that, prior to describing specific contents for the implementation of the present disclosure, configurations that are not directly related to the technical gist of the present disclosure are omitted within a range that does not obscure the technical gist of the present disclosure. |[0031] In addition, terms or words used in the present specification and claims should be interpreted as meanings and concepts conforming to the technical spirit of the present invention based on the principle that the inventor can define appropriate concepts of terms in order to describe his or her invention in the best way.|[0032] In this specification, the expression that a part "includes" a certain component means that the part may further include another component, rather than excluding another component.|[0033] In addition, terms such as "‥unit‥", "device", and "‥module" refer to a unit for processing at least one function or operation, and may be classified as hardware, software, or a combination thereof.|[0034] In addition, the term "at least one" is defined as a term including a singular number and a plural number, and it will be apparent that each component may exist in the singular or the plural number even if the term "at least one" does not exist, and may mean the singular or the plural number. |[0035] Hereinafter, preferred embodiments of a transaction service system and method using carbon reduction information according to an embodiment of the present disclosure will be described in detail with reference to the accompanying drawings.|[0036] FIG. 1 is a block diagram illustrating a configuration of a transaction service system using carbon reduction information according to an embodiment of the present disclosure, FIG. 2 is a block diagram illustrating a configuration of a management server of the transaction service system using carbon reduction information according to the embodiment of FIG. 1, FIG. 3 is a block diagram illustrating a configuration of a buyer management unit of the management server according to the embodiment of FIG. 2, FIG. 4 is a block diagram illustrating a configuration of a seller management unit of the management server according to the embodiment of FIG. 2, and FIG. 5 is a block diagram illustrating a configuration of a community management unit of the management server according to the embodiment of FIG. 2.|[0037] Referring to FIGS. 1 to 5, a transaction service system using carbon reduction information according to an embodiment of the present disclosure may include a plurality of buyer terminals 100, a management server 200, and a plurality of seller terminals 300 to connect a buyer and a low-carbon emission seller who sells an environmental product to share information and knowledge based on carbon reduction activities, and to convert points of the buyer generated according to transactions of the environmental product into stocks of the low-carbon emission seller to perform transactions.|[0038] The buyer terminal 100 is a component that accesses the management server 200 through a network to perform electronic commerce with the plurality of seller terminals 300, seller terminal 1 (300a) to seller terminal n (300n), and may be configured as a desktop PC, a notebook PC, a tablet PC, or a mobile terminal capable of installing any application program (app).|[0039] In addition, the buyer terminal 100 may transmit, to the management server 200, subscription information including the buyer's regional information input by the buyer, authentication information such as login, and transaction information related to orders such as environmental products, addresses, buyers, contacts, and payments for electronic commerce.|[0040] In addition, the buyer terminal 100 receives storytelling information related to the environmental product sold in the seller terminal 300 and the seller terminal 1 (300a) to the seller terminal n (300n) transmitted from the management server 200, and buyer point accumulation information generated according to the transaction of the environmental product, and displays the received storytelling information.|[0041] In addition, the buyer terminal 100 may receive setting information for use and transaction of the accumulated buyer point from the user and output the setting information to the management server 200.|[0042] In addition, the buyer terminal 100 may identify activity information and knowledge information of the seller related to low carbon emission, carbon reduction, and the like, and receive activity information and knowledge information related to low carbon emission, carbon reduction, and the like for each seller transmitted from the management server 200 so that the buyer may utilize a voluntary carbon emission trading market by sellers (or companies) requiring carbon emission trading through trading with the buyer and share the activity information and knowledge information with the buyer.|[0043] Here, the activity information and knowledge information related to low carbon emission and carbon reduction may include ESG management report information, and may be ESG management effort introduced or promoted in a production facility of a seller or a listed company in stages, selection information on green consumers, assembly business information for greenhouse gas reduction, bioenergy with carbon capture and storage (BECCS), and technology information related to Carbon Dioide Removal (CDR.).|[0044] In addition, the buyer terminal 100 may receive, from the buyer, one or more of use information of points to be used for the transaction of the environmental product, for example, stock investment based on the encashment of accumulated points and low-carbon emission seller information.|[0045] In addition, when stock investment is input for the buyer point, the buyer terminal 100 may set the buyer point as investment money, receive setting information so that at least a part of the buyer point is invested in the stock investment product provided by the management server 200 through the stock based on arbitrary low-carbon emission seller information set by the buyer, and output the setting information to the management server 200.|[0046] The management server 200 is a component that manages transactions of the environmental product to be performed among the plurality of buyer terminals 100, the buyer terminal 1 (100a) to the buyer terminal n (100n), the seller terminal 300 of the low-carbon emission seller who sells the environmental product, and the seller terminal 1 (300a) to the seller terminal n (300n), and may be configured as a server system.|[0047] In addition, the management server 200 may check activity information and knowledge information of the seller related to low carbon emission and carbon reductions of the buyer, and the seller may collect carbon reduction activity information and carbon reduction knowledge information of the low carbon emission seller and share the information with the buyer terminal 100, the buyer terminal 1 (100a), or the buyer terminal n (100n) so that the seller may utilize a voluntary carbon emission trading market by sellers (or companies) requiring carbon emission trading through trading with the buyer.|[0048] In addition, the management server 200 may manage so that buyer points generated by the buyer terminal 100, the buyer terminal 1 (100a) to the buyer terminal n (100n) by performing the transaction of the environmental goods with one or more seller terminals 300, the seller terminal 1 (300a) to the seller terminal n (300n) are accumulated for each individual buyer.|[0049] In addition, the management server 200 may set the accumulated buyer points to be used for transactions of other environment products according to setting information individually input from the buyer terminal 100, the buyer terminal 1 100a, or the buyer terminal n 100n.|[0050] In addition, the management server 200 may manage the buyer points accumulated according to the setting information individually input from the buyer terminal 100, the buyer terminal 1 (100a), or the buyer terminal n (100n) so that at least a part of the buyer points are invested as stocks in the stock investment product so that stock investment transactions based on arbitrary low-carbon emission seller information are made.|[0051] In addition, the management server 200 may manage the accumulated transaction of the purchaser point to be used for an environmental product traded in a predetermined shopping mall or a stock investment transaction of a low-carbon emission seller or a listed company selling the environmental product in the corresponding shopping mall.|[0052] To this end, the management server 200 may include a buyer management unit 210, a seller management unit 220, a shopping mall management unit 230, a community management unit 240, and a database 250.|[0053] The purchaser management unit 210 is a component for managing subscription information including area information of the purchaser input from the purchaser terminal 100 and the purchaser terminal 1 (100a) to the purchaser terminal n (100n), authentication information, and transaction information of the environmental product, accumulation of purchaser points according to the transaction of the environmental product, and transaction of the accumulated purchaser points, and may be configured to include a purchaser information management unit 211 and a point information management unit 212.|[0054] The buyer information management unit 211 receives subscription information and authentication information including region information of the buyer individually input from the buyer terminal 100 and the buyer terminal 1 (100a) to the buyer terminal n (100n), transaction information of the environmental product through each of the buyer terminals 100, 100a to 100n, accumulation information of the buyer point according to the transaction of the environmental product, use information, and the like, and stores the received information in the database 250.|[0055] The point information management unit 212 manages a stock investment transaction so that at least a part of the buyer points can be invested and used as stocks so that the accumulated buyer points can be used by subtracting the accumulated buyer points from a transaction related to the purchase of another environmental product according to a use method set by the buyer or used by being used in a stock investment transaction based on arbitrary low-carbon emission seller information input by the user.|[0056] Such a buyer's stock investment transaction may form a "green communication" between sellers (or companies) and buyers who need carbon emission trading, and may activate the seller's voluntary carbon emission trading market. |[0057] The seller management unit 220 is a component for managing subscription information including area information of a low-carbon emission seller individually input from the seller terminal 300 and the seller terminal 1 (300a) to the seller terminal n (300n), authentication information, environmental product information including storytelling information of the seller, transaction information of the environmental product, carbon reduction activity information and carbon reduction knowledge information of the low-carbon emission seller, and may be configured to include a seller information management unit 221 and a product information management unit 222.|[0058] The seller information management unit 221 receives subscription information and authentication information of a low-carbon emission seller individually input from the seller terminal 300, the seller terminal 1 (300a) to the seller terminal n (300n), environmental product information including storytelling information of the seller, carbon reduction activity information for low-carbon emission of a seller who sells the environmental product, knowledge information for carbon reduction, and the like, and stores and manages the received information in the database 250.|[0059] The product information management unit 222 manages environmental product information individually input from the seller terminal 300, the seller terminal 1 300a, or the seller terminal n 300n, and transaction information with the individual buyer terminals 100, 100a, or 100n that purchases each environmental product information.|[0060] Here, the environmental product may include content information such as agricultural/fishery/livestock products, eco-friendly products, recycled products, and eco-friendly experience programs, application programs for forming and managing an eco-friendly community, and the like.|[0061] In addition, the storytelling information of the seller may be information for the seller to deliver a process of producing, selling, managing, distributing, and the like of the environmental product to the buyer.|[0062] The shopping mall management unit 230 manages the transaction of the environment product through the e-commerce between the buyer terminal 100, the buyer terminal 1 (100a) to the buyer terminal n (100n), the seller terminal 300, and the seller terminal 1 (300a) to the seller terminal n (300n), and stores the transaction result in the database 250.|[0063] In addition, the shopping mall management unit 230 may be configured to search for the seller terminal 300, 100a to 100n having the same regional information based on regional information of the buyer terminal 100, 300a to 300n when trading the environmental product, and display the environmental product of the searched seller terminal 300, 300a to 300n on the buyer terminal 100, 100a to 100n.|[0064] That is, the shopping mall management unit 230 manages the environmental product transaction between the buyer and the seller in the same area so that the carbon emission reduction activity can be performed through the environmental product transaction in the corresponding area.|[0065] The community management unit 240 may search and collect carbon reduction activity information and carbon reduction-related knowledge information for low carbon emission of the seller input from the seller management unit 220 through the database 250 or an external server connected through a network.|[0066] In addition, the community management unit 240 may analyze each of the low carbon emission seller and the carbon reduction technology based on the collected carbon reduction-related activity information and knowledge information of the seller, and individually transmit the analysis result to the purchaser terminal 100, the purchaser terminal 1 (100a), or the purchaser terminal n (100n) to manage the analysis result to be shared.|[0067] To this end, the community management unit 240 may include a carbon reduction information collection unit 241, a carbon reduction information analysis unit 242, and an analysis information management unit 243.|[0068] The carbon reduction information collection unit 241 is a component for collecting carbon reduction activity information and carbon reduction-related knowledge information of a seller for low carbon emission, and may collect carbon reduction activity information and carbon reduction-related knowledge information of the seller from the carbon reduction-related information of the seller input through the seller management unit 220 or an external public information providing server (e.g., the Korea Exchange, the U.S. Securities and Exchange Commission, etc.) accessed through a network.|[0069] The carbon reduction information analysis unit 142 may classify and analyze a seller for low carbon emission, ESG management information for carbon reduction, assembly business information for greenhouse gas reduction, BECCS, and carbon removal (CDR.) technologies based on the carbon reduction activity information and carbon reduction related knowledge information of the seller collected by the carbon reduction information collection unit 241.|[0070] The analysis information management unit 243 transmits the analysis result of the carbon reduction information analysis unit 142 to the individual buyer terminals 100, 100a to 100n to manage the analysis result to be shared, thereby allowing the individual buyer to check carbon reduction-related management information, facility investment information, and the like for low carbon emission for each seller.|[0071] The database 250 stores management information of the purchaser management unit 210, the seller management unit 220, the shopping mall management unit 230, and the community management unit 240.|[0072] The seller terminal 300 is a component that accesses the management server 200 through a network to perform electronic commerce with the plurality of buyer terminals 100, the buyer terminal 1 (100a) to the buyer terminal n (100n), and may be configured as a desktop PC, a notebook PC, a tablet PC, or a mobile terminal capable of installing any application program (app).|[0073] In addition, the seller terminal 300 may transmit, to the management server 200, seller's subscription information input by the seller, authentication information such as login, and transaction information related to orders such as environmental product information and payment for electronic commerce.|[0074] Here, the seller may include an agricultural/fisheries/livestock business operator or association, a general environment-related organization, an enterprise that produces and distributes eco-friendly or recycled products, a listed enterprise that needs to be traded in a voluntary carbon emission trading market, a public institution, and the like.|[0075] In addition, the seller terminal 300 may provide related information to the management server 200 so that the buyer can check the seller's activity information and knowledge information related to low carbon emission and carbon reduction, for example, ESG management report information, ESG management effort introduced or promoted in the production facilities of the seller or listed company in stages, assembly business information for greenhouse gas reduction, BECCS, and carbon removal (CDR.) related technology information.|[0077] Next, a transaction service method using carbon reduction information according to an embodiment of the present disclosure will be described.|[0078] FIG. 6 is a flowchart illustrating a transaction service method using carbon reduction information according to an embodiment of the present invention, FIG. 7 is a flowchart illustrating a process of collecting information of a buyer and a seller in the transaction service method using carbon reduction information according to the embodiment of FIG. 6, FIG. 8 is a flowchart illustrating a process of setting point use information in the process of collecting buyer information according to the embodiment of FIG. 7, and FIG. 9 is a flowchart illustrating a process of outputting carbon reduction information and investment product information in the transaction service method using carbon reduction information according to the embodiment of FIG. 6.|[0079] Referring to FIGS. 1 to 9, in the transaction service method using carbon reduction information according to an embodiment of the present disclosure, the management server 200 collects buyer information and seller information from a buyer terminal 100, a buyer terminal 1 (100a) to a buyer terminal n (100n), a seller terminal 300 of a low-carbon emission seller who sells environmental products, and a seller terminal 1 (300a) to a seller terminal n (300n) connected through a network (S100).|[0080] Describing step S100 in more detail, the management server 200 checks whether the input information is purchaser information or seller information.|[0081] As a result of the checking, if the purchaser information is the purchaser information, the management server 200 may perform purchaser authentication based on subscription information including the purchaser's region information and login information input from the individual purchaser terminals 100, 100a to 100n (S110).|[0082] In addition, the management server 200 may perform a process of searching for and displaying purchaser point information in the database 250 (S120) as the purchaser authentication in step S110 is completed, and setting use information of the purchaser point based on user setting information input from the purchaser terminal 100, 100a to 100n of the authenticated purchaser (S130).|[0083] In step S130, when any one of stock investment based on seller information for performing encashment or low carbon emission for using the use information of the buyer point set from each of the buyer terminals 100, 100a to 100n for the transaction of the environmental product is input (S131), the management server 200 may allow the buyer point to be used according to the input setting information.|[0084] In this case, when stock investment is input in step S131, the management server 200 sets buyer points as investments to set stock investment information or stock investment products based on seller information input from the corresponding buyer terminal 100, 100a to 100n (S132), and changes the buyer points into investments according to the set investment information to invest in the corresponding investment products or stocks of the seller (or company) (S133).|[0085] In addition, the management server 200 may search for and provide stock information or investment product information of a corresponding seller from a stock information providing server (not shown) linked through a network.|[0086] Meanwhile, although the encashment and stock investment by the buyer are described as being used for product payment of a seller or a company that sells environmental products in a shopping mall managed by the management server 200 or invested in stocks, the present disclosure is not limited thereto.|[0087] In addition, as a result of the checking in step S100, when the seller information is the seller information, the management server 200 performs seller authentication based on subscription information including regional information of the seller input from the individual seller terminals 300, 300a to 300n and login information (S110′). |[0088] In addition, when the seller authentication in step S110′ is completed, the management server 200 receives environmental product information including storytelling information of the seller for electronic commerce from the individual seller terminals 300, 300a to 300n (S120′) and stores the environmental product information in the database 150, and the environmental product information is disclosed in the shopping mall webpage.|[0089] In addition, the environmental product information in step S120′ may include content information such as agricultural/fishery/livestock products, eco-friendly products, recycled products, and eco-friendly experience programs, application programs for forming and managing an eco-friendly community, and the like.|[0090] In addition, in step S120′, the seller may additionally receive an input of the seller's storytelling information for delivering the seller's process of production, sale, management, distribution, and the like of the environmental product to the buyer.|[0091] In addition, the management server 200 receives carbon reduction activity information and carbon reduction-related knowledge information for low carbon emission input for each seller from the individual seller terminals 300, 300a to 300n (S130′) and stores the same in the database 150, and the carbon reduction activity information and the carbon reduction-related knowledge information are disclosed in the shopping mall webpage.|[0092] In addition, the management server 200 collects the carbon reduction activity information and the carbon reduction knowledge information for low carbon emission of the seller input in step S100, and transmits the collected information to the individual purchaser terminals 100, 100a to 100n to share the same (S200).|[0093] In step S200, the management server 200 may search for and collect the carbon reduction activity information and the carbon reduction knowledge information of the seller for low carbon emission input in step S100 (S210).|[0094] In step S210, the management server 200 may collect the carbon reduction-related information of the seller input from the individual seller terminals 300, 300a to 300n or the carbon reduction-related knowledge information and carbon reduction activity information of the seller from an external public information providing server (e.g., the Korea Exchange, the U.S. Securities and Exchange Commission, etc.) connected through a network.|[0095] In addition, the management server 200 may analyze and evaluate ESG management information for carbon reduction, assembly business information for greenhouse gas reduction, BECCS, carbon removal (CDR.), and the like for each technology based on the carbon reduction activity information and carbon reduction-related knowledge information of the seller collected in step S210 (S220), and may classify and extract the seller for low carbon emission according to the analyzed evaluation result (S230).|[0096] In addition, the management server 200 searches for seller information for low carbon emission and related investment product and stock information according to the carbon reduction information based on the analysis results of steps S220 and S230, and transmits the searched result together with the seller information and the carbon reduction information to the individual purchaser terminals 100, 100a to 100n to be disclosed and shared (S240), thereby allowing the individual purchaser to check carbon reduction-related management information, facility investment information, and the like for low carbon emission for each seller.|[0097] Subsequently, the management server 200 manages the transaction of the environmental product between the individual purchaser terminals 100, 100a to 100n and the seller terminals 300, 300a to 300n connected to the shopping mall website (S300).|[0098] In step S300, the management server 200 may search for the seller terminal 300, 100a, or 100n having the same area information based on the area information of the buyer terminal 100, 300a, or 300n so that the transaction of the environment product may be performed between the buyer and the seller in the same area, and preferentially provide the environment product of the searched seller terminal 300, 300a, or 300n to the buyer terminal 100, 100a, or 100n so that carbon emission reduction activities through the transaction of the environment product in the corresponding area may be performed.|[0099] In addition, the management server 200 determines whether a buyer point is generated by each of the buyer terminals 100, 100a to 100n performing a transaction of an environmental product with one or more seller terminals 300, 300a to 300n (S400).|[0100] As a result of the determination in step S400, when the buyer points are generated through the transaction of the environmental product, the management server 200 accumulates the generated buyer points as individual buyer points, and uses the accumulated buyer points for the transaction of another environmental product according to the setting information input from the corresponding buyer terminal 100, 100a to 100n, sets the stock investment transaction based on any low-carbon emission seller information to be performed, or manages the stock investment transaction to be performed in conjunction with a financial company server (not shown) so that some buyer points are used for the transaction of another environmental product and the rest are used for the stock investment transaction (S500).|[0101] Subsequently, the management server 200 may determine whether the access to the shopping mall web page is terminated after the e-commerce between the purchaser terminal 100, 100a to 100n and the seller terminal 300, 300a to 300n is terminated (S600).|[0102] As a result of the determination in step S600, when the connection termination is confirmed, the information set in steps S100 to S500 is stored in the database 250 (SS700).|[0103] Therefore, the present invention can share information and knowledge based on a carbon reduction activity by connecting a buyer and a low-carbon emission seller who sells an environmental product, and convert points of the buyer generated according to a transaction of the environmental product into stocks of the low-carbon emission seller to transact the same.|[0104] In addition, the buyer may share and confirm activity information and knowledge information of the seller related to low carbon emissions, carbon reductions, etc., and may utilize the voluntary carbon emission trading market by sellers who need carbon emission trading through trading with the buyer.|[0105] As described above, although it has been described with reference to preferred embodiments of the present disclosure, it will be understood by those skilled in the art that the present disclosure may be variously modified and changed without departing from the spirit and scope of the present disclosure described in the following claims.|[0106] In addition, the reference numerals described in the claims of the present disclosure are only described for clarity and convenience of description, and are not limited thereto, and in the process of describing the embodiments, the thicknesses of lines or the sizes of components shown in the drawings may be exaggerated for clarity and convenience of description.|[0107] In addition, the above-described terms are terms defined in consideration of functions in the present disclosure, which may vary depending on the intention or custom of a user or operator, and thus the interpretation of these terms should be made based on the contents throughout the present specification.|[0108] In addition, even if it is not explicitly shown or described, it is obvious that a person skilled in the art to which the present invention pertains can make various modifications including the technical idea of the present invention from the description of the present invention, and this still belongs to the scope of the present invention. |[0109] In addition, the embodiments described above with reference to the accompanying drawings are described for the purpose of describing the present disclosure, and the scope of the present disclosure is not limited to these embodiments.|REFERENCE SIGNS LIST|[0110] 100: purchaser terminal 100a: purchaser terminal 1 100n: purchaser terminal n 200: management server 210: purchaser management unit 211: purchaser information management unit 212: point information management unit 220: seller management unit 221: seller information management unit 222: product information management unit 230: shopping mall management unit 240: community management unit 241: carbon reduction information collection unit 242: carbon reduction information analysis unit 243: analysis information management unit 250: database 300: seller terminal 300a: seller terminal 1 300n: seller terminal n | Family Number|(111691506)|111691506|Advantages / Prev. Drawbacks|(KR102769477 B1)| (...) effort introduced or promoted in a production facility of a seller or a listed company in stages, selection information on green consumers, assembly business information for greenhouse gas reduction, bioenergy with carbon capture and storage (BECCS), and technology information related to Carbon Dioide Removal (CDR.).| | IT methods for management | G06Q-010/40|G06Q-030/02/16|G06Q-030/06/13|G06Q-040/04|G06Q-050/01|G06Q-050/10|G06Q-050/22|G06Q-050/26|G06Q-050/26/5 | G06Q-010/40|G06Q-030/02/16|G06Q-030/06/13|G06Q-040/04|G06Q-050/01|G06Q-050/10|G06Q-050/22|G06Q-050/26|G06Q-050/26/5 | G06Q-030/02|G06Q-030/06|G06Q-040/04|G06Q-050/00|G06Q-050/26 | G06Q-030/02|G06Q-030/06|G06Q-040/04|G06Q-050/00|G06Q-050/26 | KR102480019|KR102448618|KR20150071803|JP2001209732 | KR102480019 103112002 WHO=Examiner SELF=N|KR102448618 101965831 WHO=Examiner SELF=N|KR20150071803 70256724 WHO=Examiner SELF=N|JP2001209732 1426404 WHO=Examiner SELF=N | 한국 등록특허공보 등록번호 제10-1052789호(발명의 명칭: 탄소배출권 거래 중계 방법 및 시스템) | JP2001209732; KR20150071803; KR102448618; KR102480019 | GRANTED | (KR10-2769477)|GRANTED | ALIVE | (KR10-2769477)|ALIVE | (KR10-2769477)|LEGAL DETAILS FOR KR10-2769477|Actual or expected expiration date=2043-03-23|Legal state=ALIVE|Status=GRANTED|Event publication date=2023-03-23|Event code=KR/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=KR KR10-2023-0037657|Application date=2023-03-23|Standardized application number=2023KR-0037657|Event publication date=2024-10-02|Event code=KR/A|Event group=Examination events|Published application|Publication country=KR|Publication number=KR10-2024-0142963|Publication stage code=A|Publication date=2024-10-02|Standardized publication number=KR20240142963|Event publication date=2024-11-13|Event code=KR/E701|Event indicator=Pos|Event group=Examination events|Decision to grant or registration|Event publication date=2025-02-13|Event code=KR/GRNT|Event indicator=Pos|Event group=Examination events|Written decision to grant|Event publication date=2025-02-17|Event code=KR/B1|Event indicator=Pos|Event group=Event indicating In Force|Patent specification|Publication country=KR|Publication number=KR10-2769477|Publication stage code=B1|Publication date=2025-02-17|Standardized publication number=KR102769477|Event publication date=2026-02-27|Event code=KR/R18|CHANGES TO PARTY CONTACT INFORMATION RECORDED|St27 status event code: A-5-5-R10-R18-OTH-X000 (AS PROVIDED BY THE NATIONAL OFFICE) | (KR10-2769477)|KR | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=TF3wXQSsXsNDHvbjr0YSbiq6vml3jfM5bZEW38EL5eC5GkWmuuS7QKXL31I9s5RZSNnPjhgoLnPBB0W7Jy7i6Q==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=KR0000000007581530&ekey=2213&xpn=KR102769477&kind=B1 | https://doi.org/10.8080/1020230037657 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=nhns6TfVBF0FZvFIy%252BhYfJNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | KR | (KR10-2769477)|KR|(KR10-2024-0142963)|KR | (KR10-2769477)|NAME=MOON, Yoo Jung , COUNTRY=KR|(KR10-2024-0142963)|NAME=MOON, Yoo Jung , COUNTRY=KR | (KR10-2769477)|NAME=WOO, KWANG-JE|(KR10-2024-0142963)|NAME=WOO, KWANG-JE | (KR10-2769477)|NAME=MOON, Yoo Jung|NAME=SEO, Jaekwan|(KR10-2024-0142963)|NAME=MOON, YU JUNG|NAME=SEO JAE KWAN | (KR10-2769477)|9 | 1 | 1 | (KR10-2769477)|Number of Claims: NCL=13|Primary examiner: 복진요||(KR10-2024-0142963)|Number of Claims: NCL=13|Primary examiner: 복진요| | (KR10-2769477)|KOREAN (KOR) | (KR102769477)|Patent|(KR102769477)|Patent | Titre: (KR10-2769477)|Transaction service system and method using carbon reduction information Résumé: (KR10-2769477)|Disclosed are a transaction service system using carbon reduction information and a method thereof. The present invention connects a purchaser and a low carbon emission seller who sells an environmental product to share information and knowledge based on carbon reduction activities, and converts points of the purchaser generated according to the transaction of the environmental product into stocks of the low carbon emission seller to perform the transaction.COPYRIGHT MOIP 2025 Autre: (KR10-2769477)|1. A seller terminal (210) comprising: a buyer management unit (210) for managing subscription information including local information of a buyer, authentication information, transaction information of an environmental product, purchaser points accumulation according to transactions of the environmental product, and accumulated transactions of the purchaser points, while forming communication between the buyers and sellers who need carbon emission trading and setting the purchaser points as investment money to perform stock investment trading based on low-carbon emission seller information inputted from each purchaser terminal (100, 100a, 100n); a seller management unit (220) for managing environmental product information including local information of a low-carbon emission seller inputted from each seller terminal (300, 300a, 300n), authentication information, and storytelling information of the seller, wherein the storytelling information is information for the seller to deliver a process for production, sale, management, and distribution of the environmental product to the buyer; transaction information of the environmental product; carbon reduction activity information and carbon knowledge reduction information of the low-carbon emission seller; and a seller terminal (300, 300a, 300n) for managing transactions of the environmental product between the purchaser terminal (100, 100a, 100n) and the seller terminal (300, 100a, 100n), and having the same local information of the buyer terminal (100, 100a, 100n, 300a, 30, 300n) A transaction service system using carbon reduction information, comprising: a shopping mall management unit 230 configured to first provide an environmental product of the terminal 300 (300a to 300n) to the buyer terminal 100 (100a to 100n) to manage carbon emissions reduction through the environmental product transaction of a corresponding region; a community management unit 240 configured to collect activity information and knowledge information of a seller related to low carbon emissions and carbon reductions from the seller terminal 300 (300a to 300n), analyze the collected activity information and knowledge information for each low carbon emission seller and carbon reduction technology based on the carbon reduction-related activity information and knowledge information of the seller, and manage the analyzed information to be shared with the buyer terminal 100 (100a to 100n); and a management server 200 including a database 250 configured to store management information of the buyer management unit 210, the seller management unit 220, the shopping mall management unit 230, and the community management unit 240.|2. AMENDSTATUS: Delete|3. AMENDSTATUS: Delete|4. The transaction service system of claim 1, wherein the buyer management unit (210) comprises: a buyer information management unit (211) configured to accumulate subscription information including region information of a buyer inputted from the buyer terminal (100, 100a to 100n), authentication information, transaction information of an environmental product, and buyer point information according to a transaction of the environmental product; and a point information management unit (212) configured to set the accumulated buyer points as investments according to seller information inputted from the buyer terminal (100, 100a to 100n) to perform a stock investment transaction based on stock investment information or a stock investment product.|5. The transaction service system of claim 1, wherein the seller management unit (220) comprises: a seller information management unit (221) configured to manage subscription information including regional information of a low carbon emission seller inputted from the seller terminal (300, 300a to 300n), authentication information, carbon reduction activity information of the low carbon emission seller, and carbon reduction knowledge information; and a product information management unit (222) configured to manage the environmental product information and transaction information with the purchaser terminal (100, 100a to 100n).|6. AMENDSTATUS: Delete|7. The transaction service system of claim 1, wherein the community management unit 240 includes: a carbon reduction information collection unit 241 configured to collect carbon reduction activity information and carbon reduction knowledge information of a low carbon emission seller input to the seller management unit 220; a carbon reduction information analysis unit 242 configured to analyze the collected carbon reduction related information for each low carbon emission seller and carbon reduction technology based on the collected carbon reduction related information; and an analysis information management unit 243 configured to transmit the analysis result to the purchaser terminal 100 (100a to 100n) and manage the analysis result to be shared.|8. A) a step in which the management server 200 collects activity information and knowledge information of a seller related to low carbon emission and carbon reduction from the seller terminals 300, 100a, and 100n, collects activity information and knowledge information of the seller related to the low carbon emission and carbon reduction from the seller terminals 300, 300a, and 300n, and analyzes the collected activity information and knowledge information related to carbon reduction of the seller for each low carbon emission seller and carbon reduction technology on the basis of the collected activity information and knowledge information related to carbon reduction of the seller to manage the low carbon emission seller and the low carbon reduction technology to be shared with the buyer terminals 100, 300a, and 300n, and b) a step in which the management server 200 manages an environmental transaction between the buyer terminals 100, 100a, and 100n and the seller terminals 300, 100a, and 100n, searches for a seller terminal 300, 300a, and 300n having the same regional information on the basis of regional information of the buyer terminals 100, 100a, and 100n, and provides the searched environmental product to the buyer terminals 100, 300a, 300n, 300a, and 300n to preferentially manage the environmental transaction between the buyer terminals 100, 300, and 100a A transaction service method using carbon reduction information, comprising: managing so that carbon emissions are reduced through local environmental product transactions and determining whether a buyer point is generated by a certain buyer terminal 100(100n to 100a) performing a transaction of an environmental product with one or more seller terminals 300(100n to 300a); and managing so that individual buyer points generated by the management server 200 according to generation of a buyer point through the transaction of the environmental product are accumulated, the accumulated buyer points are set as investments to form communication between buyers and sellers who need a carbon emission right transaction, and stock investment transactions are performed based on low-carbon emission seller information input from each buyer terminal 100(300n to 100a 100n).|9. AMENDSTATUS: Delete|10. AMENDSTATUS: Delete|11. AMENDSTATUS: Delete|12. AMENDSTATUS: Delete|13. AMENDSTATUS: Delete | 12 | Abstract | gpt-4o-mini | no | The article focuses on a transaction service system related to carbon reduction information and does not describe a system involving biomass energy production combined with carbon capture and storage. | |||||||||||||||||||||
| 13 | CN202410486464 | CN202410486464 | CN118684553 | 111559278 | CN118684553 A 2024-09-24 [CN118684553] | 2024-04-22 | 2024-04-22 | 2024-09-24 | (CN118684553)|2044-04-22 | (CN118684553)|Preparation process and system of renewable methanol | (CN118684553)|The invention provides a renewable methanol preparation process and system. The renewable methanol preparation process comprises the following steps: A, preparation of renewable hydrogen: preparing renewable hydrogen and renewable oxygen from renewable energy power generation electrolyzed water; b, preparing renewable carbon dioxide and recycling by-products: fermenting biomass to generate biogas, then separating renewable methane and renewable carbon dioxide from the biogas, continuously synthesizing renewable carbon dioxide and water from the renewable methane and the renewable oxygen in the step A, and generating heat energy; c, preparing renewable methanol and recycling by-products: synthesizing the two parts of renewable carbon dioxide in the step B and the renewable hydrogen in the step A into renewable methanol and water, and generating heat energy; wherein water and heat energy generated in the steps B and C are circulated to the step A. According to the method, the carbon content conversion rate of converting the carbon content in the biogas generated by biomass fermentation into renewable carbon dioxide is increased to 99.1%, so that the renewable methanol with low carbon in the whole process is generated, and the cost is reduced. | QIANQIAN TECHNOLOGY DEVELOPMENT SHANGHAI | (CN118684553)|QIANQIAN TECHNOLOGY DEVELOPMENT (SHANGHAI) CO., LTD. ([CN]) | XU JIECHUN|XU JINGYAN | (CN118684553)|XU JIECHUN|XU JINGYAN | (CN118684553)|REN NING;SHANGHAI HANGSOME INTELLECTUAL PROPERTY LTD.|Reg. Nb: 31236|HU JING;SHANGHAI HANGSOME INTELLECTUAL PROPERTY LTD.|Reg. Nb: 31236 | (CN118684553)|By adopting the technical scheme, the invention has the following advantages and positive effects compared with the prior art:|The advantages and features of the present invention will become more apparent from the following description.|The hydrogen production method by alkaline water electrolysis is a preferred hydrogen production method in the embodiment, and the hydrogen production method by alkaline water electrolysis has the advantages of simple process and easy operation.|Currently renewable methanol is divided into two major categories, biological methanol and green methanol, and the shortcomings of the current solutions are as follows: biological methanol produced from biomass, wherein the main production mode such as a fluidized bed method consumes a large amount of energy, or the conversion rate of the produced methanol is low, and the conversion rate is accompanied by a large amount of carbon dioxide release into the atmosphere, the carbon reduction effect is not ideal from the viewpoints of carbon metering and carbon emission reduction; the related art of using carbon dioxide captured from renewable resources such as bioenergy captured and stored in carbon (BECCS) and Direct Air (DAC) and renewable methanol produced from renewable hydrogen produced by renewable energy power generation is currently not mature, is extremely costly, and requires waiting for the technology to mature.| | (CN118684553)|1. A process for the preparation of renewable methanol, comprising the steps of: a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; B: renewable carbon dioxide preparation and byproduct recycling: biomass is fermented to generate biogas, renewable methane and renewable carbon dioxide are separated from the biogas, the renewable methane and renewable oxygen in the step A are continuously synthesized into renewable carbon dioxide and water, heat energy is generated, the generated water and heat energy can be recycled to the step A, and the renewable carbon dioxide and the water continuously participate in the reaction; c: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |7. A system for producing renewable methanol, comprising: anaerobic fermentation device, gas separation device, electrolytic water hydrogen production device, synthesis reaction device and methanol synthesis device; the renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the methanol synthesis device; The renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the synthesis reaction device; The biomass is fermented by the anaerobic fermentation device, the anaerobic fermentation device is connected with the gas separation device, and the gas separation device is used for separating renewable methane and renewable carbon dioxide; the renewable methane outlet of the gas separation device is connected with the synthesis reaction device, and the renewable carbon dioxide outlet of the gas separation device is connected with the raw material inlet of the methanol synthesis device; the renewable carbon dioxide outlet of the synthesis reaction device is connected with the raw material inlet of the methanol synthesis device, and the water outlet of the synthesis reaction device is connected with the water inlet of the water electrolysis device; The heat energy of the synthesis reaction device provides needed and/or renewable electric energy for the water electrolysis hydrogen production device through a heat exchange mode. | | (CN118684553)|Based on the technical problems, the invention provides a renewable methanol preparation process and a renewable methanol preparation system, which are characterized in that renewable carbon dioxide and renewable methane are separated from gas generated by biomass fermentation, the renewable carbon dioxide is synthesized by the renewable methane and renewable oxygen generated by electrolysis of water of renewable power, and the renewable methanol is synthesized by the renewable carbon dioxide and the renewable hydrogen generated by electrolysis of water.|The invention also provides a preparation system of renewable methanol, which comprises: anaerobic fermentation device, gas separation device, electrolytic water hydrogen production device, synthesis reaction device and methanol synthesis device;|The invention provides a renewable methanol preparation process and a renewable methanol preparation system, wherein the renewable methanol preparation process comprises the following steps: a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; b: renewable carbon dioxide preparation and byproduct recycling: generating biogas by fermenting biomass, separating renewable methane and renewable carbon dioxide from the biogas, continuously synthesizing renewable carbon dioxide and water by the renewable methane and renewable oxygen in the step A, and generating heat energy; c: renewable methanol preparation and byproduct recycling: synthesizing renewable methanol and water by the two parts of renewable carbon dioxide in the step B and the renewable hydrogen in the step A, and generating heat energy; wherein the water and thermal energy produced in steps B and C are recycled to step a.| | (CN118684553)|RENEWABLE METHANOL(100,37)|PRODUCING RENEWABLE METHANOL(100,3)|ANAEROBIC FERMENTATION(66,12)|RENEWABLE CARBON DIOXIDE(61,48)|BYPRODUCT RECYCLING(61,8)|RENEWABLE METHANE(58,20)|SEPARATING RENEWABLE METHANE(49,4)|RENEWABLE OXYGEN(48,19)|BIOMASS FERMENTATION(48,6)|METHANOL SYNTHESIS(43,15)|RENEWABLE HYDROGEN(31,29)|ELECTROLYTIC WATER(31,21)|RENEWABLE METHANE OUTLET(29,3)|CARBON METERING VIEWPOINT(29,1)|BIOGAS(26,15)|RENEWABLE METHANOL SYNTHESIS TOWER(26,2)|CARBON DIOXIDE(24,75)|RENEWABLE OXYGEN OUTLET(23,3)|BIOMASS(22,10)|SYNTHESIS REACTION(20,37)|ELECTROLYTIC WATER HYDROGEN PRODUCTION(20,20)|MAJOR CATEGORY(20,1)|GENERATION ELECTROLYZED WATER(18,4)|CARBON METERING(18,1)|METHANE OUTLET(17,3)|RENEWABLE METHANOL PREPARATION(16,3)|HYDROGEN PRODUCTION(15,33)|GREEN METHANOL(15,2)|RENEWABLE HYDROGEN OUTLET(14,4)|BIOENERGY(14,1)|GAS SEPARATION(13,17)|CARBON DIOXIDE OUTLET(13,7)|RENEWABLE ENERGY POWER(13,4)|BIOGAS PRODUCTION(13,1)|FLUIDIZED BED(13,1)|HEAT ENERGY(12,38)|METHANOL PREPARATION(12,3)|RENEWABLE METHANOL PRODUCT(12,3)|RENEWABLE METHANOL SYNTHESIS REACTION(12,2)|RENEWABLE RESOURCE(12,2)|BECCS(12,1)|RENEWABLE POWER(11,17)|UNREACTED GAS(11,8)|REGENERATING TOWER(11,7)|ALKALI ELECTROLYTIC TANK(11,4)|PRODUCED METHANOL(11,1)|PRODUCTION MODE(11,1)|WAITING(11,1)|WATER GENERATION(10,8)|ELECTROLYSIS(10,4)|BIOMASS ELECTRIC ENERGY(10,3)|RENEWABLE ELECTRIC ENERGY(10,3)|RAW MATERIAL INLET(9,12)|RECOVERY TOWER(9,7)|WATER ELECTROLYSIS(9,6)|WATER INLET(9,3)|WATER OUTLET(9,3)|WATER ELECTROLYSIS WATER INLET(9,2)|RENEWABLE HYDROGEN GAS(9,1)|ADSORPTION TOWER(8,4)|CONVERSION RATE(8,4)|ALKALINE WATER ELECTROLYSIS(8,3)|RENEWABLE POWER WATER(8,1)|COMPRESSOR COMBINATION(7,10)|SOLID OXIDE ELECTROLYTIC TANK(7,6)|CARBON CONTENT(7,5)|CARBON EMISSION REDUCTION(7,4)|POULTRY MANURE(7,3)|RENEWABLE ENERGY(7,3)|TOWER PRESSURIZATION(7,3)|PRESSURIZED RECTIFYING TOWER(7,2)|RENEWABLE HYDROGEN REACTION RATIO(7,2)|PRESSURIZING TOWER REBOILER(7,1)|ABSORPTION TOWER(6,3)|DEOXIDIZING TOWER(6,2)|RECTIFYING CABINET(6,2)|SYNTHESIS TOWER SHELL(6,2)|WATER ELECTROLYSIS HYDROGEN PRODUCTION(6,2)|ADSORBED IMPURITY DESORPTION(6,1)|CARBON REDUCTION(6,1)|PRESSURIZED RECTIFICATION TOWER(6,1)|REGENERATED LEAN ABSORBENT(6,1)|REGENERATION TOWER REFLUX TANK(6,1)|TOWER KETTLE REBOILER(6,1)|RENEWABLE ENERGY SOURCE(5,10)|ANION EXCHANGE MEMBRANE(5,5)|CARBON CONSUMPTION(5,5)|PROTON EXCHANGE MEMBRANE(5,5)|ELECTROLYSIS CELL(5,3)|HEAT EXCHANGE MODE(5,3)|RENEWABLE METHANE SYNTHESIS REACTION(5,3)|ELECTROLYTE CIRCULATION(5,2)|TOWER GAS PREHEATER(5,2)|ATMOSPHERIC RECTIFICATION TOWER(5,1)|CHINESE METHANOL PRODUCTIVITY(5,1)|REGENERATION TOWER REFLUX PUMP(5,1)|HEAT EXCHANGE(4,4)|NITROGEN REPLACEMENT(4,3)|PRODUCED RENEWABLE METHANOL(4,3)|REFINED METHANOL PRODUCT(4,3)|ELECTROLYSIS CHAMBER(4,2)|PURIFICATION TANK(4,2)|ADSORPTION DRYING TOWER(4,1)|AIRTIGHTNESS INSPECTION(4,1)|ALKALI LIQUOR CIRCULATION(4,1)|AVIATION TRANSPORTATION(4,1)|DEOXIDIZATION TOWER(4,1)|FLASHED CRUDE METHANOL(4,1)|OXYHYDROGEN SEPARATOR(4,1)|RAILWAY TRANSPORTATION(4,1)|RENEWABLE RESOURCE INSTABILITY(4,1)|VACUUM RECTIFICATION TOWER(4,1)|VACUUM TOWER KETTLE(4,1)|RAW MATERIAL GAS(3,9)|ELECTROLYZED WATER RAW MATERIAL(3,4)|ELECTROLYZE WATER(3,3)|FORESTRY ORGANIC MATTER(3,3)|LIVESTOCK(3,3)|ALKALI LIQUOR HEAT EXCHANGER(3,2)|ELECTROLYZING(3,2)|GAS EVACUATION(3,2)|ALKALI LIQUOR BOX(3,1)|ALKALINE ELECTROLYTIC TANK(3,1)|CRUDE METHANOL PUMP(3,1)|DECARBONIZATION TOWER BOTTOM PUMP(3,1)|ECONOMIC REQUIREMENT(3,1)|EXCESS HYDROGEN(3,1)|GREEN CONCEPT(3,1)|HARMFUL EMISSION(3,1)|METHANOL SEPARATOR(3,1)|OXYGEN SEPARATOR(3,1)|PREHEAT TOWER GAS(3,1)|PUMPING ELECTROLYTE(3,1)|RENEWABLE CONCEPT(3,1)|RICH ABSORBENT(3,1)|SUSTAINABLE METHANOL COST(3,1)|TOWER FEED(3,1)|TOWER INLET GAS PREHEATER(3,1)|VEHICLE TRANSPORTATION(3,1)|CARBON DIOXIDE GAS(2,4)|LIGHT COMPONENT REMOVAL TOWER(2,4)|REACTION HEAT ENERGY CONDITION(2,4)|RENEWABLE SECONDARY ENERGY SOURCE(2,3)|AGRICULTURE(2,2)|METHANOL AQUEOUS SOLUTION(2,2)|RECTIFIER(2,2)|RENEWABLE ELECTRICAL POWER(2,2)|WATER CONDENSATION(2,2)|ALCOHOL AMINE ABSORBENT(2,1)|ELECTRICITY GENERATION(2,1)|ENVIRONMENT FRIENDLY INDEX MONITORING(2,1)|FLASH TANK(2,1)|HYDROGEN CONDENSATION(2,1)|LIQUID CRUDE METHANOL(2,1)|LYE CIRCULATION SIZE(2,1)|METHANOL VAPOR(2,1)|PHOTOVOLTAIC ENERGY(2,1)|PRESSURIZING TOWER HEATING SOURCE(2,1)|PRODUCED SUSTAINABLE METHANOL(2,1)|PROPORTION(2,1)|REGENERATION TOWER BOTTOM PUMP(2,1)|RESIDUAL METHANOL(2,1)|RICH SOLVENT(2,1)|SEPARATING RENEWABLE CARBON DIOXIDE(2,1)|SYNTHESIS STEAM DRUM(2,1)|TOWER OUTLET GAS(2,1)|UNABSORBED GAS(2,1)|ABSORBING HEAT EXCHANGER(1,1)|ALKALINE AQUEOUS SOLUTION(1,1)|ANODE REACTION(1,1)|AUTOMATIC VALVE(1,1)|BIOMASS ELECTRICAL ENERGY(1,1)|BIOMASS ENERGY UTILIZATION(1,1)|BOOSTING(1,1)|BYPRODUCT(1,1)|CATALYTIC OXIDATION REACTION(1,1)| | (CN118684553)|1. A process for the preparation of renewable methanol, comprising the steps of:| a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; | B: renewable carbon dioxide preparation and byproduct recycling: biomass is fermented to generate biogas, renewable methane and renewable carbon dioxide are separated from the biogas, the renewable methane and renewable oxygen in the step A are continuously synthesized into renewable carbon dioxide and water, heat energy is generated, the generated water and heat energy can be recycled to the step A, and the renewable carbon dioxide and the water continuously participate in the reaction; | c: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |2. The process for the preparation of renewable methanol according to claim 1, wherein said step a comprises in particular: renewable energy sources are adopted to generate electricity to obtain renewable power, and the renewable power is combined with various electrolytic tanks to electrolyze water to prepare renewable hydrogen and renewable oxygen;| The electrolytic tank is selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank. |3. The process for the preparation of renewable methanol according to claim 1, wherein said step B comprises in particular:| b01: the biomass is used for producing biogas by anaerobic fermentation, and the biogas is physically separated into renewable methane and renewable carbon dioxide according to different specific gravities; | And B02: the renewable methane reacts with renewable oxygen in a synthesis reaction device to generate renewable carbon dioxide and water, and heat energy and water are generated and used for the reaction heat energy conditions of the step A and the raw materials of the electrolyzed water; and/or converting the heat energy into biomass electric energy to provide electric energy for the electrolyzed water in the step A. |4. The process for the preparation of renewable methanol according to claim 1, wherein said step C comprises in particular:| The two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction; heat energy and water are used for the reaction heat energy conditions of the step A and the raw materials of the electrolyzed water; and/or converting the heat energy into biomass electric energy to provide electric energy for the electrolyzed water in the step A. |5. The process for the preparation of renewable methanol according to claim 4, wherein said step C comprises: the reaction ratio of the renewable hydrogen to the renewable carbon dioxide is adjusted to be more than or equal to 3:1, the synthesis reaction is carried out under the action of the catalyst, and the renewable methanol product meeting the standard is obtained after rectification and water separation are carried out to remove impurities.|6. The process for producing renewable methanol according to claim 4, wherein renewable carbon dioxide is compressed to 1.6MPa for the first time, mixed with renewable hydrogen gas to 2.0MPa for the second time, and then mixed with unreacted gas in the renewable methanol synthesis reaction to 8.0MPa for the third time; the raw material gas after three times of compression enters a renewable methanol synthesis tower system for synthesis reaction, and unreacted gas returns to be mixed and compressed with the raw material gas.|7. A system for producing renewable methanol, comprising: anaerobic fermentation device, gas separation device, electrolytic water hydrogen production device, synthesis reaction device and methanol synthesis device;| the renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the methanol synthesis device; | The renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the synthesis reaction device; | The biomass is fermented by the anaerobic fermentation device, the anaerobic fermentation device is connected with the gas separation device, and the gas separation device is used for separating renewable methane and renewable carbon dioxide; the renewable methane outlet of the gas separation device is connected with the synthesis reaction device, and the renewable carbon dioxide outlet of the gas separation device is connected with the raw material inlet of the methanol synthesis device; the renewable carbon dioxide outlet of the synthesis reaction device is connected with the raw material inlet of the methanol synthesis device, and the water outlet of the synthesis reaction device is connected with the water inlet of the water electrolysis device; | The heat energy of the synthesis reaction device provides needed and/or renewable electric energy for the water electrolysis hydrogen production device through a heat exchange mode. | (CN118684553)|TECHNICAL FIELD|Technical Field|[0001] The invention belongs to the technical field of methanol preparation and renewable energy and biomass energy utilization, and particularly relates to a preparation process and a system of renewable methanol.|BACKGROUND ART|[0002] Methanol (CH 3 OH) is the simplest, safest, most easily stored and transported liquid carbon hydroxide. By the end of 2022, the productivity of Chinese methanol has been nearly 12,000 ten thousand tons/year, and the main raw materials are derived from fossil fuels such as coal and natural gas.|[0003] Renewable methanol (CH 3 OH) can replace fossil fuels to reduce greenhouse gas (GHG) emissions, and in some cases other harmful emissions (e.g., sulfur oxides (SO X), nitrogen oxides (NO X), aerosols (PM), etc.), and the carbon emission reduction effect is obvious from the transportation and shipping industries.|[0004] The physical properties of the renewable methanol (CH 3 OH) are the same as those of the traditional methanol (CH 3 OH), the methanol (CH 3 OH) is an important intermediate product of chemical raw materials, the chemical product system which can be synthesized by the methanol (CH 3 OH) is huge, and the original production facilities are not required to be changed by using the renewable methanol (CH 3 OH). The carbon emission reduction effect of the chemical industry is direct and obvious.|[0005] Renewable methanol (CH 3 OH) converts renewable energy sources such as wind energy, photovoltaic energy, biomass energy and the like into renewable secondary energy sources, namely hydrogen (H 2), and converts and stores the renewable secondary energy sources through the combination of biomass energy and carbon dioxide, so that the renewable secondary energy sources are safer and are more convenient to store and transport, and various transportation systems such as aviation transportation, railway transportation, ship transportation and vehicle transportation can use the renewable methanol to achieve the aim of reducing carbon emission.|[0006] Currently renewable methanol is divided into two major categories, biological methanol and green methanol, and the shortcomings of the current solutions are as follows: biological methanol produced from biomass, wherein the main production mode such as a fluidized bed method consumes a large amount of energy, or the conversion rate of the produced methanol is low, and the conversion rate is accompanied by a large amount of carbon dioxide release into the atmosphere, the carbon reduction effect is not ideal from the viewpoints of carbon metering and carbon emission reduction; the related art of using carbon dioxide captured from renewable resources such as bioenergy captured and stored in carbon (BECCS) and Direct Air (DAC) and renewable methanol produced from renewable hydrogen produced by renewable energy power generation is currently not mature, is extremely costly, and requires waiting for the technology to mature.|DISCLOSURE|Disclosure of Invention|[0007] Based on the technical problems, the invention provides a renewable methanol preparation process and a renewable methanol preparation system, which are characterized in that renewable carbon dioxide and renewable methane are separated from gas generated by biomass fermentation, the renewable carbon dioxide is synthesized by the renewable methane and renewable oxygen generated by electrolysis of water of renewable power, and the renewable methanol is synthesized by the renewable carbon dioxide and the renewable hydrogen generated by electrolysis of water.|[0008] In order to achieve the above purpose, the technical scheme of the invention is as follows:|[0009] A process for the preparation of renewable methanol comprising the steps of: |[0010] a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; |[0011] B: renewable carbon dioxide preparation and byproduct recycling: biomass is fermented to generate biogas, renewable methane and renewable carbon dioxide are separated from the biogas, the renewable methane and renewable oxygen in the step A are continuously synthesized into renewable carbon dioxide and water, heat energy is generated, the generated water and heat energy can be recycled to the step A, and the renewable carbon dioxide and the water continuously participate in the reaction; |[0012] c: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |[0013] Preferably, the step a specifically includes: generating electricity by using renewable energy sources to obtain renewable power, wherein the renewable power is combined with various electrolytic tanks to electrolyze water to prepare renewable hydrogen and renewable oxygen; the electrolytic tank is selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank.|[0014] Preferably, the step B specifically includes:|[0015] b01: the biomass is subjected to anaerobic fermentation to produce the biogas, and the biogas is physically separated into the renewable methane and the renewable carbon dioxide according to different specific gravities; |[0016] And B02: the renewable methane and renewable oxygen react in the synthesis reaction device to generate renewable carbon dioxide and water, and heat energy is generated, the heat energy and water are used for the reaction heat energy condition of the step A and the raw material of the electrolyzed water, and/or the heat energy can be converted into biomass electric energy, namely the renewable electric power of the step A participates in the reaction. |[0017] Preferably, the step C specifically includes:|[0018] The two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction; heat energy and water are used for the reaction heat energy conditions of the step A and the raw materials of the electrolyzed water; and/or the thermal energy may also be converted into biomass electrical energy, i.e. the renewable power of step a participates in the reaction. |[0019] Preferably, the step C specifically includes: the reaction ratio of the renewable hydrogen to the renewable carbon dioxide is adjusted to be more than or equal to 3:1, the synthesis reaction is carried out under the action of the catalyst, and the renewable methanol product meeting the standard is obtained after rectification and water separation are carried out to remove impurities.|[0020] Preferably, the renewable carbon dioxide is compressed to 1.6MPa for the first time, mixed with renewable hydrogen for the second time to 2.0MPa, and then mixed with unreacted gas (recycle gas) in the renewable methanol synthesis reaction for the third time to 8.0MPa; the raw material gas after three times of compression enters a renewable methanol synthesis tower device for synthesis reaction, and unreacted gas (circulating gas) returns to be mixed with the raw material gas for compression.|[0021] The invention also provides a preparation system of renewable methanol, which comprises: anaerobic fermentation device, gas separation device, electrolytic water hydrogen production device, synthesis reaction device and methanol synthesis device;|[0022] the renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the methanol synthesis device; |[0023] The renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the synthesis reaction device; |[0024] The biomass is fermented by the anaerobic fermentation device, the anaerobic fermentation device is connected with the gas separation device, and the gas separation device is used for separating renewable methane and renewable carbon dioxide; the renewable methane outlet of the gas separation device is connected with the synthesis reaction device, and the renewable carbon dioxide outlet of the gas separation device is connected with the raw material inlet of the methanol synthesis device; the renewable carbon dioxide outlet of the synthesis reaction device is connected with the raw material inlet of the methanol synthesis device, and the water outlet of the synthesis reaction device is connected with the water inlet of the water electrolysis device; |[0025] The heat energy of the synthesis reaction device provides needed and/or renewable electric energy for the water electrolysis hydrogen production device through a heat exchange mode, and further, the heat energy can be directly provided for a high-temperature solid oxide electrolytic tank. |[0026] By adopting the technical scheme, the invention has the following advantages and positive effects compared with the prior art:|[0027] The renewable hydrogen generated by renewable electric power and renewable carbon dioxide in methane generated after biomass fermentation are used as sources of raw materials in the renewable methanol preparation process, and in order to improve the conversion efficiency, renewable oxygen generated by renewable electric power and renewable methane in methane generated after biomass fermentation continue to react to obtain the conversion efficiency of converting the carbon content in the methane into the carbon content of renewable carbon dioxide, wherein the carbon content in the methane is up to 99.1%, so that the carbon consumption generated by the system and the cost of sustainable methanol are reduced. Meanwhile, heat energy and pure water generated by the synthesis reaction of renewable methane and renewable oxygen can be converted into renewable power, so that renewable power and electrolysis water required by the operation of various electrolytic tank devices are supplemented, and the carbon consumption of the system and the cost of the produced sustainable methanol are further reduced. |DRAWINGS DESCRIPTION|[0028] FIG. 1 is a process flow for the preparation of renewable methanol in an embodiment of the present invention.|INVENTION MODE|Detailed Description|[0029] The process and system for preparing renewable methanol according to the present invention will be described in further detail with reference to the accompanying drawings and examples. The advantages and features of the present invention will become more apparent from the following description.|[0030] In the traditional methanol synthesis system, methane is usually treated and simply decomposed into methane and carbon dioxide, wherein the methane is only sold and profitable in a liquefied natural gas mode after being simply purified and filtered, and the liquefied natural gas is usually used for supplying heat in a combustion mode, and the generated carbon dioxide is directly discharged; the carbon dioxide decomposed by the biogas is usually directly discharged, and if the biogas is captured and utilized, the carbon conversion rate is only 30-35%, and the method does not meet the thought of reducing the carbon emission under the view of the current double-carbon requirement. In the preparation process of the renewable methanol, the conversion rate of the carbon content in the methane to the renewable carbon dioxide is improved to 99.1%, so that the preparation process meets the low-carbon emission requirement and the economic requirement.|[0031] The renewable concepts herein have the same meaning as the general green concepts: such as renewable methanol=green methanol, renewable hydrogen=green hydrogen, and the like.|[0032] Example 1|[0033] Referring to fig. 1, a renewable methanol preparation process comprises the steps of:|[0034] a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; |[0035] B: renewable carbon dioxide preparation and byproduct recycling: generating biogas by biomass fermentation, separating renewable methane and renewable carbon dioxide from the biogas, continuously synthesizing the renewable carbon dioxide and water by the renewable methane and renewable oxygen in the step A, and generating heat energy, wherein the generated water and heat energy can be recycled to the step A to continuously participate in the reaction; |[0036] C: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |[0037] The step A specifically comprises the following steps: renewable energy sources such as wind energy, solar energy, biomass energy, nuclear energy and the like are adopted to generate renewable power, and the renewable power is combined with electrolysis of water in an electrolytic cell to prepare renewable hydrogen and renewable oxygen;|[0038] The electrolytic tank is selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank. |[0039] The heat energy generated in the synthesis reaction process of renewable methane and renewable hydrogen can be directly used in the heating process in the scheme of preparing hydrogen by using the high-temperature solid oxide electrolytic cell to electrolyze water (SOEC), so that the carbon consumption of a preparation process system and the cost of the produced renewable methanol are further reduced.|[0040] The step B specifically comprises the following steps:|[0041] B01: the biomass is produced by anaerobic fermentation, the biogas is physically separated into renewable methane and renewable carbon dioxide according to different specific gravities, and the biomass can be agriculture and forestry organic matters, livestock and poultry manure, waste and municipal waste generated in industrial and agricultural production processes; |[0042] and B02: the renewable methane and the renewable hydrogen are synthesized in a synthesis reaction device to generate renewable carbon dioxide and water: CH 4+2O2→CO2+2H2 O and generates heat energy, which is used to electrolyze water in step a. |[0043] The step C specifically comprises the following steps: the ratio of the renewable hydrogen to the renewable carbon dioxide is more than or equal to 3:1, so that the renewable carbon dioxide is ensured to fully react, the synthesis reaction is carried out under the action of the catalyst, and the renewable methanol product meeting the standard is obtained after the impurities are removed by rectification and water separation.|[0044] The synthesis reaction of methanol is as follows: CO 2+3H2→CH3OH+H2 O|[0045] Further, the renewable carbon dioxide is compressed to 1.6MPa for the first time, purified, mixed with renewable hydrogen for the second time to 2.0MPa, and then mixed with unreacted gas (namely recycle gas) in the synthesis reaction for the third time to 8.0MPa;|[0046] The raw material gas after three times of compression enters a methanol synthesis tower device for synthesis reaction, and unreacted gas (namely recycle gas) returns to be mixed with the raw material gas for compression. |[0047] The renewable methanol preparation source provided in this embodiment is renewable hydrogen generated by renewable power and renewable carbon dioxide in biogas generated after biomass fermentation, and in order to improve conversion efficiency, renewable oxygen generated by renewable power and renewable methane in biogas generated after biomass fermentation are continuously reacted to obtain conversion efficiency of converting carbon content in biogas to carbon content of renewable carbon dioxide up to 99.1%, so as to reduce carbon consumption produced by the system and cost of renewable methanol. Meanwhile, heat energy and pure water generated by the synthesis reaction of renewable methane and renewable oxygen can be converted into renewable power, so that the renewable power and electrolysis water required by the operation of various electrolytic tank devices are supplemented, and the carbon consumption of a process system and the cost of the produced renewable methanol are further reduced. In particular, the heat energy generated by the synthesis reaction of renewable methane and renewable oxygen can be directly used in the heating process in the scheme of water electrolysis (SOEC) hydrogen production in a high-temperature solid oxide electrolytic cell, so that the carbon consumption of the system and the cost of the produced renewable methanol are further reduced.|[0048] Example 2|[0049] Referring to fig. 1, a system for producing renewable methanol, comprising: anaerobic fermentation device, gas separation device, synthesis reaction device, methanol synthesis device and electrolytic water hydrogen production device,|[0050] Renewable power generated by renewable energy sources such as wind energy, solar energy and the like is combined with an electrolytic water hydrogen production device, the electrolytic water hydrogen production device is used for generating renewable hydrogen by electrolyzing water, a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of a synthesis reaction device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of a methanol synthesis device;|[0051] The biomass is fermented into methane through an anaerobic fermentation device, the anaerobic fermentation device is connected with a gas separation device, the gas separation device is used for separating renewable carbon dioxide and renewable methane from the methane, a renewable methane outlet of the gas separation device is connected with a synthesis reaction device, a renewable carbon dioxide outlet of the gas separation device is connected with a raw material inlet of a methanol synthesis device, a renewable carbon dioxide outlet of the synthesis reaction device is connected with a raw material inlet of the methanol synthesis device, and a water outlet of the synthesis reaction device is connected with a water inlet of an electrolytic water device; |[0052] the heat energy of the synthesis reaction device adopts a heat exchange mode to provide the required heat energy for the electrolytic water hydrogen production device and/or convert the heat energy into renewable electric energy to be provided for various electrolytic water hydrogen production devices. |[0053] Specifically, the hydrogen production by utilizing renewable energy to electrolyze water is a completely clean hydrogen production mode, and the technical process is simple and the product purity is high. According to different electrolytic tank production technologies, the electrolytic water hydrogen production device can be divided into an alkaline electrolytic tank, a proton exchange membrane electrolytic tank, a high-temperature solid oxide electrolytic tank and an anion exchange membrane electrolytic tank. The electrolytic tank can be selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank.|[0054] The hydrogen production method by alkaline water electrolysis is a preferred hydrogen production method in the embodiment, and the hydrogen production method by alkaline water electrolysis has the advantages of simple process and easy operation. The hydrogen production device by alkaline water electrolysis consists of a plurality of single electrolytic cells, and each electrolytic cell consists of a cathode, an anode, a diaphragm and electrolyte. After direct current is applied, water is decomposed in the electrolytic cell, and hydrogen and oxygen are generated at the cathode and the anode respectively. The electrolyte is potassium hydroxide solution with the concentration of 20-30wt%. The operation temperature of the alkaline aqueous solution electrolytic cell is 70-80 ℃ and the gas pressure is 0.1-3 MPa. The main reaction principle is as follows:|[0055] cathode reaction: 4e+4H 2O→4OH-+2H2|[0056] Anode reaction: 4OH -→2H2O+O2 +4e|[0057] Total reaction: 2H (H) 2O→2H2+O2|[0058] The electrolytic water hydrogen production device adopts a unit assembly type structure. The device mainly comprises seven devices, namely a gas device, an electrolyte circulating device, a gas evacuation (nitrogen replacement) device, a raw material water supplementing device, a cooling water device, an alkali supplementing device and a control and detection device.|[0059] (1) Gas device|[0060] When the electrolysis cell is connected with a direct current power supply and the electrolysis current rises to a preset value, water in the electrolysis cell is electrolyzed into hydrogen and oxygen. Hydrogen and alkali liquor from the cathode side of each electrolysis chamber in the electrolytic tank enter a separation section of the hydrogen separator through an alkali liquor heat exchanger by means of the lift and the gas lift of a circulating pump, and are separated under the action of gravity. The separated gas enters a washing section to cool and defog the gas. Oxygen and alkali liquor from the anode side of each electrolysis cell in the electrolytic tank enter a separation section of the oxygen separator through the alkali liquor heat exchanger by means of the lift and the gas lift of the circulating pump, and are separated under the action of gravity. The separated gas enters a washing section to cool and defog the gas.|[0061] (2) Electrolyte circulation device|[0062] The purpose of electrolyte circulation is to supplement pure water consumed by electrolysis to the electrode area, take away hydrogen, oxygen and heat generated in the electrolysis process, increase the stirring of the electrolyte in the electrode area, reduce concentration polarization voltage, reduce the gas content in alkali liquor, reduce cell voltage, reduce energy consumption and the like, so that the electrolytic tank works under stable conditions. The size of the lye circulation affects the cell voltage and gas purity in the cell.|[0063] (3) Gas evacuation (nitrogen replacement) device|[0064] The electrolytic hydrogen production device is provided with a nitrogen filling port for air tightness inspection and nitrogen replacement before startup.|[0065] (4) Raw material water supplementing device|[0066] In the electrolysis process, raw water in the device is continuously consumed, so that the raw water needs to be periodically replenished into the device in order to ensure continuous electrolysis. The water in the water tank is respectively pumped into the oxyhydrogen separator and the circulating alkali liquor through the water pump and enters the electrolysis chamber for continuous electrolysis, and meanwhile, the concentration of alkali in the electrolyte is kept in the optimal use range.|[0067] (5) Cooling water device|[0068] In the hydrogen production process, cooling water is needed for gas-liquid treatment, a hydrogen purification device and a rectifying cabinet. Wherein the cooling water of the gas-liquid separation device and the hydrogen purification device is provided by a cooling tower, and the cooling water of the rectifying cabinet is provided by a refrigerator. The cooling medium is desalted water.|[0069] (6) Alkali supplementing device|[0070] Before the device is started, alkali liquor is prepared. And (3) proportioning 30% potassium hydroxide solution in an alkali liquor box, and pumping electrolyte into the electrolytic tank through a valve from the alkali liquor box to a hydrogen production frame after the proportioning is finished.|[0071] (7) Purification scheme|[0072] The purifying device mainly comprises three steps of deoxidization, cooling and drying, and comprises a deoxidization tower and three adsorption towers. The working principle is as follows: in the deoxidizing tower, hydrogen and oxygen react under the action of catalyst to produce water.|[0073] The purpose of deoxidizing is achieved through catalytic oxidation reaction. The molecular sieve is arranged in the adsorption tower, and has a certain adsorption effect on water, carbon dioxide and other impurities, so that the aim of removing water is fulfilled. The principle of regeneration is that hydrogen is used to raise the temperature of molecular sieve in adsorption tower to 200 deg.c to desorb the adsorbed impurity and take it out of the system, the water after molecular sieve analysis is first condensed in cooler and the condensed water is automatically discharged through automatic valve. The hydrogen first passes through a deoxidizing tower, and oxygen in the hydrogen reacts with the hydrogen to generate water under the action of a catalyst. Then, the hydrogen gas enters an adsorption drying tower through a hydrogen condenser (the gas is cooled to condense water vapor in the gas into water, and the condensed water is automatically discharged out of the system through a liquid collector). Three adsorption towers, one regeneration (A), one working (B), and one cooling (C). Every 24 hours is a switching cycle.|[0074] The outlet pressure of the hydrogen is about 1.5MPa, and the hydrogen is removed from the methanol synthesis device. Meanwhile, considering the instability of renewable resources such as wind, light and electricity, a certain amount of hydrogen storage tanks are required to be arranged. Hydrogen is produced when the electric power is sufficient, and the surplus hydrogen is stored; when the electric power is insufficient, the hydrogen in the storage tank is used for supplementing the raw material of the methanol to synthesize the hydrogen.|[0075] 2. The methanol synthesis device comprises a compression device, a methanol synthesis tower device and a rectifying device,|[0076] (1) Compression device|[0077] The compression device comprises a first compressor, a purification tank, a second combined compressor and a third combined compressor, carbon dioxide outlets of the gas separation device and the synthesis reaction device are connected with an inlet of the first compressor, an outlet of the first compressor and a renewable hydrogen outlet of the electrolyzed water hydrogen production device are connected with an inlet of the second combined compressor, and the second combined compressor is connected with the third combined compressor;|[0078] the third combined compressor is connected with the methanol synthesis tower device, and an unreacted gas pipeline of the methanol synthesis tower device is connected with an inlet of the third combined compressor; |[0079] The carbon dioxide separated by the gas separation device and the carbon dioxide synthesized by the synthesis reaction device are collected and then compressed to 1.6MPa by the first compressor, then the carbon dioxide enters the purification tank, impurities in the carbon dioxide are further removed, the hydrogen pressure of the electrolytic water hydrogen production device is 1.5MPa, the carbon dioxide and the purified carbon dioxide are mixed to be fresh gas, the temperature is 40 ℃, the pressure is 2.0MPa, the fresh gas enters the low-pressure synthesis container of the second combined compressor for compression, and the compressed carbon dioxide enters the circulation section for mixing with unreacted gas (circulation gas) from the methanol synthesis tower device, and the mixture is compressed to 8.0MPa and then is introduced into the methanol synthesis tower device. |[0080] The fresh gas and the circulating gas respectively enter a third combined compressor, the pressure is about 8.0MPa after pressurization, and the temperature is about 45-60 ℃, so that the tower entering gas is obtained. The tower inlet gas firstly passes through the shell side of the tower inlet gas preheater, exchanges heat with the outlet gas (tower outlet gas) of the methanol synthesis tower device, heats to 220 ℃ below zero, and enters the catalyst bed layer of the methanol synthesis tower device for reaction.|[0081] (2) Methanol synthesis tower device|[0082] The synthesis steam drum and the synthesis tower shell side furnace water form a natural circulation system, reaction generated heat in the reaction tube is taken away through boiling of the synthesis tower shell side furnace water, and medium-pressure steam is produced as a byproduct.|[0083] The temperature of the gas (the gas discharged from the tower) after the reaction of the methanol synthesis tower device is about-250 ℃, firstly, the gas enters a pipe side of a tower gas preheater to preheat the tower gas; preheating carbon dioxide gas after entering a tower gas preheater, sending the preheated carbon dioxide gas to a vacuum tower as a reboiler heat source, carrying out high-pressure gas-liquid separation at the temperature of about 90 ℃ after cooling, cooling the gas phase in a water cooler, reducing the temperature to below 40 ℃, and refluxing cooling liquid to a gas-liquid separator; most of unreacted gas (namely recycle gas) returns to the combined compressor for boosting and then is recycled, and part of the gas is discharged; the liquid phase is removed to a low pressure flash drum.|[0084] The liquid crude methanol obtained from the lower part of the methanol separator is decompressed to 0.5MPa and then enters a flash tank. The small amount of gas dissolved at high pressure is mostly flashed off there. The flashed crude methanol is sent to a crude methanol storage tank or a direct rectifying tower in the rectifying process, and the flash gas is sent out of the boundary.|[0085] (3) Rectifying device|[0086] The crude methanol from the synthesis process enters a crude methanol storage tank and is sent to a rectification process through a crude methanol pump, and a rectification device comprises a light component removal tower unit, a reduced pressure rectification tower unit, a pressurized rectification tower unit, an atmospheric rectification tower unit and a recovery tower unit;|[0087] the light component removing tower unit is connected with the vacuum rectifying tower unit, the vacuum rectifying tower unit is connected with the pressurizing rectifying tower unit, the pressurizing rectifying tower unit is connected with the normal pressure rectifying tower unit, and the normal pressure rectifying tower unit is connected with the recovery tower unit. |[0088] The crude methanol synthesized by carbon dioxide enters a light component removal tower unit after flash evaporation, light components with boiling point lower than that of the methanol are removed from the top of the light component removal tower unit, and methanol aqueous solution after the light components are removed is discharged from the tower bottom of the light component removal tower unit and enters a vacuum rectification tower unit; obtaining a part of refined methanol product at the top of the vacuum rectifying tower unit, and enabling other methanol aqueous solutions to enter the pressurizing rectifying tower unit after coming out of the tower kettle of the vacuum rectifying tower unit; obtaining a part of refined methanol product at the top of the pressurized rectifying tower unit, and enabling the residual methanol aqueous solution to enter the normal pressure rectifying tower unit after coming out of the tower kettle of the pressurized rectifying tower unit; obtaining a part of refined methanol product at the top of the normal pressure rectifying tower unit, and enabling tower bottom liquid of the normal pressure rectifying tower unit to enter a recovery tower unit; and obtaining a mixed alcohol product at the top of the recovery tower unit, and purifying and recycling the waste water at the bottom of the recovery tower after preheating and pressurizing the feed of the tower unit.|[0089] The heating heat source of the light component removing tower unit and the reboiler is provided after the vapor at the top of the recovery tower unit is pressurized; the heating source of the vacuum rectifying tower unit and the reboiler is provided by low-level heat of synthesis gas synthesized by carbon dioxide and methanol; the heating source of the pressurizing tower unit is provided by steam generated by synthesizing carbon dioxide and methanol; the heating source of the normal pressure rectifying tower unit is mostly provided by methanol vapor at the top of the pressurizing tower unit; the recovery tower unit heating source is provided by continuously cooling condensed water of the pressurizing tower unit reboiler.|[0090] The method comprises the steps that carbon dioxide-containing raw material gas is pressurized by a fan and enters the bottom of an absorption tower unit, the raw material gas is in reverse contact with alcohol amine absorbent added into the top of the absorption tower unit, carbon dioxide components in the raw material gas are absorbed, unabsorbed gas is discharged from the top of the tower, and an environment-friendly index monitoring system is arranged; the tower bottom is rich solvent after absorbing carbon dioxide, is pressurized by a decarbonization tower unit bottom pump, exchanges heat with an alcohol amine absorbent heat exchanger, and enters a regeneration tower unit after being heated.|[0091] The rich absorbent is regenerated by removing carbon dioxide gas from the top of the tower in a heating mode in a regeneration tower unit, and steam is used as a reboiler heat source for a tower kettle reboiler. The regenerated lean absorbent is subjected to heat exchange to recover energy, and then is cooled by a bottom pump of the regeneration tower unit and returned to the absorption tower unit. The carbon dioxide gas discharged from the top of the regeneration tower unit contains water vapor and a small amount of solvent, the water vapor and the small amount of solvent are condensed by a condenser at the top of the regeneration tower unit and then enter a reflux tank of the regeneration tower, all condensate is returned to the top of the tower as reflux by a reflux pump of the regeneration tower unit, and the non-condensed gas is the product renewable carbon dioxide and is introduced into a compression device.|[0092] Therefore, the raw materials for preparing the methanol in the embodiment are all from renewable energy sources, agricultural and forestry organic matters, livestock and poultry manure, wastes and municipal wastes generated in industrial and agricultural production processes can be consumed, and pure water and heat energy generated in the process are recycled for preparing renewable oxygen and renewable hydrogen by electrolyzing water. Therefore, the prepared methanol is renewable methanol, does not produce waste gas polluting the environment in the preparation process, can consume agriculture and forestry organic matters, livestock and poultry manure, wastes, municipal waste and the like produced in the industrial and agricultural production processes, and is environment-friendly.|[0093] The embodiments of the present invention have been described in detail with reference to the drawings, but the present invention is not limited to the above embodiments. Even if various changes are made to the present invention, it is within the scope of the appended claims and their equivalents to fall within the scope of the invention. | (CN118684553)|TECHNICAL FIELD|Technical Field|[0001] The invention belongs to the technical field of methanol preparation and renewable energy and biomass energy utilization, and particularly relates to a preparation process and a system of renewable methanol.|BACKGROUND ART|[0002] Methanol (CH 3 OH) is the simplest, safest, most easily stored and transported liquid carbon hydroxide. By the end of 2022, the productivity of Chinese methanol has been nearly 12,000 ten thousand tons/year, and the main raw materials are derived from fossil fuels such as coal and natural gas.|[0003] Renewable methanol (CH 3 OH) can replace fossil fuels to reduce greenhouse gas (GHG) emissions, and in some cases other harmful emissions (e.g., sulfur oxides (SO X), nitrogen oxides (NO X), aerosols (PM), etc.), and the carbon emission reduction effect is obvious from the transportation and shipping industries.|[0004] The physical properties of the renewable methanol (CH 3 OH) are the same as those of the traditional methanol (CH 3 OH), the methanol (CH 3 OH) is an important intermediate product of chemical raw materials, the chemical product system which can be synthesized by the methanol (CH 3 OH) is huge, and the original production facilities are not required to be changed by using the renewable methanol (CH 3 OH). The carbon emission reduction effect of the chemical industry is direct and obvious.|[0005] Renewable methanol (CH 3 OH) converts renewable energy sources such as wind energy, photovoltaic energy, biomass energy and the like into renewable secondary energy sources, namely hydrogen (H 2), and converts and stores the renewable secondary energy sources through the combination of biomass energy and carbon dioxide, so that the renewable secondary energy sources are safer and are more convenient to store and transport, and various transportation systems such as aviation transportation, railway transportation, ship transportation and vehicle transportation can use the renewable methanol to achieve the aim of reducing carbon emission.|[0006] Currently renewable methanol is divided into two major categories, biological methanol and green methanol, and the shortcomings of the current solutions are as follows: biological methanol produced from biomass, wherein the main production mode such as a fluidized bed method consumes a large amount of energy, or the conversion rate of the produced methanol is low, and the conversion rate is accompanied by a large amount of carbon dioxide release into the atmosphere, the carbon reduction effect is not ideal from the viewpoints of carbon metering and carbon emission reduction; the related art of using carbon dioxide captured from renewable resources such as bioenergy captured and stored in carbon (BECCS) and Direct Air (DAC) and renewable methanol produced from renewable hydrogen produced by renewable energy power generation is currently not mature, is extremely costly, and requires waiting for the technology to mature.|DISCLOSURE|Disclosure of Invention|[0007] Based on the technical problems, the invention provides a renewable methanol preparation process and a renewable methanol preparation system, which are characterized in that renewable carbon dioxide and renewable methane are separated from gas generated by biomass fermentation, the renewable carbon dioxide is synthesized by the renewable methane and renewable oxygen generated by electrolysis of water of renewable power, and the renewable methanol is synthesized by the renewable carbon dioxide and the renewable hydrogen generated by electrolysis of water.|[0008] In order to achieve the above purpose, the technical scheme of the invention is as follows:|[0009] A process for the preparation of renewable methanol comprising the steps of: |[0010] a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; |[0011] B: renewable carbon dioxide preparation and byproduct recycling: biomass is fermented to generate biogas, renewable methane and renewable carbon dioxide are separated from the biogas, the renewable methane and renewable oxygen in the step A are continuously synthesized into renewable carbon dioxide and water, heat energy is generated, the generated water and heat energy can be recycled to the step A, and the renewable carbon dioxide and the water continuously participate in the reaction; |[0012] c: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |[0013] Preferably, the step a specifically includes: generating electricity by using renewable energy sources to obtain renewable power, wherein the renewable power is combined with various electrolytic tanks to electrolyze water to prepare renewable hydrogen and renewable oxygen; the electrolytic tank is selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank.|[0014] Preferably, the step B specifically includes:|[0015] b01: the biomass is subjected to anaerobic fermentation to produce the biogas, and the biogas is physically separated into the renewable methane and the renewable carbon dioxide according to different specific gravities; |[0016] And B02: the renewable methane and renewable oxygen react in the synthesis reaction device to generate renewable carbon dioxide and water, and heat energy is generated, the heat energy and water are used for the reaction heat energy condition of the step A and the raw material of the electrolyzed water, and/or the heat energy can be converted into biomass electric energy, namely the renewable electric power of the step A participates in the reaction. |[0017] Preferably, the step C specifically includes:|[0018] The two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction; heat energy and water are used for the reaction heat energy conditions of the step A and the raw materials of the electrolyzed water; and/or the thermal energy may also be converted into biomass electrical energy, i.e. the renewable power of step a participates in the reaction. |[0019] Preferably, the step C specifically includes: the reaction ratio of the renewable hydrogen to the renewable carbon dioxide is adjusted to be more than or equal to 3:1, the synthesis reaction is carried out under the action of the catalyst, and the renewable methanol product meeting the standard is obtained after rectification and water separation are carried out to remove impurities.|[0020] Preferably, the renewable carbon dioxide is compressed to 1.6MPa for the first time, mixed with renewable hydrogen for the second time to 2.0MPa, and then mixed with unreacted gas (recycle gas) in the renewable methanol synthesis reaction for the third time to 8.0MPa; the raw material gas after three times of compression enters a renewable methanol synthesis tower device for synthesis reaction, and unreacted gas (circulating gas) returns to be mixed with the raw material gas for compression.|[0021] The invention also provides a preparation system of renewable methanol, which comprises: anaerobic fermentation device, gas separation device, electrolytic water hydrogen production device, synthesis reaction device and methanol synthesis device;|[0022] the renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the methanol synthesis device; |[0023] The renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the synthesis reaction device; |[0024] The biomass is fermented by the anaerobic fermentation device, the anaerobic fermentation device is connected with the gas separation device, and the gas separation device is used for separating renewable methane and renewable carbon dioxide; the renewable methane outlet of the gas separation device is connected with the synthesis reaction device, and the renewable carbon dioxide outlet of the gas separation device is connected with the raw material inlet of the methanol synthesis device; the renewable carbon dioxide outlet of the synthesis reaction device is connected with the raw material inlet of the methanol synthesis device, and the water outlet of the synthesis reaction device is connected with the water inlet of the water electrolysis device; |[0025] The heat energy of the synthesis reaction device provides needed and/or renewable electric energy for the water electrolysis hydrogen production device through a heat exchange mode, and further, the heat energy can be directly provided for a high-temperature solid oxide electrolytic tank. |[0026] By adopting the technical scheme, the invention has the following advantages and positive effects compared with the prior art:|[0027] The renewable hydrogen generated by renewable electric power and renewable carbon dioxide in methane generated after biomass fermentation are used as sources of raw materials in the renewable methanol preparation process, and in order to improve the conversion efficiency, renewable oxygen generated by renewable electric power and renewable methane in methane generated after biomass fermentation continue to react to obtain the conversion efficiency of converting the carbon content in the methane into the carbon content of renewable carbon dioxide, wherein the carbon content in the methane is up to 99.1%, so that the carbon consumption generated by the system and the cost of sustainable methanol are reduced. Meanwhile, heat energy and pure water generated by the synthesis reaction of renewable methane and renewable oxygen can be converted into renewable power, so that renewable power and electrolysis water required by the operation of various electrolytic tank devices are supplemented, and the carbon consumption of the system and the cost of the produced sustainable methanol are further reduced. |DRAWINGS DESCRIPTION|[0028] FIG. 1 is a process flow for the preparation of renewable methanol in an embodiment of the present invention.|INVENTION MODE|Detailed Description|[0029] The process and system for preparing renewable methanol according to the present invention will be described in further detail with reference to the accompanying drawings and examples. The advantages and features of the present invention will become more apparent from the following description.|[0030] In the traditional methanol synthesis system, methane is usually treated and simply decomposed into methane and carbon dioxide, wherein the methane is only sold and profitable in a liquefied natural gas mode after being simply purified and filtered, and the liquefied natural gas is usually used for supplying heat in a combustion mode, and the generated carbon dioxide is directly discharged; the carbon dioxide decomposed by the biogas is usually directly discharged, and if the biogas is captured and utilized, the carbon conversion rate is only 30-35%, and the method does not meet the thought of reducing the carbon emission under the view of the current double-carbon requirement. In the preparation process of the renewable methanol, the conversion rate of the carbon content in the methane to the renewable carbon dioxide is improved to 99.1%, so that the preparation process meets the low-carbon emission requirement and the economic requirement.|[0031] The renewable concepts herein have the same meaning as the general green concepts: such as renewable methanol=green methanol, renewable hydrogen=green hydrogen, and the like.|[0032] Example 1|[0033] Referring to fig. 1, a renewable methanol preparation process comprises the steps of:|[0034] a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; |[0035] B: renewable carbon dioxide preparation and byproduct recycling: generating biogas by biomass fermentation, separating renewable methane and renewable carbon dioxide from the biogas, continuously synthesizing the renewable carbon dioxide and water by the renewable methane and renewable oxygen in the step A, and generating heat energy, wherein the generated water and heat energy can be recycled to the step A to continuously participate in the reaction; |[0036] C: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |[0037] The step A specifically comprises the following steps: renewable energy sources such as wind energy, solar energy, biomass energy, nuclear energy and the like are adopted to generate renewable power, and the renewable power is combined with electrolysis of water in an electrolytic cell to prepare renewable hydrogen and renewable oxygen;|[0038] The electrolytic tank is selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank. |[0039] The heat energy generated in the synthesis reaction process of renewable methane and renewable hydrogen can be directly used in the heating process in the scheme of preparing hydrogen by using the high-temperature solid oxide electrolytic cell to electrolyze water (SOEC), so that the carbon consumption of a preparation process system and the cost of the produced renewable methanol are further reduced.|[0040] The step B specifically comprises the following steps:|[0041] B01: the biomass is produced by anaerobic fermentation, the biogas is physically separated into renewable methane and renewable carbon dioxide according to different specific gravities, and the biomass can be agriculture and forestry organic matters, livestock and poultry manure, waste and municipal waste generated in industrial and agricultural production processes; |[0042] and B02: the renewable methane and the renewable hydrogen are synthesized in a synthesis reaction device to generate renewable carbon dioxide and water: CH 4+2O2→CO2+2H2 O and generates heat energy, which is used to electrolyze water in step a. |[0043] The step C specifically comprises the following steps: the ratio of the renewable hydrogen to the renewable carbon dioxide is more than or equal to 3:1, so that the renewable carbon dioxide is ensured to fully react, the synthesis reaction is carried out under the action of the catalyst, and the renewable methanol product meeting the standard is obtained after the impurities are removed by rectification and water separation.|[0044] The synthesis reaction of methanol is as follows: CO 2+3H2→CH3OH+H2 O|[0045] Further, the renewable carbon dioxide is compressed to 1.6MPa for the first time, purified, mixed with renewable hydrogen for the second time to 2.0MPa, and then mixed with unreacted gas (namely recycle gas) in the synthesis reaction for the third time to 8.0MPa;|[0046] The raw material gas after three times of compression enters a methanol synthesis tower device for synthesis reaction, and unreacted gas (namely recycle gas) returns to be mixed with the raw material gas for compression. |[0047] The renewable methanol preparation source provided in this embodiment is renewable hydrogen generated by renewable power and renewable carbon dioxide in biogas generated after biomass fermentation, and in order to improve conversion efficiency, renewable oxygen generated by renewable power and renewable methane in biogas generated after biomass fermentation are continuously reacted to obtain conversion efficiency of converting carbon content in biogas to carbon content of renewable carbon dioxide up to 99.1%, so as to reduce carbon consumption produced by the system and cost of renewable methanol. Meanwhile, heat energy and pure water generated by the synthesis reaction of renewable methane and renewable oxygen can be converted into renewable power, so that the renewable power and electrolysis water required by the operation of various electrolytic tank devices are supplemented, and the carbon consumption of a process system and the cost of the produced renewable methanol are further reduced. In particular, the heat energy generated by the synthesis reaction of renewable methane and renewable oxygen can be directly used in the heating process in the scheme of water electrolysis (SOEC) hydrogen production in a high-temperature solid oxide electrolytic cell, so that the carbon consumption of the system and the cost of the produced renewable methanol are further reduced.|[0048] Example 2|[0049] Referring to fig. 1, a system for producing renewable methanol, comprising: anaerobic fermentation device, gas separation device, synthesis reaction device, methanol synthesis device and electrolytic water hydrogen production device,|[0050] Renewable power generated by renewable energy sources such as wind energy, solar energy and the like is combined with an electrolytic water hydrogen production device, the electrolytic water hydrogen production device is used for generating renewable hydrogen by electrolyzing water, a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of a synthesis reaction device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of a methanol synthesis device;|[0051] The biomass is fermented into methane through an anaerobic fermentation device, the anaerobic fermentation device is connected with a gas separation device, the gas separation device is used for separating renewable carbon dioxide and renewable methane from the methane, a renewable methane outlet of the gas separation device is connected with a synthesis reaction device, a renewable carbon dioxide outlet of the gas separation device is connected with a raw material inlet of a methanol synthesis device, a renewable carbon dioxide outlet of the synthesis reaction device is connected with a raw material inlet of the methanol synthesis device, and a water outlet of the synthesis reaction device is connected with a water inlet of an electrolytic water device; |[0052] the heat energy of the synthesis reaction device adopts a heat exchange mode to provide the required heat energy for the electrolytic water hydrogen production device and/or convert the heat energy into renewable electric energy to be provided for various electrolytic water hydrogen production devices. |[0053] Specifically, the hydrogen production by utilizing renewable energy to electrolyze water is a completely clean hydrogen production mode, and the technical process is simple and the product purity is high. According to different electrolytic tank production technologies, the electrolytic water hydrogen production device can be divided into an alkaline electrolytic tank, a proton exchange membrane electrolytic tank, a high-temperature solid oxide electrolytic tank and an anion exchange membrane electrolytic tank. The electrolytic tank can be selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank.|[0054] The hydrogen production method by alkaline water electrolysis is a preferred hydrogen production method in the embodiment, and the hydrogen production method by alkaline water electrolysis has the advantages of simple process and easy operation. The hydrogen production device by alkaline water electrolysis consists of a plurality of single electrolytic cells, and each electrolytic cell consists of a cathode, an anode, a diaphragm and electrolyte. After direct current is applied, water is decomposed in the electrolytic cell, and hydrogen and oxygen are generated at the cathode and the anode respectively. The electrolyte is potassium hydroxide solution with the concentration of 20-30wt%. The operation temperature of the alkaline aqueous solution electrolytic cell is 70-80 ℃ and the gas pressure is 0.1-3 MPa. The main reaction principle is as follows:|[0055] cathode reaction: 4e+4H 2O→4OH-+2H2|[0056] Anode reaction: 4OH -→2H2O+O2 +4e|[0057] Total reaction: 2H (H) 2O→2H2+O2|[0058] The electrolytic water hydrogen production device adopts a unit assembly type structure. The device mainly comprises seven devices, namely a gas device, an electrolyte circulating device, a gas evacuation (nitrogen replacement) device, a raw material water supplementing device, a cooling water device, an alkali supplementing device and a control and detection device.|[0059] (1) Gas device|[0060] When the electrolysis cell is connected with a direct current power supply and the electrolysis current rises to a preset value, water in the electrolysis cell is electrolyzed into hydrogen and oxygen. Hydrogen and alkali liquor from the cathode side of each electrolysis chamber in the electrolytic tank enter a separation section of the hydrogen separator through an alkali liquor heat exchanger by means of the lift and the gas lift of a circulating pump, and are separated under the action of gravity. The separated gas enters a washing section to cool and defog the gas. Oxygen and alkali liquor from the anode side of each electrolysis cell in the electrolytic tank enter a separation section of the oxygen separator through the alkali liquor heat exchanger by means of the lift and the gas lift of the circulating pump, and are separated under the action of gravity. The separated gas enters a washing section to cool and defog the gas.|[0061] (2) Electrolyte circulation device|[0062] The purpose of electrolyte circulation is to supplement pure water consumed by electrolysis to the electrode area, take away hydrogen, oxygen and heat generated in the electrolysis process, increase the stirring of the electrolyte in the electrode area, reduce concentration polarization voltage, reduce the gas content in alkali liquor, reduce cell voltage, reduce energy consumption and the like, so that the electrolytic tank works under stable conditions. The size of the lye circulation affects the cell voltage and gas purity in the cell.|[0063] (3) Gas evacuation (nitrogen replacement) device|[0064] The electrolytic hydrogen production device is provided with a nitrogen filling port for air tightness inspection and nitrogen replacement before startup.|[0065] (4) Raw material water supplementing device|[0066] In the electrolysis process, raw water in the device is continuously consumed, so that the raw water needs to be periodically replenished into the device in order to ensure continuous electrolysis. The water in the water tank is respectively pumped into the oxyhydrogen separator and the circulating alkali liquor through the water pump and enters the electrolysis chamber for continuous electrolysis, and meanwhile, the concentration of alkali in the electrolyte is kept in the optimal use range.|[0067] (5) Cooling water device|[0068] In the hydrogen production process, cooling water is needed for gas-liquid treatment, a hydrogen purification device and a rectifying cabinet. Wherein the cooling water of the gas-liquid separation device and the hydrogen purification device is provided by a cooling tower, and the cooling water of the rectifying cabinet is provided by a refrigerator. The cooling medium is desalted water.|[0069] (6) Alkali supplementing device|[0070] Before the device is started, alkali liquor is prepared. And (3) proportioning 30% potassium hydroxide solution in an alkali liquor box, and pumping electrolyte into the electrolytic tank through a valve from the alkali liquor box to a hydrogen production frame after the proportioning is finished.|[0071] (7) Purification scheme|[0072] The purifying device mainly comprises three steps of deoxidization, cooling and drying, and comprises a deoxidization tower and three adsorption towers. The working principle is as follows: in the deoxidizing tower, hydrogen and oxygen react under the action of catalyst to produce water.|[0073] The purpose of deoxidizing is achieved through catalytic oxidation reaction. The molecular sieve is arranged in the adsorption tower, and has a certain adsorption effect on water, carbon dioxide and other impurities, so that the aim of removing water is fulfilled. The principle of regeneration is that hydrogen is used to raise the temperature of molecular sieve in adsorption tower to 200 deg.c to desorb the adsorbed impurity and take it out of the system, the water after molecular sieve analysis is first condensed in cooler and the condensed water is automatically discharged through automatic valve. The hydrogen first passes through a deoxidizing tower, and oxygen in the hydrogen reacts with the hydrogen to generate water under the action of a catalyst. Then, the hydrogen gas enters an adsorption drying tower through a hydrogen condenser (the gas is cooled to condense water vapor in the gas into water, and the condensed water is automatically discharged out of the system through a liquid collector). Three adsorption towers, one regeneration (A), one working (B), and one cooling (C). Every 24 hours is a switching cycle.|[0074] The outlet pressure of the hydrogen is about 1.5MPa, and the hydrogen is removed from the methanol synthesis device. Meanwhile, considering the instability of renewable resources such as wind, light and electricity, a certain amount of hydrogen storage tanks are required to be arranged. Hydrogen is produced when the electric power is sufficient, and the surplus hydrogen is stored; when the electric power is insufficient, the hydrogen in the storage tank is used for supplementing the raw material of the methanol to synthesize the hydrogen.|[0075] 2. The methanol synthesis device comprises a compression device, a methanol synthesis tower device and a rectifying device,|[0076] (1) Compression device|[0077] The compression device comprises a first compressor, a purification tank, a second combined compressor and a third combined compressor, carbon dioxide outlets of the gas separation device and the synthesis reaction device are connected with an inlet of the first compressor, an outlet of the first compressor and a renewable hydrogen outlet of the electrolyzed water hydrogen production device are connected with an inlet of the second combined compressor, and the second combined compressor is connected with the third combined compressor;|[0078] the third combined compressor is connected with the methanol synthesis tower device, and an unreacted gas pipeline of the methanol synthesis tower device is connected with an inlet of the third combined compressor; |[0079] The carbon dioxide separated by the gas separation device and the carbon dioxide synthesized by the synthesis reaction device are collected and then compressed to 1.6MPa by the first compressor, then the carbon dioxide enters the purification tank, impurities in the carbon dioxide are further removed, the hydrogen pressure of the electrolytic water hydrogen production device is 1.5MPa, the carbon dioxide and the purified carbon dioxide are mixed to be fresh gas, the temperature is 40 ℃, the pressure is 2.0MPa, the fresh gas enters the low-pressure synthesis container of the second combined compressor for compression, and the compressed carbon dioxide enters the circulation section for mixing with unreacted gas (circulation gas) from the methanol synthesis tower device, and the mixture is compressed to 8.0MPa and then is introduced into the methanol synthesis tower device. |[0080] The fresh gas and the circulating gas respectively enter a third combined compressor, the pressure is about 8.0MPa after pressurization, and the temperature is about 45-60 ℃, so that the tower entering gas is obtained. The tower inlet gas firstly passes through the shell side of the tower inlet gas preheater, exchanges heat with the outlet gas (tower outlet gas) of the methanol synthesis tower device, heats to 220 ℃ below zero, and enters the catalyst bed layer of the methanol synthesis tower device for reaction.|[0081] (2) Methanol synthesis tower device|[0082] The synthesis steam drum and the synthesis tower shell side furnace water form a natural circulation system, reaction generated heat in the reaction tube is taken away through boiling of the synthesis tower shell side furnace water, and medium-pressure steam is produced as a byproduct.|[0083] The temperature of the gas (the gas discharged from the tower) after the reaction of the methanol synthesis tower device is about-250 ℃, firstly, the gas enters a pipe side of a tower gas preheater to preheat the tower gas; preheating carbon dioxide gas after entering a tower gas preheater, sending the preheated carbon dioxide gas to a vacuum tower as a reboiler heat source, carrying out high-pressure gas-liquid separation at the temperature of about 90 ℃ after cooling, cooling the gas phase in a water cooler, reducing the temperature to below 40 ℃, and refluxing cooling liquid to a gas-liquid separator; most of unreacted gas (namely recycle gas) returns to the combined compressor for boosting and then is recycled, and part of the gas is discharged; the liquid phase is removed to a low pressure flash drum.|[0084] The liquid crude methanol obtained from the lower part of the methanol separator is decompressed to 0.5MPa and then enters a flash tank. The small amount of gas dissolved at high pressure is mostly flashed off there. The flashed crude methanol is sent to a crude methanol storage tank or a direct rectifying tower in the rectifying process, and the flash gas is sent out of the boundary.|[0085] (3) Rectifying device|[0086] The crude methanol from the synthesis process enters a crude methanol storage tank and is sent to a rectification process through a crude methanol pump, and a rectification device comprises a light component removal tower unit, a reduced pressure rectification tower unit, a pressurized rectification tower unit, an atmospheric rectification tower unit and a recovery tower unit;|[0087] the light component removing tower unit is connected with the vacuum rectifying tower unit, the vacuum rectifying tower unit is connected with the pressurizing rectifying tower unit, the pressurizing rectifying tower unit is connected with the normal pressure rectifying tower unit, and the normal pressure rectifying tower unit is connected with the recovery tower unit. |[0088] The crude methanol synthesized by carbon dioxide enters a light component removal tower unit after flash evaporation, light components with boiling point lower than that of the methanol are removed from the top of the light component removal tower unit, and methanol aqueous solution after the light components are removed is discharged from the tower bottom of the light component removal tower unit and enters a vacuum rectification tower unit; obtaining a part of refined methanol product at the top of the vacuum rectifying tower unit, and enabling other methanol aqueous solutions to enter the pressurizing rectifying tower unit after coming out of the tower kettle of the vacuum rectifying tower unit; obtaining a part of refined methanol product at the top of the pressurized rectifying tower unit, and enabling the residual methanol aqueous solution to enter the normal pressure rectifying tower unit after coming out of the tower kettle of the pressurized rectifying tower unit; obtaining a part of refined methanol product at the top of the normal pressure rectifying tower unit, and enabling tower bottom liquid of the normal pressure rectifying tower unit to enter a recovery tower unit; and obtaining a mixed alcohol product at the top of the recovery tower unit, and purifying and recycling the waste water at the bottom of the recovery tower after preheating and pressurizing the feed of the tower unit.|[0089] The heating heat source of the light component removing tower unit and the reboiler is provided after the vapor at the top of the recovery tower unit is pressurized; the heating source of the vacuum rectifying tower unit and the reboiler is provided by low-level heat of synthesis gas synthesized by carbon dioxide and methanol; the heating source of the pressurizing tower unit is provided by steam generated by synthesizing carbon dioxide and methanol; the heating source of the normal pressure rectifying tower unit is mostly provided by methanol vapor at the top of the pressurizing tower unit; the recovery tower unit heating source is provided by continuously cooling condensed water of the pressurizing tower unit reboiler.|[0090] The method comprises the steps that carbon dioxide-containing raw material gas is pressurized by a fan and enters the bottom of an absorption tower unit, the raw material gas is in reverse contact with alcohol amine absorbent added into the top of the absorption tower unit, carbon dioxide components in the raw material gas are absorbed, unabsorbed gas is discharged from the top of the tower, and an environment-friendly index monitoring system is arranged; the tower bottom is rich solvent after absorbing carbon dioxide, is pressurized by a decarbonization tower unit bottom pump, exchanges heat with an alcohol amine absorbent heat exchanger, and enters a regeneration tower unit after being heated.|[0091] The rich absorbent is regenerated by removing carbon dioxide gas from the top of the tower in a heating mode in a regeneration tower unit, and steam is used as a reboiler heat source for a tower kettle reboiler. The regenerated lean absorbent is subjected to heat exchange to recover energy, and then is cooled by a bottom pump of the regeneration tower unit and returned to the absorption tower unit. The carbon dioxide gas discharged from the top of the regeneration tower unit contains water vapor and a small amount of solvent, the water vapor and the small amount of solvent are condensed by a condenser at the top of the regeneration tower unit and then enter a reflux tank of the regeneration tower, all condensate is returned to the top of the tower as reflux by a reflux pump of the regeneration tower unit, and the non-condensed gas is the product renewable carbon dioxide and is introduced into a compression device.|[0092] Therefore, the raw materials for preparing the methanol in the embodiment are all from renewable energy sources, agricultural and forestry organic matters, livestock and poultry manure, wastes and municipal wastes generated in industrial and agricultural production processes can be consumed, and pure water and heat energy generated in the process are recycled for preparing renewable oxygen and renewable hydrogen by electrolyzing water. Therefore, the prepared methanol is renewable methanol, does not produce waste gas polluting the environment in the preparation process, can consume agriculture and forestry organic matters, livestock and poultry manure, wastes, municipal waste and the like produced in the industrial and agricultural production processes, and is environment-friendly.|[0093] The embodiments of the present invention have been described in detail with reference to the drawings, but the present invention is not limited to the above embodiments. Even if various changes are made to the present invention, it is within the scope of the appended claims and their equivalents to fall within the scope of the invention. | Family Number|(111559278)|111559278|Advantages / Prev. Drawbacks|(CN118684553 A)|( . . . ) atmosphere , the carbon reduction effect is not ideal from the viewpoints of carbon metering and carbon emission reduction ; the related art of using carbon dioxide captured from renewable resources such as bioenergy captured and stored in carbon ( BECCS ) and Direct Air ( DAC ) and renewable methanol produced from renewable hydrogen produced by renewable energy power generation is currently not mature , is extremely costly , and requires waiting for the technology to mature . | | Biotechnology|Organic fine chemistry|Surface technology, coating | C07C-029/151/6|C07C-031/04|C12M-021/04|C12M-047/18|C12P-005/02/3|C25B-001/04 | (GR1) C07C-029/151/6[RK1]; C07C-031/04[RK2] | C07C-029/151/6|C07C-031/04|C12M-021/04|C12M-047/18|C12P-005/02/3|C25B-001/04 | C07C-029/151|C07C-031/04|C12M-001/00|C12M-001/107|C12P-005/02|C25B-001/04 | C07C-029/151|C07C-031/04|C12M-001/00|C12M-001/107|C12P-005/02|C25B-001/04 | PENDING | (CN118684553)|PENDING | ALIVE | (CN118684553)|ALIVE | (CN118684553)|LEGAL DETAILS FOR CN118684553|Actual or expected expiration date=2044-04-22|Legal state=ALIVE|Status=PENDING|Event publication date=2024-04-22|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202410486464|Application date=2024-04-22|Standardized application number=2024CN-0486464|Event publication date=2024-09-24|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN118684553|Publication stage code=A|Publication date=2024-09-24|Standardized publication number=CN118684553|Event publication date=2024-09-24|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2024-10-15|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination | (CN118684553)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoSFE9ZnRzHLnlfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000074542116&ekey=2218&xpn=CN118684553&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=sacLATSd8aNiAXyFzq0sgZNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN118684553)|CN | (CN118684553)|NAME=QIANQIAN TECHNOLOGY DEVELOPMENT (SHANGHAI) CO., LTD. , COUNTRY=CN | (CN118684553)|NAME=REN NING;SHANGHAI HANGSOME INTELLECTUAL PROPERTY LTD. , REG=31236NAME=HU JING;SHANGHAI HANGSOME INTELLECTUAL PROPERTY LTD. , REG=31236 | (CN118684553)|NAME=XU JIECHUN|NAME=XU JINGYAN | (CN118684553)|1 | 1 | 1 | (CN118684553)|Number of Claims: NCL=7|Gazette date: GAZDATE=2024-09-24|Gazette number: GAZNUM=40-3901|Number of Pages: NPAGES=11| | (CN118684553)|CHINESE (CHI) | (CN118684553)|Patent | Titre: (CN118684553)|Preparation process and system of renewable methanol Résumé: (CN118684553)|The invention provides a renewable methanol preparation process and system. The renewable methanol preparation process comprises the following steps: A, preparation of renewable hydrogen: preparing renewable hydrogen and renewable oxygen from renewable energy power generation electrolyzed water; b, preparing renewable carbon dioxide and recycling by-products: fermenting biomass to generate biogas, then separating renewable methane and renewable carbon dioxide from the biogas, continuously synthesizing renewable carbon dioxide and water from the renewable methane and the renewable oxygen in the step A, and generating heat energy; c, preparing renewable methanol and recycling by-products: synthesizing the two parts of renewable carbon dioxide in the step B and the renewable hydrogen in the step A into renewable methanol and water, and generating heat energy; wherein water and heat energy generated in the steps B and C are circulated to the step A. According to the method, the carbon content conversion rate of converting the carbon content in the biogas generated by biomass fermentation into renewable carbon dioxide is increased to 99.1%, so that the renewable methanol with low carbon in the whole process is generated, and the cost is reduced. Autre: (CN118684553)|1. A process for the preparation of renewable methanol, comprising the steps of:| a: renewable hydrogen preparation: renewable energy power generation electrolyzed water is used for preparing renewable hydrogen and renewable oxygen; | B: renewable carbon dioxide preparation and byproduct recycling: biomass is fermented to generate biogas, renewable methane and renewable carbon dioxide are separated from the biogas, the renewable methane and renewable oxygen in the step A are continuously synthesized into renewable carbon dioxide and water, heat energy is generated, the generated water and heat energy can be recycled to the step A, and the renewable carbon dioxide and the water continuously participate in the reaction; | c: renewable methanol preparation and byproduct recycling: the two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction. |2. The process for the preparation of renewable methanol according to claim 1, wherein said step a comprises in particular: renewable energy sources are adopted to generate electricity to obtain renewable power, and the renewable power is combined with various electrolytic tanks to electrolyze water to prepare renewable hydrogen and renewable oxygen;| The electrolytic tank is selected from any one or a mixture of a plurality of alkaline electrolytic tank, proton exchange membrane electrolytic tank, high-temperature solid oxide electrolytic tank and anion exchange membrane electrolytic tank. |3. The process for the preparation of renewable methanol according to claim 1, wherein said step B comprises in particular:| b01: the biomass is used for producing biogas by anaerobic fermentation, and the biogas is physically separated into renewable methane and renewable carbon dioxide according to different specific gravities; | And B02: the renewable methane reacts with renewable oxygen in a synthesis reaction device to generate renewable carbon dioxide and water, and heat energy and water are generated and used for the reaction heat energy conditions of the step A and the raw materials of the electrolyzed water; and/or converting the heat energy into biomass electric energy to provide electric energy for the electrolyzed water in the step A. |4. The process for the preparation of renewable methanol according to claim 1, wherein said step C comprises in particular:| The two parts of renewable carbon dioxide prepared in the step B and the renewable hydrogen prepared in the step A are synthesized into renewable methanol and water, and heat energy is generated; wherein the generated water and heat energy can be recycled to the step A to continue to participate in the reaction; heat energy and water are used for the reaction heat energy conditions of the step A and the raw materials of the electrolyzed water; and/or converting the heat energy into biomass electric energy to provide electric energy for the electrolyzed water in the step A. |5. The process for the preparation of renewable methanol according to claim 4, wherein said step C comprises: the reaction ratio of the renewable hydrogen to the renewable carbon dioxide is adjusted to be more than or equal to 3:1, the synthesis reaction is carried out under the action of the catalyst, and the renewable methanol product meeting the standard is obtained after rectification and water separation are carried out to remove impurities.|6. The process for producing renewable methanol according to claim 4, wherein renewable carbon dioxide is compressed to 1.6MPa for the first time, mixed with renewable hydrogen gas to 2.0MPa for the second time, and then mixed with unreacted gas in the renewable methanol synthesis reaction to 8.0MPa for the third time; the raw material gas after three times of compression enters a renewable methanol synthesis tower system for synthesis reaction, and unreacted gas returns to be mixed and compressed with the raw material gas.|7. A system for producing renewable methanol, comprising: anaerobic fermentation device, gas separation device, electrolytic water hydrogen production device, synthesis reaction device and methanol synthesis device;| the renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable hydrogen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the methanol synthesis device; | The renewable power generated by renewable energy sources is combined with the electrolytic water hydrogen production device, and a renewable oxygen outlet of the electrolytic water hydrogen production device is connected with a raw material inlet of the synthesis reaction device; | The biomass is fermented by the anaerobic fermentation device, the anaerobic fermentation device is connected with the gas separation device, and the gas separation device is used for separating renewable methane and renewable carbon dioxide; the renewable methane outlet of the gas separation device is connected with the synthesis reaction device, and the renewable carbon dioxide outlet of the gas separation device is connected with the raw material inlet of the methanol synthesis device; the renewable carbon dioxide outlet of the synthesis reaction device is connected with the raw material inlet of the methanol synthesis device, and the water outlet of the synthesis reaction device is connected with the water inlet of the water electrolysis device; | The heat energy of the synthesis reaction device provides needed and/or renewable electric energy for the water electrolysis hydrogen production device through a heat exchange mode. | 13 | Abstract | gpt-4o-mini | uncertain | The article discusses a process for producing renewable methanol from biomass and includes CO₂ generation and recycling, but it does not clearly indicate a system for capturing and storing CO₂, which is central to BECCS. | |||||||||||||||||||||||||
| 14 | CN202411601172 | CN202411601172 | CN119476842 | 113425432 | CN119476842 A 2025-02-18 [CN119476842] | 2024-11-11 | 2024-11-11 | 2025-02-18 | (CN119476842)|2044-11-11 | (CN119476842)|Agricultural integrated energy system scheduling method considering biomass energy and air source heat pump | (CN119476842)|The invention relates to an agricultural integrated energy system (IAES) low-carbon economic dispatching method considering biomass energy power generation and air source heat pump energy supply, which is characterized by comprising the following steps of: firstly, proposing an IAES topological structure considering the energy supply of a biomass energy power plant and an air source heat pump; secondly, mathematical modeling is conducted on key equipment in the IAES, such as a biomass energy power plant, a cogeneration device, a carbon capture device and an air source heat pump; secondly, considering the power grid electricity price and the wind power electricity price in the peak-valley normal period, considering the carbon transaction cost into the daily operation cost, and performing day-ahead low-carbon economic dispatching on the IAES; finally, simulation verification shows that the provided optimal scheduling method can excavate the IAES carbon emission reduction potential to the maximum extent and considers the system operation economy. | DONGYING POWER SUPPLY|STATE GRID SHANDONG ELECTRIC POWER | (CN119476842)|STATE GRID SHANDONG ELECTRIC POWER COMPANY GUANGRAO POWER SUPPLY COMPANY ([CN])|DONGYING POWER SUPPLY COMPANY, STATE GRID SHANDONG ELECTRIC POWER CO., LTD. | YANG ZHEN|HAN DONG|REN MENGMENG|WANG FENGXIANG|WANG YULING|SUN YONGJIAN|WANG PENGCHENG|SONG JUNHUA|HAN CHUNJIN|HOU JIANJIAN | (CN119476842)|YANG ZHEN|HAN DONG|REN MENGMENG|WANG FENGXIANG|WANG YULING|SUN YONGJIAN|WANG PENGCHENG|SONG JUNHUA|HAN CHUNJIN|HOU JIANJIAN | (CN119476842)|Shui Qian;BEIJING JINSHUOGUO INTELLECTUAL PROPERTY AGENCY|Reg. Nb: 11259 | (CN119476842)|Compared with other types of heat pumps, the air source heat pump has the advantages of convenience in installation, strong adaptability, low initial investment, no geothermal loop requirement and the like, and is applied to a certain degree in the northern heat supply and industrial parks.| | (CN119476842)|1. The method for dispatching the agricultural comprehensive energy system by considering biomass energy and an air source heat pump comprises the steps of firstly modeling the whole comprehensive energy system in an agricultural scene, breaking a barrier of a single energy system in the agricultural comprehensive energy system to meet higher electric heating and cooling load in an agricultural base, realizing complementary and mutual utilization of different energy sources, effectively exerting advantages and potential of different energy sources, enabling equipment in the agricultural comprehensive energy system to comprise a PV (photovoltaic) device, a BPP (thermal processing) device, a CHP (absorption refrigeration) device, an ORC (organic matters-based) low-temperature waste heat generating device, an air source heat pump, an electric refrigerator, an electric energy storage device, a thermal energy storage device, a CCS (carbon storage) device, a P2G (Peer-2G) device and the like, and providing a new path for the consumption of wind power by taking into account a principle of nearby consumption into account, and increasing the purchase of green electricity of the self, wherein the P is combined with the CCS device, and carbon emission of the system is reduced and participates in carbon trading in a rural market under the stimulation of stepped carbon trading.|4. The proposed scheduling strategy is already a mixed integer linear problem, key equipment such as BPP, CHP, air source heat pump and BECCS and the like are modeled in an agricultural comprehensive energy system, a stepped carbon transaction mechanism and a green certificate transaction mechanism are introduced, carbon transaction cost and green certificate purchase are made into a part serving as an objective function, and finally under the conditions of meeting equipment output constraint, energy balance constraint and the like, the objective function is as follows: for the daily purchase cost of the system, The cost of purchasing a green certificate for the system,The benefits obtained for selling energy of the agricultural comprehensive energy system; the proposed low-carbon economic dispatching strategy can be used for solving an optimal solution through a mathematical programming accurate algorithm, and a CPLEX solver in a YALMIP tool box is called by using a MATLAB platform to solve. | | (CN119476842)|The invention provides the low-carbon economic dispatching method of the agricultural comprehensive energy system considering biomass energy power generation and air source heat pump energy supply, which reduces the impact of the agricultural comprehensive energy system on the power distribution network, reduces the peak regulation pressure of the power distribution network, combines a stepped carbon transaction mechanism to further excavate the carbon emission reduction potential of the agricultural comprehensive energy system, ensures the economy of the system and simultaneously further reduces the carbon emission.|The invention relates to a low-carbon economic dispatching method of an agricultural comprehensive energy system (INTEGRATED AGRICULTURAL ENERGY SYSTEM, IAES) taking biomass energy power generation and air source heat pump energy into consideration, which is characterized in that a IAES topological structure taking biomass energy power generation and air source heat pump energy supply is firstly proposed, key equipment in IAES such as biomass energy power generation plants, cogeneration devices, carbon capture devices, air source heat pumps and the like are subjected to mathematical modeling, the power grid electricity price and wind power electricity price at peak-valley time periods are taken into consideration, the carbon transaction cost is taken into consideration of daily operation cost, the IAES is subjected to daily low-carbon economic dispatching, and finally simulation verification shows that the proposed optimal dispatching method can furthest excavate IAES carbon emission reduction potential and take account the system operation economy.| | (CN119476842)|COMPREHENSIVE ENERGY SYSTEM(100,39)|AGRICULTURAL COMPREHENSIVE ENERGY SYSTEM(100,38)|AIR SOURCE HEAT PUMP(100,18)|BIOMASS ENERGY(100,18)|BPP(100,16)|BECCS(100,9)|CARBON TRANSACTION(100,9)|STEPPED CARBON TRANSACTION(100,8)|COMBINED HEATING AND POWER(100,5)|ECONOMIC DISPATCHING(100,4)|CARBON TRANSACTION COST(100,2)|KEY EQUIPMENT(100,2)|OBJECTIVE FUNCTION(100,2)|AIR SOURCE(100,1)|CONSIDERING BIOMASS ENERGY(100,1)|ENERGY BALANCE CONSTRAINT(100,1)|EQUIPMENT OUTPUT CONSTRAINT(100,1)|GREEN CERTIFICATE PURCHASE(100,1)|GREEN CERTIFICATE TRANSACTION(100,1)|PROPOSED SCHEDULING STRATEGY(100,1)|ECONOMIC DISPATCHING STRATEGY(90,1)|YALMIP TOOLBOX(74,1)|CPLEX SOLVER(70,1)|PROPOSED OPTIMAL DISPATCHING(64,1)|AGRICULTURAL SCENE(63,1)|SIMULATION VERIFICATION(63,1)|GEOTHERMAL LOOP REQUIREMENT(60,2)|MATLAB PLATFORM(59,1)|STEPPED CARBON TRADING STIMULATION(58,1)|BIOMASS STRAW(55,2)|RURAL MARKET(54,1)|HARVESTED CROP STRAW(45,2)|CROP STRAW HUMIDITY(43,2)|CROP SEASONALITY(42,1)|RICH BIOMASS RESOURCE(40,2)|COGENERATION(40,1)|IAES TOPOLOGICAL STRUCTURE(40,1)|ELECTRICITY PRICE(39,2)|IAES(39,2)|GENERATION PLANT(39,1)|DAILY PURCHASE(38,3)|NEARBY CONSUMPTION(38,2)|IAES CARBON EMISSION(38,1)|STEPPED CARBON TRADING(38,1)|INVESTMENT(37,4)|WEAK CONSUMPTION INTENTION(36,1)|ABSORPTION TOWER(34,4)|ADAPTABILITY(34,2)|GREEN CERTIFICATE(33,6)|CCS(32,6)|ELECTROTHERMAL CONVERSION COEFFICIENT(32,2)|GREEN ELECTRICITY QUOTA PROPORTION(30,2)|MATHEMATICAL MODELING(30,1)|GREEN ELECTRICITY COMPETITIVENESS(29,2)|NORTHERN HEAT SUPPLY(29,2)|REGENERATING TOWER(29,2)|SELLING ENERGY(29,2)|REWARDING COEFFICIENT(28,2)|PURCHASE(28,1)|GREEN ELECTRICITY(27,7)|CARBON TRADING(27,5)|P2G(27,3)|PEAK REGULATION(27,3)|PHOTOVOLTAIC(27,2)|SELF GREEN ELECTRICITY(27,2)|MATHEMATICAL PROGRAMMING(27,1)|ABSORPTION REFRIGERATION(26,1)|ENERGY QUOTA(26,1)|OPTIMAL SOLUTION(26,1)|ELECTRICAL REFRIGERATOR(25,7)|BIOMASS PARTICLE(24,2)|BPP DAY(24,2)|BPP MODEL(24,2)|DEVELOPMENT PROSPECT(24,2)|PURCHASING GREEN ELECTRICITY(24,2)|SMOKE(23,4)|LOW CARBON ECONOMIC DISPATCHING(23,3)|BPP MEET(23,2)|INDUSTRIAL PARK(23,2)|POWER GRID ELECTRICITY PRICE(23,1)|WINDPOWER ELECTRICITY PRICE(23,1)|CARBON EMISSION(22,11)|MONOETHANOLAMINE(22,4)|CERTIFICATE ELECTRICITY SEPARATION(22,2)|USER ENTHUSIASM(22,2)|CARBON STORAGE(22,1)|ECONOMY(22,1)|HARVEST ABLE STRAW WEIGHT(22,1)|CARBON QUOTA FACTOR(21,2)|CROP STRAW STORAGE PERFORMANCE(21,2)|DAILY SCHEDULING PERIOD(21,2)|CARBON TRADING INFLUENCE(21,1)|PEER(21,1)|CONSUMER(19,4)|GREEN ELECTRICITY QUOTA RATIO(19,2)|P2G EQUIPMENT(19,2)|AGRICULTURAL BASE(18,5)|GAS TURBINE CARBON QUOTA(18,2)|RELEASED MEA SOLUTION(18,2)|SUSTAINABILITY(18,2)|WINDPOWER CONSUMPTION(18,2)|CSD(17,6)|REFRIGERATION WORKING STATE MARK(17,2)|TRANSACTION MODE(17,2)|GREEN TRADING(17,1)|NEXT ROUND ABSORPTION(17,1)|PUNISHMENT(16,3)|BPP POWER GENERATION(16,2)|ENTERPRISE IMAGE(16,2)|WINDPOWER(16,2)|REFRIGERATING POWER(15,2)|CARBON CAPTURE(14,5)|REDUCTION POTENTIAL(14,3)|PRETREATMENT(14,2)|ANDTHE ELECTRIC HEATING(14,1)|CARBON TRADE MARKET(13,3)|ANDTHE ELECTRICAL POWER(13,2)|ANDTHE POWER(13,2)|CRUSHING(13,2)|FAIRNESS(13,2)|FERTILIZER(13,2)|TOTAL CARBON EMISSION QUOTA(13,2)|DAILY OPERATION COST(13,1)|NEGATIVE CARBON EMISSION(13,1)|AGRICULTURAL ENERGY SYSTEM(12,1)|CHINA STILL(12,1)|COMPACTING(12,1)|CROP HARVEST SEASONALITY(12,1)|ELECTRIC ENERGY(11,3)|FIXATION(11,2)|PEANUT(11,2)|PENALTY(11,2)|PLANTING AREA(11,2)|SOYBEAN(11,2)|COLD PRODUCTION(11,1)|DAILY LOW CARBON(11,1)|AGRICULTURAL INTEGRATED ENERGY SYSTEM(10,13)|HEAT PUMP(10,11)|ENERGY SUPPLY(10,4)|AQUEOUS SOLUTION(10,2)|BIOMASS ENERGY CARBON CAPTURE(10,2)|BIOMASS POWER GENERATION(10,2)|CARBON TRADE BASE PRICE(10,2)|CARBON TRADE MODEL(10,2)|CET(10,2)|GREEN ELECTRICAL POWER(10,2)|MATCHING SOURCE LOAD(10,2)|PERFORMING STORAGE(10,2)|PREPROCESSING BIOMASS MATERIAL(10,2)|SLAG(10,2)|WHEAT(10,2)|CONSUMED ELECTRIC LOAD CONDITION(10,1)|HEAT PUMP HOT LOAD(10,1)|ELECTRIC HEATING(9,6)|ENERGY SOURCE(9,5)|POWER GRID(9,5)|CARBON TRADE COST(9,2)|COOLING LOAD(9,2)|CORN(9,2)|ECONOMIC RETURN(9,2)|INTERVAL LENGTH(9,2)|SOURCE LOAD MATCHING POTENTIAL(9,2)|WASTE HEAT(9,2)|LOW CARBON PROPOSITION(9,1)|BIOMASS ENERGY POWER PLANT(8,2)|CARBON EMISSION REDUCTION POTENTIAL(8,2)|COMBUSTION(8,2)|SUPPLYING HEAT(8,2)|SYSTEM OPERATION ECONOMY(8,1)|WASTE CROP STRAW(8,1)|WINDPOWER PLANT(7,6)|CARBON EMISSION SOURCE(7,2)|CHAIN CLOSED LOOP(7,2)|CROP UNIT AREA(7,2)|ENERGY CONVERSION(7,2)|GREEN EVIDENCE(7,2)|GROWTH(7,2)|WORKING MODEL(7,2)|LADDER CARBON TRANSACTION(7,1)|PEAK VALLEY TIME PERIOD(7,1)|REFRIGERATOR EXISTENCE(7,1)|SCHEDULING STRATEGY(7,1)|COLD LOAD(6,5)|POWER DISTRIBUTION NETWORK(6,4)|BECCS JOINT P2G(6,1)|HARVESTING CROP(6,1)|NORTHERN AGRICULTURAL BASE TRANSFORMATION(6,1)|SCENARIO(5,6)|ALLOWING CARBON EMISSION(5,2)|CARBON REDUCTION(5,2)|INTEGRATED ABSORPTION REFRIGERATOR(5,2)|ORGANIC MATTERS BASED(5,2)| | (CN119476842)|1. The method for dispatching the agricultural comprehensive energy system by considering biomass energy and an air source heat pump comprises the steps of firstly modeling the whole comprehensive energy system in an agricultural scene, breaking a barrier of a single energy system in the agricultural comprehensive energy system to meet higher electric heating and cooling load in an agricultural base, realizing complementary and mutual utilization of different energy sources, effectively exerting advantages and potential of different energy sources, enabling equipment in the agricultural comprehensive energy system to comprise a PV (photovoltaic) device, a BPP (thermal processing) device, a CHP (absorption refrigeration) device, an ORC (organic matters-based) low-temperature waste heat generating device, an air source heat pump, an electric refrigerator, an electric energy storage device, a thermal energy storage device, a CCS (carbon storage) device, a P2G (Peer-2G) device and the like, and providing a new path for the consumption of wind power by taking into account a principle of nearby consumption into account, and increasing the purchase of green electricity of the self, wherein the P is combined with the CCS device, and carbon emission of the system is reduced and participates in carbon trading in a rural market under the stimulation of stepped carbon trading.|2. The content of claim 1, wherein the internal key devices are specifically and mathematically modeled:| Crops such as wheat, corn, soybean, peanut and the like are planted in the agricultural comprehensive energy system, crop straws can be used as rich biomass resources, slag and the like generated after combustion can be used as fertilizer to be fed back to the land in the agricultural comprehensive energy system, the traditional biomass energy power plant needs to carry out a large amount of investment in purchasing, transporting, storing and preprocessing biomass materials, the agricultural comprehensive energy system can finish an industrial chain closed loop of biomass energy power generation, the biomass purchasing and transporting process is omitted, the biomass itself is considered as 0 carbon emission, CO 2 generated in the combustion process is equivalent to CO 2 absorbed by the biomass during the growth process, smoke generated by combustion can be captured through CCS, CO 2 is fed into P2G equipment, negative carbon emission can be realized, the carbon reduction potential of the agricultural comprehensive energy system is further excavated, the thermal value of the harvested crop straws is calculated by taking years as a period, and the thermal value of the crop is limited by the seasonality of crop harvesting: | Wherein L CS is the total heat value of crop straws harvested within one year, N is the number of types of crops capable of harvesting straws, s i is the planting area of the ith crop, m i is the weight of the harvestable straws in the unit area of the ith crop, and L i is the heat value of the unit mass of the ith crop straws; | In order to improve the stability and storage performance of crop straws and reduce the volume and humidity of the crop straws, so that the crop straws are more suitable for biomass energy power generation, the biomass straws are subjected to pretreatment, usually drying, crushing and compacting processes, and the biomass straws can participate in daily scheduling in consideration of the sustainability of a biomass power plant, so that the total heat value of biomass particles capable of participating in power generation every day is L CSD: | wherein E CSD and Q CSD are total values of electric energy and heat energy of biomass power generation which participate in daily scheduling, AndThe electric heating conversion efficiency of biomass energy;| the BPP meets the requirement that the total electric energy sent in a daily scheduling period is equal to E CSD, so that the source side flexibility can be improved, the potential of source load matching is further mined, and the model of the BPP participating in scheduling is as follows: | Wherein the method comprises the steps of Delta BPP (t) is the working state sign of the BPP and is a variable of 0-1; And P Maximum and minimum output power for BPP; And Minimum continuous working time and maximum switching times per day of the BPP;| The smoke generated by BPP power generation can finally be absorbed and stored to CO 2 in an absorption tower through monoethanolamine (monoethanolamine, MEA) aqueous solution to finish the biomass energy carbon capturing (biomass energy carbon capture and storage, BECCS), besides BPP, the smoke from CHP can also be subjected to the process in an agricultural integrated energy system, CO 2 is heated and released in a regeneration tower through heating, the released MEA solution can be sent back to the absorption tower for CO 2 absorption of the next round, and the released CO 2 can be sent to a P2G system for fixation; | Compared with other types of heat pumps, the air source heat pump has the advantages of convenience in installation, strong adaptability, low initial investment, no geothermal loop requirement and the like, is applied to a certain extent in the northern heat supply and industrial park, is used as an energy conversion unit for providing the required cold and hot loads in the agricultural comprehensive energy system, and focuses on the equipment energy flow condition, so that the conditions of consumed electric load and produced cold and hot loads of a heat pump unit are mainly considered, and a working model is as follows: | Wherein the method comprises the steps of AndThe electric power consumed by the heat pump and the heating and refrigerating power are respectively; And Heating and cooling efficiencies respectively; And The heat supply and refrigeration working state marks are respectively 0-1 variable; And The maximum power of heating and cooling is respectively.|3. According to claim 1, the influence of a carbon trading mechanism and a green trading mechanism is considered in scheduling of the agricultural integrated energy system, a reward and punishment type stepped carbon trading mechanism is adopted, the low-carbon potential of the system can be further excavated while fairness is achieved, BPP in the agricultural integrated energy system is considered to be 0 carbon emission in the carbon trading mechanism, a carbon emission source is a gas turbine, so that a carbon emission quota is set for the gas turbine, the gas turbine can produce electricity and heat at the same time, a conversion coefficient is introduced, and the carbon quota of the gas turbine is as follows:| wherein C QUO is the total carbon emission quota of the agricultural integrated energy system, ε QUO is the unit thermal power carbon quota factor, γ is the electrothermal conversion coefficient of the gas turbine, the part of the agricultural integrated energy system exceeding the carbon emission quota needs to be purchased in the carbon trade market, the part below the carbon emission quota can be sold in the carbon trade market to obtain benefits, and the whole carbon trade model is as follows: | Wherein f CET is the carbon trade cost, χ is the carbon trade base price, α and β are penalty and rewarding coefficients, respectively, l is the interval length, and C tran is the carbon trade amount; | The green electric power purchase certificate has great development prospect in China, but at present, china still generally adopts a transaction mode of 'certificate-electricity separation', and most consumers have weak consumption intention on the green certificate, and a 'certificate-electricity integrated' model is adopted, so that the green electricity and the green certificate are bound and sold, and the green certificate is purchased at the same time when an agricultural comprehensive energy system purchases electricity from a wind power plant, thereby accelerating the economic return of the wind power plant and enabling the consumers to more easily trace the green electricity; | In order to improve the enthusiasm of users for purchasing green electricity and promote the competitiveness of green electricity in the market, a reasonable green electricity quota proportion is set for an energy purchasing main body, so that the consumption rate of new energy can be improved, good enterprise images can be built, and the quota of the energy purchasing main body in an agricultural comprehensive energy system can meet the following conditions: | Wherein the method comprises the steps of AndThe power is purchased from the agricultural comprehensive energy system to the wind power plant and the power grid,And θ is the set green electricity quota ratio.|4. The proposed scheduling strategy is already a mixed integer linear problem, key equipment such as BPP, CHP, air source heat pump and BECCS and the like are modeled in an agricultural comprehensive energy system, a stepped carbon transaction mechanism and a green certificate transaction mechanism are introduced, carbon transaction cost and green certificate purchase are made into a part serving as an objective function, and finally under the conditions of meeting equipment output constraint, energy balance constraint and the like, the objective function is as follows:| for the daily purchase cost of the system, The cost of purchasing a green certificate for the system,The benefits obtained for selling energy of the agricultural comprehensive energy system;| the proposed low-carbon economic dispatching strategy can be used for solving an optimal solution through a mathematical programming accurate algorithm, and a CPLEX solver in a YALMIP tool box is called by using a MATLAB platform to solve. | (CN119476842)|TECHNICAL FIELD|Technical Field|[0001] The invention belongs to the field of comprehensive energy system optimization scheduling, and particularly relates to a low-carbon economic scheduling method of an agricultural comprehensive energy system taking biomass energy power generation and air source heat pump energy supply into consideration.|BACKGROUND ART|[0002] Along with the trend of 'coal to electricity' becoming the clean heat supply of northern agricultural base transformation, because agricultural base electric heating load has the characteristics of high power and strong rigidity, a large amount of electric refrigeration load and other production loads are generated due to the existence of a refrigerator in the agricultural base, the large-scale development of the electric heating load can impact a power distribution network which is weaker in rural areas, and the electric heating load brings great peak regulation pressure to a power grid, so that potential safety hazards are generated.|[0003] The agricultural comprehensive energy system is internally coupled with various energy sources, biomass energy power generation is carried out through devices such as a heat pump and waste crop straws, so that the source measurement flexibility can be greatly improved, the peak regulation pressure of a power grid is reduced, the terminal multi-energy load requirement is met, and the low-carbon economy of an agricultural base is further optimized. Therefore, low-carbon economic dispatch research on an agricultural integrated energy system considering biomass energy power generation and air source heat pump energy supply is very necessary.|DISCLOSURE|Disclosure of Invention|[0004] The invention provides the low-carbon economic dispatching method of the agricultural comprehensive energy system considering biomass energy power generation and air source heat pump energy supply, which reduces the impact of the agricultural comprehensive energy system on the power distribution network, reduces the peak regulation pressure of the power distribution network, combines a stepped carbon transaction mechanism to further excavate the carbon emission reduction potential of the agricultural comprehensive energy system, ensures the economy of the system and simultaneously further reduces the carbon emission.|[0005] In order to realize the low-carbon economic dispatching method of the agricultural comprehensive energy system, the system needs to be modeled and analyzed through the following processes:|[0006] In order to meet higher electric heating and cooling loads in an agricultural base, break barriers of a single energy system in an agricultural integrated energy system, realize complementary mutual benefits of different energy sources, and effectively exert advantages and potential of different energy sources, equipment in the agricultural integrated energy system comprises Photovoltaic (PV), biomass power plants (biomass powerplant, BPP), combined HEATING AND power (CHP) devices of an integrated absorption refrigerator, low-temperature waste heat power generation devices based on organic RANKINE CYCLE, ORC (organic) devices, air source heat pumps, electric refrigerators, electric energy storage, thermal energy storage, carbon capture (carbon capture and storage, CCS), power-to-gas (P2G) devices and the like. When the agricultural comprehensive energy system is connected with the air network and the power distribution network, the principle of nearby consumption is considered, and the agricultural comprehensive energy system and a distributed wind power plant nearby the rural area are subjected to a protocol, so that a new path is provided for wind power consumption, and the purchase of self green electricity is increased. The BPP is combined with the CCS device, reduces the carbon emission of the system under the stimulation of the stepped carbon trade and participates in the carbon trade market. |[0007] Crops such as wheat, corn, soybean, peanut and the like are planted in the agricultural comprehensive energy system, crop straws can be used as rich biomass resources, and slag and the like generated after combustion can be used as fertilizer to be fed back to the land in the agricultural comprehensive energy system. The traditional biomass energy power plant needs to carry out a large amount of investment in purchasing, transporting, storing and preprocessing biomass materials, and the agricultural comprehensive energy system can complete the industrial chain closed loop of biomass energy power generation, so that the biomass purchasing and transporting process is omitted. The biomass is regarded as 0 carbon emission, CO 2 generated in the combustion process is equivalent to CO 2 absorbed in the growth process, smoke generated in the combustion can be captured through CCS, CO 2 is sent to P2G equipment, carbon emission can be achieved, and carbon reduction potential of the agricultural comprehensive energy system is further exploited. The heat value of the harvested crop straw is calculated by taking years as a period limited by the seasonality of crop harvest:|[0008] |[0009] Wherein L CS is the total heat value of the crop straw harvested within one year, N is the number of types of crops capable of harvesting the straw, s i is the planting area of the ith crop, m i is the weight of the straw capable of harvesting per unit area of the ith crop, and L i is the heat value of the unit mass of the ith crop straw. |[0010] In order to improve the stability and storage performance of crop straws and reduce the volume and humidity of the crop straws, so that the crop straws are more suitable for biomass energy power generation, pretreatment, usually drying, crushing and compacting processes are carried out. Considering the sustainability of a biomass power plant and its participation in the day-ahead schedule, the total heating value of biomass particles that can participate in power generation daily is made to be L CSD.|[0011] |[0012] Wherein E CSD and Q CSD are total values of electric energy and heat energy of biomass power generation which participate in daily scheduling,AndIs the electrothermal conversion efficiency of biomass energy.|[0013] The BPP meets the requirement that the total electric energy sent in a daily scheduling period is equal to E CSD, so that the source side flexibility can be improved, the potential of source load matching is further mined, and the model of the BPP participating in scheduling is as follows:|[0014] |[0015] Wherein the method comprises the steps of Delta BPP (t) is the working state sign of the BPP and is a variable of 0-1; And Maximum and minimum output power for BPP; And The minimum continuous operation time and the maximum switching times per day of the BPP.|[0016] The flue gas generated by BPP power generation can finally be absorbed and stored in the CO 2 through the monoethanolamine (monoethanolamine, MEA) aqueous solution in an absorption tower to complete the biomass carbon capturing (biomass energy carbon capture and storage, BECCS). In addition to BPP in the agricultural integrated energy system, the flue gas from CHP can also be used for the above process. The CO 2 is heated and released in the regeneration tower, the released MEA solution can be sent back to the absorption tower for the next round of CO 2 absorption, and the released CO 2 can be sent to the P2G system for fixation.|[0017] Compared with other types of heat pumps, the air source heat pump has the advantages of convenience in installation, strong adaptability, low initial investment, no geothermal loop requirement and the like, and is applied to a certain degree in the northern heat supply and industrial parks. The air source heat pump is used as an energy conversion unit to provide cold and hot loads required in an agricultural comprehensive energy system, and the energy flow condition of equipment is concerned, so that the conditions of electricity consumption load and cold and hot load output of a heat pump unit are mainly considered, and the working model is as follows:|[0018] |[0019] Wherein the method comprises the steps of AndThe electric power consumed by the heat pump and the heating and refrigerating power are respectively; And Heating and cooling efficiencies respectively; And The heat supply and refrigeration working state marks are respectively 0-1 variable; And The maximum power of heating and cooling is respectively.|DRAWINGS DESCRIPTION|[0020] FIG. 1 is a diagram of an agricultural integrated energy system operating framework taking biomass energy power generation and air source heat pumps into account.|[0021] Fig. 2 is a flow chart of BECCS-joint P2G.|INVENTION MODE|Detailed Description|[0022] The scheduling method adopts a punishment and punishment type ladder-type carbon transaction mechanism, so that the low-carbon potential of the system can be further excavated while fairness is achieved. The BPP in the agricultural comprehensive energy system is considered to be 0 carbon emission in a carbon trading mechanism, the carbon emission source is a gas turbine, so that the gas turbine is provided with carbon emission quota, the gas turbine can produce electricity and heat simultaneously, and the conversion coefficient is introduced, so that the carbon quota of the gas turbine is as follows:|[0023] |[0024] Wherein C QUO is the total carbon emission quota of the agricultural integrated energy system, epsilon QUO is the unit thermal power carbon quota factor, and gamma is the electrothermal conversion coefficient of the gas turbine. The part of the agricultural integrated energy system exceeding the carbon emission allowance needs to be purchased in the carbon trade market, while the part below the carbon emission allowance can be sold in the carbon trade market to obtain benefits, and the whole carbon trade model is as follows: |[0025] |[0026] where f CET is the carbon trade cost, χ is the carbon trade base price, α and β are penalty and rewarding coefficients, respectively, l is the interval length, and C tran is the carbon trade amount. |[0027] The green electric power purchase certificate has great development prospect in China. At present, a transaction mode of 'certificate-electricity separation' is still commonly adopted in China, and the consumption will of most consumers on green certificates is not strong. The model of 'electricity and evidence integration' is adopted, so that green electricity and green evidence are bound and sold, and the green evidence is purchased at the same time when an agricultural comprehensive energy system purchases electricity to a wind power plant, so that the economic return of the wind power plant is quickened, and consumers can more easily trace the source of the green electricity.|[0028] In order to improve the enthusiasm of users for purchasing green electricity, promote the competitiveness of green electricity in the market, set up reasonable green electricity quota proportion to purchasing energy main body, not only can promote the rate of absorption of new energy, but also can establish good enterprise image. The quota of the agricultural integrated energy system should meet the following conditions:|[0029] |[0030] Wherein the method comprises the steps of AndThe power is purchased from the agricultural comprehensive energy system to the wind power plant and the power grid,And θ is the set green electricity quota ratio.|[0031] The agricultural comprehensive energy system aims at minimizing daily purchase and sale energy under the condition of meeting balance of electric power, heat power, cold power and gas power:|[0032] |[0033] for the daily purchase cost of the system, The cost of purchasing a green certificate for the system,The method is a benefit obtained for selling energy of an agricultural comprehensive energy system.|[0034] In order to avoid the mechanism of natural gas' one-zone monovalentAndAnd under the condition that the values are taken at the same time and cannot be solved, the following constraint is satisfied:|[0035] |[0036] The following 5 scenes were set for comparative analysis. Scene 1 including BPP and BECCS system and ORC based low temperature waste heat power generation device, but considering only conventional carbon transaction mechanism, scene 2 including BPP and ORC based low temperature waste heat power generation device, no BECCS system and considering stepped carbon transaction mechanism, scene 3 including BPP and BECCS system, no ORC based low temperature waste heat power generation device, considering stepped carbon transaction mechanism, scene 4 including CCS system and ORC based low temperature waste heat power generation device, no BPP and considering stepped carbon transaction mechanism, and scene 5 including BPP, BECCS system and ORC based low temperature waste heat power generation device, and considering stepped carbon transaction mechanism. The optimized scheduling results in each scenario are shown in table 1. |[0037] Optimizing scheduling results in various scenes|[0038] |[0039] As can be seen from table 1, in scenario 5, the carbon emission of the system was 29748kg, which is the lowest of the scenarios, was 445kg lower than scenario 1 under the traditional carbon trade mechanism, 1363kg lower than scenario 2 without BECCS, 2324kg lower than scenario 4 without BPP, and thus it can be seen that BECCS combined with the stepped carbon trade mechanism can maximize the carbon emission reduction potential of the excavation system. In terms of operation cost, since the influence of the scene 1 on the operation of the agricultural comprehensive energy system due to the traditional carbon transaction mechanism is less remarkable than that of the stepped carbon transaction, the cost of the scene 1 is the lowest, and in the other 4 scenes considering the stepped carbon transaction, the operation cost of the scene 5 is lower than that of other scenes, so that the aim of low-carbon economic operation of the agricultural comprehensive energy system is fulfilled.|[0040] The air source heat pump and the electric refrigerator bear most of cold and hot loads in the agricultural comprehensive energy system, and as the vegetable fresh-keeping in the agricultural comprehensive energy system needs to work for a long time, the cold load still remains larger at night, and when the midday air temperature rises, the cold load can be increased sharply, the change of the heat load is relatively stable relative to the cold load, and the average value is still higher. The electric refrigerator can provide relatively stable cold load, and the rest of a large amount of cold load needs the air source heat pump to flexibly supply energy.|[0041] Because the efficiency of the air source heat pump is higher, a double air source heat pump is adopted in the scheduling strategy, the heat pump 1 is almost in a full-power output state in the whole process, and because the peak-valley difference of the heat load is smaller and the average value is larger, the heat pump 1 with larger capacity bears the 'base load' part of the heat load. The working state of the heat pump 2 is flexible, and the power of the cold load is smaller in the valley period, and the energy supply priority of the electric refrigerator is not high, so that the electric refrigerator has certain standby capacity, the heat pump 2 can supply heat in the peak period of the heat load, and the refrigeration is selected in the non-peak period of the heat load. The configuration mode of the double heat pump combined electric refrigerator improves the flexibility of internal energy supply and the economical efficiency of the agricultural comprehensive energy system.|[0042] While the present invention has been described in detail, it will be apparent that the present invention is not limited to the embodiments given, but is intended to cover various modifications which can be made by those skilled in the art without departing substantially from the spirit and scope of the present invention. | (CN119476842)|TECHNICAL FIELD|Technical Field|[0001] The invention belongs to the field of comprehensive energy system optimization scheduling, and particularly relates to a low-carbon economic scheduling method of an agricultural comprehensive energy system taking biomass energy power generation and air source heat pump energy supply into consideration.|BACKGROUND ART|[0002] Along with the trend of 'coal to electricity' becoming the clean heat supply of northern agricultural base transformation, because agricultural base electric heating load has the characteristics of high power and strong rigidity, a large amount of electric refrigeration load and other production loads are generated due to the existence of a refrigerator in the agricultural base, the large-scale development of the electric heating load can impact a power distribution network which is weaker in rural areas, and the electric heating load brings great peak regulation pressure to a power grid, so that potential safety hazards are generated.|[0003] The agricultural comprehensive energy system is internally coupled with various energy sources, biomass energy power generation is carried out through devices such as a heat pump and waste crop straws, so that the source measurement flexibility can be greatly improved, the peak regulation pressure of a power grid is reduced, the terminal multi-energy load requirement is met, and the low-carbon economy of an agricultural base is further optimized. Therefore, low-carbon economic dispatch research on an agricultural integrated energy system considering biomass energy power generation and air source heat pump energy supply is very necessary.|DISCLOSURE|Disclosure of Invention|[0004] The invention provides the low-carbon economic dispatching method of the agricultural comprehensive energy system considering biomass energy power generation and air source heat pump energy supply, which reduces the impact of the agricultural comprehensive energy system on the power distribution network, reduces the peak regulation pressure of the power distribution network, combines a stepped carbon transaction mechanism to further excavate the carbon emission reduction potential of the agricultural comprehensive energy system, ensures the economy of the system and simultaneously further reduces the carbon emission.|[0005] In order to realize the low-carbon economic dispatching method of the agricultural comprehensive energy system, the system needs to be modeled and analyzed through the following processes:|[0006] In order to meet higher electric heating and cooling loads in an agricultural base, break barriers of a single energy system in an agricultural integrated energy system, realize complementary mutual benefits of different energy sources, and effectively exert advantages and potential of different energy sources, equipment in the agricultural integrated energy system comprises Photovoltaic (PV), biomass power plants (biomass powerplant, BPP), combined HEATING AND power (CHP) devices of an integrated absorption refrigerator, low-temperature waste heat power generation devices based on organic RANKINE CYCLE, ORC (organic) devices, air source heat pumps, electric refrigerators, electric energy storage, thermal energy storage, carbon capture (carbon capture and storage, CCS), power-to-gas (P2G) devices and the like. When the agricultural comprehensive energy system is connected with the air network and the power distribution network, the principle of nearby consumption is considered, and the agricultural comprehensive energy system and a distributed wind power plant nearby the rural area are subjected to a protocol, so that a new path is provided for wind power consumption, and the purchase of self green electricity is increased. The BPP is combined with the CCS device, reduces the carbon emission of the system under the stimulation of the stepped carbon trade and participates in the carbon trade market. |[0007] Crops such as wheat, corn, soybean, peanut and the like are planted in the agricultural comprehensive energy system, crop straws can be used as rich biomass resources, and slag and the like generated after combustion can be used as fertilizer to be fed back to the land in the agricultural comprehensive energy system. The traditional biomass energy power plant needs to carry out a large amount of investment in purchasing, transporting, storing and preprocessing biomass materials, and the agricultural comprehensive energy system can complete the industrial chain closed loop of biomass energy power generation, so that the biomass purchasing and transporting process is omitted. The biomass is regarded as 0 carbon emission, CO 2 generated in the combustion process is equivalent to CO 2 absorbed in the growth process, smoke generated in the combustion can be captured through CCS, CO 2 is sent to P2G equipment, carbon emission can be achieved, and carbon reduction potential of the agricultural comprehensive energy system is further exploited. The heat value of the harvested crop straw is calculated by taking years as a period limited by the seasonality of crop harvest:|[0008] |[0009] Wherein L CS is the total heat value of the crop straw harvested within one year, N is the number of types of crops capable of harvesting the straw, s i is the planting area of the ith crop, m i is the weight of the straw capable of harvesting per unit area of the ith crop, and L i is the heat value of the unit mass of the ith crop straw. |[0010] In order to improve the stability and storage performance of crop straws and reduce the volume and humidity of the crop straws, so that the crop straws are more suitable for biomass energy power generation, pretreatment, usually drying, crushing and compacting processes are carried out. Considering the sustainability of a biomass power plant and its participation in the day-ahead schedule, the total heating value of biomass particles that can participate in power generation daily is made to be L CSD.|[0011] |[0012] Wherein E CSD and Q CSD are total values of electric energy and heat energy of biomass power generation which participate in daily scheduling,AndIs the electrothermal conversion efficiency of biomass energy.|[0013] The BPP meets the requirement that the total electric energy sent in a daily scheduling period is equal to E CSD, so that the source side flexibility can be improved, the potential of source load matching is further mined, and the model of the BPP participating in scheduling is as follows:|[0014] |[0015] Wherein the method comprises the steps of Delta BPP (t) is the working state sign of the BPP and is a variable of 0-1; And Maximum and minimum output power for BPP; And The minimum continuous operation time and the maximum switching times per day of the BPP.|[0016] The flue gas generated by BPP power generation can finally be absorbed and stored in the CO 2 through the monoethanolamine (monoethanolamine, MEA) aqueous solution in an absorption tower to complete the biomass carbon capturing (biomass energy carbon capture and storage, BECCS). In addition to BPP in the agricultural integrated energy system, the flue gas from CHP can also be used for the above process. The CO 2 is heated and released in the regeneration tower, the released MEA solution can be sent back to the absorption tower for the next round of CO 2 absorption, and the released CO 2 can be sent to the P2G system for fixation.|[0017] Compared with other types of heat pumps, the air source heat pump has the advantages of convenience in installation, strong adaptability, low initial investment, no geothermal loop requirement and the like, and is applied to a certain degree in the northern heat supply and industrial parks. The air source heat pump is used as an energy conversion unit to provide cold and hot loads required in an agricultural comprehensive energy system, and the energy flow condition of equipment is concerned, so that the conditions of electricity consumption load and cold and hot load output of a heat pump unit are mainly considered, and the working model is as follows:|[0018] |[0019] Wherein the method comprises the steps of AndThe electric power consumed by the heat pump and the heating and refrigerating power are respectively; And Heating and cooling efficiencies respectively; And The heat supply and refrigeration working state marks are respectively 0-1 variable; And The maximum power of heating and cooling is respectively.|DRAWINGS DESCRIPTION|[0020] FIG. 1 is a diagram of an agricultural integrated energy system operating framework taking biomass energy power generation and air source heat pumps into account.|[0021] Fig. 2 is a flow chart of BECCS-joint P2G.|INVENTION MODE|Detailed Description|[0022] The scheduling method adopts a punishment and punishment type ladder-type carbon transaction mechanism, so that the low-carbon potential of the system can be further excavated while fairness is achieved. The BPP in the agricultural comprehensive energy system is considered to be 0 carbon emission in a carbon trading mechanism, the carbon emission source is a gas turbine, so that the gas turbine is provided with carbon emission quota, the gas turbine can produce electricity and heat simultaneously, and the conversion coefficient is introduced, so that the carbon quota of the gas turbine is as follows:|[0023] |[0024] Wherein C QUO is the total carbon emission quota of the agricultural integrated energy system, epsilon QUO is the unit thermal power carbon quota factor, and gamma is the electrothermal conversion coefficient of the gas turbine. The part of the agricultural integrated energy system exceeding the carbon emission allowance needs to be purchased in the carbon trade market, while the part below the carbon emission allowance can be sold in the carbon trade market to obtain benefits, and the whole carbon trade model is as follows: |[0025] |[0026] where f CET is the carbon trade cost, χ is the carbon trade base price, α and β are penalty and rewarding coefficients, respectively, l is the interval length, and C tran is the carbon trade amount. |[0027] The green electric power purchase certificate has great development prospect in China. At present, a transaction mode of 'certificate-electricity separation' is still commonly adopted in China, and the consumption will of most consumers on green certificates is not strong. The model of 'electricity and evidence integration' is adopted, so that green electricity and green evidence are bound and sold, and the green evidence is purchased at the same time when an agricultural comprehensive energy system purchases electricity to a wind power plant, so that the economic return of the wind power plant is quickened, and consumers can more easily trace the source of the green electricity.|[0028] In order to improve the enthusiasm of users for purchasing green electricity, promote the competitiveness of green electricity in the market, set up reasonable green electricity quota proportion to purchasing energy main body, not only can promote the rate of absorption of new energy, but also can establish good enterprise image. The quota of the agricultural integrated energy system should meet the following conditions:|[0029] |[0030] Wherein the method comprises the steps of AndThe power is purchased from the agricultural comprehensive energy system to the wind power plant and the power grid,And θ is the set green electricity quota ratio.|[0031] The agricultural comprehensive energy system aims at minimizing daily purchase and sale energy under the condition of meeting balance of electric power, heat power, cold power and gas power:|[0032] |[0033] for the daily purchase cost of the system, The cost of purchasing a green certificate for the system,The method is a benefit obtained for selling energy of an agricultural comprehensive energy system.|[0034] In order to avoid the mechanism of natural gas' one-zone monovalentAndAnd under the condition that the values are taken at the same time and cannot be solved, the following constraint is satisfied:|[0035] |[0036] The following 5 scenes were set for comparative analysis. Scene 1 including BPP and BECCS system and ORC based low temperature waste heat power generation device, but considering only conventional carbon transaction mechanism, scene 2 including BPP and ORC based low temperature waste heat power generation device, no BECCS system and considering stepped carbon transaction mechanism, scene 3 including BPP and BECCS system, no ORC based low temperature waste heat power generation device, considering stepped carbon transaction mechanism, scene 4 including CCS system and ORC based low temperature waste heat power generation device, no BPP and considering stepped carbon transaction mechanism, and scene 5 including BPP, BECCS system and ORC based low temperature waste heat power generation device, and considering stepped carbon transaction mechanism. The optimized scheduling results in each scenario are shown in table 1. |[0037] Optimizing scheduling results in various scenes|[0038] |[0039] As can be seen from table 1, in scenario 5, the carbon emission of the system was 29748kg, which is the lowest of the scenarios, was 445kg lower than scenario 1 under the traditional carbon trade mechanism, 1363kg lower than scenario 2 without BECCS, 2324kg lower than scenario 4 without BPP, and thus it can be seen that BECCS combined with the stepped carbon trade mechanism can maximize the carbon emission reduction potential of the excavation system. In terms of operation cost, since the influence of the scene 1 on the operation of the agricultural comprehensive energy system due to the traditional carbon transaction mechanism is less remarkable than that of the stepped carbon transaction, the cost of the scene 1 is the lowest, and in the other 4 scenes considering the stepped carbon transaction, the operation cost of the scene 5 is lower than that of other scenes, so that the aim of low-carbon economic operation of the agricultural comprehensive energy system is fulfilled.|[0040] The air source heat pump and the electric refrigerator bear most of cold and hot loads in the agricultural comprehensive energy system, and as the vegetable fresh-keeping in the agricultural comprehensive energy system needs to work for a long time, the cold load still remains larger at night, and when the midday air temperature rises, the cold load can be increased sharply, the change of the heat load is relatively stable relative to the cold load, and the average value is still higher. The electric refrigerator can provide relatively stable cold load, and the rest of a large amount of cold load needs the air source heat pump to flexibly supply energy.|[0041] Because the efficiency of the air source heat pump is higher, a double air source heat pump is adopted in the scheduling strategy, the heat pump 1 is almost in a full-power output state in the whole process, and because the peak-valley difference of the heat load is smaller and the average value is larger, the heat pump 1 with larger capacity bears the 'base load' part of the heat load. The working state of the heat pump 2 is flexible, and the power of the cold load is smaller in the valley period, and the energy supply priority of the electric refrigerator is not high, so that the electric refrigerator has certain standby capacity, the heat pump 2 can supply heat in the peak period of the heat load, and the refrigeration is selected in the non-peak period of the heat load. The configuration mode of the double heat pump combined electric refrigerator improves the flexibility of internal energy supply and the economical efficiency of the agricultural comprehensive energy system.|[0042] While the present invention has been described in detail, it will be apparent that the present invention is not limited to the embodiments given, but is intended to cover various modifications which can be made by those skilled in the art without departing substantially from the spirit and scope of the present invention. | Family Number|(113425432)|113425432|Independent Claims|(CN119476842 A)|4. The proposed scheduling strategy is already a mixed integer linear problem , key equipment such as BPP , CHP , air source heat pump and BECCS and the like are modeled in an agricultural comprehensive energy system , a stepped carbon transaction mechanism and a green certificate transaction mechanism are introduced , carbon transaction cost and green certificate purchase are made into ( . . . ) | | Electrical machinery, apparatus, energy|IT methods for management | G06Q-010/04|G06Q-010/06/31|G06Q-030/02/06|G06Q-050/02|G06Q-050/06|H02J-003/00/8|H02J-003/28|H02J-003/38/1|H02J-2101/28 | G06Q-010/04|G06Q-010/06/31|G06Q-030/02/06|G06Q-050/02|G06Q-050/06|H02J-003/00/8|H02J-003/28|H02J-003/38/1|H02J-2101/28 | G06Q-010/04|G06Q-010/0631|G06Q-030/0201|G06Q-050/02|G06Q-050/06|H02J-003/00|H02J-003/28|H02J-003/38 | G06Q-010/04|G06Q-010/0631|G06Q-030/0201|G06Q-050/02|G06Q-050/06|H02J-003/00|H02J-003/28|H02J-003/38 | PENDING | (CN119476842)|PENDING | ALIVE | (CN119476842)|ALIVE | (CN119476842)|LEGAL DETAILS FOR CN119476842|Actual or expected expiration date=2044-11-11|Legal state=ALIVE|Status=PENDING|Event publication date=2024-11-11|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202411601172|Application date=2024-11-11|Standardized application number=2024CN-1601172|Event publication date=2025-02-18|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN119476842|Publication stage code=A|Publication date=2025-02-18|Standardized publication number=CN119476842|Event publication date=2025-02-18|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2025-04-08|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination | (CN119476842)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoTHTzGZbyJwHFfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000076450012&ekey=2371&xpn=CN119476842&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=amoVkcASMfB4cXXwIagmWJNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN119476842)|CN | (CN119476842)|NAME=STATE GRID SHANDONG ELECTRIC POWER COMPANY GUANGRAO POWER SUPPLY COMPANY , COUNTRY=CN | (CN119476842)|NAME=Shui Qian;BEIJING JINSHUOGUO INTELLECTUAL PROPERTY AGENCY , REG=11259 | (CN119476842)|NAME=YANG ZHEN|NAME=HAN DONG|NAME=REN MENGMENG|NAME=WANG FENGXIANG|NAME=WANG YULING|NAME=SUN YONGJIAN|NAME=WANG PENGCHENG|NAME=SONG JUNHUA|NAME=HAN CHUNJIN|NAME=HOU JIANJIAN | (CN119476842)|2 | 1 | 1 | (CN119476842)|Number of Claims: NCL=4|Gazette date: GAZDATE=2025-02-18|Gazette number: GAZNUM=41-0801|Number of Pages: NPAGES=10| | (CN119476842)|CHINESE (CHI) | (CN119476842)|Patent | Titre: (CN119476842)|Agricultural integrated energy system scheduling method considering biomass energy and air source heat pump Résumé: (CN119476842)|The invention relates to an agricultural integrated energy system (IAES) low-carbon economic dispatching method considering biomass energy power generation and air source heat pump energy supply, which is characterized by comprising the following steps of: firstly, proposing an IAES topological structure considering the energy supply of a biomass energy power plant and an air source heat pump; secondly, mathematical modeling is conducted on key equipment in the IAES, such as a biomass energy power plant, a cogeneration device, a carbon capture device and an air source heat pump; secondly, considering the power grid electricity price and the wind power electricity price in the peak-valley normal period, considering the carbon transaction cost into the daily operation cost, and performing day-ahead low-carbon economic dispatching on the IAES; finally, simulation verification shows that the provided optimal scheduling method can excavate the IAES carbon emission reduction potential to the maximum extent and considers the system operation economy. Autre: (CN119476842)|1. The method for dispatching the agricultural comprehensive energy system by considering biomass energy and an air source heat pump comprises the steps of firstly modeling the whole comprehensive energy system in an agricultural scene, breaking a barrier of a single energy system in the agricultural comprehensive energy system to meet higher electric heating and cooling load in an agricultural base, realizing complementary and mutual utilization of different energy sources, effectively exerting advantages and potential of different energy sources, enabling equipment in the agricultural comprehensive energy system to comprise a PV (photovoltaic) device, a BPP (thermal processing) device, a CHP (absorption refrigeration) device, an ORC (organic matters-based) low-temperature waste heat generating device, an air source heat pump, an electric refrigerator, an electric energy storage device, a thermal energy storage device, a CCS (carbon storage) device, a P2G (Peer-2G) device and the like, and providing a new path for the consumption of wind power by taking into account a principle of nearby consumption into account, and increasing the purchase of green electricity of the self, wherein the P is combined with the CCS device, and carbon emission of the system is reduced and participates in carbon trading in a rural market under the stimulation of stepped carbon trading.|2. The content of claim 1, wherein the internal key devices are specifically and mathematically modeled:| Crops such as wheat, corn, soybean, peanut and the like are planted in the agricultural comprehensive energy system, crop straws can be used as rich biomass resources, slag and the like generated after combustion can be used as fertilizer to be fed back to the land in the agricultural comprehensive energy system, the traditional biomass energy power plant needs to carry out a large amount of investment in purchasing, transporting, storing and preprocessing biomass materials, the agricultural comprehensive energy system can finish an industrial chain closed loop of biomass energy power generation, the biomass purchasing and transporting process is omitted, the biomass itself is considered as 0 carbon emission, CO 2 generated in the combustion process is equivalent to CO 2 absorbed by the biomass during the growth process, smoke generated by combustion can be captured through CCS, CO 2 is fed into P2G equipment, negative carbon emission can be realized, the carbon reduction potential of the agricultural comprehensive energy system is further excavated, the thermal value of the harvested crop straws is calculated by taking years as a period, and the thermal value of the crop is limited by the seasonality of crop harvesting: | Wherein L CS is the total heat value of crop straws harvested within one year, N is the number of types of crops capable of harvesting straws, s i is the planting area of the ith crop, m i is the weight of the harvestable straws in the unit area of the ith crop, and L i is the heat value of the unit mass of the ith crop straws; | In order to improve the stability and storage performance of crop straws and reduce the volume and humidity of the crop straws, so that the crop straws are more suitable for biomass energy power generation, the biomass straws are subjected to pretreatment, usually drying, crushing and compacting processes, and the biomass straws can participate in daily scheduling in consideration of the sustainability of a biomass power plant, so that the total heat value of biomass particles capable of participating in power generation every day is L CSD: | wherein E CSD and Q CSD are total values of electric energy and heat energy of biomass power generation which participate in daily scheduling, AndThe electric heating conversion efficiency of biomass energy;| the BPP meets the requirement that the total electric energy sent in a daily scheduling period is equal to E CSD, so that the source side flexibility can be improved, the potential of source load matching is further mined, and the model of the BPP participating in scheduling is as follows: | Wherein the method comprises the steps of Delta BPP (t) is the working state sign of the BPP and is a variable of 0-1; And P Maximum and minimum output power for BPP; And Minimum continuous working time and maximum switching times per day of the BPP;| The smoke generated by BPP power generation can finally be absorbed and stored to CO 2 in an absorption tower through monoethanolamine (monoethanolamine, MEA) aqueous solution to finish the biomass energy carbon capturing (biomass energy carbon capture and storage, BECCS), besides BPP, the smoke from CHP can also be subjected to the process in an agricultural integrated energy system, CO 2 is heated and released in a regeneration tower through heating, the released MEA solution can be sent back to the absorption tower for CO 2 absorption of the next round, and the released CO 2 can be sent to a P2G system for fixation; | Compared with other types of heat pumps, the air source heat pump has the advantages of convenience in installation, strong adaptability, low initial investment, no geothermal loop requirement and the like, is applied to a certain extent in the northern heat supply and industrial park, is used as an energy conversion unit for providing the required cold and hot loads in the agricultural comprehensive energy system, and focuses on the equipment energy flow condition, so that the conditions of consumed electric load and produced cold and hot loads of a heat pump unit are mainly considered, and a working model is as follows: | Wherein the method comprises the steps of AndThe electric power consumed by the heat pump and the heating and refrigerating power are respectively; And Heating and cooling efficiencies respectively; And The heat supply and refrigeration working state marks are respectively 0-1 variable; And The maximum power of heating and cooling is respectively.|3. According to claim 1, the influence of a carbon trading mechanism and a green trading mechanism is considered in scheduling of the agricultural integrated energy system, a reward and punishment type stepped carbon trading mechanism is adopted, the low-carbon potential of the system can be further excavated while fairness is achieved, BPP in the agricultural integrated energy system is considered to be 0 carbon emission in the carbon trading mechanism, a carbon emission source is a gas turbine, so that a carbon emission quota is set for the gas turbine, the gas turbine can produce electricity and heat at the same time, a conversion coefficient is introduced, and the carbon quota of the gas turbine is as follows:| wherein C QUO is the total carbon emission quota of the agricultural integrated energy system, ε QUO is the unit thermal power carbon quota factor, γ is the electrothermal conversion coefficient of the gas turbine, the part of the agricultural integrated energy system exceeding the carbon emission quota needs to be purchased in the carbon trade market, the part below the carbon emission quota can be sold in the carbon trade market to obtain benefits, and the whole carbon trade model is as follows: | Wherein f CET is the carbon trade cost, χ is the carbon trade base price, α and β are penalty and rewarding coefficients, respectively, l is the interval length, and C tran is the carbon trade amount; | The green electric power purchase certificate has great development prospect in China, but at present, china still generally adopts a transaction mode of 'certificate-electricity separation', and most consumers have weak consumption intention on the green certificate, and a 'certificate-electricity integrated' model is adopted, so that the green electricity and the green certificate are bound and sold, and the green certificate is purchased at the same time when an agricultural comprehensive energy system purchases electricity from a wind power plant, thereby accelerating the economic return of the wind power plant and enabling the consumers to more easily trace the green electricity; | In order to improve the enthusiasm of users for purchasing green electricity and promote the competitiveness of green electricity in the market, a reasonable green electricity quota proportion is set for an energy purchasing main body, so that the consumption rate of new energy can be improved, good enterprise images can be built, and the quota of the energy purchasing main body in an agricultural comprehensive energy system can meet the following conditions: | Wherein the method comprises the steps of AndThe power is purchased from the agricultural comprehensive energy system to the wind power plant and the power grid,And θ is the set green electricity quota ratio.|4. The proposed scheduling strategy is already a mixed integer linear problem, key equipment such as BPP, CHP, air source heat pump and BECCS and the like are modeled in an agricultural comprehensive energy system, a stepped carbon transaction mechanism and a green certificate transaction mechanism are introduced, carbon transaction cost and green certificate purchase are made into a part serving as an objective function, and finally under the conditions of meeting equipment output constraint, energy balance constraint and the like, the objective function is as follows:| for the daily purchase cost of the system, The cost of purchasing a green certificate for the system,The benefits obtained for selling energy of the agricultural comprehensive energy system;| the proposed low-carbon economic dispatching strategy can be used for solving an optimal solution through a mathematical programming accurate algorithm, and a CPLEX solver in a YALMIP tool box is called by using a MATLAB platform to solve. | 9 | Abstract | gpt-4o-mini | uncertain | The article discusses an integrated energy system involving biomass energy and carbon capture, but it primarily focuses on scheduling and economic dispatching rather than explicitly detailing the capture and storage of CO₂. | ||||||||||||||||||||||||||
| 15 | JP2023020350 | JP2023020350 | JP2024106935 | 110943542 | JP2024106935 A 2024-08-08 [JP2024106935] | 2023-01-27 | 2023-01-27 | 2024-08-08 | (JP2024106935)|2043-01-27 | (JP2024106935)|Method for suppressing and reducing increase in carbon dioxide in atmosphere, and system for suppressing and reducing increase in carbon dioxide in atmosphere | (JP2024106935)|PROBLEM TO BE SOLVED: To provide a method for suppressing and reducing an increase in carbon dioxide in atmosphere which simply and efficiently suppresses carbon dioxide discharge relating to waste combustion originated from a fossil fuel, fixes bio-carbon carbonized bio-charcoal formed by absorbing carbon dioxide in the atmosphere and carbonizing for a long period of time, and thereby recovering and reducing carbon dioxide in the atmosphere, and a system for suppressing and reducing increase in carbon dioxide in atmosphere to which these methods are applied.SOLUTION: A method heats a hydrocarbon compound under low oxygen or oxygen-free environment, carbonizes or semi-carbonizes the hydrocarbon compound or converts it into a mixture thereof, fills or buries the produced carbide, semi-carbide or a mixture thereof, and carbide slurry water obtained by micronizing the carbide and being mixed with water into a space which is formed underground or on the ground and is surrounded by a flame-retardant or noncombustible material having corrosion resistance or fills or stores them in a container composed of the material, and thereby stores the material for a long period of time while suppressing emission of warming gas by ignition and combustion of the carbide, semi-carbide or a mixture thereof, and decomposition of microorganisms.SELECTED DRAWING: Figure 1COPYRIGHT: (C)2024,JPO&INPIT | SOLUTION CREATORS | (JP2024106935)|SOLUTION CREATORS CO LTD | KAWABATA YASUHARU | (JP2024106935)|KAWABATA YASUHARU | (JP2024106935)|However, it is desirable to suppress energy consumption and increase of carbon dioxide associated with carbonization of woody biomass by generating electric power using this fuel and using it as driving power for a chip-making device or a carbonization furnace, or by using the generated heat for drying and carbonization of woody biomass by burning a boiler.|In this way, oxygen in the atmosphere is consumed in the combustion process, and by binding with oxygen, carbon dioxide gas with increased volume and mass of bound oxygen components is recovered and stored in a smaller volume and lighter weight than carbon dioxide gas with no oxygen bond However, it has the advantage of being able to carry and store easily and efficiently with a small volume.|It also has the advantage of being extremely low.|As for the carbon storage agriculture method constituting the conventional technology of patent document 2, there is a problem that when biocoal is applied to agricultural land, hydrocarbon compounds other than hardly decomposable carbon contained in the biocoal are decomposed by microorganisms in the soil and dissipated into the atmosphere as warming substances such as carbon dioxide, and the reduction in carbon dioxide reduction effect by the decomposition of biocoal by such microorganisms in the soil is not estimated and considered.|Further, the present invention is limited to the use of biocoal on agricultural land, and can be constructed in a waste tunnel space or underground by a method for carbon neutralization in which carbon dioxide emission into the atmosphere can be suppressed by carbonizing and embedding a hydrocarbon waste derived from fossil fuels, a method for negative emission in which carbon dioxide in the atmosphere is removed and fixed for a long period of time while suppressing decomposition of hydrocarbons by microorganisms by embedding biocoal in a mining site or a waste pit, and a carbide obtained by carbonizing the hydrocarbon waste incinerated can be constructed in a waste tunnel space or underground by a shield method There is a problem that it is not possible to cope with a method for suppressing the emission of carbon dioxide into the atmosphere by filling and embedding in an artificial storage tank, and it is not possible to estimate the emission suppression value of carbon dioxide and the recovery reduction value of atmospheric carbon dioxide using these methods.|In addition, since the place where the injected carbon dioxide is leaked and not vaporized and dissipated and can be stored for a long period of time is limited, the exhaust gas containing carbon dioxide is energized while being blown into an aqueous solvent containing an inorganic substance, and is reacted with the inorganic substance to recover it as a solid carbonic acid compound A method of storage or effective utilization (patent document 1) has been proposed. Further, as a method for recovering and reducing carbon dioxide in the atmosphere by absorbing and fixing carbon dioxide gas accumulated in the atmosphere through conventional industrial activities, etc., a method for separating and recovering and fixing carbon dioxide gas contained in combustion exhaust gas during power generation or heat utilization using biomass which has absorbed and fixed carbon dioxide in the atmosphere (BECCS), or a method for carbonizing a biomass resource by subjecting the biomass resource to high-temperature heating at 350°C or higher in an oxygen-free or low-carbon environment, thereby making the biomass resource difficult to decompose Carbon storage farming (carbon farming), in which carbon originating from biomass is fixed in soil for a long period of time, is also put into practical use, while realizing the soil improvement of agricultural land by applying it to the agricultural land of mineral soil or the like in which microbial decomposition is suppressed, as a bio-coal composed of carbon and hydrocarbon compounds, and a system for efficiently estimating and evaluating the carbon reduction value in emission right trading (patent document 2) has been proposed.| | (JP2024106935)|1. A carbonized product or semi-carbonized product originating in a hydrocarbon compound is produced by heating the hydrocarbon compound in a low-oxygen or oxygen-free environment to form a carbonized product, a semi-carbonized product or a mixture thereof, forming the formed carbonized product, semi-carbonized product or mixture thereof underground or on the ground, filling or embedding the product in a space partially or wholly enclosed with a corrosion-resistant flame-retardant or non-combustible material, and sealing a part or the whole of an exposed part after filling or embedding with a corrosion-resistant flame-retardant or non-combustible material A method of long-term storage of |3. carbon or carbide, wherein the long-term storage space is defined as a waste mine site and a waste pit, a cave, a tunnel space on a waste railroad and a waste road, a used underground piping and common ditch, a water well or hot spring well that is not used or stopped to be used Long-term storage method for |9. carbon or carbide, characterized in that a surface constituting material and a joining sealing material for a wall surface are reinforced concrete or concrete, mortar, or one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility; and a method of long-term storage of carbon or | | (JP2024106935)|As shown in Fig. 2, this system is a system in which fossil fuels have been stockpiled while ensuring thorough risk management against fire and leakage, but the prospect of utilization has disappeared as a result of abolition.|The purpose of the present invention is to achieve a method and a method for recovering and reducing carbon dioxide in the atmosphere by easily and efficiently suppressing the emission of carbon dioxide associated with the combustion of waste derived from fossil fuels, or by fixing bio-coal, which has absorbed and carbonized carbon dioxide in the atmosphere for a long period of time, while significantly reducing the carbon dioxide reduction effect associated with the decomposition of hydrocarbons by microorganisms in soil, and significantly reducing the risk of the emission of carbon dioxide caused by the ignition, ignition, and combustion of stored carbon Provided is a system for suppressing and reducing an increase in atmospheric carbon dioxide which has been applied.| | (JP2024106935)|CARBON DIOXIDE(100,88)|CARBIDE(100,27)|CARBON(100,27)|LONG TERM STORAGE(100,26)|HYDROCARBON COMPOUND(100,24)|HYDROCARBON(100,11)|FLAME RETARDANT(100,8)|FILLING(100,7)|OXYGEN FREE ENVIRONMENT(100,5)|CORROSION RESISTANT FLAME RETARDANT(100,3)|NON COMBUSTIBLE MATERIAL(100,3)|SEMICARBONIZED PRODUCT(100,3)|CARBONIZED PRODUCT(100,2)|WOODY BIOMASS CARBONIZATION(100,2)|FORMED CARBONIZED PRODUCT(100,1)|BIOMASS RESOURCE CARBONIZATION(66,1)|BIOCARBON CARBONIZED BIOCHARCOAL(64,1)|WASTE PIT(45,2)|CARBIDE SLURRY REPLENISHMENT MANAGEMENT(43,1)|BIOMASS RESOURCE(41,5)|WOODY BIOMASS(40,6)|WASTE RAILROAD(40,1)|CARBONIZATION FURNACE(39,1)|UTILIZATION PROSPECT(38,1)|EMISSION SUPPRESSION(35,6)|WASTE ROAD(33,1)|MICROORGANISM(32,7)|HYDROCARBON WASTE(31,4)|WASTE TUNNEL SPACE(31,2)|WARMING SUBSTANCE(31,1)|AGRICULTURAL LAND(30,6)|DECOMPOSE CARBON STORAGE FARMING(30,1)|UNDERGROUND(28,10)|ABANDONED SAND BASIN(28,1)|MINERAL SOIL AGRICULTURAL LAND(28,1)|CARBIDE COMBUSTION(27,1)|DECOMPOSABLE CARBON(27,1)|MINING SITE(27,1)|CARBON DIOXIDE EMISSION(26,5)|MICROBIAL DECOMPOSITION(26,3)|CARBON NEUTRALIZATION(25,1)|ARTIFICIAL UNDERGROUND SPACE(24,4)|CARBON STORAGE AGRICULTURE(24,1)|NONFLAMMABLE CONTAINER(24,1)|SLURRY CARBONIZATION(24,1)|BIOMASS(23,2)|FOSSIL FUEL(22,17)|COMBUSTIBILITY(22,4)|AGRICULTURAL LAND SOIL IMPROVEMENT(22,1)|NEGATIVE EMISSION(22,1)|GROUND(21,9)|WASTE COMBUSTION(21,5)|LEAK SITE(20,1)|GENERATION STATUS(19,5)|DITCH(19,2)|CARBON DIOXIDE GAS(18,24)|IGNITION(18,9)|SHIELD(18,3)|WOODY BIOMASS CARBONIZATION FURNACE(18,3)|INORGANIC SUBSTANCE(18,2)|CONCRETE WALL CONSTRUCTION(18,1)|OXYGEN BINDING COMPONENT(18,1)|ATMOSPHERIC CARBON DIOXIDE(17,8)|RESIDUAL CARBIDE(17,2)|ABOLISHED DAM WATER TANK(17,1)|BIOCOAL(17,1)|COMBUSTION EXHAUST GAS(17,1)|NONCOMBUSTIBLE(17,1)|CARBON SLURRY WATER(16,2)|TUNNEL SPACE(16,2)|BOILER(16,1)|INJECTED CARBON DIOXIDE(16,1)|CORROSION RESISTANCE(15,12)|REDUCING RECOVERY(15,2)|AIRTIGHTNESS(15,1)|BECCS(15,1)|GENERATING ELECTRIC(15,1)|CARBON DIOXIDE REDUCTION(14,8)|MINERAL(14,4)|STORED CARBON COMBUSTION(14,2)|LIGHTER(14,1)|AQUEOUS SOLVENT(13,3)|CAVE(13,3)|REINFORCED CONCRETE(13,3)|CARBONIC ACID COMPOUND(13,2)|NONFLAMMABLE MATERIAL(13,2)|OILFIELD(13,2)|ABOLITION RESULT(13,1)|CARBIDE PRODUCT(13,1)|INDUSTRIAL ACTIVITY(13,1)|MINERAL SOIL(13,1)|LONG TERM STORAGE CONTAINER(12,19)|DECOMPOSITION(12,7)|ARTIFICIAL STORAGE TANK(12,3)|DEOXIDIZED AIR(12,2)|NONFLAMMABLE SPACE(12,2)|CARBON FARMING(12,1)|OUTFLOW LIQUID COMPONENT(12,1)|POWER GENERATION(12,1)|RISK MANAGEMENT(12,1)|SOIL IMPROVEMENT(12,1)|CONCRETE(11,4)|MORTAR(11,4)|SEMICARBIDE(11,4)|COMBUSTIBLE CARBONIZATION FURNACE(11,2)|GLOBAL WARMING GAS(11,2)|IDLE WATER SITE(11,2)|CARBON DIOXIDE DISCHARGE(11,1)|COMBUSTION(11,1)|CEMENT WALL(10,2)|EMISSION SOURCE SUBSTANCE(10,2)|FILLING GAS(10,2)|SMALL VOLUME(10,2)|CONTAINER WALL(10,1)|HEAT GENERATION(10,1)|INCREASED VOLUME(10,1)|FIRE RETARDANT(9,3)|SPACE PRESSURIZATION(9,2)|STORAGE SPACE(8,26)|CARBON LONG TERM STORAGE(8,8)|GREENHOUSE GAS(8,6)|CARBON(8,4)|JOINING SEALING MATERIAL(8,3)|RESIN MATERIAL(8,3)|CARBONIC ACID(8,2)|GAS FILLING(8,2)|COMBUSTIBLE WASTE(7,3)|CARBIDE PULVERIZER(7,2)|ENERGY CONSUMPTION(7,2)|HOT SPRING(7,2)|NEIGHBORING FOREST(7,2)|DECOMMISSIONED UNDERGROUND PIPE(7,1)|EMISSION RIGHT(7,1)|THINNED WOOD CARBONIZATION(7,1)|WOODY BIOMASS RESOURCE(7,1)|COMBUSTIBLE GAS(6,4)|HEAT RESISTANCE(6,3)|ORE RESIDUE(6,3)|UNUSED UNDERGROUND SPACE(6,3)|WASTE CARBON(6,2)|CARBON REDUCTION VALUE(6,1)|GROUNDWATER GUSH(6,1)|MICROORGANISM INHABITANT(6,1)|OXYGEN REMOVED HYPOXIC AIR(6,1)|SEMI CARBONIZED MATERIAL(6,1)|USED UNDERGROUND PIPING(6,1)|WASTE TUNNEL ENTRANCE(6,1)|EXHAUST GAS(5,5)|HYPOXIC ENVIRONMENT(5,2)|DECOMMISSIONED ROAD(5,1)|DRIVING POWER(5,1)|FOREST DERIVED BIOMASS RESOURCE(5,1)|INTERNAL GAS COMPONENT(5,1)|LOW CARBON ENVIRONMENT(5,1)|SOIL MICROBIOME(5,1)|SUSTAINABLE RECOVERY(5,1)|UNUSED WASTE TUNNEL(5,1)|LONG TERM STORAGE SPACE(4,25)|MINING(4,3)|MOISTURE EVAPORATION(4,3)|STEEL PIPE(4,2)|WALL SURFACE(4,2)|AGRICULTURAL LAND LAW(4,1)|BIOMASS ORIGIN(4,1)|BURNING BIOCHAR(4,1)|CARBONIZED MATERIAL MIXED PRODUCT(4,1)|CLEARING TREE(4,1)|ESTIMATE EVALUATION(4,1)|FIRE EXTINGUISHING(4,1)|HARMLESS SUBSTANCE(4,1)|OIL STOCK PILING(4,1)|SEWAGE FACILITY(4,1)|SLURRY AGITATION(4,1)|SLURRY PULVERIZER(4,1)|SOIL MICROORGANISM(4,1)|UNUTILIZED UNDERGROUND SPACE(4,1)|WASTE ORE UNDERGROUND SPACE(4,1)|ENVIRONMENTAL VALUE(3,4)|SEALING MATERIAL(3,4)|SOLID CARBON(3,4)|GAS MEASURING SENSOR(3,3)|INERT GAS(3,3)|FLOW RATE(3,2)|HOT SPRING WELL(3,2)|NITROGEN SEAL(3,2)|REINFORCED CONCRETE WALL(3,2)|SEEDLING(3,2)|WASTE INCINERATION(3,2)|WASTE TREATMENT PLANT(3,2)|AQUEOUS CARBONIZED SLURRY SOLUTION(3,1)|BIOCOAL STORAGE(3,1)|CARBON DIOXIDE EMISSION SUPPRESSION(3,1)|CONTAINER FILLING(3,1)|ELECTROLYTIC ENERGY(3,1)|ELECTROLYTIC TREATMENT(3,1)|FIRE GENERATION(3,1)|HARMFUL SUBSTANCE(3,1)|IGNITION ENERGY(3,1)|INSIDE WASTE MINE(3,1)|INTERNAL MONITORING NOTIFICATION(3,1)|MATURE TREE(3,1)|MEADOW PASTURELAND(3,1)|METAL MINE EXCAVATION SITE(3,1)|MOISTURE EXTRACTION(3,1)|NATURAL TERRAIN(3,1)|NEARBY FIRE(3,1)|NITROGEN ENCAPSULATION(3,1)|OXYGEN MIXING(3,1)|PETROLEUM REFINING PLANT(3,1)|ROCK BED(3,1)|STEAM EXTRACTION PORT(3,1)|STORAGE WATER SURFACE(3,1)|STORED BIOCHARCOAL COMBUSTION(3,1)|TECHNICAL IDEA(3,1)|TON VOLUME(3,1)|UNDERGROUND UNUSED SPACE(3,1)|WASTE DISPOSAL PLANT(3,1)|WASTE RAILWAY(3,1)| | (JP2024106935)|1. A carbonized product or semi-carbonized product originating in a hydrocarbon compound is produced by heating the hydrocarbon compound in a low-oxygen or oxygen-free environment to form a carbonized product, a semi-carbonized product or a mixture thereof, forming the formed carbonized product, semi-carbonized product or mixture thereof underground or on the ground, filling or embedding the product in a space partially or wholly enclosed with a corrosion-resistant flame-retardant or non-combustible material, and sealing a part or the whole of an exposed part after filling or embedding with a corrosion-resistant flame-retardant or non-combustible material A method of long-term storage of |2. carbon or carbide, characterized in that a mixture is stored for a long period of time in a fire-retardant or nonflammable space having corrosion resistance. A hydrocarbon compound is heated in a low oxygen or oxygen-free environment to form a carbonized, semi-carbonized or mixed product of carbonized, semi-carbonized or mixed products of carbonized, semi-carbonized or mixed products of carbonized, semi-carbonized or mixed products of carbonized, semi-carbonized or mixed products of carbonized or nonflammable materials having corrosion resistance and heat resistance. A part or the whole of the exposed part after the filling is subjected to corrosion resistance A method of long-term storage of carbon or carbide, characterized in that by sealing with a heat-resistant, flame-retardant, or nonflammable material, carbide, semi-carbide, or a mixture thereof originating from a hydrocarbon compound is stored for a long period of time in a corrosion-resistant, flame-retardant, or nonflammable container. In the long-term storage space described in claim 1, there is provided a method for long-term storage of |3. carbon or carbide, wherein the long-term storage space is defined as a waste mine site and a waste pit, a cave, a tunnel space on a waste railroad and a waste road, a used underground piping and common ditch, a water well or hot spring well that is not used or stopped to be used Long-term storage method for |4. carbon or carbide characterized by being any of the oil field, gas field, or coal field The long-term storage space described in claim 1 is an artificial underground space constructed by a shield method for constructing a concrete wall while excavating a mountain or an underground, or an artificial underground space formed by inserting a cement wall or a steel pipe while excavating an underground Long-term storage method for |5. carbon or carbide The long-term storage container described in claim 2 is a storage tank for fossil fuel which has been used and an abandoned sand basin A method of long-term storage of |6. carbon or a carbonized material, characterized in that it is an idle water site, a water tank or an abolished dam water tank. Claims 1 to 5, the method of long-term storage of carbon or a hydrocarbon compound, characterized in that, when carbon or a hydrocarbon compound is filled or buried in a long-term storage space or a long-term storage container, the carbon, semi-carbonized material or a mixture thereof is pulverized, mixed with water and stirred to form a slurry, and filled or buried as carbonized slurry water. The method of long-term storage of |7. carbon or a carbonized material, described in claim 6, is characterized in that it is filled or buried as carbonized slurry water Alternatively, the method for long-term storage of a hydrocarbon compound is characterized in that, in the method for long-term storage of a hydrocarbon compound, the carbide concentration of the carbide slurry water is increased or the total amount of the water is evaporated and removed by repeating the replenishment of a new carbide slurry water while evaporating the moisture of the carbide slurry water in the tank without sealing the storage tank for the |8. carbide slurry water, and only the residual carbide is stored in the tank. Further, the method for long-term storage of a carbon or carbide is characterized in that the long-term storage space is constituted by an inner wall covering material and a wall covering material as described in Claims 1, 3 and 4 A method of long-term storage of |9. carbon or carbide, characterized in that a surface constituting material and a joining sealing material for a wall surface are reinforced concrete or concrete, mortar, or one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility; and a method of long-term storage of carbon or |10. carbide, characterized in that the constituting material for a container and the joining sealing material for a container wall described in claims 2 and 5 are one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility A method of managing the long-term storage state of a |11. carbon or carbide, characterized in that the long-term storage space or the interior of a long-term storage container described in Claims 1-9 is filled with oxygen-removed hypoxic air or deoxidized air, or inert gas other than carbon dioxide gas to form a pressurized space, and the pressure and components of the filled gas in the space are measured and monitored to manage the airtightness and the generation status of greenhouse gases within the long-term storage space or the long-term storage container A method of managing the long-term storage state of |12. carbon or carbide, characterized in that the replenishment management of the carbide slurry water into a long-term storage space or a long-term storage container and the generation status of greenhouse gases from the surface of the slurry are monitored and managed by measuring and monitoring the water level of the carbide slurry water described in claim 6 and the gas components in the vicinity of the storage water surface. In the case where leakage is detected from the long-term storage space or the long-term storage container by the monitoring and management method described in claim 10 or claim 11, leakage of internal gas or internal liquid is detected A method of maintenance and management of a long-term storage of carbon or hydrocarbon compounds, characterized in that after repairing the long-term storage space or long-term storage container by the method described in claim 7 or claim 8 for a specified leak site, the long-term storage of |13. carbon or hydrocarbon compounds is resumed by refilling the slurry water of the carbide described in claim 6 or the filling gas described in claim 10 and by the method described in claim 10 or claim 11 According to the monitoring and management method described in, the amount of global warming gas leaked from the long-term storage space or the long-term storage container is calculated from the flow rate and gas component of the internal gas measured when leakage is detected from the long-term storage space or the long-term storage container, or from the flow rate and component of the outflow liquid measured, and the environmental value based on the net amount of carbon storage is calculated by subtracting the amount of leakage from the initial amount of |14. carbon storage A system for suppressing the increase and reduction of carbon dioxide in the atmosphere, characterized by carbonizing carbon or a hydrocarbon compound, which is a carbon dioxide emission source substance, without burning by means of the method described in claim 1-14, and then storing the obtained carbide or carbide slurry water in a long-term storage space or in a long-term storage container for a long period of time, thereby suppressing the emission of carbon dioxide gas related to waste combustion originating in fossil fuels or recovering and reducing carbon dioxide in the atmosphere | (JP2024106935)|TECHNICAL FIELD|[0001] Disclosed are: a method for suppressing the emission of carbon dioxide, which is a substance that is a main cause of global warming, into the atmosphere; a method for reducing carbon dioxide accumulated in the atmosphere up to now; and a system for embodying these methods.|BACKGROUND ART|[0002] A method has been proposed and put into practical use, in which carbon dioxide gas contained in exhaust gas is separated and recovered when fossil fuels are used or incinerated waste containing hydrocarbons is burned to suppress the increase of carbon dioxide, which is the main greenhouse gas, and is then press-fitted and fixed into underground storage tanks such as drying oil fields and aquifers.|[0003] On the other hand, in the separation and recovery of low-concentration carbon dioxide gas contained in an exhaust gas, compression and liquefaction for transportation to a storage site, and press-fixing into an underground storage tank, a large amount of energy and cost are generated. In addition, since the place where the injected carbon dioxide is leaked and not vaporized and dissipated and can be stored for a long period of time is limited, the exhaust gas containing carbon dioxide is energized while being blown into an aqueous solvent containing an inorganic substance, and is reacted with the inorganic substance to recover it as a solid carbonic acid compound A method of storage or effective utilization (patent document 1) has been proposed.|[0004] Further, as a method for recovering and reducing carbon dioxide in the atmosphere by absorbing and fixing carbon dioxide gas accumulated in the atmosphere through conventional industrial activities, etc., a method for separating and recovering and fixing carbon dioxide gas contained in combustion exhaust gas during power generation or heat utilization using biomass which has absorbed and fixed carbon dioxide in the atmosphere (BECCS), or a method for carbonizing a biomass resource by subjecting the biomass resource to high-temperature heating at 350°C or higher in an oxygen-free or low-carbon environment, thereby making the biomass resource difficult to decompose Carbon storage farming (carbon farming), in which carbon originating from biomass is fixed in soil for a long period of time, is also put into practical use, while realizing the soil improvement of agricultural land by applying it to the agricultural land of mineral soil or the like in which microbial decomposition is suppressed, as a bio-coal composed of carbon and hydrocarbon compounds, and a system for efficiently estimating and evaluating the carbon reduction value in emission right trading (patent document 2) has been proposed.|CITATION LIST|PATENT LITERATURE|[0006] Tokkai 2022-145080|Tokkai 2022-153012|SUMMARY OF INVENTION|TECHNICAL PROBLEM|[0007] As described above, according to the prior art of patent document 1, carbon dioxide gas contained in exhaust gas generated when various hydrocarbon compounds are burned, including fossil fuels, hydrocarbon-containing wastes, and biomass resources produced by absorbing and fixing carbon dioxide in the atmosphere, can be recovered as solid carbonic acid compounds that are easy to transport, store, and effectively use. According to the prior art of patent document 2, carbon is easily and efficiently fixed by carbonizing hydrocarbon compounds including biomass resources and embedding them in soil It is possible to easily and properly evaluate the environmental value, but these technologies have the following problems.|[0008] In the prior art of patent document 1, a large amount of gas compression energy is required in the step of blowing the whole amount of exhaust gas containing carbon dioxide gas of low concentration into an aqueous solvent, and a large amount of electrolytic energy is also required in the step of electrifying the aqueous solvent to perform electrolytic treatment. In addition, a large amount of energy is generated in the step of manufacturing and procuring a magnesium alloy as a raw material. Therefore, a net carbon dioxide reduction effect is achieved when electric power originated from a fossil fuel is used in these steps The problem is that the cost of recovering and fixing carbon dioxide increases due to a large amount of power consumption and the cost associated with the procurement of a raw material for a magnesium alloy, as well as the reduction of carbon dioxide emission suppression effect (reduction of carbon dioxide or emission suppression value).|[0009] As for the carbon storage agriculture method constituting the conventional technology of patent document 2, there is a problem that when biocoal is applied to agricultural land, hydrocarbon compounds other than hardly decomposable carbon contained in the biocoal are decomposed by microorganisms in the soil and dissipated into the atmosphere as warming substances such as carbon dioxide, and the reduction in carbon dioxide reduction effect by the decomposition of biocoal by such microorganisms in the soil is not estimated and considered.|[0010] In other words, with regard to the decomposition effect of the hydrocarbon compounds in the biocharcoal by the microorganisms in the soil, since the number and activity of the microorganisms in the soil, including the species and number of inhabitants of the microorganisms in the soil to which the biocharcoal is applied, vary depending on the environment such as the temperature, humidity, and acidity of the soil and the characteristics of the biocharcoal to which the biocharcoal is applied, the net carbon dioxide reduction effect of the biocharcoal application can be estimated by estimating the decomposition effect of the biocharcoal to which the biocharcoal is applied in addition to these factors and deducting it from the carbon dioxide reduction effect There is also no method of estimation evaluation that can achieve the same effect.|[0011] Further, the present invention is limited to the use of biocoal on agricultural land, and can be constructed in a waste tunnel space or underground by a method for carbon neutralization in which carbon dioxide emission into the atmosphere can be suppressed by carbonizing and embedding a hydrocarbon waste derived from fossil fuels, a method for negative emission in which carbon dioxide in the atmosphere is removed and fixed for a long period of time while suppressing decomposition of hydrocarbons by microorganisms by embedding biocoal in a mining site or a waste pit, and a carbide obtained by carbonizing the hydrocarbon waste incinerated can be constructed in a waste tunnel space or underground by a shield method There is a problem that it is not possible to cope with a method for suppressing the emission of carbon dioxide into the atmosphere by filling and embedding in an artificial storage tank, and it is not possible to estimate the emission suppression value of carbon dioxide and the recovery reduction value of atmospheric carbon dioxide using these methods.|[0012] For example, in the calculation of the carbon dioxide reduction reduction amount in the transaction of carbon dioxide reduction value (for example, the J-credit system in Japan) by the application of bio-charcoal to agricultural land, the carbon retention rate after 100 years according to the type of bio-charcoal (0.65 to 0.89 under the J-credit system) is specified. This coefficient is applied only when bio-charcoal is applied to the soil of mineral in agricultural land or meadow/pastureland stipulated in the Agricultural Land Law, and the soil microbiome is low temperature Thus, it is possible to suppress the decomposition effect of soil microorganisms by storing them in an artificial storage tank composed of concrete walls and metal containers, and to store solid carbon with an increased carbon residual rate 100 years later for a long period of time. However, there has been no disclosure of such method and method for evaluating the value thereof.|[0013] In addition, unutilized underground spaces such as metal mine excavation sites, abandoned mines, and waste tunnels in the mountains, and underground spaces that can be formed using the shield method in the underground or in the mountains have an extremely low risk of ignition and fire generation due to lightning strikes and the spread of nearby fires. In addition, generally, the environment becomes high and humid at low temperatures. It also has the advantage of being extremely low.|[0014] In addition, when the carbon storage space is sealed or sealed with inert gas or water, the amount of oxygen flowing from the outside is limited. Therefore, even if ignition or ignition occurs, the flame does not easily spread due to oxygen shortage, and it is easy to extinguish the fire. Therefore, it has the feature of achieving long-term stable storage of solid carbon while burning biochar and carbide originating from waste and not discharging it as carbon dioxide gas, and suppressing emissions of greenhouse gases such as carbon dioxide due to microbial decomposition.|[0015] Further, the long-term storage of carbonized or semi-carbonized carbon and hydrocarbons in the artificial storage tank as a solid is not limited to biomass-derived carbon, but is also applied to hydrocarbon waste such as plastic, vinyl, fiber and paper, which is derived from fossil fuels or is produced using fossil fuels in a production process. Thus, it has been conventionally required to prevent carbon dioxide gas from being discharged into the atmosphere and being accumulated by incineration at a waste treatment plant. However, the conventional technology cannot evaluate the environmental value based on such a method.|[0016] In addition, not only biomass-derived biochar but also waste containing hydrocarbon derived from fossil fuels are combusted, not dissipated into carbon dioxide gas in the atmosphere, and carbonized prior to combustion and stored in a carbon storage tank as solid carbon or hydrocarbon compounds. In this way, oxygen in the atmosphere is consumed in the combustion process, and by binding with oxygen, carbon dioxide gas with increased volume and mass of bound oxygen components is recovered and stored in a smaller volume and lighter weight than carbon dioxide gas with no oxygen bond However, it has the advantage of being able to carry and store easily and efficiently with a small volume. In particular, the volume of one ton of carbon dioxide gas is approximately 509 cubic meters, and the volume of solid carbon, which is a generation source of one ton of carbon dioxide gas, is approximately 0.51 cubic meters. The volume difference is approximately 1,000 times.|[0017] The purpose of the present invention is to achieve a method and a method for recovering and reducing carbon dioxide in the atmosphere by easily and efficiently suppressing the emission of carbon dioxide associated with the combustion of waste derived from fossil fuels, or by fixing bio-coal, which has absorbed and carbonized carbon dioxide in the atmosphere for a long period of time, while significantly reducing the carbon dioxide reduction effect associated with the decomposition of hydrocarbons by microorganisms in soil, and significantly reducing the risk of the emission of carbon dioxide caused by the ignition, ignition, and combustion of stored carbon Provided is a system for suppressing and reducing an increase in atmospheric carbon dioxide which has been applied.|TECHNICAL SOLUTION|[0018] In order to solve the above problem, the invention of claim 1 is characterized in that a hydrocarbon compound is heated in a low oxygen or oxygen-free environment to form a carbonized, semi-carbonized or mixed product thereof, and the formed carbonized, semi-carbonized or mixed product thereof is formed underground or on the ground. The resulting material is filled or buried in a space partially or wholly enclosed by a corrosion-resistant flame-retardant or non-combustible material, and a part or all of an exposed part after filling or embedding is a corrosion-resistant or non-combustible material The method is characterized in that a carbide, a semi-carbide or a mixture thereof originating from a hydrocarbon compound is stored for a long period of time in a fire-retardant or nonflammable space having corrosion resistance by sealing with.|[0019] In the invention of claim 2, a hydrocarbon compound is heated in a low oxygen or oxygen-free environment to form a carbide, semi-carbide, or mixture thereof. The resulting carbide, semi-carbide, or mixture thereof is filled into a container which is partially or wholly made of a flame-retardant or non-flammable material having corrosion resistance and heat resistance, and a part or all of the exposed portion after the container filling is sealed with a flame-retardant or non-flammable material having corrosion resistance and heat resistance. Thus, the carbide, semi-carbide, or carbide originating from the hydrocarbon compound The present invention is characterized in that a mixture is stored for a long period of time in a fire-retardant or non-flammable container having corrosion resistance.|[0020] The invention described in claim 3 is characterized in that the long-term storage space described in claim 1 is any one of the following: a former site of mining of a waste mine, a waste tunnel, a cave, a tunnel space on a waste railway and a decommissioned road, a decommissioned underground pipe and a common ditch, a water well or hot spring well that has not been used or is suspended, an oilfield after being mined, a gas field and a coal field.|[0021] The invention described in claim 4 is characterized in that the long-term storage space described in claim 1 is an artificial underground space constructed by a shield construction method in which a concrete wall is constructed while excavating a mountain or an underground, or an artificial underground space formed by inserting a cement wall or a steel pipe while excavating an underground.|[0022] The invention described in claim 5 is characterized in that the long-term storage container described in claim 2 is any one of a storage tank for fossil fuel which has been discontinued, a settling pond for water and sewage facilities which have been discontinued, an idle water site and a water tank, or a dam water tank which has been discontinued.|[0023] The invention described in claim 6 is a method for long-term storage of carbon or hydrocarbon compounds described in claims 1 to 5, characterized in that when carbon or hydrocarbon compounds are filled or buried in a long-term storage space or in a long-term storage container, the carbide, semi-carbide, or mixture thereof is pulverized, mixed with water and stirred to form a slurry, and filled or buried as carbide slurry water.|[0024] The invention of claim 7 is characterized in that in the method for storing carbon or a hydrocarbon compound of claim 6 for a long period of time, the carbide concentration of the carbide slurry water is increased or the total amount of water is evaporated and removed by repeating the replenishment of a new carbide slurry water while evaporating the moisture of the carbide slurry water in the tank without sealing the storage tank for the carbide slurry water, and only the residual carbide is stored in the tank.|[0025] The invention described in claim 8 is characterized in that the inner wall covering material constituting the long-term storage space described in claim 1, claim 3 and claim 4, the wall surface constituting material, and the joining sealing material for the wall surface are reinforced concrete, concrete, mortar, or one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility.|[0026] The invention described in claim 9 is characterized in that the container-constituting material and the container-wall joining-sealing material described in claim 2 and claim 5 are any one or more of a metal, mineral, or resin material having corrosion resistance, flame retardancy, or incombustibility.|[0027] The invention described in claim 10 is characterized in that the long-term storage space described in claims 1 to 9 or the interior of the long-term storage container is filled with oxygen-removed hypoxia air or deoxidized air, or inert gas other than carbon dioxide gas to form a pressurized space, and the pressure and components of the filled gas in the space are measured and monitored to control the airtightness and the generation status of greenhouse gases within the long-term storage space or the long-term storage container.|[0028] The invention described in claim 11 is characterized in that the level of the carbide slurry water described in claim 6 and the gas component in the vicinity of the reserving water surface are measured and monitored in the long-term reserving space described in claims 1-9 or inside the long-term reserving container, thereby monitoring and managing the replenishment of the carbide slurry water into the long-term reserving space or the long-term reserving container and the generation status of greenhouse gas from the slurry level.|[0029] If leakage is detected in the long-term storage space or the long-term storage container by the monitoring and management method described in claim 10 or claim 11, the invention described in claim 12 refills the long-term storage space or the long-term storage container by the method described in claim 7 or claim 8 with the carbide slurry water described in claim 6 or the filling gas described in claim 10, and then refills the leakage location identified from the leakage status of the internal gas or internal liquid Monitoring and management of the long-term storage state of carbon or hydrocarbon compounds are resumed by the method described in 10 or claim 11.|[0030] The invention described in claim 13 is based on the net amount of carbon storage by subtracting the amount of global warming gas leaked from the long-term storage space or the long-term storage container from the amount of flow of internal gas and gas components measured when leakage is detected from the long-term storage space or the long-term storage container, or from the measured amount of flow of leaked liquid and components of flow-out liquid by the monitoring and management method described in claim 10 or claim 11 Characterized by calculating value.|[0031] The invention described in claim 14 is characterized in that the method described in claims 1 to 14 is used to carbonize carbon or a hydrocarbon compound, which is a carbon dioxide emission source substance, without burning the carbon or hydrocarbon compound, and the obtained carbide or carbide slurry water is stored in a long-term storage space or in a long-term storage container for a long period of time, thereby suppressing the emission of carbon dioxide gas related to the waste combustion originating in fossil fuels or collecting and reducing the carbon dioxide in the atmosphere.|ADVANTAGEOUS EFFECTS|[0032] According to the present invention, carbon dioxide in the atmosphere can be recovered and reduced by a simple and efficient method with low energy consumption and low cost burden, while reducing the effect of reducing carbon dioxide associated with decomposition of hydrocarbons by microorganisms in soil and reducing the risk of carbon dioxide emission due to ignition, ignition, and combustion of stored carbon, and by reducing the emission of carbon dioxide gas related to waste combustion originating in fossil fuels or by long-term storage of biocoal that has been carbonized by absorbing carbon dioxide in the atmosphere.|DESCRIPTION OF DRAWINGS|[0033] A method of absorbing and reducing atmospheric carbon dioxide gas, in which bio-charcoal obtained by carbonizing a thinned material into an underground space in a waste mine is stored for a long period of time and monitored and managed, and a schematic drawing showing the system.|[0034] A method for preventing carbon dioxide gas emission, which comprises carbonizing a waste containing a fossil fuel-derived plastic, slurrizing the carbonized waste, storing the slurry in a storage tank of a waste petroleum storage base for a long period of time, and monitoring and managing the carbonized waste, and a schematic drawing showing the system.|DESCRIPTION OF EMBODIMENTS|[0035] The best form for implementing the invention is described in the following drawing. The scope of the present invention is stated in the claims and is not limited to this embodiment.|[0036] (First Embodiment)|[0037] A method and a system for absorbing and reducing atmospheric carbon dioxide gas, in which biocharcoal obtained by carbonizing thinned wood is stored for a long period of time in an underground space in a waste mine and monitored and managed, according to a first embodiment of the present invention are explained on the basis of Fig. 1.|[0038] As shown in Fig. 1, this system has a metal mineral in a strong rock bed, and although the mining was conducted in underground space in the mountains, the mining was completed and turned into waste ore. In the waste mine 1 having unused underground space after the mining and unused waste tunnels, biocoal 4 obtained by carbonizing forest-derived biomass resources 3 grown by absorbing atmospheric carbon dioxide is buried in the unused underground space 2, and the atmospheric carbon dioxide is recovered and reduced by long-term storage.|[0039] In this system, biocharcoal 4 is produced by a woody biomass carbonization furnace (5) in which a woody biomass (3) obtained by thinning or clearing forests growing on the surface of a waste mine or nearby forests is dried and chipped, and then carbonized by heating to 350°C or higher in an oxygen-free or hypoxic environment. In the process of carbonization of biomass, a part of woody biomass can be gasified and used as fuel. However, it is desirable to suppress energy consumption and increase of carbon dioxide associated with carbonization of woody biomass by generating electric power using this fuel and using it as driving power for a chip-making device or a carbonization furnace, or by using the generated heat for drying and carbonization of woody biomass by burning a boiler.|[0040] On the other hand, in the unused underground space in the waste mine where the biocoal is stored, there are places with cracks in the bedrock and places where the groundwater gushes out. If such places are not sealed, there is a risk that a part of the stored biocoal may enter the groundwater or enter the cracks and mix with the groundwater. Therefore, the inner wall of the storage tank and the floor surface are sealed by filling or applying concrete or mortar in such places so that the stored biocoal does not flow out It is desirable to construct 6.|[0041] However, if the biochar to be stored does not contain harmful substances, it is not necessary to fill or apply concrete or mortar to the entire top, wall, or floor surface of the underground space. This is because biocoal itself is a harmless substance, and even if it is mixed into ground water and flowed out, it does not lead to water pollution and emission of carbon dioxide gas.|[0042] Thus, the underground unused space in the waste ore is formed into a storage space suitable for long-term storage of biocoal. After the biocoal generated in the above step is used for burying, a sealing wall (7) made of reinforced concrete is constructed to bury and seal the long-term storage space. Thus, it is possible to long-term storage of carbon from biomass origin, which has absorbed carbon dioxide in the atmosphere, in the underground space of the waste ore.|[0043] A communication hole 8 for monitoring the inside of the storage tank and a nitrogen gas supply pipe 9 for sealing nitrogen in the storage tank are constructed on the sealing wall. A pressure sensor 10 for measuring the pressure in the storage tank and a gas sensor 11 for measuring and monitoring the state of generation of carbon dioxide gas and combustible gas in the storage tank are connected to the communication hole 8. Measurement information from these sensors is intensively analyzed by an in-storage tank monitoring and reporting edge terminal 12, and the storage state in the storage tank is monitored, and an alarm is issued or a leak is generated in the event of abnormality The system is configured so as to transmit estimated analysis data of the leakage amount.|[0044] On the other hand, a nitrogen gas cylinder (13) for sealing nitrogen in the storage tank and a gas compressor (14) for forcing the nitrogen gas into the storage tank are connected to the end of the nitrogen gas supply pipe (9). These can be carried in and utilized when the storage of bio-coal is completed and sealed, or when the biocoal is refilled when leakage, the pressure in the storage tank is lowered, or the nitrogen concentration is lowered and the oxygen concentration is increased. During the storage and storage after filling, the valve on the supply pipe (9) can be closed to maintain the sealed state.|[0045] The nitrogen encapsulation is for monitoring and confirming the generation status of carbon dioxide caused by the decomposition of the biocoal when deducting the environmental value in the case where the decomposition of the biocoal generates a combustible gas and oxygen mixes in the storage tank to generate an ignition source inside to cause ignition and combustion, and carbon dioxide gas is generated by the decomposition of the biocoal to diffuse the extracted air. In the storage tank, the biocoal sterilized by the high temperature rise is stored in a space with a low temperature and high humidity underground When the risk of ignition and combustion of stored biocharcoal is extremely low, the generation of carbon dioxide by microbial decomposition does not occur, or the amount of generated carbon dioxide is extremely small, the method does not necessarily require encapsulation of nitrogen gas or monitoring and management of the storage tank.|[0046] By using the above method, biochar obtained from woody biomass resources obtained on the surface of a waste mine or from neighboring forests is buried and stored in the waste mine, and it is possible to recover and reduce atmospheric carbon dioxide through long-term storage of biochar. In addition, after thinning or clearing trees on the surface of a waste mine or from neighboring forests in this method, seedlings (15) are planted and raised, whereby trees are grown while further reducing the amount of atmospheric carbon dioxide absorbed through the growth of seedlings, trees are thinned or cut at a point where a mature tree having a reduced carbon dioxide absorption rate is reached, and biocoal obtained by this method is stored underground, thereby enabling the sustainable recovery and reduction of atmospheric carbon dioxide. (Second Embodiment)|[0047] Next, according to the second embodiment of the present invention, a carbon dioxide gas emission control method and a system therefor are explained on the basis of Fig. 2, in which a carbide obtained by carbonizing a hydrocarbon waste derived from a fossil fuel is pulverized and stored as carbide slurry water mixed with water, and monitoring and management are performed in a petroleum storage tank at a waste petroleum storage base.|[0048] As shown in Fig. 2, this system is a system in which fossil fuels have been stockpiled while ensuring thorough risk management against fire and leakage, but the prospect of utilization has disappeared as a result of abolition. The oil stockpiling tank in the petroleum refining plant is converted to a long-term storage tank (16) for carbide slurry water, and by incineration at a waste disposal plant, carbide (17) obtained by carbonizing hydrocarbon waste that can be a source of carbon dioxide gas emissions is converted to slurry water and stored in the tank. Thus, the system is incinerated The purpose of the present invention is to suppress an increase in carbon dioxide emissions.|[0049] In this system, a combustible waste 18 such as waste plastic and vinyl recovered from a waste collection vehicle and paper and cloth which have conventionally been incinerated in a waste treatment plant is dried and crushed, then a mixture of carbon and hydrocarbon is formed by a combustible carbonization furnace 19 which is heated to 500°C or higher in an oxygen-free or hypoxic environment and carbonized, and then it is pulverized by a carbide pulverizer 20 and mixed with water and stirred by a slurry agitator 21 to carbonize the product Slurry water obtained as water is poured into a storage tank 16 through a pump 22 and stopped when the liquid level reaches an upper limit.|[0050] The lid is equipped with a liquid level sensor (23) for measuring the liquid level position of the slurry water to grasp the storage state in the tank, and a gas measurement sensor (24) with a fire detection function capable of grasping the generation state of carbon dioxide gas and combustible gas from the liquid level and the occurrence state of a fire. An edge terminal (12) for monitoring the storage state and issuing an alarm when an abnormality occurs is installed. However, the slurry water stored in the tank does not generate carbon dioxide gas and combustible gas by merely evaporation of moisture In this case, the gas measuring sensor 24 with the fire detecting function may be a simple fire detector or may not be installed. This is because, unlike stored oil, aqueous carbonized slurry solution has low volatility and is difficult to burn, and therefore, without sufficient ignition energy, it does not ignite and is difficult to spread the fire.|[0051] A water vapor extraction port (25) for extracting moisture from the carbonized slurry water is attached to the vicinity of the top surface lid of the container. The evaporated moisture is extracted from the storage tank, and the drain water generated via the radiator is condensed as raw material water in the slurry forming device (21). Thus, the amount of rehydration water used when the slurry water is generated is reduced. When the slurry water in the tank is concentrated and the liquid level is lowered, a pump is used to extract the evaporated moisture By appropriately replenishing the slurry water, the carbon storage amount in the tank can be increased.|[0052] With such an arrangement, carbon originating from waste is accumulated in a storage tank as slurry water, and then the amount of carbon stored in the tank is increased by repeating water evaporation and replenishment of the slurry water. Thus, carbon dioxide generation accompanying incineration of waste can be suppressed and the carbon can be stored as carbon. After the tank is filled with stored carbon by this method, the set of a liquid feed system for carbonization, slurrification, and slurry water is transferred to other storage tanks, and the same operation is repeated successively, thereby enabling long-term storage of carbon in a plurality of tanks.|INDUSTRIAL APPLICABILITY|[0053] The present invention is not limited to the aforementioned embodiments, and for example, the embodiments shown in the figure are not limited to waste mines or discontinued oil storage tanks, but are carried out using natural terrain such as caves and mountain valleys, or various organic substances burned and exhausted in a natural or artificial storage space, such as by sealing the entrance of a waste tunnel with a reinforced concrete wall, mixing biocoal with a carbonized material of combustible waste, and sealing the exit with a reinforced concrete wall to store carbon The carbonization and storage can be used as a method for suppressing the emission of carbon dioxide and for reducing the recovery of atmospheric carbon dioxide.|[0054] Thus, any item having a structure substantially identical to the technical idea described in the patent claims and exhibiting a similar action effect is included in the technical scope of the invention.|REFERENCE SIGNS LIST|[0055] 1...waste mine 2...unused underground space inside waste mine 3...woody biomass 4...woody biomass 4...woody biomass carbonization furnace 6...woody biomass carbonization furnace 7...storage inner wall 7...sealing wall 8...storage internal communication hole 9...nitrogen gas supply pipe 10...storage tank internal pressure measurement sensor 11..storage tank internal pressure measurement sensor 12..storage tank internal monitoring notification edge terminal 13..nitrogen gas cylinder 14..gas compressor 15..seedling 16..carbide slurry water storage tank 17... 18 ... combustible waste 19 ... combustible carbonization furnace 20 ... carbide pulverizer 21 ... slurry pulverizer 22 ... slurry liquid pump 23 ... liquid level sensor 24 ... gas measurement sensor with fire detection function 25 ... steam extraction port | (JP2024106935)|TECHNICAL FIELD|[0001] Disclosed are: a method for suppressing the emission of carbon dioxide, which is a substance that is a main cause of global warming, into the atmosphere; a method for reducing carbon dioxide accumulated in the atmosphere up to now; and a system for embodying these methods.|BACKGROUND ART|[0002] A method has been proposed and put into practical use, in which carbon dioxide gas contained in exhaust gas is separated and recovered when fossil fuels are used or incinerated waste containing hydrocarbons is burned to suppress the increase of carbon dioxide, which is the main greenhouse gas, and is then press-fitted and fixed into underground storage tanks such as drying oil fields and aquifers.|[0003] On the other hand, in the separation and recovery of low-concentration carbon dioxide gas contained in an exhaust gas, compression and liquefaction for transportation to a storage site, and press-fixing into an underground storage tank, a large amount of energy and cost are generated. In addition, since the place where the injected carbon dioxide is leaked and not vaporized and dissipated and can be stored for a long period of time is limited, the exhaust gas containing carbon dioxide is energized while being blown into an aqueous solvent containing an inorganic substance, and is reacted with the inorganic substance to recover it as a solid carbonic acid compound A method of storage or effective utilization (patent document 1) has been proposed.|[0004] Further, as a method for recovering and reducing carbon dioxide in the atmosphere by absorbing and fixing carbon dioxide gas accumulated in the atmosphere through conventional industrial activities, etc., a method for separating and recovering and fixing carbon dioxide gas contained in combustion exhaust gas during power generation or heat utilization using biomass which has absorbed and fixed carbon dioxide in the atmosphere (BECCS), or a method for carbonizing a biomass resource by subjecting the biomass resource to high-temperature heating at 350°C or higher in an oxygen-free or low-carbon environment, thereby making the biomass resource difficult to decompose Carbon storage farming (carbon farming), in which carbon originating from biomass is fixed in soil for a long period of time, is also put into practical use, while realizing the soil improvement of agricultural land by applying it to the agricultural land of mineral soil or the like in which microbial decomposition is suppressed, as a bio-coal composed of carbon and hydrocarbon compounds, and a system for efficiently estimating and evaluating the carbon reduction value in emission right trading (patent document 2) has been proposed.|CITATION LIST|PATENT LITERATURE|[0006] Tokkai 2022-145080|Tokkai 2022-153012|SUMMARY OF INVENTION|TECHNICAL PROBLEM|[0007] As described above, according to the prior art of patent document 1, carbon dioxide gas contained in exhaust gas generated when various hydrocarbon compounds are burned, including fossil fuels, hydrocarbon-containing wastes, and biomass resources produced by absorbing and fixing carbon dioxide in the atmosphere, can be recovered as solid carbonic acid compounds that are easy to transport, store, and effectively use. According to the prior art of patent document 2, carbon is easily and efficiently fixed by carbonizing hydrocarbon compounds including biomass resources and embedding them in soil It is possible to easily and properly evaluate the environmental value, but these technologies have the following problems.|[0008] In the prior art of patent document 1, a large amount of gas compression energy is required in the step of blowing the whole amount of exhaust gas containing carbon dioxide gas of low concentration into an aqueous solvent, and a large amount of electrolytic energy is also required in the step of electrifying the aqueous solvent to perform electrolytic treatment. In addition, a large amount of energy is generated in the step of manufacturing and procuring a magnesium alloy as a raw material. Therefore, a net carbon dioxide reduction effect is achieved when electric power originated from a fossil fuel is used in these steps The problem is that the cost of recovering and fixing carbon dioxide increases due to a large amount of power consumption and the cost associated with the procurement of a raw material for a magnesium alloy, as well as the reduction of carbon dioxide emission suppression effect (reduction of carbon dioxide or emission suppression value).|[0009] As for the carbon storage agriculture method constituting the conventional technology of patent document 2, there is a problem that when biocoal is applied to agricultural land, hydrocarbon compounds other than hardly decomposable carbon contained in the biocoal are decomposed by microorganisms in the soil and dissipated into the atmosphere as warming substances such as carbon dioxide, and the reduction in carbon dioxide reduction effect by the decomposition of biocoal by such microorganisms in the soil is not estimated and considered.|[0010] In other words, with regard to the decomposition effect of the hydrocarbon compounds in the biocharcoal by the microorganisms in the soil, since the number and activity of the microorganisms in the soil, including the species and number of inhabitants of the microorganisms in the soil to which the biocharcoal is applied, vary depending on the environment such as the temperature, humidity, and acidity of the soil and the characteristics of the biocharcoal to which the biocharcoal is applied, the net carbon dioxide reduction effect of the biocharcoal application can be estimated by estimating the decomposition effect of the biocharcoal to which the biocharcoal is applied in addition to these factors and deducting it from the carbon dioxide reduction effect There is also no method of estimation evaluation that can achieve the same effect.|[0011] Further, the present invention is limited to the use of biocoal on agricultural land, and can be constructed in a waste tunnel space or underground by a method for carbon neutralization in which carbon dioxide emission into the atmosphere can be suppressed by carbonizing and embedding a hydrocarbon waste derived from fossil fuels, a method for negative emission in which carbon dioxide in the atmosphere is removed and fixed for a long period of time while suppressing decomposition of hydrocarbons by microorganisms by embedding biocoal in a mining site or a waste pit, and a carbide obtained by carbonizing the hydrocarbon waste incinerated can be constructed in a waste tunnel space or underground by a shield method There is a problem that it is not possible to cope with a method for suppressing the emission of carbon dioxide into the atmosphere by filling and embedding in an artificial storage tank, and it is not possible to estimate the emission suppression value of carbon dioxide and the recovery reduction value of atmospheric carbon dioxide using these methods.|[0012] For example, in the calculation of the carbon dioxide reduction reduction amount in the transaction of carbon dioxide reduction value (for example, the J-credit system in Japan) by the application of bio-charcoal to agricultural land, the carbon retention rate after 100 years according to the type of bio-charcoal (0.65 to 0.89 under the J-credit system) is specified. This coefficient is applied only when bio-charcoal is applied to the soil of mineral in agricultural land or meadow/pastureland stipulated in the Agricultural Land Law, and the soil microbiome is low temperature Thus, it is possible to suppress the decomposition effect of soil microorganisms by storing them in an artificial storage tank composed of concrete walls and metal containers, and to store solid carbon with an increased carbon residual rate 100 years later for a long period of time. However, there has been no disclosure of such method and method for evaluating the value thereof.|[0013] In addition, unutilized underground spaces such as metal mine excavation sites, abandoned mines, and waste tunnels in the mountains, and underground spaces that can be formed using the shield method in the underground or in the mountains have an extremely low risk of ignition and fire generation due to lightning strikes and the spread of nearby fires. In addition, generally, the environment becomes high and humid at low temperatures. It also has the advantage of being extremely low.|[0014] In addition, when the carbon storage space is sealed or sealed with inert gas or water, the amount of oxygen flowing from the outside is limited. Therefore, even if ignition or ignition occurs, the flame does not easily spread due to oxygen shortage, and it is easy to extinguish the fire. Therefore, it has the feature of achieving long-term stable storage of solid carbon while burning biochar and carbide originating from waste and not discharging it as carbon dioxide gas, and suppressing emissions of greenhouse gases such as carbon dioxide due to microbial decomposition.|[0015] Further, the long-term storage of carbonized or semi-carbonized carbon and hydrocarbons in the artificial storage tank as a solid is not limited to biomass-derived carbon, but is also applied to hydrocarbon waste such as plastic, vinyl, fiber and paper, which is derived from fossil fuels or is produced using fossil fuels in a production process. Thus, it has been conventionally required to prevent carbon dioxide gas from being discharged into the atmosphere and being accumulated by incineration at a waste treatment plant. However, the conventional technology cannot evaluate the environmental value based on such a method.|[0016] In addition, not only biomass-derived biochar but also waste containing hydrocarbon derived from fossil fuels are combusted, not dissipated into carbon dioxide gas in the atmosphere, and carbonized prior to combustion and stored in a carbon storage tank as solid carbon or hydrocarbon compounds. In this way, oxygen in the atmosphere is consumed in the combustion process, and by binding with oxygen, carbon dioxide gas with increased volume and mass of bound oxygen components is recovered and stored in a smaller volume and lighter weight than carbon dioxide gas with no oxygen bond However, it has the advantage of being able to carry and store easily and efficiently with a small volume. In particular, the volume of one ton of carbon dioxide gas is approximately 509 cubic meters, and the volume of solid carbon, which is a generation source of one ton of carbon dioxide gas, is approximately 0.51 cubic meters. The volume difference is approximately 1,000 times.|[0017] The purpose of the present invention is to achieve a method and a method for recovering and reducing carbon dioxide in the atmosphere by easily and efficiently suppressing the emission of carbon dioxide associated with the combustion of waste derived from fossil fuels, or by fixing bio-coal, which has absorbed and carbonized carbon dioxide in the atmosphere for a long period of time, while significantly reducing the carbon dioxide reduction effect associated with the decomposition of hydrocarbons by microorganisms in soil, and significantly reducing the risk of the emission of carbon dioxide caused by the ignition, ignition, and combustion of stored carbon Provided is a system for suppressing and reducing an increase in atmospheric carbon dioxide which has been applied.|TECHNICAL SOLUTION|[0018] In order to solve the above problem, the invention of claim 1 is characterized in that a hydrocarbon compound is heated in a low oxygen or oxygen-free environment to form a carbonized, semi-carbonized or mixed product thereof, and the formed carbonized, semi-carbonized or mixed product thereof is formed underground or on the ground. The resulting material is filled or buried in a space partially or wholly enclosed by a corrosion-resistant flame-retardant or non-combustible material, and a part or all of an exposed part after filling or embedding is a corrosion-resistant or non-combustible material The method is characterized in that a carbide, a semi-carbide or a mixture thereof originating from a hydrocarbon compound is stored for a long period of time in a fire-retardant or nonflammable space having corrosion resistance by sealing with.|[0019] In the invention of claim 2, a hydrocarbon compound is heated in a low oxygen or oxygen-free environment to form a carbide, semi-carbide, or mixture thereof. The resulting carbide, semi-carbide, or mixture thereof is filled into a container which is partially or wholly made of a flame-retardant or non-flammable material having corrosion resistance and heat resistance, and a part or all of the exposed portion after the container filling is sealed with a flame-retardant or non-flammable material having corrosion resistance and heat resistance. Thus, the carbide, semi-carbide, or carbide originating from the hydrocarbon compound The present invention is characterized in that a mixture is stored for a long period of time in a fire-retardant or non-flammable container having corrosion resistance.|[0020] The invention described in claim 3 is characterized in that the long-term storage space described in claim 1 is any one of the following: a former site of mining of a waste mine, a waste tunnel, a cave, a tunnel space on a waste railway and a decommissioned road, a decommissioned underground pipe and a common ditch, a water well or hot spring well that has not been used or is suspended, an oilfield after being mined, a gas field and a coal field.|[0021] The invention described in claim 4 is characterized in that the long-term storage space described in claim 1 is an artificial underground space constructed by a shield construction method in which a concrete wall is constructed while excavating a mountain or an underground, or an artificial underground space formed by inserting a cement wall or a steel pipe while excavating an underground.|[0022] The invention described in claim 5 is characterized in that the long-term storage container described in claim 2 is any one of a storage tank for fossil fuel which has been discontinued, a settling pond for water and sewage facilities which have been discontinued, an idle water site and a water tank, or a dam water tank which has been discontinued.|[0023] The invention described in claim 6 is a method for long-term storage of carbon or hydrocarbon compounds described in claims 1 to 5, characterized in that when carbon or hydrocarbon compounds are filled or buried in a long-term storage space or in a long-term storage container, the carbide, semi-carbide, or mixture thereof is pulverized, mixed with water and stirred to form a slurry, and filled or buried as carbide slurry water.|[0024] The invention of claim 7 is characterized in that in the method for storing carbon or a hydrocarbon compound of claim 6 for a long period of time, the carbide concentration of the carbide slurry water is increased or the total amount of water is evaporated and removed by repeating the replenishment of a new carbide slurry water while evaporating the moisture of the carbide slurry water in the tank without sealing the storage tank for the carbide slurry water, and only the residual carbide is stored in the tank.|[0025] The invention described in claim 8 is characterized in that the inner wall covering material constituting the long-term storage space described in claim 1, claim 3 and claim 4, the wall surface constituting material, and the joining sealing material for the wall surface are reinforced concrete, concrete, mortar, or one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility.|[0026] The invention described in claim 9 is characterized in that the container-constituting material and the container-wall joining-sealing material described in claim 2 and claim 5 are any one or more of a metal, mineral, or resin material having corrosion resistance, flame retardancy, or incombustibility.|[0027] The invention described in claim 10 is characterized in that the long-term storage space described in claims 1 to 9 or the interior of the long-term storage container is filled with oxygen-removed hypoxia air or deoxidized air, or inert gas other than carbon dioxide gas to form a pressurized space, and the pressure and components of the filled gas in the space are measured and monitored to control the airtightness and the generation status of greenhouse gases within the long-term storage space or the long-term storage container.|[0028] The invention described in claim 11 is characterized in that the level of the carbide slurry water described in claim 6 and the gas component in the vicinity of the reserving water surface are measured and monitored in the long-term reserving space described in claims 1-9 or inside the long-term reserving container, thereby monitoring and managing the replenishment of the carbide slurry water into the long-term reserving space or the long-term reserving container and the generation status of greenhouse gas from the slurry level.|[0029] If leakage is detected in the long-term storage space or the long-term storage container by the monitoring and management method described in claim 10 or claim 11, the invention described in claim 12 refills the long-term storage space or the long-term storage container by the method described in claim 7 or claim 8 with the carbide slurry water described in claim 6 or the filling gas described in claim 10, and then refills the leakage location identified from the leakage status of the internal gas or internal liquid Monitoring and management of the long-term storage state of carbon or hydrocarbon compounds are resumed by the method described in 10 or claim 11.|[0030] The invention described in claim 13 is based on the net amount of carbon storage by subtracting the amount of global warming gas leaked from the long-term storage space or the long-term storage container from the amount of flow of internal gas and gas components measured when leakage is detected from the long-term storage space or the long-term storage container, or from the measured amount of flow of leaked liquid and components of flow-out liquid by the monitoring and management method described in claim 10 or claim 11 Characterized by calculating value.|[0031] The invention described in claim 14 is characterized in that the method described in claims 1 to 14 is used to carbonize carbon or a hydrocarbon compound, which is a carbon dioxide emission source substance, without burning the carbon or hydrocarbon compound, and the obtained carbide or carbide slurry water is stored in a long-term storage space or in a long-term storage container for a long period of time, thereby suppressing the emission of carbon dioxide gas related to the waste combustion originating in fossil fuels or collecting and reducing the carbon dioxide in the atmosphere.|ADVANTAGEOUS EFFECTS|[0032] According to the present invention, carbon dioxide in the atmosphere can be recovered and reduced by a simple and efficient method with low energy consumption and low cost burden, while reducing the effect of reducing carbon dioxide associated with decomposition of hydrocarbons by microorganisms in soil and reducing the risk of carbon dioxide emission due to ignition, ignition, and combustion of stored carbon, and by reducing the emission of carbon dioxide gas related to waste combustion originating in fossil fuels or by long-term storage of biocoal that has been carbonized by absorbing carbon dioxide in the atmosphere.|DESCRIPTION OF DRAWINGS|[0033] A method of absorbing and reducing atmospheric carbon dioxide gas, in which bio-charcoal obtained by carbonizing a thinned material into an underground space in a waste mine is stored for a long period of time and monitored and managed, and a schematic drawing showing the system.|[0034] A method for preventing carbon dioxide gas emission, which comprises carbonizing a waste containing a fossil fuel-derived plastic, slurrizing the carbonized waste, storing the slurry in a storage tank of a waste petroleum storage base for a long period of time, and monitoring and managing the carbonized waste, and a schematic drawing showing the system.|DESCRIPTION OF EMBODIMENTS|[0035] The best form for implementing the invention is described in the following drawing. The scope of the present invention is stated in the claims and is not limited to this embodiment.|[0036] (First Embodiment)|[0037] A method and a system for absorbing and reducing atmospheric carbon dioxide gas, in which biocharcoal obtained by carbonizing thinned wood is stored for a long period of time in an underground space in a waste mine and monitored and managed, according to a first embodiment of the present invention are explained on the basis of Fig. 1.|[0038] As shown in Fig. 1, this system has a metal mineral in a strong rock bed, and although the mining was conducted in underground space in the mountains, the mining was completed and turned into waste ore. In the waste mine 1 having unused underground space after the mining and unused waste tunnels, biocoal 4 obtained by carbonizing forest-derived biomass resources 3 grown by absorbing atmospheric carbon dioxide is buried in the unused underground space 2, and the atmospheric carbon dioxide is recovered and reduced by long-term storage.|[0039] In this system, biocharcoal 4 is produced by a woody biomass carbonization furnace (5) in which a woody biomass (3) obtained by thinning or clearing forests growing on the surface of a waste mine or nearby forests is dried and chipped, and then carbonized by heating to 350°C or higher in an oxygen-free or hypoxic environment. In the process of carbonization of biomass, a part of woody biomass can be gasified and used as fuel. However, it is desirable to suppress energy consumption and increase of carbon dioxide associated with carbonization of woody biomass by generating electric power using this fuel and using it as driving power for a chip-making device or a carbonization furnace, or by using the generated heat for drying and carbonization of woody biomass by burning a boiler.|[0040] On the other hand, in the unused underground space in the waste mine where the biocoal is stored, there are places with cracks in the bedrock and places where the groundwater gushes out. If such places are not sealed, there is a risk that a part of the stored biocoal may enter the groundwater or enter the cracks and mix with the groundwater. Therefore, the inner wall of the storage tank and the floor surface are sealed by filling or applying concrete or mortar in such places so that the stored biocoal does not flow out It is desirable to construct 6.|[0041] However, if the biochar to be stored does not contain harmful substances, it is not necessary to fill or apply concrete or mortar to the entire top, wall, or floor surface of the underground space. This is because biocoal itself is a harmless substance, and even if it is mixed into ground water and flowed out, it does not lead to water pollution and emission of carbon dioxide gas.|[0042] Thus, the underground unused space in the waste ore is formed into a storage space suitable for long-term storage of biocoal. After the biocoal generated in the above step is used for burying, a sealing wall (7) made of reinforced concrete is constructed to bury and seal the long-term storage space. Thus, it is possible to long-term storage of carbon from biomass origin, which has absorbed carbon dioxide in the atmosphere, in the underground space of the waste ore.|[0043] A communication hole 8 for monitoring the inside of the storage tank and a nitrogen gas supply pipe 9 for sealing nitrogen in the storage tank are constructed on the sealing wall. A pressure sensor 10 for measuring the pressure in the storage tank and a gas sensor 11 for measuring and monitoring the state of generation of carbon dioxide gas and combustible gas in the storage tank are connected to the communication hole 8. Measurement information from these sensors is intensively analyzed by an in-storage tank monitoring and reporting edge terminal 12, and the storage state in the storage tank is monitored, and an alarm is issued or a leak is generated in the event of abnormality The system is configured so as to transmit estimated analysis data of the leakage amount.|[0044] On the other hand, a nitrogen gas cylinder (13) for sealing nitrogen in the storage tank and a gas compressor (14) for forcing the nitrogen gas into the storage tank are connected to the end of the nitrogen gas supply pipe (9). These can be carried in and utilized when the storage of bio-coal is completed and sealed, or when the biocoal is refilled when leakage, the pressure in the storage tank is lowered, or the nitrogen concentration is lowered and the oxygen concentration is increased. During the storage and storage after filling, the valve on the supply pipe (9) can be closed to maintain the sealed state.|[0045] The nitrogen encapsulation is for monitoring and confirming the generation status of carbon dioxide caused by the decomposition of the biocoal when deducting the environmental value in the case where the decomposition of the biocoal generates a combustible gas and oxygen mixes in the storage tank to generate an ignition source inside to cause ignition and combustion, and carbon dioxide gas is generated by the decomposition of the biocoal to diffuse the extracted air. In the storage tank, the biocoal sterilized by the high temperature rise is stored in a space with a low temperature and high humidity underground When the risk of ignition and combustion of stored biocharcoal is extremely low, the generation of carbon dioxide by microbial decomposition does not occur, or the amount of generated carbon dioxide is extremely small, the method does not necessarily require encapsulation of nitrogen gas or monitoring and management of the storage tank.|[0046] By using the above method, biochar obtained from woody biomass resources obtained on the surface of a waste mine or from neighboring forests is buried and stored in the waste mine, and it is possible to recover and reduce atmospheric carbon dioxide through long-term storage of biochar. In addition, after thinning or clearing trees on the surface of a waste mine or from neighboring forests in this method, seedlings (15) are planted and raised, whereby trees are grown while further reducing the amount of atmospheric carbon dioxide absorbed through the growth of seedlings, trees are thinned or cut at a point where a mature tree having a reduced carbon dioxide absorption rate is reached, and biocoal obtained by this method is stored underground, thereby enabling the sustainable recovery and reduction of atmospheric carbon dioxide. (Second Embodiment)|[0047] Next, according to the second embodiment of the present invention, a carbon dioxide gas emission control method and a system therefor are explained on the basis of Fig. 2, in which a carbide obtained by carbonizing a hydrocarbon waste derived from a fossil fuel is pulverized and stored as carbide slurry water mixed with water, and monitoring and management are performed in a petroleum storage tank at a waste petroleum storage base.|[0048] As shown in Fig. 2, this system is a system in which fossil fuels have been stockpiled while ensuring thorough risk management against fire and leakage, but the prospect of utilization has disappeared as a result of abolition. The oil stockpiling tank in the petroleum refining plant is converted to a long-term storage tank (16) for carbide slurry water, and by incineration at a waste disposal plant, carbide (17) obtained by carbonizing hydrocarbon waste that can be a source of carbon dioxide gas emissions is converted to slurry water and stored in the tank. Thus, the system is incinerated The purpose of the present invention is to suppress an increase in carbon dioxide emissions.|[0049] In this system, a combustible waste 18 such as waste plastic and vinyl recovered from a waste collection vehicle and paper and cloth which have conventionally been incinerated in a waste treatment plant is dried and crushed, then a mixture of carbon and hydrocarbon is formed by a combustible carbonization furnace 19 which is heated to 500°C or higher in an oxygen-free or hypoxic environment and carbonized, and then it is pulverized by a carbide pulverizer 20 and mixed with water and stirred by a slurry agitator 21 to carbonize the product Slurry water obtained as water is poured into a storage tank 16 through a pump 22 and stopped when the liquid level reaches an upper limit.|[0050] The lid is equipped with a liquid level sensor (23) for measuring the liquid level position of the slurry water to grasp the storage state in the tank, and a gas measurement sensor (24) with a fire detection function capable of grasping the generation state of carbon dioxide gas and combustible gas from the liquid level and the occurrence state of a fire. An edge terminal (12) for monitoring the storage state and issuing an alarm when an abnormality occurs is installed. However, the slurry water stored in the tank does not generate carbon dioxide gas and combustible gas by merely evaporation of moisture In this case, the gas measuring sensor 24 with the fire detecting function may be a simple fire detector or may not be installed. This is because, unlike stored oil, aqueous carbonized slurry solution has low volatility and is difficult to burn, and therefore, without sufficient ignition energy, it does not ignite and is difficult to spread the fire.|[0051] A water vapor extraction port (25) for extracting moisture from the carbonized slurry water is attached to the vicinity of the top surface lid of the container. The evaporated moisture is extracted from the storage tank, and the drain water generated via the radiator is condensed as raw material water in the slurry forming device (21). Thus, the amount of rehydration water used when the slurry water is generated is reduced. When the slurry water in the tank is concentrated and the liquid level is lowered, a pump is used to extract the evaporated moisture By appropriately replenishing the slurry water, the carbon storage amount in the tank can be increased.|[0052] With such an arrangement, carbon originating from waste is accumulated in a storage tank as slurry water, and then the amount of carbon stored in the tank is increased by repeating water evaporation and replenishment of the slurry water. Thus, carbon dioxide generation accompanying incineration of waste can be suppressed and the carbon can be stored as carbon. After the tank is filled with stored carbon by this method, the set of a liquid feed system for carbonization, slurrification, and slurry water is transferred to other storage tanks, and the same operation is repeated successively, thereby enabling long-term storage of carbon in a plurality of tanks.|INDUSTRIAL APPLICABILITY|[0053] The present invention is not limited to the aforementioned embodiments, and for example, the embodiments shown in the figure are not limited to waste mines or discontinued oil storage tanks, but are carried out using natural terrain such as caves and mountain valleys, or various organic substances burned and exhausted in a natural or artificial storage space, such as by sealing the entrance of a waste tunnel with a reinforced concrete wall, mixing biocoal with a carbonized material of combustible waste, and sealing the exit with a reinforced concrete wall to store carbon The carbonization and storage can be used as a method for suppressing the emission of carbon dioxide and for reducing the recovery of atmospheric carbon dioxide.|[0054] Thus, any item having a structure substantially identical to the technical idea described in the patent claims and exhibiting a similar action effect is included in the technical scope of the invention.|REFERENCE SIGNS LIST|[0055] 1...waste mine 2...unused underground space inside waste mine 3...woody biomass 4...woody biomass 4...woody biomass carbonization furnace 6...woody biomass carbonization furnace 7...storage inner wall 7...sealing wall 8...storage internal communication hole 9...nitrogen gas supply pipe 10...storage tank internal pressure measurement sensor 11..storage tank internal pressure measurement sensor 12..storage tank internal monitoring notification edge terminal 13..nitrogen gas cylinder 14..gas compressor 15..seedling 16..carbide slurry water storage tank 17... 18 ... combustible waste 19 ... combustible carbonization furnace 20 ... carbide pulverizer 21 ... slurry pulverizer 22 ... slurry liquid pump 23 ... liquid level sensor 24 ... gas measurement sensor with fire detection function 25 ... steam extraction port | Family Number|(110943542)|110943542|Advantages / Prev. Drawbacks|(JP2024106935 A)| (...) activities, etc., a method for separating and recovering and fixing carbon dioxide gas contained in combustion exhaust gas during power generation or heat utilization using biomass which has absorbed and fixed carbon dioxide in the atmosphere (BECCS), or a method for carbonizing a biomass resource by subjecting the biomass resource to high-temperature heating at 350°C or higher in an oxygen-free or low-carbon environment, thereby making the biomass resource difficult to decompose Carbon (...) | | Environmental technology | B09B-003/40 | B09B-003/40|B09B-005/00 | 特開２０２２－１４５０８０|特開２０２２－１５３０１２ | PENDING | (JP2024106935)|PENDING | ALIVE | (JP2024106935)|ALIVE | (JP2024106935)|LEGAL DETAILS FOR JP2024106935|Actual or expected expiration date=2043-01-27|Legal state=ALIVE|Status=PENDING|Event publication date=2023-01-27|Event code=JP/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=JP JP2023020350|Application date=2023-01-27|Standardized application number=2023JP-0020350|Event publication date=2024-08-08|Event code=JP/A|Event group=Examination events|Published application|Publication country=JP|Publication number=JP2024106935|Publication stage code=A|Publication date=2024-08-08|Standardized publication number=JP2024106935 | (JP2024106935)|JP | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=N5221X+da3/VqaCiWXghUgMqfaYWomYVbZEW38EL5eC5GkWmuuS7QKXL31I9s5RZSNnPjhgoLnPBB0W7Jy7i6Q==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=JP0000000022380262&ekey=1934&xpn=JP2024106935&kind=A | https://www.j-platpat.inpit.go.jp/c1801/PU/JP-2023-020350/10/en | https://permalink.orbit.com/RenderStaticFirstPage?XPN=pFB%252FXFtWG8H6RsUtyZy%252B5LmsLuw%252FR4oY%252BQgpgFzVRnM%3D%26n%3D1&id=0&base=FAMPAT | JP | (JP2024106935)|NAME=KAWABATA YASUHARU | (JP2024106935)|2 | 1 | 1 | (JP2024106935)|Number of Claims: NCL=15|Form: FORM=書面|Request for examination: REQEXA=false| | (JP2024106935)|JAPANESE (JPN) | (JP2024106935)|Patent | Titre: (JP2024106935)|Method for suppressing and reducing increase in carbon dioxide in atmosphere, and system for suppressing and reducing increase in carbon dioxide in atmosphere Résumé: (JP2024106935)|PROBLEM TO BE SOLVED: To provide a method for suppressing and reducing an increase in carbon dioxide in atmosphere which simply and efficiently suppresses carbon dioxide discharge relating to waste combustion originated from a fossil fuel, fixes bio-carbon carbonized bio-charcoal formed by absorbing carbon dioxide in the atmosphere and carbonizing for a long period of time, and thereby recovering and reducing carbon dioxide in the atmosphere, and a system for suppressing and reducing increase in carbon dioxide in atmosphere to which these methods are applied.SOLUTION: A method heats a hydrocarbon compound under low oxygen or oxygen-free environment, carbonizes or semi-carbonizes the hydrocarbon compound or converts it into a mixture thereof, fills or buries the produced carbide, semi-carbide or a mixture thereof, and carbide slurry water obtained by micronizing the carbide and being mixed with water into a space which is formed underground or on the ground and is surrounded by a flame-retardant or noncombustible material having corrosion resistance or fills or stores them in a container composed of the material, and thereby stores the material for a long period of time while suppressing emission of warming gas by ignition and combustion of the carbide, semi-carbide or a mixture thereof, and decomposition of microorganisms.SELECTED DRAWING: Figure 1COPYRIGHT: (C)2024,JPO&INPIT Autre: (JP2024106935)|1. A carbonized product or semi-carbonized product originating in a hydrocarbon compound is produced by heating the hydrocarbon compound in a low-oxygen or oxygen-free environment to form a carbonized product, a semi-carbonized product or a mixture thereof, forming the formed carbonized product, semi-carbonized product or mixture thereof underground or on the ground, filling or embedding the product in a space partially or wholly enclosed with a corrosion-resistant flame-retardant or non-combustible material, and sealing a part or the whole of an exposed part after filling or embedding with a corrosion-resistant flame-retardant or non-combustible material A method of long-term storage of |2. carbon or carbide, characterized in that a mixture is stored for a long period of time in a fire-retardant or nonflammable space having corrosion resistance. A hydrocarbon compound is heated in a low oxygen or oxygen-free environment to form a carbonized, semi-carbonized or mixed product of carbonized, semi-carbonized or mixed products of carbonized, semi-carbonized or mixed products of carbonized, semi-carbonized or mixed products of carbonized, semi-carbonized or mixed products of carbonized or nonflammable materials having corrosion resistance and heat resistance. A part or the whole of the exposed part after the filling is subjected to corrosion resistance A method of long-term storage of carbon or carbide, characterized in that by sealing with a heat-resistant, flame-retardant, or nonflammable material, carbide, semi-carbide, or a mixture thereof originating from a hydrocarbon compound is stored for a long period of time in a corrosion-resistant, flame-retardant, or nonflammable container. In the long-term storage space described in claim 1, there is provided a method for long-term storage of |3. carbon or carbide, wherein the long-term storage space is defined as a waste mine site and a waste pit, a cave, a tunnel space on a waste railroad and a waste road, a used underground piping and common ditch, a water well or hot spring well that is not used or stopped to be used Long-term storage method for |4. carbon or carbide characterized by being any of the oil field, gas field, or coal field The long-term storage space described in claim 1 is an artificial underground space constructed by a shield method for constructing a concrete wall while excavating a mountain or an underground, or an artificial underground space formed by inserting a cement wall or a steel pipe while excavating an underground Long-term storage method for |5. carbon or carbide The long-term storage container described in claim 2 is a storage tank for fossil fuel which has been used and an abandoned sand basin A method of long-term storage of |6. carbon or a carbonized material, characterized in that it is an idle water site, a water tank or an abolished dam water tank. Claims 1 to 5, the method of long-term storage of carbon or a hydrocarbon compound, characterized in that, when carbon or a hydrocarbon compound is filled or buried in a long-term storage space or a long-term storage container, the carbon, semi-carbonized material or a mixture thereof is pulverized, mixed with water and stirred to form a slurry, and filled or buried as carbonized slurry water. The method of long-term storage of |7. carbon or a carbonized material, described in claim 6, is characterized in that it is filled or buried as carbonized slurry water Alternatively, the method for long-term storage of a hydrocarbon compound is characterized in that, in the method for long-term storage of a hydrocarbon compound, the carbide concentration of the carbide slurry water is increased or the total amount of the water is evaporated and removed by repeating the replenishment of a new carbide slurry water while evaporating the moisture of the carbide slurry water in the tank without sealing the storage tank for the |8. carbide slurry water, and only the residual carbide is stored in the tank. Further, the method for long-term storage of a carbon or carbide is characterized in that the long-term storage space is constituted by an inner wall covering material and a wall covering material as described in Claims 1, 3 and 4 A method of long-term storage of |9. carbon or carbide, characterized in that a surface constituting material and a joining sealing material for a wall surface are reinforced concrete or concrete, mortar, or one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility; and a method of long-term storage of carbon or |10. carbide, characterized in that the constituting material for a container and the joining sealing material for a container wall described in claims 2 and 5 are one or more of metal, mineral, or resin materials having corrosion resistance, flame retardancy, or incombustibility A method of managing the long-term storage state of a |11. carbon or carbide, characterized in that the long-term storage space or the interior of a long-term storage container described in Claims 1-9 is filled with oxygen-removed hypoxic air or deoxidized air, or inert gas other than carbon dioxide gas to form a pressurized space, and the pressure and components of the filled gas in the space are measured and monitored to manage the airtightness and the generation status of greenhouse gases within the long-term storage space or the long-term storage container A method of managing the long-term storage state of |12. carbon or carbide, characterized in that the replenishment management of the carbide slurry water into a long-term storage space or a long-term storage container and the generation status of greenhouse gases from the surface of the slurry are monitored and managed by measuring and monitoring the water level of the carbide slurry water described in claim 6 and the gas components in the vicinity of the storage water surface. In the case where leakage is detected from the long-term storage space or the long-term storage container by the monitoring and management method described in claim 10 or claim 11, leakage of internal gas or internal liquid is detected A method of maintenance and management of a long-term storage of carbon or hydrocarbon compounds, characterized in that after repairing the long-term storage space or long-term storage container by the method described in claim 7 or claim 8 for a specified leak site, the long-term storage of |13. carbon or hydrocarbon compounds is resumed by refilling the slurry water of the carbide described in claim 6 or the filling gas described in claim 10 and by the method described in claim 10 or claim 11 According to the monitoring and management method described in, the amount of global warming gas leaked from the long-term storage space or the long-term storage container is calculated from the flow rate and gas component of the internal gas measured when leakage is detected from the long-term storage space or the long-term storage container, or from the flow rate and component of the outflow liquid measured, and the environmental value based on the net amount of carbon storage is calculated by subtracting the amount of leakage from the initial amount of |14. carbon storage A system for suppressing the increase and reduction of carbon dioxide in the atmosphere, characterized by carbonizing carbon or a hydrocarbon compound, which is a carbon dioxide emission source substance, without burning by means of the method described in claim 1-14, and then storing the obtained carbide or carbide slurry water in a long-term storage space or in a long-term storage container for a long period of time, thereby suppressing the emission of carbon dioxide gas related to waste combustion originating in fossil fuels or recovering and reducing carbon dioxide in the atmosphere | 14 | Abstract | gpt-4o-mini | no | The article focuses on carbon dioxide suppression related to fossil fuel combustion and carbonization of hydrocarbon compounds, without involving biomass energy production or CO₂ capture and storage from biomass. | |||||||||||||||||||||||||||||||
| 16 | IN202221038543 | IN202221038543 | IN202221038543 | 109076587 | IN202221038543 A 2024-01-12 [IN202221038543] | 2022-07-05 | 2022-07-05 | 2024-01-12 | (IN202221038543)|2042-07-05 | (IN202221038543)|A scalable co2 and pathogen quenching scrubber | (IN202221038543)|The present invention absorbs and concentrates CO2 inside an adsorption chamber (7) using amine resins (13). The resin (13) after saturation with CO2 can be utilized for carbon sequestration applications. Alternatively, the concentrated CO2 captured by the resin (13) is released and utilized for a host of other carbon cycling applications. The ambient air or exhaust gas supplied by the air intake blower is filtered by a HEPA filter (3), and a UV sterilizer (4). This filtrated air is sucked into an adsorption chamber (7) that contains the resins (13) and a heater (9) or a solar concentrator (9). During the adsorption cycle, air flows continuously through the adsorption chamber for a prescribed period after which the solenoid valves (5) shut down the suction and discharge and turn on the heating cycle or open the top cover to activate the solar concentrator where the temperature inside the adsorption chamber (7) is increased to a set temperature that forces the resins (13) to release the absorbed CO2. | GREENGROVES BAHRAIN WLL | (IN202221038543)|GREENGROVES BAHRAIN WLL | Kumar Ramachandran Rajeev|Riain Liam Sean O|Parambil Shanavas Kallam|Jacob Dangly Ann|Chinnasamy Senthil | (IN202221038543)|Kumar Ramachandran Rajeev|Riain Liam Sean O|Parambil Shanavas Kallam|Jacob Dangly Ann|Chinnasamy Senthil | (IN202221038543)|The objects, features, and advantages of the present invention will now be described in greater detail.| | (IN202221038543)|1. A scalable CO2 and pathogen quenching scrubber, comprising: a) an external casing (1); b) a plurality of replaceable cartridges (6); said each replaceable cartridge comprising an adsorption chamber (7) holding amine resins (13) capable of absorbing CO2 during an adsorption cycle; c) a plurality of solenoid valves (5) located in front of said adsorption chamber (7) being capable of controlling the suction and discharge of air from said adsorption chambers (7); d) an HEPA filter (3) being capable of removing dust and other particulate matter; e) a UV sterilizer (4) being capable of removing pathogens, including viruses; f) an air intake blower (2) being capable of providing suction to pull the air filtered through said HEPA filter (3) and UV sterilizer (4) into said device for the adsorption and removal of CO2; g) a heating element (9) being capable of increasing the temperature in the adsorption casing and releasing the absorbed CO2; and h) a probe and sensors (11) for temperature and CO2.| | (IN202221038543)|The main aspect of the present invention is to provide scalable CO2 and pathogen quenching scrubber having an external casing and single or multiple replaceable cartridges, said each replaceable cartridge consists of an adsorption chamber; said adsorption chamber holds the resins being capable to absorb the CO2 during an adsorption cycle while the space between said adsorption chamber component and said external casing component holds the CO2 being insulated with a thermal insulation to prevent the escape of heat during the heating cycle; a solenoid valves being capable to control the suction and discharge of air from the adsorption chambers; an HEPA filter being capable to remove the dust and other particulate matter; an UV sterilizer being capable to remove pathogens including the virus; an air intake blower provides the suction that pulls the air filtered through said HEPA filter, said UV sterilizer into the device for the adsorption and removal of CO2; a heater being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater covered with a heater casing; a solar concentrator with an automated opening and closing mechanism being capable to increase the temperature in the adsorption casing and to release the CO2 being absorbed and a probe and a sensors for temperature and CO2. Another aspect of the present invention is to provide a scalable CO2 and pathogen quenching scrubber that contains an intake filtration system that consists of a dust filter along with a UV filtration unit for the removal of pathogens.|The present invention relates to a scalable CO2 and pathogen quenching scrubber.|The principal object of the present invention is to overcome all the mentioned and existing drawbacks of the prior arts by providing a fully automated CO2 scrubber for concentrating carbon dioxide for further use in a Microalgae based BEECS, CCS, or CCU system. The secondary object of the present invention is to provide a CO2 scrubber system that can also function as an indoor or outdoor air filter which can also be integrated with an HVAC system where the system can remove dust and pathogens providing a single-source solution for quenching and removal of CO2, dust, and pathogens including the SARS-CoV-2 virus. Another object of the present invention is to provide a fully automated CO2 scrubber that consists of single or multiple replaceable cartridges installed in equal number of adsorption chambers where the CO2 is absorbed using an amine resin which is released in a heat cycle by raising the temperatures using a heater along with HEPA and UV sterilizer integrated into the system. In another aspect of the present invention, the heating is done using a solar concentrator. Yet another object of the present invention is to provide an automated carbon dioxide scrubber that uses a UV sterilizer and amine resins to concentrate and release CO2 that can be used for various applications including but not limited to HVAC or outdoor air purification, purification of emissions from diesel or natural gas gensets, Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Utilization (CCU) & Carbon Capture and Sequestration (CCS).| | (IN202221038543)|PATHOGEN(100,23)|SCRUBBER(100,23)|SCALABLE CO2(100,16)|PATHOGEN QUENCHING SCRUBBER(100,1)|ADSORPTION CHAMBER(68,33)|REPLACEABLE CARTRIDGE(68,9)|UV STERILIZER(67,15)|SOLAR CONCENTRATOR(56,11)|ADSORPTION CASING(54,7)|MICROALGAE BEECS(45,1)|HEPA FILTER(41,11)|ADSORPTION CYCLE(36,6)|AMINE RESIN(33,11)|MICROALGAE BIOENERGY(32,4)|AUTOMATED CO2 SCRUBBER(30,5)|CO2 REMOVAL(29,4)|ABSORBING CO2(29,1)|FILTERING INTAKE(29,1)|CO2(28,41)|ABSORBED CO2(28,4)|HEATER CASING(26,3)|UV FILTRATION(26,1)|ADSORBED CO2(25,3)|SUCTION(24,6)|HEATER(22,15)|ADSORPTION(22,6)|VIRUS(22,4)|ABSORB CO2(20,2)|CONCENTRATED CO2(20,1)|AIR INTAKE BLOWER(19,7)|CO2 SCRUBBER(19,7)|SOLENOID VALVE(18,11)|CASING(18,10)|AUTOMATED OPENING(18,2)|ADSORPTION CHAMBER COMPONENT(18,1)|DUST(17,9)|PROBE(16,6)|CARBON CYCLING HOST(16,1)|FILTRATED AIR(15,1)|QUENCHING(15,1)|CONCENTRATING CARBON DIOXIDE(14,2)|RELEASE CO2(14,2)|HVAC(13,4)|PARTICULATE MATTER(13,4)|ESCAPE PREVENTION(13,3)|HEPA(13,1)|CARBON DIOXIDE SCRUBBER(12,4)|INSULATOR(12,4)|CO2 DISCHARGE SOLENOID VALVE(12,2)|DECARBONATED AIR(12,2)|NATURAL GAS GENSET(12,2)|OUTDOOR AIR PURIFICATION(12,2)|SHUTDOWN(12,1)|CARBON SEQUESTRATION(11,4)|SARS COV(11,4)|OUTDOOR AIR FILTER(11,1)|SATURATION(11,1)|HEAT(10,14)|THERMAL INSULATION(10,4)|CO2 RICH AIR(10,2)|DIESEL(10,2)|BECCS(9,4)|DUST FILTER(9,1)|HEATING ELEMENT(8,3)|SUCTION CONTROL(7,3)|CONDUCTING(7,2)|SOLAR CONCENTRATOR TOP COVER(7,2)|AIR DISCHARGE SOLENOID VALVE(6,2)|CO2 FLOW(6,2)|INPUT SOLENOID VALVE(6,2)|EXHAUST GAS(6,1)|FEEDING ALGAE PHOTOBIOREACTOR(6,1)|MICROALGAE BECCS(6,1)|CARBON CAPTURE(5,10)|ERRATIC CLIMATE(5,1)|CARBON DIOXIDE(4,7)|GREENHOUSE GASE(4,7)|HEAT CYCLE(4,2)|OPPOSITE CYCLE(4,2)|PLC SCADA CONTROL PANEL(4,2)|ADVANCED FILTRATION FACILITY(4,1)|HEATER SOLAR CONCENTRATOR(4,1)|MICROALGAE BIOENERGY CARBON CAPTURE(4,1)|MICROBIAL FILTRATION(4,1)|NET NEGATIVE OUTCOME(4,1)|SEA VAN CONTAINER(4,1)|SORBENT REGENERATION(4,1)|UNITED NATIONS FRAMEWORK CONVENTION(4,1)|VIRUS SARS COV(4,1)|SET TEMPERATURE(3,3)|CARBONATE SALT(3,2)|CIRCULATED REAGENT SOLUTION(3,1)|DISCHARGED CO2(3,1)|MAJOR REPERCUSSION(3,1)|REGENERATING CHAMBER(3,1)|SECONDARY OBJECT(3,1)|SCALABLE DESIGN(2,2)|ABSORPTION CHAMBER(2,1)|AIR FLOW(2,1)|AIR SUCTION(2,1)|ALWAYS RELEASING CO2(2,1)|ANTHROPOGENIC INDUCED CLIMATE CHANGE(2,1)|AQUATIC(2,1)|AUTOMATION(2,1)|BIODIVERSITY(2,1)|BIOMASS(2,1)|CAPITA(2,1)|CARBON DIOXIDE ADSORPTION(2,1)|CARBON DIOXIDE SORBENT(2,1)|CARTRIDGE(2,1)|CATTLE PRODUCTION(2,1)|CLIMATE CHANGE ADVENT(2,1)|CUTTING EMISSION(2,1)|DECARBONIZATION(2,1)|DISINFECTING COMPONENT(2,1)|HUMAN POPULATION EXPANSION(2,1)|INDOOR CONDITION(2,1)|INTAKE FILTER(2,1)|MAJOR CHALLENGE(2,1)|MICROALGAE CARBON CAPTURE(2,1)|PROJECTED INCREASE(2,1)|SINGLE SOURCE SOLUTION(2,1)|STERILIZATION(2,1)|SULFUROUS COMPONENT(2,1)| | (IN202221038543)|1. A scalable CO2 and pathogen quenching scrubber, comprising: a) an external casing (1); b) a plurality of replaceable cartridges (6); said each replaceable cartridge comprising an adsorption chamber (7) holding amine resins (13) capable of absorbing CO2 during an adsorption cycle; c) a plurality of solenoid valves (5) located in front of said adsorption chamber (7) being capable of controlling the suction and discharge of air from said adsorption chambers (7); d) an HEPA filter (3) being capable of removing dust and other particulate matter; e) a UV sterilizer (4) being capable of removing pathogens, including viruses; f) an air intake blower (2) being capable of providing suction to pull the air filtered through said HEPA filter (3) and UV sterilizer (4) into said device for the adsorption and removal of CO2; g) a heating element (9) being capable of increasing the temperature in the adsorption casing and releasing the absorbed CO2; and h) a probe and sensors (11) for temperature and CO2.|2. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said adsorption chamber and said external case being insulated with a thermal insulation (12) to prevent the escape of heat during the heating cycle.|3. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said heating element (9) can be a heater being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater (9) covered with a heater casing (8); or a solar concentrator (9) with an automated opening and closing mechanism (8) being capable to increase the temperature in the adsorption casing and to release the CO2 being absorbed and a probe and a sensors for temperature and CO2.|4. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said amine resins (13) are capable of absorbing the CO2 during an adsorption cycle while the space between said adsorption chamber (7) component and said external casing (1) component holds the CO2.|5. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein components are held inside an external casing (1) and an insulator (12) between the external casing and the adsorption chamber (7) where the CO2 rich air is held after the resins (13) release the adsorbed CO2 upon heating where the insulator (12) prevents the heating from escaping by conduction.|6. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said solenoid valves (5) and said heater (9) or solar concentrator top cover (8) are controlled by PLC/SCADA-based control panel (10).|7. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said solenoid valves (5) remain closed for a period of set time cycles when the heating element (9) turns on and increases the temperature in the adsorption chamber (7) to a set temperature that causes the amine resins (13) to lose the adsorbed CO2.|8. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said CO2 discharge solenoid valve (5) opens for a period of set time cycles where the CO2 flows out for the intended use of the CO2.|9. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said air is passed through the adsorption chamber (7) for a period of set time cycles throughout which the input solenoid valve (5) and the air discharge solenoid valve (5) are open; during that time of which the resins (13) being capable of absorbing the CO2 and the decarbonated air continuously flows out.|10. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said adsorption chambers (7) function in opposite cycles between the adsorption and heating cycles with the cycles being controlled automatically by a PLC/SCADA control system. | (IN202221038543)|FIELD OF THE INVENTION:|The present invention relates to a scalable CO2 and pathogen quenching scrubber. More particularly it relates to an automated carbon dioxide scrubber that uses a UV sterilizer and amine resins to concentrate and release CO2 that can be used for various applications including but not limited to HVAC or outdoor air purification, purification of emissions from diesel or natural gas gensets, Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Utilization (CCU) & Carbon Capture and Sequestration (CCS).|BACKGROUND OF THE INVENTION:|There is a scientific consensus that climate change caused due to anthropogenic activities can lead to net negative outcomes leading to [a] Erratic climate events, [b] adverse impacts on aquatic and on-land biodiversity, and human health, [c] Rise in sea levels, and [d] Food and water security issues.|Under the United Nations Framework Convention on Climate Change (UNFCC), the Paris agreement's long-term temperature goal is to restrict the rise in the global average temperature to under 2 °C above the pre-industrial levels with the ideal goal being the temperatures to a more stringent average temperature rise of under 1.5 °C. These pledges were further renewed in the COP 26 conference (26th UN Climate Change Conference of the Parties (COP26) in Glasgow on 31 October - 13 November 2021) where the countries provided renewed pledges and many committed to net-zero emissions by 2050.|The countries of the Gulf Cooperation Council (GCC) emit the highest quantities of Greenhouse Gases (GHGs) per capita globally and are among the largest exporters of crude petroleum and natural gas worldwide. Hence, the countries of the GCC are actively exploring avenues to reduce their carbon footprint with the UAE committing to achieve net-zero by 2050 and Saudi Arabia committing to net-zero by 2060.|The reduction in GHGs can be achieved by either:|1) Cutting emissions can be achieved through various approaches including [a] shifting to renewables sources of energy like wind, solar, biomass, hydel, and geothermal energy [b] increasing the proportion of vehicles using alternative modes of energy such as Battery Electric Vehicles (BEVs) and Fuel Cell Electric Vehicles (FCEVs), [c] reducing emissions from food production, specifically cattle production, and [d] lifestyle changes.|2) Absorbing GHGs using net-negative carbon technologies that reduce the existing concentration of GHGs in the atmosphere using Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Storage (CCS), or Carbon Capture and Utilization (CCUs) technologies.|There is significant diversity in the types of carbon capture technologies with multiple publications and patents being filed for various methods of carbon capture. US patent US 2021/0252451A1 assigned to Catherine Thibaud and Zhipeng Zhong consists of a Carbon dioxide scrubber with a moving bed structure that has a continuously movable carbon dioxide sorbent bed through the adsorption chamber and the regeneration chamber.|Meanwhile, the patent US 2013/0178145A1 assigned to Carlos Gomez et al, uses a carbon dioxide scrubber in a sea van container consisting of a gas-selective membrane with a CO2/O2 selectivity ratio greater than 1:1 forming a curtain that effectively makes the inner plenum chamber airtight.|Similarly, the patent US 9,149,761B2 assigned to Northrop and Anderson removed acidic gases such as sulfurous components and carbon dioxide from a gas processing facility which in various embodiments can be used to capture CO2 from the tail gas generated from a Claus sulfur recovery unit.|Patent applications with a similar application include US 2014/0342443A1 assigned to Dale Bohn which uses scrubbers for feeding algae photobioreactors but uses a circulated reagent solution instead of solid amines for the adsorption of carbon dioxide.|Another patent application by Eisenberger, US2020/047116A1 uses a sorbent under ambient conditions, to obtain relatively pure CO2 using process heat, preferably in the form of steam, at a temperature range of lower than 130 °C, to capture the relatively pure CO2 and to regenerate the sorbent for repeated use.|None of the prior arts disclosed a CO2 scrubber that includes a scalable fully automated system that contains a dust-filtration unit, UV filter, and a filter containing an efficient sterilizing agent like in its intake system which allows it to operate in both indoor and outdoor conditions. It consists of a single or multiple replaceable cartridges installed in equal number of adsorption chambers where the CO2 is absorbed using amine resins which are released in a heat cycle by raising the temperatures using a heater and the CO2 is directed to either an indoor or outdoor CCU unit or a combination of the above. In another embodiment of the present invention, the heating is done using a solar concentrator.|The intended application of this scrubber was not found in any previous publications or applications with the technical features suggested in this invention. Similar systems differ either in the design of the invention or both the design and the application of the invention.|The present invention is differentiated from the prior art by its automation, scalable design, intake filters consisting of dust and microbial filtration, and its application for use as a CCU unit or CCS unit or an indoor air filtration unit, or a combination of the above.|OBJECT OF THE INVENTION:|The principal object of the present invention is to overcome all the mentioned and existing drawbacks of the prior arts by providing a fully automated CO2 scrubber for concentrating carbon dioxide for further use in a Microalgae based BEECS, CCS, or CCU system.|The secondary object of the present invention is to provide a CO2 scrubber system that can also function as an indoor or outdoor air filter which can also be integrated with an HVAC system where the system can remove dust and pathogens providing a single-source solution for quenching and removal of CO2, dust, and pathogens including the SARS-CoV-2 virus.|Another object of the present invention is to provide a fully automated CO2 scrubber that consists of single or multiple replaceable cartridges installed in equal number of adsorption chambers where the CO2 is absorbed using an amine resin which is released in a heat cycle by raising the temperatures using a heater along with HEPA and UV sterilizer integrated into the system. In another aspect of the present invention, the heating is done using a solar concentrator.|Yet another object of the present invention is to provide an automated carbon dioxide scrubber that uses a UV sterilizer and amine resins to concentrate and release CO2 that can be used for various applications including but not limited to HVAC or outdoor air purification, purification of emissions from diesel or natural gas gensets, Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Utilization (CCU) & Carbon Capture and Sequestration (CCS).|SUMMARY OF THE INVENTION:|This summary is provided to introduce a selection of concepts in a simplified form that is further disclosed in the detailed description of the invention. This summary is not intended to identify key or essential inventive concepts of the claimed subject matter.|The present invention is all about a scalable CO2 and pathogen quenching scrubber which is a scalable fully automated CO2 scrubber for concentrating carbon dioxide that can be released and used for various applications including but not limited to CCS, CCU, or air purification.|The main aspect of the present invention is to provide scalable CO2 and pathogen quenching scrubber having an external casing and single or multiple replaceable cartridges, said each replaceable cartridge consists of an adsorption chamber; said adsorption chamber holds the resins being capable to absorb the CO2 during an adsorption cycle while the space between said adsorption chamber component and said external casing component holds the CO2 being insulated with a thermal insulation to prevent the escape of heat during the heating cycle; a solenoid valves being capable to control the suction and discharge of air from the adsorption chambers; an HEPA filter being capable to remove the dust and other particulate matter; an UV sterilizer being capable to remove pathogens including the virus; an air intake blower provides the suction that pulls the air filtered through said HEPA filter, said UV sterilizer into the device for the adsorption and removal of CO2; a heater being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater covered with a heater casing; a solar concentrator with an automated opening and closing mechanism being capable to increase the temperature in the adsorption casing and to release the CO2 being absorbed and a probe and a sensors for temperature and CO2.|Another aspect of the present invention is to provide a scalable CO2 and pathogen quenching scrubber that contains an intake filtration system that consists of a dust filter along with a UV filtration unit for the removal of pathogens. Hence, the scrubbers work as an integrated functional unit both for the adsorption and use of CO2 in a Microalgae-based BECCS or CCU or CCS units as well as a system to potentially maintain indoor air quality by removing pathogens and dust.|Another aspect of the present invention is to provide a scrubber further includes single or multiple adsorption chambers with heaters installed in them with probes and sensors for temperature and CO2. In another embodiment, solar concentrators are used in each adsorption chamber instead of heaters.|Another aspect of the present invention is to provide chambers containing amine resins that absorbs the CO2 from the air after which the chamber is heated using the heater or solar concentrator. The higher temperature (70 °C) causes the resins to release the absorbed CO2. The suction and discharge of air and CO2 are controlled by solenoid valves and the system is fully automated by PLC.|In another aspect of the present invention, the device can be used as a CCU system. An example is where the discharged CO2 is supplied to a Microalgae based Carbon Capture and Storage system/facility and hence becomes an avenue for the utilization of the carbon.|In another aspect of the invention, the system provides a crucial avenue for decarbonization at a localized level as a CCS system where concentrated CO2 is converted into another compound and stored for further utilization in the industry. An example for this application would be to store the CO2 as Calcium Carbonate or other carbonate salts which can be used for various applications.|BRIEF|DESCRIPTION OF THE DRAWINGS:|The foregoing summary, as well as the following detailed description of the invention, is better understood when read in conjunction with the appended drawings. To illustrate the invention, exemplary constructions of the invention are shown in the drawings.|The function and application of the present invention will be apparent from the figures with a detailed description given below:|Fig 1 illustrates the schematic flow diagram of the CO2 scrubber which provides a brief overview of the function of the scrubber along with its various components. The embodiment in the figure contains two cartridges and absorption chambers.|DETAILED|DESCRIPTION OF THE INVENTION:|Detailed embodiments of the present invention are disclosed herein, however, it is to be understood that the disclosed embodiments are merely exemplary of the invention, which may be embodied in various forms. Therefore, specific functional and structural details disclosed herein are not to be interpreted as limiting, but merely as a basis for the claims and as a representative basis for teaching one skilled in the art to variously employ the present invention in virtually any appropriately detailed structure.|Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the invention belongs.|The present invention overcomes the aforesaid drawbacks of the conventional system. The objects, features, and advantages of the present invention will now be described in greater detail. Also, the following description includes various specific details and is to be regarded as merely exemplary. Accordingly, those of ordinary skill in the art will recognize that: without departing from the scope and spirit of the present disclosure and its various embodiments there may be any number of changes and modifications described herein.|It must also be noted that as used herein and in the appended claims, the singular forms "a", "an," and "the" include plural references unless the context dictates otherwise. Although any systems and methods similar or equivalent to those described herein can be used in the practice or testing of embodiments of the present invention, the preferred, systems are now described.|The present invention is related to the field of mechanical engineer, chemical engineering, electrical engineering and environmental engineering and more specifically to carbon capture and cycling technology and other applications which include the improvement of indoor and outdoor ambient air quality. The advent of climate change is a major challenge for humanity with major repercussions for human health and society apart from effects on biodiversity and climatic conditions. A majority of the anthropogenic-induced climate change is caused by increased emission of GHGs which is expected to rise with an expanding human population and improvement in the standard of living in developing countries. This projected rise in GHGs emissions if continued at the current rate of emission would require carbon sequestration technologies that will reduce the GHGs in the atmosphere as humanity moves to renewable sources of energy.|This invention relates to a scalable, automated CO2 scrubber that can continuously concentrate and supply CO2 due to the presence of two adsorption chambers (7) that work sequentially such that one chamber is always releasing CO2. It provides a mechanism to concentrate CO2 to be used either for a Microalgae based Bioenergy Carbon Capture & Utilisation (CCU) system or other types of Carbon Capture & Storage (CCS) systems. In addition, it could also be used to improve air quality due to the presence of an advanced filtration facility including HEPA (3), and UV sterilizer (4).|As per detailed embodiment of the present invention, a scalable CO2 and pathogen quenching scrubber having an external casing (1) and single or multiple replaceable cartridges (6), said each replaceable cartridge consists of an adsorption chamber; said adsorption chamber holds the resins (13) being capable to absorb the CO2 during an adsorption cycle while the space between said adsorption chamber (7) component and said external casing (1) component holds the CO2 being insulated with a thermal insulation (12) to prevent the escape of heat during the heating cycle; solenoid valves (5) being capable to control the suction and discharge of air from the adsorption chambers; an HEPA filter (3) being capable to remove the dust and other particulate matter; an UV sterilizer (4) being capable to remove pathogens including the virus; an air intake blower (2) provides the suction that pulls the air filtered through said HEPA filter, said UV sterilizer into the device for the adsorption and removal of CO2; a heater (9) being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater (9) covered with a heater casing (8); or a solar concentrator (9) with an automated top cover (8) being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed and which has a top cover that opens and closes automatically, and a probe and a sensors for temperature and CO2.|As per the detailed embodiment of the present invention, the system provides for a scalable design that can be used for multiple applications including the Microalgae based Bioenergy with Carbon Capture and Storage (BECCS) and a CCS unit to store CO2 as a usable compound or the CCS unit as an indoor air quality filter.|As per the detailed embodiment of the present invention, the scrubber has an air suction with a HEPA filter (3) where air passes through the filter and a UV sterilizer (4) where pathogens and microorganisms including SARS-CoV-2 are filtered hence allowing the scrubber to function as a filtration system. The scrubber in itself can be used in an HVAC system to reduce the concentration of CO2 in recirculated air that might otherwise lead to elevated levels of CO2 over time. The disinfection component would also provide the added benefits of filtering various pathogens including the virus SARS-CoV-2. The system would hence function as a single source filtration and scrubbing system that can remove CO2, dust, and pathogens.|As per the detailed embodiment of the present invention, the solenoid valves (5) are capable to control the suction and discharge of air from the adsorption chambers. The solenoid valves (5) and heater (9) or solar concentrator top cover (8) are controlled by PLC/SCADA or a microcontroller-based control panel (10) and hence making the system entirely automated. The solenoid valves close for a period of set time cycles when the heater (9) turns on or when the top cover (8) of the solar concentrator (9) opens or closes, and increases the temperature in the adsorption chamber (7) to a set temperature that causes the resins (13) to lose the adsorbed CO2. The CO2 discharge solenoid valve (5) opens for a period of set time cycles where the CO2 flows out for the intended use of the CO2.|As per the detailed embodiment of the present invention, the air taken into the scrubber is filtered which in this embodiment is done using HEPA/UV sterilizer (3 and 4) or their combinations. The air is sucked into the adsorption chamber (7) using an intake blower (2) which absorbs the filtered air into the chamber during the adsorption cycle.|As per the detailed embodiment of the present invention, the air is passed through the adsorption chamber (7) for a period of set time cycles during which the input solenoid valve (5) and the air discharge solenoid valve (5) are open during the time of which the resins (13) absorb the CO2 and the decarbonated air continuously flows out.|As per the detailed embodiment of the present invention, the components are held inside an external casing (1) and an insulator (12) between the external casing and the adsorption chamber (7) where the CO2-rich air is held after the resins (13) release the absorbed CO2 upon heating where the insulator (12) prevents the heating from escaping by conduction.|As per another embodiment of the present invention, the CO2 released by the resins (13) upon heating is passed through a CCU unit that may be a biological unit such as a Microalgae based photobioreactor (PBR).|As per another embodiment of the present invention, a part of the produced CO2 may be diverted to a CCS system and stored for further utilization in the industry. An example for this application would be to store the CO2 as Calcium Carbonate or other carbonate salts which can be used for various applications.|As per another embodiment of the present invention, two adsorption chambers (7) function in opposite cycles between the adsorption and heating cycles with the cycles being controlled automatically by a PLC/SCADA control panel (10).|Referring to Fig. 1 shows a schematic flow diagram of the CO2 scrubber. Said scrubber has an external casing (1) and an air intake blower (2) on the external side. The air intake blower (2) sucks the air filtered through a HEPA filter (3) and UV sterilizer (4). The HEPA filter (3) removes the dust and other particulate matter. The UV sterilizer (4) removes the pathogens including the small molecular virus such as SARS-CoV-2. The suction and discharge of the air from the adsorption chambers (7) are controlled by the solenoid valves (5) in this embodiment, two absorption chambers are portrayed. The temperature sensor and CO2 sensor are provided to monitor the temperature and CO2 respectively. The scalable and automated CO2 scrubber absorbs and concentrates the CO2 inside a chamber using amine resins (13).|Without further description, it is believed that one ordinary skill in the art can, using the preceding description and the illustrative examples, make and utilize the present invention and practice the claimed methods. It should be understood that the foregoing discussion and examples merely present a detailed description of certain preferred embodiments. It will be apparent to those of ordinary skill in the art that various modifications and equivalents can be made without departing from the spirit and scope of the invention.|REFERENCE NUMERALS:|1. External casing|2. Air intake blower|3. HEPA filter|4. UV sterilizer|5. Solenoid valves|6. Replaceable cartridge|7. Adsorption chamber|8. Heater casing/Top cover of solar concentrator|9. Heater/Solar concentrator|10. Control panel|11. Probes & sensors|12. Thermal insulation|13. Amine resins | (IN202221038543)|FIELD OF THE INVENTION:|The present invention relates to a scalable CO2 and pathogen quenching scrubber. More particularly it relates to an automated carbon dioxide scrubber that uses a UV sterilizer and amine resins to concentrate and release CO2 that can be used for various applications including but not limited to HVAC or outdoor air purification, purification of emissions from diesel or natural gas gensets, Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Utilization (CCU) & Carbon Capture and Sequestration (CCS).|BACKGROUND OF THE INVENTION:|There is a scientific consensus that climate change caused due to anthropogenic activities can lead to net negative outcomes leading to [a] Erratic climate events, [b] adverse impacts on aquatic and on-land biodiversity, and human health, [c] Rise in sea levels, and [d] Food and water security issues.|Under the United Nations Framework Convention on Climate Change (UNFCC), the Paris agreement's long-term temperature goal is to restrict the rise in the global average temperature to under 2 °C above the pre-industrial levels with the ideal goal being the temperatures to a more stringent average temperature rise of under 1.5 °C. These pledges were further renewed in the COP 26 conference (26th UN Climate Change Conference of the Parties (COP26) in Glasgow on 31 October - 13 November 2021) where the countries provided renewed pledges and many committed to net-zero emissions by 2050.|The countries of the Gulf Cooperation Council (GCC) emit the highest quantities of Greenhouse Gases (GHGs) per capita globally and are among the largest exporters of crude petroleum and natural gas worldwide. Hence, the countries of the GCC are actively exploring avenues to reduce their carbon footprint with the UAE committing to achieve net-zero by 2050 and Saudi Arabia committing to net-zero by 2060.|The reduction in GHGs can be achieved by either:|1) Cutting emissions can be achieved through various approaches including [a] shifting to renewables sources of energy like wind, solar, biomass, hydel, and geothermal energy [b] increasing the proportion of vehicles using alternative modes of energy such as Battery Electric Vehicles (BEVs) and Fuel Cell Electric Vehicles (FCEVs), [c] reducing emissions from food production, specifically cattle production, and [d] lifestyle changes.|2) Absorbing GHGs using net-negative carbon technologies that reduce the existing concentration of GHGs in the atmosphere using Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Storage (CCS), or Carbon Capture and Utilization (CCUs) technologies.|There is significant diversity in the types of carbon capture technologies with multiple publications and patents being filed for various methods of carbon capture. US patent US 2021/0252451A1 assigned to Catherine Thibaud and Zhipeng Zhong consists of a Carbon dioxide scrubber with a moving bed structure that has a continuously movable carbon dioxide sorbent bed through the adsorption chamber and the regeneration chamber.|Meanwhile, the patent US 2013/0178145A1 assigned to Carlos Gomez et al, uses a carbon dioxide scrubber in a sea van container consisting of a gas-selective membrane with a CO2/O2 selectivity ratio greater than 1:1 forming a curtain that effectively makes the inner plenum chamber airtight.|Similarly, the patent US 9,149,761B2 assigned to Northrop and Anderson removed acidic gases such as sulfurous components and carbon dioxide from a gas processing facility which in various embodiments can be used to capture CO2 from the tail gas generated from a Claus sulfur recovery unit.|Patent applications with a similar application include US 2014/0342443A1 assigned to Dale Bohn which uses scrubbers for feeding algae photobioreactors but uses a circulated reagent solution instead of solid amines for the adsorption of carbon dioxide.|Another patent application by Eisenberger, US2020/047116A1 uses a sorbent under ambient conditions, to obtain relatively pure CO2 using process heat, preferably in the form of steam, at a temperature range of lower than 130 °C, to capture the relatively pure CO2 and to regenerate the sorbent for repeated use.|None of the prior arts disclosed a CO2 scrubber that includes a scalable fully automated system that contains a dust-filtration unit, UV filter, and a filter containing an efficient sterilizing agent like in its intake system which allows it to operate in both indoor and outdoor conditions. It consists of a single or multiple replaceable cartridges installed in equal number of adsorption chambers where the CO2 is absorbed using amine resins which are released in a heat cycle by raising the temperatures using a heater and the CO2 is directed to either an indoor or outdoor CCU unit or a combination of the above. In another embodiment of the present invention, the heating is done using a solar concentrator.|The intended application of this scrubber was not found in any previous publications or applications with the technical features suggested in this invention. Similar systems differ either in the design of the invention or both the design and the application of the invention.|The present invention is differentiated from the prior art by its automation, scalable design, intake filters consisting of dust and microbial filtration, and its application for use as a CCU unit or CCS unit or an indoor air filtration unit, or a combination of the above.|OBJECT OF THE INVENTION:|The principal object of the present invention is to overcome all the mentioned and existing drawbacks of the prior arts by providing a fully automated CO2 scrubber for concentrating carbon dioxide for further use in a Microalgae based BEECS, CCS, or CCU system.|The secondary object of the present invention is to provide a CO2 scrubber system that can also function as an indoor or outdoor air filter which can also be integrated with an HVAC system where the system can remove dust and pathogens providing a single-source solution for quenching and removal of CO2, dust, and pathogens including the SARS-CoV-2 virus.|Another object of the present invention is to provide a fully automated CO2 scrubber that consists of single or multiple replaceable cartridges installed in equal number of adsorption chambers where the CO2 is absorbed using an amine resin which is released in a heat cycle by raising the temperatures using a heater along with HEPA and UV sterilizer integrated into the system. In another aspect of the present invention, the heating is done using a solar concentrator.|Yet another object of the present invention is to provide an automated carbon dioxide scrubber that uses a UV sterilizer and amine resins to concentrate and release CO2 that can be used for various applications including but not limited to HVAC or outdoor air purification, purification of emissions from diesel or natural gas gensets, Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Utilization (CCU) & Carbon Capture and Sequestration (CCS).|SUMMARY OF THE INVENTION:|This summary is provided to introduce a selection of concepts in a simplified form that is further disclosed in the detailed description of the invention. This summary is not intended to identify key or essential inventive concepts of the claimed subject matter.|The present invention is all about a scalable CO2 and pathogen quenching scrubber which is a scalable fully automated CO2 scrubber for concentrating carbon dioxide that can be released and used for various applications including but not limited to CCS, CCU, or air purification.|The main aspect of the present invention is to provide scalable CO2 and pathogen quenching scrubber having an external casing and single or multiple replaceable cartridges, said each replaceable cartridge consists of an adsorption chamber; said adsorption chamber holds the resins being capable to absorb the CO2 during an adsorption cycle while the space between said adsorption chamber component and said external casing component holds the CO2 being insulated with a thermal insulation to prevent the escape of heat during the heating cycle; a solenoid valves being capable to control the suction and discharge of air from the adsorption chambers; an HEPA filter being capable to remove the dust and other particulate matter; an UV sterilizer being capable to remove pathogens including the virus; an air intake blower provides the suction that pulls the air filtered through said HEPA filter, said UV sterilizer into the device for the adsorption and removal of CO2; a heater being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater covered with a heater casing; a solar concentrator with an automated opening and closing mechanism being capable to increase the temperature in the adsorption casing and to release the CO2 being absorbed and a probe and a sensors for temperature and CO2.|Another aspect of the present invention is to provide a scalable CO2 and pathogen quenching scrubber that contains an intake filtration system that consists of a dust filter along with a UV filtration unit for the removal of pathogens. Hence, the scrubbers work as an integrated functional unit both for the adsorption and use of CO2 in a Microalgae-based BECCS or CCU or CCS units as well as a system to potentially maintain indoor air quality by removing pathogens and dust.|Another aspect of the present invention is to provide a scrubber further includes single or multiple adsorption chambers with heaters installed in them with probes and sensors for temperature and CO2. In another embodiment, solar concentrators are used in each adsorption chamber instead of heaters.|Another aspect of the present invention is to provide chambers containing amine resins that absorbs the CO2 from the air after which the chamber is heated using the heater or solar concentrator. The higher temperature (70 °C) causes the resins to release the absorbed CO2. The suction and discharge of air and CO2 are controlled by solenoid valves and the system is fully automated by PLC.|In another aspect of the present invention, the device can be used as a CCU system. An example is where the discharged CO2 is supplied to a Microalgae based Carbon Capture and Storage system/facility and hence becomes an avenue for the utilization of the carbon.|In another aspect of the invention, the system provides a crucial avenue for decarbonization at a localized level as a CCS system where concentrated CO2 is converted into another compound and stored for further utilization in the industry. An example for this application would be to store the CO2 as Calcium Carbonate or other carbonate salts which can be used for various applications.|BRIEF|DESCRIPTION OF THE DRAWINGS:|The foregoing summary, as well as the following detailed description of the invention, is better understood when read in conjunction with the appended drawings. To illustrate the invention, exemplary constructions of the invention are shown in the drawings.|The function and application of the present invention will be apparent from the figures with a detailed description given below:|Fig 1 illustrates the schematic flow diagram of the CO2 scrubber which provides a brief overview of the function of the scrubber along with its various components. The embodiment in the figure contains two cartridges and absorption chambers.|DETAILED|DESCRIPTION OF THE INVENTION:|Detailed embodiments of the present invention are disclosed herein, however, it is to be understood that the disclosed embodiments are merely exemplary of the invention, which may be embodied in various forms. Therefore, specific functional and structural details disclosed herein are not to be interpreted as limiting, but merely as a basis for the claims and as a representative basis for teaching one skilled in the art to variously employ the present invention in virtually any appropriately detailed structure.|Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the invention belongs.|The present invention overcomes the aforesaid drawbacks of the conventional system. The objects, features, and advantages of the present invention will now be described in greater detail. Also, the following description includes various specific details and is to be regarded as merely exemplary. Accordingly, those of ordinary skill in the art will recognize that: without departing from the scope and spirit of the present disclosure and its various embodiments there may be any number of changes and modifications described herein.|It must also be noted that as used herein and in the appended claims, the singular forms "a", "an," and "the" include plural references unless the context dictates otherwise. Although any systems and methods similar or equivalent to those described herein can be used in the practice or testing of embodiments of the present invention, the preferred, systems are now described.|The present invention is related to the field of mechanical engineer, chemical engineering, electrical engineering and environmental engineering and more specifically to carbon capture and cycling technology and other applications which include the improvement of indoor and outdoor ambient air quality. The advent of climate change is a major challenge for humanity with major repercussions for human health and society apart from effects on biodiversity and climatic conditions. A majority of the anthropogenic-induced climate change is caused by increased emission of GHGs which is expected to rise with an expanding human population and improvement in the standard of living in developing countries. This projected rise in GHGs emissions if continued at the current rate of emission would require carbon sequestration technologies that will reduce the GHGs in the atmosphere as humanity moves to renewable sources of energy.|This invention relates to a scalable, automated CO2 scrubber that can continuously concentrate and supply CO2 due to the presence of two adsorption chambers (7) that work sequentially such that one chamber is always releasing CO2. It provides a mechanism to concentrate CO2 to be used either for a Microalgae based Bioenergy Carbon Capture & Utilisation (CCU) system or other types of Carbon Capture & Storage (CCS) systems. In addition, it could also be used to improve air quality due to the presence of an advanced filtration facility including HEPA (3), and UV sterilizer (4).|As per detailed embodiment of the present invention, a scalable CO2 and pathogen quenching scrubber having an external casing (1) and single or multiple replaceable cartridges (6), said each replaceable cartridge consists of an adsorption chamber; said adsorption chamber holds the resins (13) being capable to absorb the CO2 during an adsorption cycle while the space between said adsorption chamber (7) component and said external casing (1) component holds the CO2 being insulated with a thermal insulation (12) to prevent the escape of heat during the heating cycle; solenoid valves (5) being capable to control the suction and discharge of air from the adsorption chambers; an HEPA filter (3) being capable to remove the dust and other particulate matter; an UV sterilizer (4) being capable to remove pathogens including the virus; an air intake blower (2) provides the suction that pulls the air filtered through said HEPA filter, said UV sterilizer into the device for the adsorption and removal of CO2; a heater (9) being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater (9) covered with a heater casing (8); or a solar concentrator (9) with an automated top cover (8) being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed and which has a top cover that opens and closes automatically, and a probe and a sensors for temperature and CO2.|As per the detailed embodiment of the present invention, the system provides for a scalable design that can be used for multiple applications including the Microalgae based Bioenergy with Carbon Capture and Storage (BECCS) and a CCS unit to store CO2 as a usable compound or the CCS unit as an indoor air quality filter.|As per the detailed embodiment of the present invention, the scrubber has an air suction with a HEPA filter (3) where air passes through the filter and a UV sterilizer (4) where pathogens and microorganisms including SARS-CoV-2 are filtered hence allowing the scrubber to function as a filtration system. The scrubber in itself can be used in an HVAC system to reduce the concentration of CO2 in recirculated air that might otherwise lead to elevated levels of CO2 over time. The disinfection component would also provide the added benefits of filtering various pathogens including the virus SARS-CoV-2. The system would hence function as a single source filtration and scrubbing system that can remove CO2, dust, and pathogens.|As per the detailed embodiment of the present invention, the solenoid valves (5) are capable to control the suction and discharge of air from the adsorption chambers. The solenoid valves (5) and heater (9) or solar concentrator top cover (8) are controlled by PLC/SCADA or a microcontroller-based control panel (10) and hence making the system entirely automated. The solenoid valves close for a period of set time cycles when the heater (9) turns on or when the top cover (8) of the solar concentrator (9) opens or closes, and increases the temperature in the adsorption chamber (7) to a set temperature that causes the resins (13) to lose the adsorbed CO2. The CO2 discharge solenoid valve (5) opens for a period of set time cycles where the CO2 flows out for the intended use of the CO2.|As per the detailed embodiment of the present invention, the air taken into the scrubber is filtered which in this embodiment is done using HEPA/UV sterilizer (3 and 4) or their combinations. The air is sucked into the adsorption chamber (7) using an intake blower (2) which absorbs the filtered air into the chamber during the adsorption cycle.|As per the detailed embodiment of the present invention, the air is passed through the adsorption chamber (7) for a period of set time cycles during which the input solenoid valve (5) and the air discharge solenoid valve (5) are open during the time of which the resins (13) absorb the CO2 and the decarbonated air continuously flows out.|As per the detailed embodiment of the present invention, the components are held inside an external casing (1) and an insulator (12) between the external casing and the adsorption chamber (7) where the CO2-rich air is held after the resins (13) release the absorbed CO2 upon heating where the insulator (12) prevents the heating from escaping by conduction.|As per another embodiment of the present invention, the CO2 released by the resins (13) upon heating is passed through a CCU unit that may be a biological unit such as a Microalgae based photobioreactor (PBR).|As per another embodiment of the present invention, a part of the produced CO2 may be diverted to a CCS system and stored for further utilization in the industry. An example for this application would be to store the CO2 as Calcium Carbonate or other carbonate salts which can be used for various applications.|As per another embodiment of the present invention, two adsorption chambers (7) function in opposite cycles between the adsorption and heating cycles with the cycles being controlled automatically by a PLC/SCADA control panel (10).|Referring to Fig. 1 shows a schematic flow diagram of the CO2 scrubber. Said scrubber has an external casing (1) and an air intake blower (2) on the external side. The air intake blower (2) sucks the air filtered through a HEPA filter (3) and UV sterilizer (4). The HEPA filter (3) removes the dust and other particulate matter. The UV sterilizer (4) removes the pathogens including the small molecular virus such as SARS-CoV-2. The suction and discharge of the air from the adsorption chambers (7) are controlled by the solenoid valves (5) in this embodiment, two absorption chambers are portrayed. The temperature sensor and CO2 sensor are provided to monitor the temperature and CO2 respectively. The scalable and automated CO2 scrubber absorbs and concentrates the CO2 inside a chamber using amine resins (13).|Without further description, it is believed that one ordinary skill in the art can, using the preceding description and the illustrative examples, make and utilize the present invention and practice the claimed methods. It should be understood that the foregoing discussion and examples merely present a detailed description of certain preferred embodiments. It will be apparent to those of ordinary skill in the art that various modifications and equivalents can be made without departing from the spirit and scope of the invention.|REFERENCE NUMERALS:|1. External casing|2. Air intake blower|3. HEPA filter|4. UV sterilizer|5. Solenoid valves|6. Replaceable cartridge|7. Adsorption chamber|8. Heater casing/Top cover of solar concentrator|9. Heater/Solar concentrator|10. Control panel|11. Probes & sensors|12. Thermal insulation|13. Amine resins | Family Number|(109076587)|109076587|Object of Invention|(IN202221038543 A)| (...) and release CO2 that can be used for various applications including but not limited to HVAC or outdoor air purification, purification of emissions from diesel or natural gas gensets, Microalgae based Bioenergy with Carbon Capture and Storage (BECCS), Carbon Capture and Utilization (CCU) & Carbon Capture and Sequestration (CCS).| | Environmental technology | B01D-053/04|B01D-053/047|B01D-053/14|B01D-053/62|B01D-053/78 | B01D-053/04|B01D-053/047|B01D-053/14|B01D-053/62|B01D-053/78 | PENDING | (IN202221038543)|PENDING | ALIVE | (IN202221038543)|ALIVE | (IN202221038543)|LEGAL DETAILS FOR IN202221038543|Actual or expected expiration date=2042-07-05|Legal state=ALIVE|Status=PENDING|Event publication date=2022-07-05|Event code=IN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=IN IN202221038543|Application date=2022-07-05|Standardized application number=2022IN-21038543|Event publication date=2024-01-12|Event code=IN/A|Event indicator=Pos|Event group=Examination events|Application laid open|Publication country=IN|Publication number=IN202221038543|Publication stage code=A|Publication date=2024-01-12|Standardized publication number=IN202221038543 | (IN202221038543)|IN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=/WizbbSQlgv/Yige86NT+N7ymDK1mJ05a/WZFbsCsqxjSQxYBqJq7iT+uVYGOkHbowE3xwgjWi0myP6vhetDsA==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=IN0000000001426153&ekey=2146&xpn=IN202221038543&kind=A | https://iprsearch.ipindia.gov.in/PublicSearch/PublicationSearch/ApplicationStatus | https://permalink.orbit.com/RenderStaticFirstPage?XPN=07BsjPSpofZn6ObuRfK%252FKsExnvIz5kLrfqHome9U%252B8A%3D%26n%3D1&id=0&base=FAMPAT | IN | (IN202221038543)|NAME=Kumar Ramachandran Rajeev|NAME=Riain Liam Sean O|NAME=Parambil Shanavas Kallam|NAME=Jacob Dangly Ann|NAME=Chinnasamy Senthil | (IN202221038543)|1 | 1 | 1 | (IN202221038543)|Number of Claims: NCL=10| | (IN202221038543)|ENGLISH (ENG) | (IN202221038543)|Patent | Titre: (IN202221038543)|A scalable co2 and pathogen quenching scrubber Résumé: (IN202221038543)|The present invention absorbs and concentrates CO2 inside an adsorption chamber (7) using amine resins (13). The resin (13) after saturation with CO2 can be utilized for carbon sequestration applications. Alternatively, the concentrated CO2 captured by the resin (13) is released and utilized for a host of other carbon cycling applications. The ambient air or exhaust gas supplied by the air intake blower is filtered by a HEPA filter (3), and a UV sterilizer (4). This filtrated air is sucked into an adsorption chamber (7) that contains the resins (13) and a heater (9) or a solar concentrator (9). During the adsorption cycle, air flows continuously through the adsorption chamber for a prescribed period after which the solenoid valves (5) shut down the suction and discharge and turn on the heating cycle or open the top cover to activate the solar concentrator where the temperature inside the adsorption chamber (7) is increased to a set temperature that forces the resins (13) to release the absorbed CO2. Autre: (IN202221038543)|1. A scalable CO2 and pathogen quenching scrubber, comprising: a) an external casing (1); b) a plurality of replaceable cartridges (6); said each replaceable cartridge comprising an adsorption chamber (7) holding amine resins (13) capable of absorbing CO2 during an adsorption cycle; c) a plurality of solenoid valves (5) located in front of said adsorption chamber (7) being capable of controlling the suction and discharge of air from said adsorption chambers (7); d) an HEPA filter (3) being capable of removing dust and other particulate matter; e) a UV sterilizer (4) being capable of removing pathogens, including viruses; f) an air intake blower (2) being capable of providing suction to pull the air filtered through said HEPA filter (3) and UV sterilizer (4) into said device for the adsorption and removal of CO2; g) a heating element (9) being capable of increasing the temperature in the adsorption casing and releasing the absorbed CO2; and h) a probe and sensors (11) for temperature and CO2.|2. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said adsorption chamber and said external case being insulated with a thermal insulation (12) to prevent the escape of heat during the heating cycle.|3. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said heating element (9) can be a heater being capable to increases the temperature in the adsorption casing and to release the CO2 being absorbed, said heater (9) covered with a heater casing (8); or a solar concentrator (9) with an automated opening and closing mechanism (8) being capable to increase the temperature in the adsorption casing and to release the CO2 being absorbed and a probe and a sensors for temperature and CO2.|4. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said amine resins (13) are capable of absorbing the CO2 during an adsorption cycle while the space between said adsorption chamber (7) component and said external casing (1) component holds the CO2.|5. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein components are held inside an external casing (1) and an insulator (12) between the external casing and the adsorption chamber (7) where the CO2 rich air is held after the resins (13) release the adsorbed CO2 upon heating where the insulator (12) prevents the heating from escaping by conduction.|6. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said solenoid valves (5) and said heater (9) or solar concentrator top cover (8) are controlled by PLC/SCADA-based control panel (10).|7. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said solenoid valves (5) remain closed for a period of set time cycles when the heating element (9) turns on and increases the temperature in the adsorption chamber (7) to a set temperature that causes the amine resins (13) to lose the adsorbed CO2.|8. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said CO2 discharge solenoid valve (5) opens for a period of set time cycles where the CO2 flows out for the intended use of the CO2.|9. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said air is passed through the adsorption chamber (7) for a period of set time cycles throughout which the input solenoid valve (5) and the air discharge solenoid valve (5) are open; during that time of which the resins (13) being capable of absorbing the CO2 and the decarbonated air continuously flows out.|10. The scalable CO2 and pathogen quenching scrubber as claimed in claim 1, wherein said adsorption chambers (7) function in opposite cycles between the adsorption and heating cycles with the cycles being controlled automatically by a PLC/SCADA control system. | 16 | Abstract | gpt-4o-mini | no | The article focuses on a CO2 scrubber that captures CO2 from ambient air or exhaust gases, which does not involve biomass or energy production, thus not fitting the BECCS criteria. | ||||||||||||||||||||||||||||||||
| 17 | US63/479,875P|US63/535,990P|US18/412,241|WOUS2024/011483|US19/022,306 | US19/022,306|WOUS2024/011483|JP2025540937|EP24707362|US18/412,241 | JP2026505712|EP4649228|US12359613|US20250154895|US20240240619|WO2024/152006 | 110578690 | US20250154895 A1 2025-05-15 [US20250154895]|WO2024/152006 A1 2024-07-18 [WO2024152006]|JP2026505712 A 2026-02-18 [JP2026505712]|EP4649228 A1 2025-11-19 [EP4649228]|US12359613 B2 2025-07-15 [US12359613]|US20240240619 A1 2024-07-18 [US20240240619] | 2023-01-13|2023-08-31|2024-01-12|2025-01-15 | 2025-01-15|2024-01-12|2024-01-12|2024-01-12|2024-01-12 | 2026-02-18|2025-11-19|2025-07-15|2025-05-15|2024-07-18|2024-07-18 | |(US12359613)|2025-07-15||| | (EP4649228)|2044-01-12|(US12359613)|2044-01-12|(US20250154895)|2044-01-12|(WO2024/152006)|2026-07-13|(JP2026505712)|2044-01-12 | (EP4649228)|Integrated carbon sequestration and power generation system and methods of use | (EP4649228)|Systems and methods for providing an integrated carbon sequestration and power generation system are disclosed. The integrated carbon sequestration and power generation system may include: a thermodynamic cycle configured to receive biomass and to output heat and power; and a direct air capture system configured to receive at least some of the heat and the power output from the thermodynamic cycle. Other aspects are described and claimed. | ARBOR ENERGY & RESOURCES | (EP4649228)|Arbor Energy And Resources Corporation ([US])|(US12359613)|Arbor Energy and Resources Corporation ([US])|(US20240240619)|Arbor Energy and Resources Corporation ([US])|(US20250154895)|Arbor Energy and Resources Corporation ([US])|(WO2024/152006)|ARBOR ENERGY AND RESOURCES CORPORATION ([US])| | GARCIA-CLARK ANDRES JOSE|HARTWIG BRADLEY|SMITH AARON EZEKIEL | (EP4649228)|GARCIA-CLARK, Andres Jose|HARTWIG, Bradley|SMITH, Aaron Ezekiel | (EP4649228)|Mathys & Squire;The Shard ([GB])|Reg. Nb: 100061165|(US12359613)|Bookoff McAndrews, PLLC|(WO2024/152006)|LAZAR, Norbert et al. ([US])|(JP2026505712)|ONDA MAKOTO|Reg. Nb: 100105957|Hiroyuki Onda|Reg. Nb: 100068755|HONDA, Jun|Reg. Nb: 100142907 | (US12359613)|Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation plants to compete in power grid markets.|Additionally, the carbon drawdown effects of afforestration/reforestration are difficult to measure and verify, while the permanence is also highly uncertain.|Afforestation/reforestation is low cost, difficult to model, and has a low time horizon for trapping the CO_2 (e.g., potentially as soon as 50-100 years). Direct air carbon capture and sequestration is higher cost (e.g., as driven by energy demands), easy to model and quantify, and has a high time horizon for captured carbon (e.g., 1000+ years depending on capture medium).| | (US12359613)|1. An integrated carbon sequestration and power generation system, comprising: a thermodynamic cycle configured to receive biomass and to generate heat and power; and a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration; wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system; wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid; wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; wherein the determining whether the predetermined condition is satisfied comprises determining whether a threshold number or type of power sources associated with the power grid are available.|10. An integrated carbon sequestration and power generation system, comprising: a gasifier configured to receive a biomass and configured to produce a syngas; a combustor configured to produce a combustion stream from the cleaned syngas, oxygen, and a recirculation carbon dioxide (CO2) stream; at least one turbine, wherein the at least one turbine is operatively coupled to a direct air capture (DAC) carbon sequestration system and to a high pressure recirculation pump to optionally or simultaneously provide power produced by the at least one turbine to the DAC carbon sequestration system in a first operating mode or to a power grid separate from the integrated carbon sequestration and power generation system in a second operating mode; wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and; wherein the determining whether the predetermined condition is satisfied comprises determining whether a threshold number or type of power sources associated with the power grid are available.|15. An integrated carbon sequestration and power generation system, comprising: a thermodynamic cycle configured to receive biomass and to generate heat and power; and a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration; wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system; wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid; wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and wherein the determining whether the predetermined condition is satisfied comprises assessing a weather forecast.|18. An integrated carbon sequestration and power generation system, comprising: a thermodynamic cycle configured to receive biomass and to generate heat and power; and a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration; wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system; wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid; wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and wherein the determining whether the predetermined condition is satisfied comprises determining whether a power grid operator has access to renewable energy from a renewable energy provider.| | (US12359613)|Among other things, for example, subject matter may be embodied as methods, devices, components, or systems.|Embodiments of the present disclosure provide for the integration of a CO_2 power cycle with a Direct Air Capture (DAC) system, which may use CO_2 and/or sCO_2 thermodynamic power cycle waste heat as a sorbent regenerator for the CO_2 sequestration cycle, as described in reference to FIG. 1.|In the context of this application, biomass 105 refers to any carbon neutral or carbon negative fuel.| | (US12359613)|CARBON SEQUESTRATION(100,81)|POWER GENERATION(100,65)|INTEGRATED CARBON SEQUESTRATION(100,48)|THERMODYNAMIC CYCLE(53,23)|SORBENT REGENERATOR(40,1)|CLEANED SYNGA(34,4)|BIOMASS(30,50)|BRAYTON CYCLE RECUPERATION(28,2)|SEQUESTRATION CYCLE(26,1)|UPCOMING WEATHER(26,1)|CARBON DRAWDOWN(25,1)|AFFORESTATION REFORESTATION(23,1)|RECIRCULATION CARBON DIOXIDE(23,1)|RENEWABLE ENERGY PROVIDER(22,6)|TIMED THRESHOLD(21,1)|TURBINE(20,24)|SEQUESTRATION(20,5)|WEATHER FORECAST(20,3)|GASIFIER(19,50)|SYNGA(18,54)|COMBUSTION STREAM(17,6)|BIOENERGY(17,1)|POWER GRID(16,77)|SCALABILITY(16,1)|TORREFACTION REACTOR(15,10)|TORREFIED BIOMASS CONVEYANCE(15,3)|INTEGRATION(15,1)|RETROFIT(15,1)|RECUPERATOR HEAT EXCHANGER(14,28)|COMBUSTOR(14,23)|SYNGA BOOST COMPRESSOR(14,4)|CAPTURING CARBON(14,3)|PERMANENCE(14,2)|BECCS(14,1)|LIQUID SORBENT(14,1)|SCRUBBER(13,19)|ADSORBENT REGENERATION(13,8)|PRESSURE RECIRCULATION(13,5)|THRESHOLD NUMBER(13,3)|SOLID SORBENT(13,1)|RECIRCULATION PUMP(12,12)|BICRS(12,3)|ADSORB 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SORBENT(6,2)|SYNGA CONDENSATE(6,2)|AFFORESTATION REFOREST RATION(6,1)|HEATING OUTPUT(6,1)|PLANT MATTER(6,1)|PREPROCESSED BIOMASS(6,1)|PRESSURIZED BIOMASS CONSTITUENT(6,1)|TIME HORIZON(6,1)|BRAYTON THERMODYNAMIC POWER CYCLE(5,7)|OXYGEN STREAM(5,7)|CARBON NEUTRAL(5,6)|INCREASED LOAD(5,5)|AQUEOUS ORGANIC AMINE(5,4)|FEED HOPPER(5,4)|POWER SOURCE(5,4)|CONDENSABLE SPECIES(5,2)|COOL SORBENT(5,2)|FAILED ASSET(5,2)|AMINE FUNCTIONALIZED CELLULOSE(5,1)|MACHINERY FLOWPATH(5,1)|SATURATED SORBENT BANK(5,1)|DIRECT AIR CAPTURE(4,86)|TEMPERATURE HEAT EXCHANGER(4,33)|CARBON SEQUESTRATION MODE(4,5)|SYNGA HEAT(4,5)|WEATHER FORECAST DATA(4,5)|AMENABLE TEMPERATURE(4,4)|COMBUSTION INJECTION PRESSURE(4,4)|LEVERAGE(4,4)|WASTE HEAT(4,4)|DEDICATED OXYGEN DELIVERY SERVICE(4,3)|TURBOALTERNATOR(4,3)|CANDLE FILTER(4,2)|FAN MODULE(4,2)|GASIFIER REACTOR VESSEL(4,2)|HISTORICAL SUNLIGHT DATA(4,2)|OXYGEN DEPRIVED ENVIRONMENT(4,2)|POWER OUTPUT(4,2)|SAWDUST WASTE(4,2)|UPCOMING DAY(4,2)|VAPOR DOME(4,2)|WOODY PLANT(4,2)|YARD WASTE(4,2)|AMINE FUNCTIONALIZED SILICA(4,1)|AMMONIA SORBENT(4,1)|ANTICIPATED CONCLUSION(4,1)|AVERAGE DAILY SUNRISE INDICATION(4,1)|BACKPRESSURE REGULATOR(4,1)|BIOMASS SOLID CONVEYANCE(4,1)|CARBONACEOUS BIOMASS(4,1)|CLEAN SYNGA(4,1)|COLLECTIVE REVENUE(4,1)|CONCERT CONCLUSION(4,1)|CONTACTOR BANK(4,1)|CONTACTOR FAN(4,1)|CONTRACTOR SPOT PRICE(4,1)|EXPLICITLY STATED MEANING(4,1)|GASIFIER JACKET LINER(4,1)|GASIFIER LINER(4,1)|GASIFIER PRESSURIZED VOLUME(4,1)|GRID STABILIZATION(4,1)|HYBRID BICRS(4,1)|NONEXCLUSIVE INCLUSION(4,1)|OCEAN CAPTURE(4,1)|OPERATIONAL ISSUE KNOWLEDGE(4,1)|OUTLET HP TURBINE(4,1)|OUTLET RECUPERATOR(4,1)|PARTICULATE CONTAMINANT(4,1)|PIPING MANIFOLD(4,1)|PLURAL REFERENT(4,1)|PNEUMATIC MODALITY(4,1)|RECUPERATOR EXHAUST(4,1)|REVENUE PROJECTION(4,1)|ROTARY DRUM REACTOR(4,1)|SORBENT PACK(4,1)|STARTUP PENALTY(4,1)|SYNGA COOLER(4,1)|TORREFACTION GAS COMBUSTION(4,1)|UNPROCESSED BIOMASS(4,1)|CARBON MONOXIDE(3,9)|POWER CYCLE(3,8)|CARBON NEGATIVE FUEL(3,6)|SOLID PRODUCT(3,6)|HIGHWAY(3,4)|CONSTITUENT COMPONENT(3,3)|DISCHARGE CYCLE(3,3)|ENTRAIN FLOW GASIFIER(3,3)|FIXED BED GASIFIER(3,3)|LEAKAGE PASSAGE(3,3)|PRESSURE COMBUSTION STREAM(3,3)|PRESSURIZING(3,3)|STREAM PUMP(3,3)|TIME THRESHOLD(3,3)|UNDERBRUSH(3,3)|WATER BOILING(3,3)|BIOMASS REACTION(3,2)|COAL POWER PLANT(3,2)|MONOETHANOLAMINE(3,2)|SOLAR ENERGY PROVIDER ABILITY(3,2)|BIOSYNGA REACTION(3,1)|CEMENT CONCRETE(3,1)|COAL GRINDING(3,1)|COMPRESSION TRAIN(3,1)|CONTACTOR FALL(3,1)|COOLED SYNGA(3,1)|CYCLE TURBOMACHINERY(3,1)|ENGINE TURBINE(3,1)|FLUID PREHEATING(3,1)|GRID INTEGRATION(3,1)|HYDROPHOBIC BEHAVIOR(3,1)|MICROWAVE REACTOR(3,1)|OUTLET COMBUSTOR(3,1)|PERMANENTLY STORED UNDERGROUND(3,1)|PLANT BIOMASS(3,1)|POWERING CARBON SEQUESTRATION(3,1)|RECIRCULATION STREAM(3,1)|REVERSE SCENARIO(3,1)|STEAM EXTRACTION(3,1)|SUDDEN LOAD DEMAND(3,1)|SUPERCRITICAL CYCLE(3,1)|SUPPLEMENTAL COOLING(3,1)|SYNGA COMPRESSION(3,1)|SYNGA REACTOR WALL(3,1)|WASTE BIOMASS(3,1)|WASTED FUEL(3,1)|AIR SEPARATION(2,14)|WORKING FLUID(2,14)|AIR CARBON SEQUESTRATION(2,4)|ELECTRICAL POWER(2,4)|TORREFACTION(2,4)|UNDERGROUND STORAGE LOCATION(2,4)|COMBUSTION(2,3)|CONDITION REMAINS(2,3)|FLY ASH(2,3)|GASEOUS HYDROGEN(2,3)|HALIDE(2,3)|ORGANIC WASTE(2,3)|RECYCLED BACK(2,3)|TREE(2,3)|ANIMAL MANURE(2,2)|CONTAMINATION(2,2)|DESIGNATION(2,2)|ELECTRICITY COST PERIOD(2,2)|FERTILIZER(2,2)|FESTIVAL(2,2)|FIREWOOD(2,2)|NATURAL DISASTER(2,2)|ONLINE SOURCE(2,2)|OPERATIONAL CONFIGURATION(2,2)|PETROLEUM PRODUCT(2,2)|POWER PROVIDER(2,2)|PRESSURE LADDER(2,2)|RELEVANT GEOGRAPHIC REGION(2,2)|SOCIETY(2,2)|SOYBEAN(2,2)|WOOL PRODUCTION(2,2)|400 COMBUSTOR OXYGEN(2,1)|65 SUCTION COMPRESSOR(2,1)|ADSORBENT MATERIAL REGENERATION(2,1)|AIR SCRUBBING(2,1)|AIR SEPARATOR(2,1)|ALGAE PRODUCTION(2,1)|ATMOSPHERIC CARBON(2,1)|BIODOME(2,1)|BOTTOMING TEMPERATURE(2,1)|BREAKING DOWN BIOMASS(2,1)|CARBON SEQUESTRATION TAX BREAK(2,1)|CLIMATE CRISIS(2,1)|CLOUDY CONDITION(2,1)|COLD STRETCH(2,1)|COMBINED RECIRCULATION(2,1)|COMBUSTION OUTLET(2,1)|COMBUSTOR TEMPERATURE(2,1)|COMPONENT ORIGIN(2,1)|COMPUTER CONTROLLER(2,1)|CONDUCTING HEAT(2,1)|CONSTANT HEAT REJECTION(2,1)|CONVEYING SOLID(2,1)|COOL CYCLE(2,1)|DENSITY DERIVATIVE(2,1)|DESTABILIZATION(2,1)|DIRTY CHEMICAL(2,1)|DISPATCH(2,1)|DOWNSTREAM COMPONENT(2,1)|EARTHQUAKE(2,1)|ENERGY INTENSIVE(2,1)|ENGINE COMPONENT(2,1)|EQUIPMENT CAPITAL INVESTMENT(2,1)|EXCESS POLLUTION(2,1)|GASIFICATION OXIDATION REACTION(2,1)|GROUND BIOMASS(2,1)|INDICATION DETECTION(2,1)|INITIATION DETECTION(2,1)|LOAD DESTINATION(2,1)|LOCK HOPPER(2,1)|MAJOR CONCERT(2,1)|REVENUE PRODUCTION(2,1)|STORMY CONDITION(2,1)|STREAM CONCENTRATION(2,1)|SWITCHING RELAY(2,1)||(US20240240619)|CARBON SEQUESTRATION(100,64)|POWER GENERATION(100,52)|INTEGRATED CARBON SEQUESTRATION(100,37)|SORBENT REGENERATOR(58,1)|CLEANED SYNGA(49,4)|TRAPPING CO2(43,1)|BRAYTON CYCLE RECUPERATION(41,2)|CARBON DRAWDOWN(37,1)|BIOMASS(36,48)|THERMODYNAMIC CYCLE(35,13)|AFFORESTATION REFORESTATION(34,1)|CO2 SEQUESTRATION CYCLE(34,1)|RECIRCULATION CARBON DIOXIDE(33,1)|TURBINE(29,23)|SEQUESTRATION(29,5)|GASIFIER(28,50)|SYNGA(26,52)|BIOENERGY(25,1)|COMBUSTION STREAM(24,6)|SCALABILITY(24,1)|TORREFACTION REACTOR(22,10)|TORREFIED BIOMASS CONVEYANCE(22,3)|RETROFIT(22,1)|RECUPERATOR HEAT EXCHANGER(21,28)|COMBUSTOR(21,23)|PERMANENCE(21,2)|CO2(20,58)|SYNGA BOOST COMPRESSOR(20,4)|CAPTURING CARBON(20,3)|BECCS(20,1)|LIQUID SORBENT(20,1)|SCRUBBER(19,19)|ADSORBENT REGENERATION(19,8)|CO2 POWER CYCLE INTEGRATION(19,1)|SOLID SORBENT(19,1)|PRESSURE RECIRCULATION(18,5)|BICRS(18,3)|ADSORB CARBON DIOXIDE(18,1)|POWER GRID MARKET(18,1)|TURBINE DISCHARGE STREAM(16,10)|MIND(16,1)|RECIRCULATION PUMP(15,9)|PROJECTED VALUE(15,7)|POWER GRID(14,69)|OXYGEN BOOST COMPRESSOR(14,4)|STEAM INJECTION(13,9)|RANKINE CYCLE(13,6)|CONTRACTING ENTITY(13,3)|OXYFUEL COMBUSTOR(13,3)|CO2 POWER CYCLE(13,1)|CO2 COMPRESSOR(12,6)|FREED CO2(12,6)|GASIFICATION REACTION(12,6)|RECIRCULATING PUMP DISCHARGE STREAM(12,4)|CO2 RECIRCULATED STREAM(12,3)|CRYOGENIC OXYGEN SEPARATOR(12,3)|GASIFIER INJECTOR(12,3)|RECIRCULATING CO2 STREAM PUMP(12,3)|PRESSURIZED GROUND TORREFIED BIOMASS(12,2)|ENERGY DEMAND(12,1)|THERMODYNAMIC POWER CYCLE(11,14)|CARBON CAPTURE(11,6)|MOLTEN SLAG(11,5)|MUNICIPAL WASTE(11,4)|OXYFUEL COMBUSTION(11,3)|CARBON DIOXIDE(11,2)|RANKINE BACKPRESSURE(11,2)|COOLING BANK(10,5)|CO2 REGENERATION(10,4)|SYNGA STREAM(10,4)|AIR CARBON CAPTURE(10,3)|ASH PARTICULATE(10,3)|BIO SYNGA(10,3)|EXTRACT WORKOUT(10,3)|FIRED TURBINE(10,3)|FLUIDIZED BED GASIFIER(10,3)|OXY COMBUSTOR(10,3)|TURBINE EXHAUST STREAM(10,3)|BIOMASS POWER PLANT(10,1)|PRESSURE TURBINE(9,9)|TIMER(9,5)|H2O RECIRCULATION(9,2)|NONLIQUID ASH FORMATION(9,2)|PRESSURED SYNGA(9,2)|REGENERATE SORBENT(9,2)|SYNGA CONDENSATE(9,2)|AFFORESTATION REFOREST RATION(9,1)|CO2 SORBENT PACK(9,1)|HEATING OUTPUT(9,1)|PLANT MATTER(9,1)|PREPROCESSED BIOMASS(9,1)|PRESSURIZED BIOMASS CONSTITUENT(9,1)|TIME HORIZON(9,1)|INCREASED LOAD(8,5)|AQUEOUS ORGANIC AMINE(8,4)|COOLED CO2 STREAM(8,4)|FEED HOPPER(8,4)|CO2 CAPTURE(8,3)|CONDENSABLE SPECIES(8,2)|COOL SORBENT(8,2)|FAILED ASSET(8,2)|AMINE FUNCTIONALIZED CELLULOSE(8,1)|FOLDING SECRET DETECTING INITIATION(8,1)|MACHINERY FLOWPATH(8,1)|SATURATED SORBENT BANK(8,1)|TEMPERATURE HEAT EXCHANGER(7,33)|BRAYTON THERMODYNAMIC POWER CYCLE(7,7)|OXYGEN STREAM(7,7)|CARBON NEUTRAL(7,6)|GASIFIER REACTOR VESSEL(7,2)|HISTORICAL SUNLIGHT DATA(7,2)|OXYGEN DEPRIVED ENVIRONMENT(7,2)|SAWDUST WASTE(7,2)|UPCOMING DAY(7,2)|WOODY PLANT(7,2)|YARD WASTE(7,2)|AMINE FUNCTIONALIZED SILICA(7,1)|AMMONIA SORBENT(7,1)|AVERAGE DAILY SUNRISE INDICATION(7,1)|BACKPRESSURE REGULATOR(7,1)|CARBONACEOUS BIOMASS(7,1)|CO2 VAPOR DOME(7,1)|COLLECTIVE REVENUE(7,1)|CONCERT CONCLUSION(7,1)|GASIFIER LINER(7,1)|NONEXCLUSIVE INCLUSION(7,1)|PNEUMATIC MODALITY(7,1)|RECUPERATOR EXHAUST(7,1)|STARTUP PENALTY(7,1)|THRESHOLD NUMBER(7,1)|UNPROCESSED BIOMASS(7,1)|CARBON SEQUESTRATION MODE(6,5)|SYNGA HEAT(6,5)|WEATHER FORECAST DATA(6,5)|AMENABLE TEMPERATURE(6,4)|ATMOSPHERIC CO2(6,4)|COMBUSTION INJECTION PRESSURE(6,4)|LEVERAGE(6,4)|WASTE HEAT(6,4)|COMPRESSED CO2(6,3)|DEDICATED OXYGEN DELIVERY SERVICE(6,3)|TEMPERATURE CO2 SORBENT(6,3)|TURBOALTERNATOR(6,3)|CANDLE FILTER(6,2)|FAN MODULE(6,2)|POWER OUTPUT(6,2)|ANTICIPATED CONCLUSION(6,1)|BIOMASS SOLID CONVEYANCE(6,1)|CLEAN SYNGA(6,1)|CONTACTOR BANK(6,1)|CONTACTOR FAN(6,1)|CONTRACTOR SPOT PRICE(6,1)|EXPLICITLY STATED MEANING(6,1)|GASIFIER JACKET LINER(6,1)|GASIFIER PRESSURIZED VOLUME(6,1)|GRID STABILIZATION(6,1)|HYBRID BICRS(6,1)|OCEAN CAPTURE(6,1)|OPERATIONAL ISSUE KNOWLEDGE(6,1)|PAIRING FOLDING(6,1)|PARTICULATE CONTAMINANT(6,1)|PIPING MANIFOLD(6,1)|PLURAL REFERENT(6,1)|REVENUE PROJECTION(6,1)|ROTARY DRUM REACTOR(6,1)|SEQUESTERING CO2(6,1)|SYNGA COOLER(6,1)|TORREFACTION GAS COMBUSTION(6,1)|CARBON MONOXIDE(5,9)|CARBON NEGATIVE FUEL(5,6)|CONSTITUENT COMPONENT(5,3)|DISCHARGE CYCLE(5,3)|ENTRAIN FLOW GASIFIER(5,3)|FIXED BED GASIFIER(5,3)|LEAKAGE PASSAGE(5,3)|PRESSURE COMBUSTION STREAM(5,3)|PRESSURIZING(5,3)|UNDERBRUSH(5,3)|WATER BOILING(5,3)|BIOMASS REACTION(5,2)|FOLDING STEAM(5,2)|SOLAR ENERGY PROVIDER ABILITY(5,2)|SUPERCRITICAL CO2 CYCLE(5,2)|BIOSYNGA REACTION(5,1)|CAPTURED CO2 LOSS(5,1)|CEMENT CONCRETE(5,1)|CO2 CONCENTRATED STREAM(5,1)|CO2 EXHAUST(5,1)|COAL GRINDING(5,1)|COMPRESSION TRAIN(5,1)|CONTACTOR FALL(5,1)|COOLED SYNGA(5,1)|CYCLE TURBOMACHINERY(5,1)|ENGINE TURBINE(5,1)|FLUID PREHEATING(5,1)|FOLDING DESIGNATION(5,1)|GRID INTEGRATION(5,1)|HYDROPHOBIC BEHAVIOR(5,1)|MICROWAVE REACTOR(5,1)|PERMANENTLY STORED UNDERGROUND(5,1)|PLANT BIOMASS(5,1)|POWERING CARBON SEQUESTRATION(5,1)|RECIRCULATION STREAM(5,1)|REVERSE SCENARIO(5,1)|SELLING CO2(5,1)|STEAM EXTRACTION(5,1)|SUDDEN LOAD DEMAND(5,1)|SUPERCRITICAL CYCLE(5,1)|SUPPLEMENTAL COOLING(5,1)|SYNGA COMPRESSION(5,1)|SYNGA REACTOR WALL(5,1)|WASTE BIOMASS(5,1)|WASTED FUEL(5,1)|SOLID PRODUCT(4,6)|AIR CARBON SEQUESTRATION(4,4)|CO2 CRITICAL PRESSURE(4,4)|HIGHWAY(4,4)|TORREFACTION(4,4)|UNDERGROUND STORAGE LOCATION(4,4)|ANIMAL MANURE(4,2)|COAL POWER PLANT(4,2)|CONTAMINATION(4,2)|ELECTRICITY COST PERIOD(4,2)|FERTILIZER(4,2)|FESTIVAL(4,2)|FIREWOOD(4,2)|MONOETHANOLAMINE(4,2)|ONLINE SOURCE(4,2)|OPERATIONAL CONFIGURATION(4,2)|PETROLEUM PRODUCT(4,2)|POWER PROVIDER(4,2)|PRESSURE LADDER(4,2)|RELEVANT GEOGRAPHIC REGION(4,2)|SOYBEAN(4,2)|WOOL PRODUCTION(4,2)|AIR SCRUBBED CO2 FALL(4,1)|AIR SCRUBBING(4,1)|ALGAE PRODUCTION(4,1)|CAPTURED ATMOSPHERIC CO2(4,1)|CARBON SEQUESTRATION TAX BREAK(4,1)|CLOUDY CONDITION(4,1)|CO2 COLLECTION(4,1)|CO2 EMISSION(4,1)|CO2 LOOP(4,1)|COLD STRETCH(4,1)|COMBINED RECIRCULATION(4,1)|COMBUSTION OUTLET(4,1)|DENSITY DERIVATIVE(4,1)|DIRTY CHEMICAL(4,1)|ENERGY INTENSIVE(4,1)|EQUIPMENT CAPITAL INVESTMENT(4,1)|EXCESS POLLUTION(4,1)|EXTRACTED CO2(4,1)|FOLDING REGARD(4,1)|GASIFICATION OXIDATION REACTION(4,1)|GROUND BIOMASS(4,1)|HARD SECRET(4,1)|HOT CO2(4,1)|INDICATION DETECTION(4,1)|INITIATION DETECTION(4,1)|LOAD DESTINATION(4,1)|LOCK HOPPER(4,1)|MAJOR CONCERT(4,1)|PRESSURE CO2 RECIRCULATION(4,1)|RENEWABLE ENERGY PROVIDER ABILITY(4,1)|REVENUE PRODUCTION(4,1)|STORMY CONDITION(4,1)|STREAM CONCENTRATION(4,1)|SUBCRITICAL CO2 WORKING FLUID(4,1)|SWITCHING RELAY(4,1)|DIRECT AIR CAPTURE(3,82)|AIR SEPARATION(3,14)|ELECTRICAL POWER(3,4)|CO2 FLOW(3,3)|CO2 PRESSURE(3,3)|COMBUSTION(3,3)|CONDITION REMAINS(3,3)|FLY ASH(3,3)|GASEOUS HYDROGEN(3,3)|HALIDE(3,3)|ORGANIC WASTE(3,3)|RECYCLED BACK(3,3)|TREE(3,3)|NATURAL DISASTER(3,2)|SOCIETY(3,2)|ADSORBENT MATERIAL REGENERATION(3,1)|AIR SEPARATOR(3,1)|ATMOSPHERIC CARBON(3,1)|BIODOME(3,1)|BOTTOMING TEMPERATURE(3,1)|BREAKING DOWN BIOMASS(3,1)|CLIMATE CRISIS(3,1)|CO2 DENSITY GRADIENT(3,1)|CO2 TEMPERATURE(3,1)|COMPONENT ORIGIN(3,1)|COMPUTER CONTROLLER(3,1)|CONDUCTING HEAT(3,1)|CONSTANT HEAT REJECTION(3,1)|CONVEYING SOLID(3,1)|COOL CYCLE(3,1)||(US20250154895)|CARBON SEQUESTRATION(100,64)|POWER GENERATION(100,53)|INTEGRATED CARBON SEQUESTRATION(100,37)|SORBENT REGENERATOR(58,1)|CLEANED SYNGA(49,4)|BRAYTON CYCLE RECUPERATION(41,2)|SEQUESTRATION CYCLE(38,1)|CARBON DRAWDOWN(37,1)|BIOMASS(36,48)|THERMODYNAMIC CYCLE(35,13)|AFFORESTATION REFORESTATION(34,1)|RECIRCULATION CARBON DIOXIDE(33,1)|TURBINE(29,24)|SEQUESTRATION(29,5)|GASIFIER(28,50)|SYNGA(26,54)|BIOENERGY(25,1)|COMBUSTION STREAM(24,6)|SCALABILITY(24,1)|TORREFACTION REACTOR(22,10)|TORREFIED BIOMASS CONVEYANCE(22,3)|INTEGRATION(22,1)|RETROFIT(22,1)|RECUPERATOR HEAT EXCHANGER(21,28)|COMBUSTOR(21,23)|PERMANENCE(21,2)|SYNGA BOOST COMPRESSOR(20,4)|CAPTURING CARBON(20,3)|BECCS(20,1)|LIQUID SORBENT(20,1)|SCRUBBER(19,19)|ADSORBENT REGENERATION(19,8)|SOLID SORBENT(19,1)|PRESSURE RECIRCULATION(18,5)|BICRS(18,3)|ADSORB CARBON DIOXIDE(18,1)|POWER GRID MARKET(18,1)|RECIRCULATION PUMP(17,12)|TURBINE DISCHARGE STREAM(16,10)|MIND(16,1)|PROJECTED VALUE(15,7)|POWER GRID(14,69)|OXYGEN BOOST COMPRESSOR(14,4)|STEAM INJECTION(13,9)|RECIRCULATED STREAM(13,7)|RANKINE CYCLE(13,6)|CONTRACTING ENTITY(13,3)|OXYFUEL COMBUSTOR(13,3)|GASIFICATION REACTION(12,6)|RECIRCULATING PUMP DISCHARGE STREAM(12,4)|SCO(12,4)|CRYOGENIC OXYGEN SEPARATOR(12,3)|GASIFIER INJECTOR(12,3)|PRESSURIZED GROUND TORREFIED BIOMASS(12,2)|ENERGY DEMAND(12,1)|THERMODYNAMIC POWER CYCLE(11,14)|CARBON CAPTURE(11,6)|MOLTEN SLAG(11,5)|MUNICIPAL WASTE(11,4)|OXYFUEL COMBUSTION(11,3)|CARBON DIOXIDE(11,2)|RANKINE BACKPRESSURE(11,2)|COOLING BANK(10,5)|SYNGA STREAM(10,4)|AIR CARBON CAPTURE(10,3)|ASH PARTICULATE(10,3)|BIO SYNGA(10,3)|EXTRACT WORKOUT(10,3)|FIRED TURBINE(10,3)|FLUIDIZED BED GASIFIER(10,3)|OXY COMBUSTOR(10,3)|TURBINE EXHAUST STREAM(10,3)|BIOMASS POWER PLANT(10,1)|PRESSURE TURBINE(9,9)|TIMER(9,5)|NONLIQUID ASH FORMATION(9,2)|PRESSURED SYNGA(9,2)|REGENERATE SORBENT(9,2)|SYNGA CONDENSATE(9,2)|AFFORESTATION REFOREST RATION(9,1)|HEATING OUTPUT(9,1)|PLANT MATTER(9,1)|PREPROCESSED BIOMASS(9,1)|PRESSURIZED BIOMASS CONSTITUENT(9,1)|TIME HORIZON(9,1)|INCREASED LOAD(8,5)|AQUEOUS ORGANIC AMINE(8,4)|FEED HOPPER(8,4)|CONDENSABLE SPECIES(8,2)|COOL SORBENT(8,2)|FAILED ASSET(8,2)|AMINE FUNCTIONALIZED CELLULOSE(8,1)|MACHINERY FLOWPATH(8,1)|SATURATED SORBENT BANK(8,1)|TEMPERATURE HEAT EXCHANGER(7,33)|BRAYTON THERMODYNAMIC POWER CYCLE(7,7)|OXYGEN STREAM(7,7)|CARBON NEUTRAL(7,6)|GASIFIER REACTOR VESSEL(7,2)|HISTORICAL SUNLIGHT DATA(7,2)|OXYGEN DEPRIVED ENVIRONMENT(7,2)|SAWDUST WASTE(7,2)|UPCOMING DAY(7,2)|VAPOR DOME(7,2)|WOODY PLANT(7,2)|YARD WASTE(7,2)|AMINE FUNCTIONALIZED SILICA(7,1)|AMMONIA SORBENT(7,1)|AVERAGE DAILY SUNRISE INDICATION(7,1)|BACKPRESSURE REGULATOR(7,1)|CARBONACEOUS BIOMASS(7,1)|COLLECTIVE REVENUE(7,1)|CONCERT CONCLUSION(7,1)|GASIFIER LINER(7,1)|NONEXCLUSIVE INCLUSION(7,1)|OUTLET HP TURBINE(7,1)|PNEUMATIC MODALITY(7,1)|RECUPERATOR EXHAUST(7,1)|STARTUP PENALTY(7,1)|THRESHOLD NUMBER(7,1)|UNPROCESSED BIOMASS(7,1)|CARBON SEQUESTRATION MODE(6,5)|SYNGA HEAT(6,5)|WEATHER FORECAST DATA(6,5)|AMENABLE TEMPERATURE(6,4)|COMBUSTION INJECTION PRESSURE(6,4)|LEVERAGE(6,4)|WASTE HEAT(6,4)|DEDICATED OXYGEN DELIVERY SERVICE(6,3)|TURBOALTERNATOR(6,3)|CANDLE FILTER(6,2)|FAN MODULE(6,2)|POWER OUTPUT(6,2)|ANTICIPATED CONCLUSION(6,1)|BIOMASS SOLID CONVEYANCE(6,1)|CLEAN SYNGA(6,1)|CONTACTOR BANK(6,1)|CONTACTOR FAN(6,1)|CONTRACTOR SPOT PRICE(6,1)|EXPLICITLY STATED MEANING(6,1)|GASIFIER JACKET LINER(6,1)|GASIFIER PRESSURIZED VOLUME(6,1)|GRID STABILIZATION(6,1)|HYBRID BICRS(6,1)|OCEAN CAPTURE(6,1)|OPERATIONAL ISSUE KNOWLEDGE(6,1)|OUTLET RECUPERATOR(6,1)|PARTICULATE CONTAMINANT(6,1)|PIPING MANIFOLD(6,1)|PLURAL REFERENT(6,1)|REVENUE PROJECTION(6,1)|ROTARY DRUM REACTOR(6,1)|SORBENT PACK(6,1)|SYNGA COOLER(6,1)|TORREFACTION GAS COMBUSTION(6,1)|CARBON MONOXIDE(5,9)|CARBON NEGATIVE FUEL(5,6)|CONSTITUENT COMPONENT(5,3)|DISCHARGE CYCLE(5,3)|ENTRAIN FLOW GASIFIER(5,3)|FIXED BED GASIFIER(5,3)|LEAKAGE PASSAGE(5,3)|PRESSURE COMBUSTION STREAM(5,3)|PRESSURIZING(5,3)|STREAM PUMP(5,3)|UNDERBRUSH(5,3)|WATER BOILING(5,3)|BIOMASS REACTION(5,2)|SOLAR ENERGY PROVIDER ABILITY(5,2)|BIOSYNGA REACTION(5,1)|CEMENT CONCRETE(5,1)|COAL GRINDING(5,1)|COMPRESSION TRAIN(5,1)|CONTACTOR FALL(5,1)|COOLED SYNGA(5,1)|CYCLE TURBOMACHINERY(5,1)|ENGINE TURBINE(5,1)|FLUID PREHEATING(5,1)|GRID INTEGRATION(5,1)|HYDROPHOBIC BEHAVIOR(5,1)|MICROWAVE REACTOR(5,1)|OUTLET COMBUSTOR(5,1)|PERMANENTLY STORED UNDERGROUND(5,1)|PLANT BIOMASS(5,1)|POWERING CARBON SEQUESTRATION(5,1)|RECIRCULATION STREAM(5,1)|REVERSE SCENARIO(5,1)|STEAM EXTRACTION(5,1)|SUDDEN LOAD DEMAND(5,1)|SUPERCRITICAL CYCLE(5,1)|SUPPLEMENTAL COOLING(5,1)|SYNGA COMPRESSION(5,1)|SYNGA REACTOR WALL(5,1)|WASTE BIOMASS(5,1)|WASTED FUEL(5,1)|POWER CYCLE(4,8)|SOLID PRODUCT(4,6)|AIR CARBON SEQUESTRATION(4,4)|HIGHWAY(4,4)|TORREFACTION(4,4)|UNDERGROUND STORAGE LOCATION(4,4)|ANIMAL MANURE(4,2)|COAL POWER PLANT(4,2)|CONTAMINATION(4,2)|DESIGNATION(4,2)|ELECTRICITY COST PERIOD(4,2)|FERTILIZER(4,2)|FESTIVAL(4,2)|FIREWOOD(4,2)|MONOETHANOLAMINE(4,2)|ONLINE SOURCE(4,2)|OPERATIONAL CONFIGURATION(4,2)|PETROLEUM PRODUCT(4,2)|POWER PROVIDER(4,2)|PRESSURE LADDER(4,2)|RELEVANT GEOGRAPHIC REGION(4,2)|SOYBEAN(4,2)|WOOL PRODUCTION(4,2)|AIR SCRUBBING(4,1)|ALGAE PRODUCTION(4,1)|CARBON SEQUESTRATION TAX BREAK(4,1)|CLOUDY CONDITION(4,1)|COLD STRETCH(4,1)|COMBINED RECIRCULATION(4,1)|COMBUSTION OUTLET(4,1)|DENSITY DERIVATIVE(4,1)|DIRTY CHEMICAL(4,1)|ENERGY INTENSIVE(4,1)|EQUIPMENT CAPITAL INVESTMENT(4,1)|EXCESS POLLUTION(4,1)|GASIFICATION OXIDATION REACTION(4,1)|GROUND BIOMASS(4,1)|INDICATION DETECTION(4,1)|INITIATION DETECTION(4,1)|LOAD DESTINATION(4,1)|LOCK HOPPER(4,1)|MAJOR CONCERT(4,1)|RENEWABLE ENERGY PROVIDER ABILITY(4,1)|REVENUE PRODUCTION(4,1)|STORMY CONDITION(4,1)|STREAM CONCENTRATION(4,1)|SWITCHING RELAY(4,1)|DIRECT AIR CAPTURE(3,82)|AIR SEPARATION(3,14)|WORKING FLUID(3,14)|ELECTRICAL POWER(3,4)|COMBUSTION(3,3)|CONDITION REMAINS(3,3)|FLY ASH(3,3)|GASEOUS HYDROGEN(3,3)|HALIDE(3,3)|ORGANIC WASTE(3,3)|RECYCLED BACK(3,3)|TREE(3,3)|NATURAL DISASTER(3,2)|SOCIETY(3,2)|400 COMBUSTOR OXYGEN(3,1)|65 SUCTION COMPRESSOR(3,1)|ADSORBENT MATERIAL REGENERATION(3,1)|AIR SEPARATOR(3,1)|ATMOSPHERIC CARBON(3,1)|BIODOME(3,1)|BOTTOMING TEMPERATURE(3,1)|BREAKING DOWN BIOMASS(3,1)|CLIMATE CRISIS(3,1)|COMBUSTOR TEMPERATURE(3,1)|COMPONENT ORIGIN(3,1)|COMPUTER CONTROLLER(3,1)|CONDUCTING HEAT(3,1)|CONSTANT HEAT REJECTION(3,1)|CONVEYING SOLID(3,1)|COOL CYCLE(3,1)|DESTABILIZATION(3,1)|DISPATCH(3,1)|DOWNSTREAM COMPONENT(3,1)|EARTHQUAKE(3,1)|ENGINE COMPONENT(3,1)|EXTRACTING HEAT(3,1)||(WO2024/152006)|CARBON SEQUESTRATION(100,101)|POWER GENERATION(100,82)|INTEGRATED CARBON SEQUESTRATION(100,67)|SORBENT REGENERATOR(68,1)|CLEANED SYNGA(52,6)|TRAPPING CO2(50,1)|BRAYTON CYCLE RECUPERATION(48,2)|THERMODYNAMIC CYCLE(44,15)|BIOMASS(43,51)|CARBON DRAWDOWN(43,1)|AFFORESTATION REFORESTATION(40,1)|CO2 SEQUESTRATION CYCLE(40,1)|TURBINE(34,25)|SEQUESTRATION(34,5)|GASIFIER(32,50)|SYNGA(30,48)|BIOENERGY(29,1)|COMBUSTION STREAM(28,9)|SCALABILITY(28,1)|TORREFACTION REACTOR(26,10)|RECIRCULATION CARBON DIOXIDE(26,3)|TORREFIED BIOMASS CONVEYANCE(26,3)|PERMANENCE(25,2)|RETROFIT(25,1)|CO2(23,54)|RECUPERATOR HEAT EXCHANGER(23,25)|COMBUSTOR(23,19)|CAPTURING CARBON(23,3)|BECCS(23,1)|LIQUID SORBENT(23,1)|SCRUBBER(22,18)|TURBINE DISCHARGE STREAM(22,12)|PRESSURE RECIRCULATION(22,5)|CO2 POWER CYCLE INTEGRATION(22,1)|SOLID SORBENT(22,1)|BICRS(21,3)|ADSORB CARBON DIOXIDE(21,1)|POWER GRID MARKET(21,1)|ADSORBENT REGENERATION(20,6)|SYNGA BOOST COMPRESSOR(20,3)|PROJECTED VALUE(19,13)|MIND(18,1)|RANKINE CYCLE(17,3)|POWER GRID(16,79)|STEAM INJECTION(15,8)|RECIRCULATION PUMP(15,7)|OXYFUEL COMBUSTOR(15,3)|PRESSURIZED GROUND TORREFIED BIOMASS(15,2)|CO2 POWER CYCLE(15,1)|GASIFICATION REACTION(14,6)|CRYOGENIC OXYGEN SEPARATOR(14,3)|GASIFIER INJECTOR(14,3)|OXYGEN BOOST COMPRESSOR(14,3)|ENERGY DEMAND(14,1)|THERMODYNAMIC POWER CYCLE(13,14)|CARBON CAPTURE(13,6)|COOLING BANK(13,6)|CO2 COMPRESSOR(13,5)|MOLTEN SLAG(13,5)|MUNICIPAL WASTE(13,4)|OXYFUEL COMBUSTION(13,3)|CONTRACTING ENTITY(13,2)|AIR CARBON CAPTURE(12,3)|FLUIDIZED BED GASIFIER(12,3)|RECIRCULATING PUMP DISCHARGE STREAM(12,3)|TURBINE EXHAUST STREAM(12,3)|TIMER(11,5)|FREED CO2(11,4)|CO2 RECIRCULATED STREAM(11,2)|H2O RECIRCULATION(11,2)|NONLIQUID ASH FORMATION(11,2)|RECIRCULATING CO2 STREAM PUMP(11,2)|REGENERATE SORBENT(11,2)|SYNGA CONDENSATE(11,2)|BIOMASS POWER PLANT(11,1)|CO2 REGENERATION(10,3)|ASH PARTICULATE(10,2)|BIO SYNGA(10,2)|CONDENSABLE SPECIES(10,2)|COOL SORBENT(10,2)|EXTRACT WORKOUT(10,2)|FAILED ASSET(10,2)|FIRED TURBINE(10,2)|OXY COMBUSTOR(10,2)|AFFORESTATION REFOREST RATION(10,1)|CO2 SORBENT PACK(10,1)|HEATING OUTPUT(10,1)|PLANT MATTER(10,1)|PREPROCESSED BIOMASS(10,1)|PRESSURIZED BIOMASS CONSTITUENT(10,1)|TIME HORIZON(10,1)|BRAYTON THERMODYNAMIC POWER CYCLE(9,7)|CARBON DIOXIDE(9,6)|CARBON NEUTRAL(9,6)|INCREASED LOAD(9,5)|FEED HOPPER(9,4)|AMINE FUNCTIONALIZED CELLULOSE(9,1)|BIOME ADAPTATION(9,1)|MACHINERY FLOWPATH(9,1)|SATURATED SORBENT BANK(9,1)|PRESSURE TURBINE(8,6)|AQUEOUS ORGANIC AMINE(8,3)|COOLED CO2 STREAM(8,3)|DEDICATED OXYGEN DELIVERY SERVICE(8,3)|TEMPERATURE CO2 SORBENT(8,3)|CO2 CAPTURE(8,2)|COOLED SYNGA(8,2)|GASIFIER REACTOR VESSEL(8,2)|HISTORICAL SUNLIGHT DATA(8,2)|OXYGEN DEPRIVED ENVIRONMENT(8,2)|SAWDUST WASTE(8,2)|SYNGA STREAM(8,2)|TURBINE EXPANSION(8,2)|UPCOMING DAY(8,2)|WOODY PLANT(8,2)|YARD WASTE(8,2)|AMINE FUNCTIONALIZED SILICA(8,1)|AMMONIA SORBENT(8,1)|AVERAGE DAILY SUNRISE INDICATION(8,1)|CARBONACEOUS BIOMASS(8,1)|CO2 VAPOR DOME(8,1)|COLLECTIVE REVENUE(8,1)|CONCERT CONCLUSION(8,1)|GASIFIER LINER(8,1)|NONEXCLUSIVE INCLUSION(8,1)|PNEUMATIC MODALITY(8,1)|PRESSURED SYNGA(8,1)|RECIRCULATION CO2 STREAM EXCHANGE(8,1)|RECUPERATOR EXHAUST(8,1)|STARTUP PENALTY(8,1)|THRESHOLD NUMBER(8,1)|UNPROCESSED BIOMASS(8,1)|TEMPERATURE HEAT EXCHANGER(7,30)|TURBINE GENERATOR(7,10)|CARBON SEQUESTRATION MODE(7,5)|OXYGEN STREAM(7,5)|SYNGA HEAT(7,5)|WEATHER FORECAST DATA(7,5)|LEVERAGE(7,4)|WASTE HEAT(7,4)|CANDLE FILTER(7,2)|FAN MODULE(7,2)|POWER OUTPUT(7,2)|ANTICIPATED CONCLUSION(7,1)|BIOMASS SOLID CONVEYANCE(7,1)|CLEAN SYNGA(7,1)|CO2 GIGATONNE(7,1)|CONTACTOR BANK(7,1)|CONTACTOR FAN(7,1)|CONTRACTOR SPOT PRICE(7,1)|EXPLICITLY STATED MEANING(7,1)|GASIFIER JACKET LINER(7,1)|GASIFIER PRESSURIZED VOLUME(7,1)|GRID STABILIZATION(7,1)|HEATED RECIRCULATION CO2(7,1)|HYBRID BICRS(7,1)|OCEAN CAPTURE(7,1)|OPERATIONAL ISSUE KNOWLEDGE(7,1)|PARTICULATE CONTAMINANT(7,1)|PIPING MANIFOLD(7,1)|PLURAL REFERENT(7,1)|REVENUE PROJECTION(7,1)|ROTARY DRUM REACTOR(7,1)|SEQUESTERING CO2(7,1)|SYNGA COOLER(7,1)|TORREFACTION GAS COMBUSTION(7,1)|CARBON MONOXIDE(6,9)|CARBON NEGATIVE FUEL(6,6)|AMENABLE TEMPERATURE(6,3)|ATMOSPHERIC CO2(6,3)|COMBUSTION INJECTION PRESSURE(6,3)|CONSTITUENT COMPONENT(6,3)|ENTRAIN FLOW GASIFIER(6,3)|FIXED BED GASIFIER(6,3)|PRESSURIZING(6,3)|UNDERBRUSH(6,3)|BIOMASS REACTION(6,2)|COMPRESSED CO2(6,2)|SOLAR ENERGY PROVIDER ABILITY(6,2)|SUPERCRITICAL CO2 CYCLE(6,2)|TURBOALTERNATOR(6,2)|SOLID PRODUCT(5,6)|ANIMAL MANURE(5,2)|CENTURY(5,2)|COAL POWER PLANT(5,2)|CONTAMINATION(5,2)|DESIGNATION(5,2)|DISCHARGE CYCLE(5,2)|ELECTRICITY COST PERIOD(5,2)|FERTILIZER(5,2)|FESTIVAL(5,2)|FIREWOOD(5,2)|LEAKAGE PASSAGE(5,2)|MONOETHANOLAMINE(5,2)|ONLINE SOURCE(5,2)|OPERATIONAL CONFIGURATION(5,2)|PETROLEUM PRODUCT(5,2)|POWER PROVIDER(5,2)|PRESSURE COMBUSTION STREAM(5,2)|PRESSURE LADDER(5,2)|RELEVANT GEOGRAPHIC REGION(5,2)|SOYBEAN(5,2)|WATER BOILING(5,2)|WOOL PRODUCTION(5,2)|BIOSYNGA REACTION(5,1)|CAPTURED CO2 LOSS(5,1)|CARBON DIOXIDE ANTHROPOGENIC EMISSION(5,1)|CEMENT CONCRETE(5,1)|CO2 CONCENTRATED STREAM(5,1)|CO2 EXHAUST(5,1)|COAL GRINDING(5,1)|COMPRESSION TRAIN(5,1)|CONTACTOR FALL(5,1)|CYCLE TURBOMACHINERY(5,1)|ENGINE TURBINE(5,1)|FLUID PREHEATING(5,1)|GRID INTEGRATION(5,1)|HYDROPHOBIC BEHAVIOR(5,1)|MICROWAVE REACTOR(5,1)|PERMANENTLY STORED UNDERGROUND(5,1)|PLANT BIOMASS(5,1)|POWERING CARBON SEQUESTRATION(5,1)|RECIRCULATION STREAM(5,1)|REVERSE SCENARIO(5,1)|SELLING CO2(5,1)|STEAM EXTRACTION(5,1)|SUDDEN LOAD DEMAND(5,1)|SUPERCRITICAL CO2 STREAM(5,1)|SUPERCRITICAL CYCLE(5,1)|SUPPLEMENTAL COOLING(5,1)|SYNGA COMPRESSION(5,1)|SYNGA REACTOR WALL(5,1)|WASTE BIOMASS(5,1)|WASTED FUEL(5,1)|DIRECT AIR CAPTURE(4,78)|AIR SEPARATION(4,13)|CO2 CRITICAL PRESSURE(4,4)|TORREFACTION(4,4)|AIR CARBON SEQUESTRATION(4,3)|CONDITION REMAINS(4,3)|FLY ASH(4,3)|GASEOUS HYDROGEN(4,3)|HIGHWAY(4,3)|ORGANIC WASTE(4,3)|TREE(4,3)|UNDERGROUND STORAGE LOCATION(4,3)|NATURAL DISASTER(4,2)|SOCIETY(4,2)|AIR SCRUBBED CO2 FALL(4,1)|AIR SCRUBBING(4,1)|ALGAE PRODUCTION(4,1)|CAPTURED ATMOSPHERIC CO2(4,1)|CARBON DIOXIDE SEQUESTRATION(4,1)|CARBON SEQUESTRATION TAX BREAK(4,1)|CLOUDY CONDITION(4,1)|CO2 COLLECTION(4,1)|CO2 EMISSION(4,1)|CO2 LOOP(4,1)|COLD STRETCH(4,1)|COMBINED RECIRCULATION(4,1)|COMBUSTION OUTLET(4,1)|DENSITY DERIVATIVE(4,1)|DIRTY CHEMICAL(4,1)|ENERGY INTENSIVE(4,1)|EQUIPMENT CAPITAL INVESTMENT(4,1)|EXCESS POLLUTION(4,1)|EXTRACTED CO2(4,1)|GASIFICATION OXIDATION REACTION(4,1)|GROUND BIOMASS(4,1)|HOT CO2(4,1)|INDICATION DETECTION(4,1)|INITIATION DETECTION(4,1)|LOAD DESTINATION(4,1)|LOCK HOPPER(4,1)|MAJOR CONCERT(4,1)|PRESSURE CO2 RECIRCULATION(4,1)|RENEWABLE ENERGY PROVIDER ABILITY(4,1)|REVENUE PRODUCTION(4,1)|STORMY CONDITION(4,1)|STREAM CONCENTRATION(4,1)|SUBCRITICAL CO2 WORKING FLUID(4,1)|SWITCHING RELAY(4,1)|ADSORBENT MATERIAL REGENERATION(3,1)|AIR SEPARATOR(3,1)|ATMOSPHERIC CARBON(3,1)|BIODOME(3,1)|BIOMASS ENERGY CONVERSION(3,1)|BOTTOMING TEMPERATURE(3,1)|BREAKING DOWN BIOMASS(3,1)|CLIMATE CRISIS(3,1)|CO2 DENSITY GRADIENT(3,1)|CO2 SORBENT MATERIAL(3,1)|CO2 TEMPERATURE(3,1)|CO2FLOW(3,1)|COMPONENT ORIGIN(3,1)|COMPUTER CONTROLLER(3,1)|CONDUCTING HEAT(3,1)|CONSTANT HEAT REJECTION(3,1)|CONVEYING SOLID(3,1)|COOL CYCLE(3,1)|DESTABILIZATION(3,1)|DISPATCH(3,1)|DOWNSTREAM COMPONENT(3,1)|EARTHQUAKE(3,1)||(JP2026505712)|CARBON ISOLATION(100,64)|INTEGRATED CARBON ISOLATION(100,5)|POWER GENERATION INTEGRATION(72,45)|DAC CARBON ISOLATION(54,6)|INTEGRATING CARBON ISOLATION(48,1)|SYNGA PURIFICATION(46,5)|REFORESTATION(41,5)|INTEGRATING CARBON SEPARATION(41,1)|THERMODYNAMIC CYCLE(39,15)|BIOMASS(37,49)|REGENERATED BRAYTON CYCLE(36,2)|EQUIPMENT CAPITAL INVESTMENT(34,1)|RECOVERY MEDIA(33,1)|GENERATION PLANT(31,1)|POWER GENERATION(30,43)|TURBINE(30,20)|SYNGA(28,58)|GASIFIER(28,46)|PERMANENCE(27,1)|AIR RECOVERY(25,7)|RECOVERING CARBON(24,5)|RECIRCULATED CARBON DIOXIDE(23,3)|COMBUSTOR(21,21)|TREFACTION REACTOR(21,9)|SCRUBBER(20,19)|LIQUID SORBENT(20,1)|SEQUESTRATION(19,3)|SOLID SORBENT(19,1)|VALUE PREDICTION(18,11)|AIR COLLECTION(18,6)|RENEWABLE ENERGY PROVIDER(18,6)|CARBON DIOXIDE ADSORPTION(18,1)|RECIRCULATION PUMP(17,11)|CARBON SEQUESTRATION(17,10)|SYNGA BOOST COMPRESSOR(17,3)|POWER GRID MARKET(17,1)|WEATHER PREDICTION(17,1)|CARBON NEUTRAL FUEL(16,4)|LONG PLANNED PERIOD(16,1)|RANKINE CYCLE(15,3)|SORBED MATERIAL REGENERATION(15,2)|BICRS(14,3)|AIR CARBON CAPTURE(14,1)|SHORT PLANNING PERIOD(14,1)|COMBUSTION FLOW(13,11)|REGENERATING DAC RECOVERY CRYOSORBENT(13,1)|POWER NETWORK(12,58)|COOLING BANK(12,8)|MOLTEN SLAG(12,5)|MUNICIPAL WASTE(12,5)|PREDICTED VALUE(12,4)|OXYGEN BOOST COMPRESSOR(12,3)|CRUSHED TREPIDIZED BIOMASS(12,1)|OPERATION MODE(11,56)|THERMODYNAMIC POWER CYCLE(11,13)|CARBON NEGATIVE FUEL(11,6)|CARBON ISOLATION OPERATION(11,2)|CONTRACTING ENTITY(11,2)|GASIFIER INJECTOR(11,2)|CRUSHED TREFIED BIOMASS(11,1)|LONG PLANNING PERIOD(11,1)|POWER NETWORK OPERATOR(10,22)|STEAM INJECTION(10,5)|DAC FAN(10,4)|CARBON CAPTURE(10,2)|CRYOGENIC OXYGEN SEPARATOR(10,2)|SORBENT REGENERATION(10,2)|BIOMASS POWER PLANT(10,1)|MUDDY WEATHER STATUS(10,1)|FEED HOPPER(9,5)|TIMER(9,5)|BIOMASS TREFACTION(9,1)|DAC BANK FAN MODULE(9,1)|DAC RECOVERY REGENERATION(9,1)|GASIFICATION INJECTOR(9,1)|HEATING OUTPUT(9,1)|SATURATED SORBENT BANK(9,1)|SEPARATING TREPIDATED BIOMASS(9,1)|POWER GRID(8,30)|TURBINE RELEASE FLOW(8,8)|BRAYTON THERMODYNAMIC POWER CYCLE(8,7)|WEATHER FORECAST DATA(8,7)|INCREASED LOAD(8,5)|BIOWASTE EMISSION(8,2)|CARBON REDUCTION(8,2)|DOWNSTREAM TURBINE(8,2)|FLUIDIZED BED GASIFIER(8,2)|OXYGEN FUEL COMBUSTOR(8,2)|BIOME ADAPTATION(8,1)|FUTURE WEATHER PHENOMENON INDICATION(8,1)|PRETREATED BIOMASS(8,1)|PRETREFACTED BIOMASS(8,1)|SCHEDULED BURDEN OCCURRENCE(8,1)|SORBENT REGENERATOR(8,1)|TURBINE DISCHARGE FLOW(7,6)|DAC COMPONENT(7,3)|HUMAN LIVING WASTEWATER(7,2)|OXYGEN FUEL COMBUSTION(7,2)|TURBINE EXPANSION(7,2)|UNDERGONE EXPANSION(7,2)|WOODY PLANT(7,2)|AMMONIA SORBENT(7,1)|ASH MICROPARTICLE(7,1)|BIOMASS DECOMPOSITION(7,1)|CARBONACEOUS BIOMASS(7,1)|CRUSHED BIOMASS SLURRY FORMATION(7,1)|DAC BANK OUTLET(7,1)|GASIFIER PRESSURIZATION VOLUME(7,1)|METALORGANIC FRAMEWORK(7,1)|MOF SORBENT(7,1)|NONEXCLUSIVE INCLUSION(7,1)|NONLIQUID ASH FORMATION(7,1)|REVENUE PREDICTION(7,1)|SYNGA CONDENSATE(7,1)|THRESHOLD NUMBER(7,1)|TREFECTION REACTOR(7,1)|CARBON ISOLATION MODE(6,5)|CRUSHING(6,4)|URBAN SOLID WASTE(6,4)|CANDLE FILTER(6,2)|BIOSIN GAS OXYGEN COMBUSTOR(6,1)|CARBON ISOLATION TAX INCENTIVE(6,1)|COMPRESSED SINGUS(6,1)|CONDENSABLE SUBSTANCE(6,1)|CONTACTOR BANK(6,1)|CONTACTOR FAN(6,1)|CONTEXT OVERVIEW(6,1)|DAC ISOLATION(6,1)|DAC RECOVERY CAPABILITY(6,1)|GASIFIER JACKET LINER(6,1)|HYBRID BICRS(6,1)|INITIATING BIOMASS REACTION(6,1)|PARTICULATE CONTAMINANT(6,1)|PIPING MANIFOLD(6,1)|PLANT BIOMASS(6,1)|SORBENT PACK(6,1)|STORMY WEATHER(6,1)|SUN ENERGY PROVIDER(6,1)|SYNGA COOLER(6,1)|SYNGA PRESSURIZATION(6,1)|SYNGA REACTOR(6,1)|TREFACTION GAS COMBUSTION(6,1)|UNTREATED BIOMASS(6,1)|SORBING MATERIAL(5,7)|TREFACTION(5,6)|FOREST(5,3)|HIGHWAY(5,3)|METEOROLOGICAL PHENOMENON(5,3)|QUENCHING(5,3)|TURBINE EXHAUST FLOW(5,3)|COMING DAY(5,2)|DEDICATED OXYGEN DELIVERY SERVICE(5,2)|GASIFICATION REACTION VESSEL(5,2)|LIQUEFACTION TRANSFER(5,2)|PROMOTING SWITCHING(5,2)|RECIRCULATED CO2 FLOW(5,2)|SOLAR ENERGY PROVIDER(5,2)|TURBINE MACHINE(5,2)|AMINE FUNCTIONALIZED CELLULOSE(5,1)|ASH PARTICLE(5,1)|ASSET FAILURE(5,1)|BIOSYNGA OXYGEN(5,1)|BOWL MILL(5,1)|CEMENT CONCRETE(5,1)|COAL GRINDING(5,1)|CONDENSER FAN(5,1)|COOLING SINGUS(5,1)|ENGINE TURBINE(5,1)|FAN BANK(5,1)|IMPACT HAMMER(5,1)|INTEGRATED DAC CARBON ISOLATION(5,1)|MACHINE MODALITY(5,1)|NATURAL DISASTER PHENOMENA(5,1)|OVERVIEW EXPLANATION(5,1)|PRESSURIZED BIOMASS COMPONENT(5,1)|RESOURCE WASTE(5,1)|REVENUE GENERATION(5,1)|REVERSE SCENARIO(5,1)|SEA RECOVERY(5,1)|STEAM EXTRACTION(5,1)|SUBTLE MEANING(5,1)|SUDDEN LOAD DEMAND(5,1)|SUNNY DAY(5,1)|SUPERCRITICAL CYCLE(5,1)|TURBINE EMISSION(5,1)|WASTE BIOMASS(5,1)|WINDY DAY(5,1)|CARBON ISOLATION SCHEMATIC DIAGRAM(4,5)|CONDUCTING(4,4)|TIMBER(4,4)|SIPHON(4,3)|ABSORPTION CYCLE(4,2)|AIR CARBON SEQUESTRANT(4,2)|ANIMAL MANURE(4,2)|COMBUSTION INJECTION PRESSURE(4,2)|COMPOUND HALOGENATION(4,2)|DESIGNATION(4,2)|DIRECT FIRE TURBINE(4,2)|FERTILIZER(4,2)|FESTIVAL(4,2)|LEAKAGE PASSAGE(4,2)|ONLINE SOURCE(4,2)|OXYGEN DEFICIENT ENVIRONMENT(4,2)|SAWDUST(4,2)|SEEDLING(4,2)|SYNGA GENERATION(4,2)|WATER BOILING(4,2)|ALGA PRODUCTION(4,1)|AMINE FUNCTIONALIZED SILICA(4,1)|AUXILIARY COOLING(4,1)|BIOSIN GAS REACTION(4,1)|CARBON ISOLATION TURBINE GENERATOR(4,1)|CHEMICAL CONTAMINATION(4,1)|COLLECTING CARBON(4,1)|COMBUSTION OUTLET(4,1)|COMPRESSION ROW(4,1)|CYCLE RECIRCULATION(4,1)|DENSITY LINEAR DERIVATIVE(4,1)|FAULT GENERATING ASSET(4,1)|FIXED BED GASIFIER(4,1)|GASIFICATION OXIDATION REACTION(4,1)|HEAT RECIRCULATION(4,1)|HEATED SYNGA(4,1)|HYDROPHOBIC REACTION(4,1)|LOAD HOPPER(4,1)|LOCK HOPPER(4,1)|MAJOR CONCERT(4,1)|PLANT MATERIAL(4,1)|POWER GENERATION CONCISE VERSION(4,1)|PRESSURIZING VOLUME(4,1)|PRODUCT REUSE(4,1)|PULVERIZABLE(4,1)|REGENERATE SORPTION MATERIAL BANK(4,1)|RELAY SWITCH(4,1)|RENEWABLE ENERGY RECEPTION(4,1)|SORBENT HEAT(4,1)|SYNGA CARBON CONTENT(4,1)|WORKING FLUID(3,14)|AIR SEPARATION(3,11)|SOLID PRODUCT(3,5)|WOOD PROCESSING(3,4)|AGRICULTURAL WASTE(3,3)|AQUEOUS INORGANIC BASE(3,3)|AQUEOUS ORGANIC AMINE(3,3)|CARBON MONOXIDE(3,3)|CARBON SEPARATION SCHEMATIC DIAGRAM(3,3)|COMBUSTION(3,3)|ORGANIC WASTE(3,3)|SUPERCRITICAL CO2 FLOW(3,3)|TREE(3,3)|UNDERGROUND STORAGE LOCATION(3,3)|AIR RECOVERY SYSTEM(3,2)|KNOWLEDGE(3,2)|AIR COLLECTION CARBON(3,1)|AIR RECOVERY CARBON(3,1)|BAD WEATHER FORECAST PERIOD(3,1)|BIODOME(3,1)|BIOENERGY(3,1)|BIOMASS ENERGY CONVERSION(3,1)|BOTTOMING TEMPERATURE(3,1)|CARBON DIOXIDE HUMAN EMISSION(3,1)|CARBON DIOXIDE INSULATION(3,1)|CARBON SEQUESTRATION ENERGY(3,1)|CENTURY(3,1)|CLIMATE CHANGE CRISIS(3,1)|COMPUTER CONTROLLER(3,1)|CONVEYANCE(3,1)|COOL CYCLE(3,1)|DISCRIMINATION(3,1)|DOWNSTREAM COMPONENT(3,1)|EARTHQUAKE(3,1)|ELECTRICAL DEMAND(3,1)|ENERGY DELIVERING(3,1)|EXHAUST HEAT(3,1)|EXPECTATION(3,1)|FAILURE GENERATING ASSET(3,1)|FUTURE WEATHER CONDITION(3,1)|GENERATOR ALTERNATOR(3,1)|GIGATON(3,1)|HABIT(3,1)|HEAT EXCHANGER INTEGRATION(3,1)|HURRICANE(3,1)|HYDROGEN FORMATION(3,1)|INDEPENDENCE(3,1)|INLET FLOW ROBUSTNESS(3,1)|INTERMEDIATE COOLING(3,1)|ISOLATION CYCLE(3,1)|JUDGEMENT(3,1)|LOAD CHANGE DESTINATION(3,1)|MONOETHANOLAMINE(3,1)| | (US12359613)|We claim:|1. An integrated carbon sequestration and power generation system, comprising:| a thermodynamic cycle configured to receive biomass and to generate heat and power; and| a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration;| wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system;| wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied;| wherein the determining whether the predetermined condition is satisfied comprises determining whether a threshold number or type of power sources associated with the power grid are available.|2. The integrated carbon sequestration and power generation system of claim 1, wherein the biomass includes at least one of: plant matter or municipal waste.|3. The integrated carbon sequestration and power generation system of claim 1, wherein sorbent material of the DAC carbon sequestration system includes a solid sorbent or a liquid sorbent configured to adsorb carbon dioxide (CO2).|4. The integrated carbon sequestration and power generation system of claim 3, wherein at least some of the heat produced by the thermodynamic cycle is utilized to regenerate the sorbent material after carbon capture.|5. The integrated carbon sequestration and power generation system of claim 1, wherein at least one of a sensor or a timer is used to determine whether the predetermined condition is satisfied.|6. The integrated carbon sequestration and power generation system of claim 1, wherein the determining whether the predetermined condition is satisfied further comprises receiving information from a power grid operator that the predetermined condition is satisfied.|7. The integrated carbon sequestration and power generation system of claim 1, wherein the determining whether the predetermined condition is satisfied further comprises determining whether an increased load is required by the power grid.|8. The integrated carbon sequestration and power generation system of claim 1, wherein the determining whether the predetermined condition is satisfied further comprises determining whether a first projected value derived from operation of the integrated carbon sequestration and power generation system in the first operating mode is greater or less than a second projected value derived from operation of the integrated carbon sequestration and power generation system in the second operating mode.|9. The integrated carbon sequestration and power generation system of claim 1, wherein the power generation system includes at least one of a Brayton cycle, a recuperated Brayton cycle, or a Rankine cycle.|10. An integrated carbon sequestration and power generation system, comprising:| a gasifier configured to receive a biomass and configured to produce a syngas;| a combustor configured to produce a combustion stream from the cleaned syngas, oxygen, and a recirculation carbon dioxide (CO2) stream;| at least one turbine, wherein the at least one turbine is operatively coupled to a direct air capture (DAC) carbon sequestration system and to a high pressure recirculation pump to optionally or simultaneously provide power produced by the at least one turbine to the DAC carbon sequestration system in a first operating mode or to a power grid separate from the integrated carbon sequestration and power generation system in a second operating mode;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and;| wherein the determining whether the predetermined condition is satisfied comprises determining whether a threshold number or type of power sources associated with the power grid are available.|11. The integrated carbon sequestration and power generation system of claim 10, wherein the biomass is a torrefied biomass.|12. The integrated carbon sequestration and power generation system of claim 10, further comprising:| a scrubber, fluidly coupled to the gasifier, configured to clean the syngas.|13. The integrated carbon sequestration and power generation system of claim 12, further comprising:| a low temperature heat exchanger, fluidly coupled to the scrubber, configured to cool the cleaned syngas.|14. The integrated carbon sequestration and power generation system of claim 10, wherein the power generation system includes at least one of a Brayton cycle, a recuperated Brayton cycle, or a Rankine cycle.|15. An integrated carbon sequestration and power generation system, comprising:| a thermodynamic cycle configured to receive biomass and to generate heat and power; and| a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration;| wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system;| wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and| wherein the determining whether the predetermined condition is satisfied comprises assessing a weather forecast.|16. The integrated carbon sequestration and power generation system of claim 15, wherein the determining comprises determining that the predetermined condition is satisfied responsive to:| identifying, from data associated with the weather forecast, that an upcoming weather event will affect an ability of a renewable energy provider to provide power provided to the power grid for a predetermined period of time.|17. The integrated carbon sequestration and power generation system of claim 16, wherein the integrated carbon sequestration and power generation system is configured to switch to and remain in the second operating mode during at least a portion of the predetermined period of time.|18. An integrated carbon sequestration and power generation system, comprising:| a thermodynamic cycle configured to receive biomass and to generate heat and power; and| a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration;| wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system;| wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and| wherein the determining whether the predetermined condition is satisfied comprises determining whether a power grid operator has access to renewable energy from a renewable energy provider.|19. The integrated carbon sequestration and power generation system of claim 1, wherein the determining comprises determining that the predetermined condition is satisfied responsive to:| identifying that the threshold number or type of power sources associated with the power grid are not available; and| determining, responsive to identifying, that the power grid will become destabilized within a predetermined timed threshold.|20. The integrated carbon sequestration and power generation system of claim 19, wherein the integrated carbon sequestration and power generation system is configured to switch to the second operating mode prior to the predetermined time threshold. | (US12359613)|CROSS REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to U.S. Provisional Application No. 63/479,875, filed on Jan. 13, 2023, and U.S. Provisional Application No. 63/535,990, filed on Aug. 31, 2023, which are both incorporated by reference herein in their entireties.|(US12359613)|TECHNICAL FIELD|[0002] Various embodiments of the present disclosure relate generally to an integrated carbon sequestration and power generation system and related methods of use, and, more particularly, to a biomass energy conversion cycle coupled with a direct air capture carbon system.|BACKGROUND|[0003] The anthropogenic emission of carbon dioxide (CO2) gases from thermal processes (combustion) over centuries has caused the atmospheric composition of the planet earth to change. This has led to a planetary warming effect that is causing the earth's climate systems to change at an unprecedented rate. The biome adaptation mechanisms are in danger of collapsing due to the rapid change in atmospheric boundary conditions. The Intergovernmental Panel on Climate Change (IPCC) has decreed that in order to keep the average atmospheric temperature increase to 1.5° C., humans must remove 100-1000 gigatonnes of CO2 in the 21st century from the atmosphere.|[0004] The present disclosure is accordingly directed to addressing the foregoing issue(s). The background description provided herein is for the purpose of generally presenting the context of the disclosure. Unless otherwise indicated herein, the materials described in this section are not prior art to the claims in this application and are not admitted to be prior art, or suggestions of the prior art, by inclusion in this section.|SUMMARY OF THE DISCLOSURE|[0005] According to certain aspects of the disclosure, an integrated carbon sequestration and power generation system is disclosed.|[0006] In accordance with an embodiment, an integrated carbon sequestration and power generation system is disclosed. The integrated carbon sequestration and power generation system includes a thermodynamic power cycle, such as a recuperated Brayton thermodynamic cycle, configured to receive biomass and to generate heat and power; and a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and the power generated by the thermodynamic power cycle, such as a recuperated Brayton thermodynamic cycle, to facilitate carbon sequestration.|[0007] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes generating syngas via a gasification reaction involving a biomass, oxygen, and steam occurring in a gasifier; passing the generated syngas through a scrubber to produce a cleaned syngas; and cooling the cleaned syngas via introduction into a low temperature heat exchanger, wherein syngas heat is removed in the low temperature heat exchanger to produce steam. The method further includes introducing the cooled syngas, oxygen, and a recirculation carbon dioxide (CO2) stream into a combustor; combusting the syngas to provide a combustion stream comprising CO2 and water; expanding the combustion stream across a first turbine to generate a first turbine discharge stream and power; and expanding the first turbine discharge stream across a second turbine to generate a second turbine discharge stream and power, wherein the power is supplied to a generator. The method further includes cooling at least a portion of the second turbine discharge stream by passing the second turbine discharge stream through a recuperator heat exchanger; and passing the cooled second turbine discharge stream into a cooling bank, wherein the cooling bank comprises sorbent material containing captured CO2, and wherein passage of the cooled second turbine discharge stream through the cooling bank heats the CO2 sorbent material. The method also includes passing the recirculation CO2 stream exiting the cooling bank through a compressor to produce a supercritical CO2 stream; passing a first portion of the supercritical CO2 stream to a storage location and passing a second portion of the supercritical CO2 stream through a recirculation pump to produce the recirculation CO2 stream; passing the recirculation CO2 stream through the recuperator heat exchanger, wherein the recirculation CO2 stream exchanges heat with the second turbine discharge stream at the recuperator heat exchanger; and passing the heated recirculation CO2 stream into the combustor.|[0008] In accordance with another embodiment, an integrated carbon sequestration and power generation system is disclosed. The integrated carbon sequestration and power generation system includes a gasifier configured to receive a biomass and configured to produce a syngas; a combustor configured to produce a combustion stream from the cleaned syngas, oxygen, and a recirculation carbon dioxide (CO2) stream; and at least one turbine, wherein the at least one turbine is operatively coupled to a direct air capture (DAC) carbon sequestration system and to a high pressure recirculation pump to optionally or simultaneously provide power produced by the at least one turbine to the DAC carbon sequestration system or to a power grid separate from the integrated carbon sequestration and power generation system.|[0009] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes operating, using one or more processors of a computer system, the integrated carbon sequestration and power generation system in a first operating mode, wherein power produced by a turbine generator of the integrated carbon sequestration and power generation system in the first operating mode is directed to power a direct air capture (DAC) carbon sequestration system; determining, using the one or more processors, that a predetermined condition is satisfied; switching, using the one or more processors and based on the determining, the operating mode of the integrated carbon sequestration and power generation system from the first operating mode to a second operating mode; and operating, subsequent to the switching, the integrated carbon sequestration and power generation system in the second operating mode, wherein the power produced by the turbine generator in the second operating mode is directed to a power grid of a power grid operator.|[0010] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes operating, using one or more processors of a computer system, the integrated carbon sequestration and power generation system in a first operating mode, wherein power produced by a turbine generator of the integrated carbon sequestration and power generation system in the first operating mode is directed to power a direct air capture (DAC) carbon sequestration system; determining, using the one or more processors, that a predetermined condition is satisfied; switching, using the one or more processors and based on the determining, the operating mode of the integrated carbon sequestration and power generation system from the first operating mode to a second operating mode; and operating, subsequent to the switching, the integrated carbon sequestration and power generation system in the second operating mode, wherein a first portion of the power produced by the turbine generator is directed to the DAC carbon sequestration system and a second portion of the power generated by the turbine generator is directed to a power grid of a power grid operator that is separate from the integrated carbon sequestration and power generation system.|[0011] In accordance with another embodiment, a method of supplying power produced by a turbine generator of an integrated carbon sequestration and power generation system to a power grid of a power grid operator is disclosed. The method includes determining, using one or more processors of a computing system, that a predetermined number or type of assets are unavailable to the power grid operator during a first time interval and are available to the power grid operator during a second time interval; causing, using the one or more processors, the power generated by the turbine generator to be transferred to the power grid of the power grid operator during the first time interval; and causing, using the one or more processors, the power generated by the turbine generator to be transferred to a direct air capture (DAC) carbon sequestration system of the integrated carbon sequestration and power generation system during the second time interval.|[0012] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes determining a first projected value derived from sequestration of carbon dioxide when operating the integrated carbon sequestration and power generation system in a first operating mode; determining a second projected value derived from provision of power to a third-party system when operating the integrated carbon sequestration and power generation system in a second operating mode; operating the integrated carbon sequestration and power generation system in the second operating mode responsive to determining that the second projected value is greater than the first projected value; and operating the integrated carbon sequestration and power generation system in the first operating mode responsive to determining that the second projected value is less than the first projected value.|[0013] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the disclosed embodiments, as claimed.|(US12359613)|BRIEF DESCRIPTION OF THE DRAWINGS|[0014] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate the disclosed embodiments, and together with the description, serve to explain the principles of the disclosed embodiments. There are many aspects and embodiments described herein. Those of ordinary skill in the art will readily recognize that the features of a particular aspect or embodiment may be used in conjunction with the features of any or all of the other aspects or embodiments described in this disclosure. In the drawings:|[0015] FIG. 1 depicts a schematic illustration of an exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0016] FIG. 2 depicts a schematic illustration of an exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0017] FIG. 3 depicts exemplary thermodynamic states of pressure and temperature of the system of FIG. 2, according to various aspects of the present disclosure.|[0018] FIG. 4 depicts an exemplary flow of operating an integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0019] FIG. 5 depicts a schematic illustration of another exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0020] FIG. 6 depicts a schematic illustration of another exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0021] FIG. 7 depicts a schematic illustration of another exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0022] FIGS. 8A and 8B depict plot diagrams illustrating cycle efficiency of the power system, without including parasitic losses, according to various aspects of the present disclosure.|[0023] FIG. 9 depicts an exemplary computing system, according to various aspects of the present disclosure.|(US12359613)|DETAILED DESCRIPTION OF THE EMBODIMENTS|[0024] Both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the features, as claimed. In this disclosure, the term “based on” means “based at least in part on.” The singular forms “a,” “an,” and “the” include plural referents unless the context dictates otherwise. As used herein, the terms “comprises,” “comprising,” or other variations thereof, are intended to cover a non-exclusive inclusion such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements, but may include other elements not expressly listed or inherent to such a process, method, article, or apparatus. Additionally, the term “exemplary” is used herein in the sense of “example,” rather than “ideal.” An embodiment or implementation described herein as “exemplary” is not to be construed as preferred or advantageous, for example, over other embodiments or implementations; rather, it is intended to reflect or indicate that the embodiment(s) is/are “example” embodiment(s).|[0025] It should be noted that all numeric values disclosed or claimed herein (including all disclosed values, limits, and ranges) may have a variation of +/−10% (unless a different variation is specified) from the disclosed numeric value. Moreover, in the claims, values, limits, and/or ranges mean the value, limit, and/or range+/−10%. In addition, relative terms, such as “approximately” and “about” are generally used to indicate a possible variation of ±10% of a stated or understood value unless indicated otherwise in the specification. In addition, the term “between” used in describing ranges of values is intended to include the minimum and maximum values described herein. The use of the term “or” in the claims and specification is used to mean “and/or” unless explicitly indicated to refer to alternatives only, or the alternatives are mutually exclusive, although the disclosure supports a definition that refers to only alternatives and “and/or.” As used herein “another” may mean at least a second or more.|[0026] As used herein, certain terms, e.g., “working fuel,” “CO2 stream,” “syngas,” and other like terms may be used interchangeably throughout the description of the embodiments.|[0027] Additional objects and advantages of the embodiments will be set forth in part in the description that follows, and in part will be obvious from the description, or may be learned by practice of the embodiments. It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the claims.|[0028] To achieve carbon sequestration, there are alternatives available, including: reforestation, direct air carbon capture and sequestration, Biomass with Carbon Removal and Storage (BiCRS), and other technologies that may be unproven (e.g., algae production and sinking, etc.). Afforestation/reforestation is low cost, difficult to model, and has a low time horizon for trapping the CO2 (e.g., potentially as soon as 50-100 years). Direct air carbon capture and sequestration is higher cost (e.g., as driven by energy demands), easy to model and quantify, and has a high time horizon for captured carbon (e.g., 1000+ years depending on capture medium). BiCRS is medium cost (e.g., as driven by equipment capital investment), easy to model and quantify, and has a high time horizon for captured carbon (e.g., 1000+ years depending on capture medium).|[0029] Most of the approaches described above require extensive energy use, which in our current society, typically comes from carbon emitting sources, thereby effectively reducing the amount of carbon sequestered. Additionally, the carbon drawdown effects of afforestration/reforestration are difficult to measure and verify, while the permanence is also highly uncertain. Although these afforestation/reforestration and other land and ocean capture methods may play a role in carbon-reduction efforts, they are unlikely to reach the scale and permanence required to avoid a climate crisis. Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation plants to compete in power grid markets.|[0030] In view of the foregoing, a solution is proposed for a system design that is made with BiCRS from the start, using oxyfuel combustion to generate a concentrated stream of CO2 that is used to power the system. Pairing this system with a bottoming temperature and pressure swing adsorption cycle that utilizes the waste heat to regenerate sorbents, a hybrid BiCRS+direct air carbon (DAC) sequestration system may be produced that has a larger carbon drawdown potential as compared to other engineered systems on an energy basis. More particularly, in some aspects, a carbon neutral or carbon negative fuel, such as waste biomass, may be converted into ready-to-sequester CO2, heat, and power, e.g., using a thermodynamic power cycle. Exemplary thermodynamic power cycles may include, e.g., a Brayton cycle, a recuperated Brayton thermodynamic cycle, a Rankine cycle, a steam turbine cycle with Rankine, etc. Such thermodynamic cycles may use CO2 and/or super critical CO2 (sCO2) as the main working fluid. At least some of the heat and power generated from the thermodynamic cycle may then be used to drive an integrated direct air carbon capture system, or the power may be used for one or more other purposes (e.g., the power may be electrical power that is utilized for grid integration, or the power may be output in the form of mechanical power). Such an exemplary system 100 is shown schematically in FIG. 1. It should be understood that FIG. 1 generally describes an overall integrated carbon sequestration and power generation system, of which systems 200, 500, 600, and 700 (discussed further herein) are exemplary embodiments.|[0031] As shown in FIG. 1, biomass 105 may be introduced into a thermodynamic power cycle 110 in which waste heat is used to power the DAC sequestration system and regenerate sorbent. In the context of this application, biomass 105 refers to any carbon neutral or carbon negative fuel. For instance, potential types of biomass 105 may include, e.g., wood products, such as wood processing wastes (e.g., firewood, wood pellets, wood chips, lumber and sawdust waste, etc.), agricultural products, including crops and waste materials (e.g., corn, soybeans, sugar cane, woody plants, algae, etc.), biogenic materials in municipal solid waste (e.g., paper, cotton, wool products, food, yard waste, etc.), non-biogenic materials in municipal solid waste (e.g., plastics or petroleum-based products), animal manure, or human sewage (e.g., bio waste discharge from water treatment plants). The biomass 105 may be broken down within the thermodynamic power cycle 110 to produce CO2. In an aspect, non-limiting types of possible thermodynamic power cycles that may be utilized include Brayton thermodynamic power cycles, recuperated Brayton thermodynamic power cycles, Rankine thermodynamic power cycles, etc. Specific examples of thermodynamic cycles and processes for breaking down biomass 105 are discussed in further detail below. It is important to note that although the examples described throughout the specification may refer to a recuperated Brayton thermodynamic power cycle, this designation is not limiting, and other thermodynamic power cycles may be utilized in lieu or, or in addition to, the recuperated Brayton thermodynamic power cycle.|[0032] In an aspect, the CO2 may be heated by combustion heat derived from a reaction of bio-syngas and oxygen in the thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic cycle) to form a CO2 working fluid. The CO2 working fluid may be a supercritical CO2 working fluid, subcritical CO2 working fluid, steam, or a combination thereof. The working fluid may be utilized to generate power and heat. In one configuration, the generated power may be provided to a direct air capture (DAC) system 115, which may be configured to capture CO2 directly from the atmosphere. More particularly, the DAC system 115 may contain sorbent materials, e.g., solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. The rejected heat from the thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic power cycle) may be used to extract the captured atmospheric CO2 and to regenerate the sorbent materials and the generated power may be used to compress the extracted CO2 captured from the DAC system 115. Once extracted, the captured CO2 may be permanently stored underground, reintroduced into the thermodynamic power cycle 110, and/or may be sold. In another operational configuration, the generated power produced by the thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic power cycle) may optionally be integrated to a power grid 120. In yet another operational configuration, a portion of the generated power may be integrated to the power grid 120, and another portion may be used to power the DAC system 115, allowing for the simultaneous supply of power to both power grid 120 and DAC system 115.|[0033] Accordingly, exemplary embodiments of the present disclosure provide for a power generation system that uses biomass as a fuel and uses CO2 as the working fluid. For example, a gasifier may be used to convert carbonaceous biomass into a useable fuel source for power generation. Such a system may utilize the CO2 working fluid to pressurize a biomass solids conveyance system, cool syngas reactor walls, or quench the syngas flow coming out of the gasifier reactor, as will be described further below.|[0034] This power generation system may further be integrated with a carbon sequestration system that is capable of directly capturing carbon from the air. Embodiments of the present disclosure provide for the integration of a CO2 power cycle with a Direct Air Capture (DAC) system, which may use CO2 and/or sCO2 thermodynamic power cycle waste heat as a sorbent regenerator for the CO2 sequestration cycle, as described in reference to FIG. 1. Additionally, power generation systems of the present disclosure may be used as “peaker plants,” or power plants that generate power for the power grid only when there is a higher demand for electricity, as will be described further below. In such an implementation, the energy generated by the disclosed systems may be used for multiple functions, e.g., for generating power for dispatch to the power grid, and for powering carbon sequestration via an integrated DAC system.|[0035] In some aspect, other embodiments of the present disclosure provide for selection of a high pressure cycle pump inlet to enable inlet flow robustness and independence from ambient conditions on the inlet of the pump system. Compressors may be sensitive to inlet conditions and may be forced to derate (i.e., reduce power) or turn off all together if conditions are not favorable. More particularly, the density of the CO2 may be sensitive to the temperature of the CO2 fluid at the bottom the pressure ladder. The temperature at the bottom of the pressure ladder may be affected by ambient temperature or may be close to the ambient temperature due to heat rejection methods. This density of the CO2 may affect the operation of the turbomachinery of the cycle. The temperature density sensitivity may be acute near the critical pressure of CO2 at 73.8 bar. In an aspect, by increasing the inlet pressure of the recirculation pump (which may be the lowest pressure in the recirculation loop), the first derivative of density and pressure at a given temperature may be decreased, thereby causing the CO2 density to be less dependent on its temperature, e.g., ambient conditions. This in turn may allow the system to operate in varied geographic locations, which may have hot, cold, or moderate ambient temperature conditions, without the need for bodies of water to conduct cooling. In some aspects, by operating above the critical pressure of CO2 (e.g., at above about 100 bar, from about 100 bar to about 150 bar, from about 120 bar to about 130 bar, or about 125 bar), normal temperature swings in ambient condition (e.g., changes in temperature from day to night or from summer to winter) may only change the CO2 density by about 20% or less, by about 15% or less, by about 10% or less, or by about 5% or less. Conversely to the foregoing, in another aspect, the system may be transcritical at a lowest pressure of, e.g., approximately 35 bar, so the inlet pressure of the recirculation pump may not need to be increased, as described above. Accordingly, aspects of the disclosure may be drawn to a more robust system that may be able to run under a wider range of ambient conditions compared to a system designed to operate near the critical pressure of CO2 will be able to.|[0036] The subject matter of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings, which form a part hereof, and which show, by way of illustration, specific exemplary embodiments. System 100 may take the form of any of the alternative embodiments described herein, e.g., in regards to FIGS. 2, 5, 6, and 7. Subject matter may be embodied in a variety of different forms and, therefore, covered or claimed subject matter is intended to be construed as not being limited to any exemplary embodiments set forth herein; exemplary embodiments are provided merely to be illustrative. Likewise, a reasonably broad scope for claimed or covered subject matter is intended. Among other things, for example, subject matter may be embodied as methods, devices, components, or systems. Accordingly, embodiments may, for example, take the form of hardware, software, firmware, or any combination thereof. The following detailed description is, therefore, not intended to be taken in a limiting sense.|[0037] Throughout the specification and claims, terms may have nuanced meanings suggested or implied in context beyond an explicitly stated meaning. Likewise, the phrase “in one embodiment” or “in some embodiments” as used herein does not necessarily refer to the same embodiment, and the phrase “in another embodiment” as used herein does not necessarily refer to a different embodiment. It is intended, for example, that claimed subject matter include combinations of exemplary embodiments in whole or in part.|[0038] The terminology used below may be interpreted in its broadest reasonable manner, even though it is being used in conjunction with a detailed description of certain specific examples of the present disclosure. Indeed, certain terms may even be emphasized below; however, any terminology intended to be interpreted in any restricted manner will be overtly and specifically defined as such in this Detailed Description section.|[0039] FIG. 2 is a diagram depicting an exemplary integrated carbon sequestration and power generation system 200 (“system”), according to one or more embodiments of the present disclosure. The system 200 may include a torrefaction reactor 202, a grinding system 204, a torrefied biomass conveyance system 206, a load and lock hopper 208, a feed hopper 210, a gasifier reactor vessel (“gasifier”) 212, an air separation unit 214, a first H2O recirculation pump 216, and a scrubber 218. Collectively, these components may prepare biomass for use as fuel. System 200 may further include a low temperature heat exchanger 220, a syngas boost compressor 222, an oxygen boost compressor 224, a combustor 226, a recuperator heat exchanger 228, a high pressure turbine 230, a high pressure CO2 recirculation pump 232, a low pressure turbine 234, and a generator 236 for producing power. In some aspects, system 200 may further include a direct action capture fan bank 238, a low/intermediate pressure compressor 240, a water condenser 242, a second H2O recirculation pump 244, a CO2 compressor 246, and a designated storage location 248 for sequestering CO2.|[0040] In an embodiment, suitable biomass, e.g., any carbon neutral or carbon negative fuel (such as agricultural products or waste, wood, trees, or underbrush cleared from forests, other organic waste, other municipal waste, any combination of the foregoing, and the like), may be pre-processed by a torrefaction process involving the torrefaction reactor 202. The torrefaction reactor 202 may be of any suitable type, including, but not limited to, a fixed bed reactor, a rotary drum reactor, a microwave reactor, a fluidized bed reactor, and/or a horizontal and vertical moving bed reactor. The torrefaction process may include drying, in the torrefaction reactor 202, the biomass and heating it in an oxygen-deprived environment. The heat generated by combustion of the torrefaction gas may be used for both torrefaction and drying of the biomass. Once the biomass reaches 200° C.-350° C., the reaction may become exothermic, and the products of the reaction may include water, oxygen, nitrogen in the biomass, and Volatile Organic Compounds (VOCs). The VOCs may be burned to generate heat for drying and initiating the biomass reaction. The VOCs may be burned in pure oxygen or air.|[0041] The biomass may come out of the torrefaction reactor 202 in a state that is easier to grind and may have other beneficial properties, such as increased carbon content density, hydrophobic behavior, higher heating value, more homogenous composition, removal of waste mass (e.g., water, or low-energy compounds) so that transport may be more efficient, etc. This torrefied biomass may be transferred into a grinding system 204 (e.g., a Stage-1 coarse grinder, a Stage-2 coarse grinder, bowl mill, impact hammer, jet mill, or other suitable systems utilized in coal grinding, or any combination thereof, etc.) in which the torrefied biomass is ground down to a suitable size and prepared for conveyance and pressurization into a gasifier injector, wherein the torrefied biomass may be partially oxidized to separate it into its constituents. More particularly, the ground, torrefied biomass may be conveyed from the grinding system 204 to a load and lock hopper 208 by components (e.g., conveyor belts, pneumatic systems, screws, buckets, etc.) of the torrefied biomass conveyance system 206. The pressurization into the gasifier injector may occur via pneumatic or mechanical modalities. Examples of mechanical pressurization include use of a solids conveyance pump, or a slurry formation of the ground biomass with other constituents to be pumped into the pressurized volume of the gasifier 212. If pneumatics are utilized, the biomass may be pressurized using an inert gas, such as CO2 or N2, which may be introduced into the load and lock hopper 208. For example, CO2 siphoned away from other portions of system 200 may be diverted toward the load and lock hopper 208 via actuation of a 3-way valve 254 or other suitable flow control mechanisms. As used herein, suitable flow control mechanisms may include, e.g., valves, orifice plates, manifolds, backpressure regulators, etc., used alone or in combination with one or more sensors. The pressurized ground torrefied biomass may then be provided to a feed hopper 210, which may be configured to convey the pressurized ground torrefied biomass into the gasifier 212 at a predetermined controlled feed rate, e.g., via the gasifier injector. Although the torrefaction reactor 202, grinding system 204, and torrefied biomass conveyance system 206 are described herein and are depicted in FIG. 2, it is contemplated that one or more of these components may be omitted from system 200 if, for example, previously torrefied biomass is received by the system 200. In such an instance, system 200 may not need to be capable of running a torrefaction process and may be operable without utilization of one or more of the foregoing components if the biomass received into the system 200 (e.g., provided to the gasifier 212) is in an already torrefied state. In other embodiments, biomass may be introduced to the system that is not torrefied, e.g., biomass that is either untreated or is treated in a manner that does not include torrefaction.|[0042] In an embodiment, one of a variety of different types of gasifiers 212 may be utilized in the system 200, e.g., a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier types. The pressurized biomass constituents may be injected into the gasifier 212 and may be reacted with oxygen (O2) and injected steam in a gasification reaction. In an embodiment, the oxygen used in the gasification reaction may be obtained from an air separation unit 214 fluidly coupled to the gasifier 212 and provided to the gasifier 212. The air separation unit 214 may, for example, leverage vacuum pressure swing absorption (VPSA) or temperature swing adsorption (TSA) technology to separate air into its constituent components. In another embodiment, the oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 214 may be a cryogenic oxygen system. In yet another embodiment, the oxygen may be obtained from a dedicated oxygen delivery service or pipeline. The injected steam may be derived from one or more different sources. For example, water may be extracted from synthesis gas (syngas) prior to insertion into one or more compressors, as further described herein, and used as a basis for the injected steam. In addition or alternatively, water generated during combustion may be removed from the system, vaporized (e.g., with heat from the gasifier or a low temperature heat exchanger, etc.), and injected into the gasifier as steam.|[0043] The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H2), carbon monoxide (CO), and CO2, along with trace amounts of species formed as a result of trace elements in the biomass. The solid products that cannot be gasified in the reaction are collected at the bottom of the gasifier 212 as molten slag and ash (e.g., fly ash, bottom ash, etc.). The solid products are the result of solid elements and compounds within the biomass, such as potassium, calcium, silica, etc. These solid products may be collected and repurposed for other utilizations, e.g., as fertilizer. For example, the molten slag may be utilized in the production of cement concrete for roads.|[0044] After the syngas is formed within the gasifier 212, it must be quenched down to usable temperatures before it can be sent downstream. These temperatures may be determined, at least in part, by the composition of the downstream components, such as scrubber 218. More particularly, the temperatures may be chosen so as to cool the syngas so that water may condense in scrubber 218 in order to remove dirty chemicals. Such a process may be facilitated by introducing water or CO2 from other portions of system 200 into the gasifier 212. For example, the water may be derived from the low temperature heat exchanger 220 or the recuperator heat exchanger 228 and provided to the gasifier, e.g., via pump 216. As another example, water extracted from the biomass drying in the torrefaction reactor 202 may be utilized. If water from within system 200 is reused, this water may need to be cleaned or otherwise processed prior to use. Alternatively or additionally, water may be supplied from an external source, such as a water plant or a body of water. In an embodiment, CO2 may be introduced into the gasifier 212, e.g., from the low pressure compressor 240. In other embodiments in which the gasifier is run at a higher pressure, the CO2 may be introduced into the gasifier from the high pressure recirculation pump 232. The introduction of water or CO2 to quench the syngas may enable formation of non-liquid ashes on the condensable species. The ashes may be recovered and removed from the main flowpath of the machinery that makes power, which may allow for longer operation of the machinery. The non-liquid ash is biogenic in nature and may be mostly composed of minerals and compounds used by the biomass. These can be delivered back into the biodome where they were taken from. Additionally or alternatively, they may be extracted and utilized as fertilizer. After the syngas leaves the gasifier 212, the water may be removed, e.g., via the scrubber 216 or the low temperature heat exchanger 220. The CO2 may be kept in the stream for oxyfuel combustion purposes and expanding in the turbine system downstream.|[0045] In an embodiment, the syngas may leave the gasifier 212 and be transported into the scrubber 216, where it may be processed in order to remove ash particulates and halides in order to produce a syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system. Additionally or alternatively, the syngas may be processed with one or more candle filters or other available gas processing systems to remove particulate contaminants.|[0046] After exiting the scrubber 216, the syngas may pass through a low temperature heat exchanger 220. The syngas heat from the gasification oxidation reaction may be removed at the low temperature heat exchanger 220, which may be placed at a low temperature suitable for steam extraction, thereby acting as a syngas cooler. In an embodiment, this steam may be utilized to remove captured CO2 from sorbent material in a direct air capture fan bank 238 of an integrated direct air capture carbon system, as further described herein. For instance, after the scrubber, there may be a large amount of steam and/or saturated water in the syngas. This steam and/or saturated water may be used to boil another, lower pressure water stream (e.g., one that is situated at ambient pressure) to steam in the low temperature heat exchanger 220, which may then be routed to regenerate the sorbent in the direct air capture fan bank 238. In some aspects, this steam may be introduced into gasifier 212 to promote hydrogen formation in the gasifier and, specifically, to use water shift to change how much H2 and CO are in the syngas. Additionally or alternatively, the extracted heat from the syngas may be provided to the CO2 cycle (e.g., in which CO2 and/or sCO2 is used as the working fluid, etc.) to increase efficiency. It is important to note that although FIG. 2 only illustrates that the syngas passes through a single heat exchanger (i.e., the low temperature heat exchanger 220), such a designation is not limiting. For example, in an embodiment, the system 200 may contain two heat exchangers that may be configured to pull and cool the syngas (e.g., the low temperature heat exchanger 220 and another heat exchanger positioned between the gasifier 212 and the scrubber 218, as illustrated in FIG. 6, which is later described herein). The other heat exchanger may be a high-temperature heat exchanger, which may be operable to generate more steam.|[0047] Additionally or alternatively, in some implementations, the gasifier 212 may have cooling water in its jacket/liner and may contain an integrated heat exchanger inside. In some embodiments of the systems described herein (e.g., systems 100, 200, 500, 600, 700), heat may be additionally or alternatively removed from the cooling elements of the gasifier jacket/liner, or from cooling elements associated with one or more other components of the system. In such an embodiment, heat may be removed directly through cooling of a component of the disclosed systems (e.g., a gasifier liner of, for example, system 100, 200, 500, 600, 700), in conjunction with or as opposed to removing heat by cooling the syngas product (e.g., cooling may be achieved via the liner, the syngas, or a combination thereof). The removed heat may be directed to other components of the disclosed systems in order to increase the efficiency of the systems. For example, steam from syngas heat rejected by the low temperature heat exchanger 220 may be directed to a DAC bank 238 to remove the CO2 gas from the sorbent materials, as further described herein. Systems described herein provide examples of where heat may be pulled from and re-directed to in order to increase the overall efficiency of such systems.|[0048] Once the syngas is fully cooled and dried, it may be compressed to full pressure (which is a suitable combustion injection pressure, e.g., approximately 415 bar) if needed by, for example, a syngas boost compressor 222, which is configured to increase the temperature and pressure of the syngas. For example, in an exemplary flow, the cooled syngas leaving the low temperature heat exchanger 220 may enter the syngas boost compressor 222 at a pressure of approximately 40 bar and a temperature of approximately 350° K. The compressed syngas stream exiting the syngas boost compressor 222 may have a pressure of approximately 413 bar and a temperature of approximately 685° K.|[0049] After being compressed, the syngas may be introduced into a combustor 226 (e.g., a bio syngas oxy combustor) where it may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 214 and compressed via an oxygen boost compressor 224), thereby creating a stream of mostly water and CO2. The stream resultant from the oxidation reaction between the syngas and oxygen stream may be combined in the combustor 226 with a recirculated stream of mostly CO2. The recirculated stream of CO2 may have been passed through a recuperator heat exchanger 228 to preheat it to an amenable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power is left to run all the supplemental power requirements of system 200). More particularly, an inlet of recuperator heat exchanger 228 may be configured to receive CO2 streams having temperatures of about 800° K to about 900° K. The CO2 exhaust stream exiting recuperator heat exchanger 228 may have a temperature in the range of about 725° K to about 825° K.|[0050] In an embodiment, a pressure and temperature of an exemplary combustion stream exiting the combustion outlet of the combustor 226 may be approximately 375 bar and approximately 1036° K, respectively. The combustion stream may be diluted and may then be expanded in a turbine, e.g., a first turbine 230 (i.e., a high pressure turbine). The high pressure turbine 230 may be a direct fired turbine and is the first main engine turbine to receive the combustion stream from the combustor 226. It is designed to efficiently extract work out of the high pressure combustion stream, which is thereafter utilized to power the main cycle recirculation pump 232, the operation of which is further described below.|[0051] In an embodiment, after the combustion stream goes through expansion at the first turbine 230, a pressure and temperature of an exemplary first turbine exhaust stream may be approximately 281.3 bar and approximately 995° K, respectively. The turbine exhaust stream may be injected into a second turbine 234 (i.e., a low pressure turbine) to fully expand to its lowest pressure level in the cycle. The second turbine expansion may provide power to a generator 236 (i.e., a turbo alternator) that is attached mechanically to a rotor of the second turbine 234 and to a low/intermediate pressure compressor 240.|[0052] While a first turbine and a second turbine are described herein, it is contemplated that one, two, or three or more turbines may be incorporated.|[0053] Energy generated by the generator 236 may be utilized in a variety of different ways based on the operating mode of the system 200. For instance, in a first operating mode, the system 200 may behave as a power plant, and the power generated by the generator 236 may be output from the system 200. For example, power may be output in the form of electricity and sent to a power grid, which may be associated with a third party (e.g., an energy provider). In some aspects, power may be output in the form of mechanical power. In a second operating mode, the system 200 may behave as a CO2 capture system, and the power generated by the generator 236 may be utilized to provide power to components of a DAC system (e.g., air-contacting fans and compressors). In a third operating mode, the system 200 may be configured to distribute the power from the generator 236 to both the power grid and to the DAC system. Additional details regarding the various operating modes of the system 200 and the power redirection paths are further described herein.|[0054] In an embodiment, after the combustion stream goes through expansion at the second turbine 234 (if more than one turbine is used), a pressure and temperature of an exemplary second turbine exhaust stream may be approximately 63 bar and approximately 800° K. The second turbine discharge stream is then passed through a recuperator heat exchanger 228. Although one recuperator heat exchanger 228 is depicted in FIG. 2, more than one heat exchanger may be incorporated in system 200. The recirculating CO2 stream from the high-pressure recirculation pump 232 may also be introduced to recuperator heat exchanger 228. This allows the second turbine discharge stream to exchange heat with the recirculating CO2 stream pump from the high-pressure recirculation pump 232, thereby heating the recirculating CO2 stream as it is directed to the main combustor 226 and cooling the second turbine discharge stream as it is being directed to a DAC fan bank 238. In various embodiments described herein, heat in the CO2 stream having passed through recuperator heat exchanger 228 may be used to boil water at the low temperature range of recuperator heat exchanger 228. In some aspects, heat may be pulled from recuperator heat exchanger 228 directly, instead of pulling heat from a CO2 stream. In still other aspects, heat may be pulled from low or high pressure heat exchanger streams. Pulling heat in this manner may increase thermal power at lower quality temperatures, increasing the efficiency of system 200. Referring back to the embodiment of FIG. 2, the second turbine discharge stream may lose the majority of its water upon passage through the recuperator heat exchanger 228. This water may be repurposed for utilization in other aspects of the system 200 (e.g., as quench water provided to the gasifier 212, as steam provided to sorbent material of a direct air capture system, etc.).|[0055] In an embodiment, after passage through the recuperator heat exchanger 228, a pressure and temperature of an exemplary second turbine discharge stream (i.e., the recuperator exhaust stream) may be approximately 60 bar and approximately 360° K to approximately 375° K. The cooled second turbine discharge stream may be directed to pass through the DAC bank 238. An outlet of the DAC bank 238 may be held at approximately 320° K to remove the rest of the heat in order to return the stream to approximately ambient temperature, e.g., of about 320° K or less. In an embodiment, the DAC bank 238 may reject heat via conduction at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration (e.g., 300° K-322° K). More particularly, the DAC bank 238 may include a piping manifold that is interconnected with low temperature CO2 sorbents. In an embodiment, one type of CO2 sorbent may be a metal-organic Framework (MOF), e.g., “mmen-Mg2(dobpdc).” The MOF sorbents have been shown to be suitable in the regeneration process (i.e., the process by which the sorbent materials are made reusable for another cycle). For example, MOF-based technology may be capable of regenerating at temperatures of about 353.15° K to about 393.15° K, which may be less energy intensive and costly. Other embodiments may leverage other types of low temperature CO2 sorbents, such as zeolite materials or ammonia based sorbents. Non-limiting types of low temperature CO2 sorbents may include, for example, liquid amines (e.g., monoethanolamine (MEA)), solid amines (e.g., amine-functionalized cellulose, amine-functionalized silicas), zeolites (e.g., Zeliote 13X (Na86[(AlO2)86(SiO2)106]·nH2O), Zeliote 4A (Na12[(AlO2)12(SiO2)12]·nH2O)), covalent organic frameworks (COFS) (e.g., COF-609), or one or more other types of MOFs (e.g., MOF-74).|[0056] In an embodiment, to facilitate the carbon capture, atmospheric air may be passed through a plurality of fans of the DAC bank 238 to cool the sorbent and allow it to come in contact with the air. In some embodiments, the fans of DAC bank 238 may be used as fans for condenser units utilized in the CO2 loop, thereby increasing system efficiency by taking advantage of the power utilized to run DAC bank 238. As the air comes in contact with the sorbents, CO2 from the air is trapped in a charge cycle. For the discharge cycle, the cooled second turbine discharge stream may be used to heat the sorbent material in the DAC bank 238 (e.g., via conduction). This preheats the sorbent material to allow it to accept the steam from the syngas heat rejected by the low temperature heat exchanger 220. This steam is used to remove the CO2 gas from the sorbent materials. Preheating the sorbent material, using heat from the system to generate steam, or using already produced steam from the system may reduce the amount of energy needed to perform carbon capture, and may increase the efficiency of the system. In some embodiments, instead of just preheating the sorbent material, aspects of the system may be configured to enable the cooled second turbine discharge stream—or heat pulled from other heat sources within system 200—to provide substantially all heat necessary to run the DAC bank 238. The freed CO2-containing stream is passed through a condenser 242, in which water in the freed CO2-containing stream is removed and pumped, via pump 244, back to the low temperature heat exchanger 220 to be utilized in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in a CO2 compressor 246 and sent to a pipeline via valve 252 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated underground storage location. For example, the CO2 may be transported to a well 248, which may be a class VI well. In another embodiment, the pipeline may transport the sequestered CO2, e.g., to one or more other contracting entities. In some aspects, at least a portion of the CO2 released from the sorbent may be directed to other components of system 200, e.g., to the lock and load hopper 208, as opposed to a pipeline or storage. For example, CO2 diverted to lock and load hopper 208 may be used to pressurize biomass prior to introduction into gasifier 212. The three-way valve 254 or other component may be used to optionally direct CO2 to either a pipeline/storage or to load and lock hopper 208.|[0057] In an embodiment, after passage through the direct air capture bank 238, a pressure and temperature of an exemplary cooled CO2 stream may be approximately 131 bar and approximately 360° K. The cooled CO2 stream may then be transported to a low/intermediate pressure compressor 240 to go through the critical point to form, in some embodiments, sCO2 before being injected into the high pressure recirculation pump 232, configured to increase the pressure of the CO2 stream to combustion injection pressures. For example, the recirculating pump discharge stream may have a pressure and temperature of approximately 417 bar and approximately 360° K. In an embodiment, one or both of the cooled CO2 stream exiting the DAC bank 238 and the compressed CO2 stream exiting the low/intermediate pressure compressor 240 may be cooled by another cooler 256 to increase efficiency. The recirculating pump discharge stream may then be heated via passage through the recuperator heat exchanger 228 and then recycled back into the combustor 226. After passing through the recuperator heat exchanger 228, the stream may have a pressure and temperature of, e.g., approximately 396 bar and approximately 730° K. In an embodiment, the CO2 that was created in the combustion process may be siphoned through a 3-way valve or other suitable flow control mechanism (e.g., an orifice plate configured to throttle the amount being rejected, or via leakage passages inside the main pump flow region, etc.) at a pressure that is ready for pipeline injection or liquefied transport through highway into the well 248 (as directed, e.g., by valves 250 and 254 or other suitable flow control mechanism). Suitable pipeline injection pressures may be approximately 142 bar. In an embodiment, the low/intermediate pressure compressor sections may utilize intercooling to increase cycle efficiency (however this is not necessary for the system 200 to operate).|[0058] It is important to note that effective operation of the system 200 may be achieved with fewer or greater components. Stated differently, the number and type of components illustrated in FIG. 2 is only exemplary, and other embodiments may be viable in which fewer components are present but may nevertheless accomplish the same outcome.|[0059] FIG. 3 depicts a simplified version of power generating portions of system 200 of FIG. 2. Additionally, Tables 1 and 2 depicted below provide exemplary thermodynamic states at various locations throughout system 200. It is important to note that the provided temperatures and pressures are only examples, and they may change, e.g., depending on the size of the power plant, the type of biomass being used, variation in carbon content of the syngas, the efficiency of the power cycle, or other factors or combinations of factors. In an embodiment, this cycle may allow for operation at high pressures to avoid the CO2 density gradients above the vapor dome, which may cause operation problems in the turbomachinery systems if the heat rejection step is done to atmosphere. If the pressure entering the pump is close to the vapor dome of the CO2 (when it becomes gas, and is out of the supercritical state), the temperature that the inlet of the pump is cooled to may affect the density of the fluid to the point that the pump system in the cycle cannot function. Accordingly, the inlet pressure condition of the pump may be placed at a higher pressure than the critical pressure of CO2, as the fluid density gradients may be less sensitive to inlet temperature conditions. This may allow system 200 to operate with heat rejection that is independent of water requirements (i.e., uses air to cool the cycle).|[0060] TABLE 1 Point Pressure Temperature Mass Flow Units Bar K. kg/s 1 125 313 105 2 395 357 105 3 375 750 105 4 355 916 112.89 5 258 872 112.89 6 137.5 790 112.89 7 130.6 365 110.92 8 55 300 5.05 9 390 472 5.05 10 55 300 2.84 11 390 Not modeled 2.84 12 1 365 1.97 13 150 320 5.92 |[0061] TABLE 2 Pressure Temperature Point Temperature Range Range Units K. bar K. Compressor 1 313 30-65 —Suction Compressor 2 381 140-400 —Discharge Recuperator 3 807 140-400 700-950 Outlet Combustor 4 1054 130-200 900-1350 Outlet HP Turbine 5 935 70-200 —Outlet Power Turbine 6 839 30-65 700-950 Outlet Recuperator 7 391 30-40 300-400 Outlet Syngas from 8 320 30-50 —Gasifier Syngas to 9 370 140-400 —Combustor Oxygen from 10 290 40-80 —ASU Oxygen to 11 365 140-400 —Combustor Water from 12 313 20-40 —Cycle Product CO2 13 320 35-150 — |[0062] Referring now to FIG. 4, an exemplary method of operating an integrated carbon sequestration and power generation system, e.g., switching an operating mode of an integrated carbon sequestration and power generation system, is disclosed. The exemplary process flow 400 may be implemented by the components of the system 100, 200.|[0063] As previously described above, the system 100, 200 may be capable of operating in a variety of different operating modes, wherein the power produced by the generator 236 of the system 100, 200 (e.g., as a result of expansion of the combustion stream across the low-pressure turbine 234) may be provided to a specific destination and may be utilized to divert power to specific components based on the selected operating mode. The system 100, 200 may switch between the operating modes without changing the operation of the cycle, thereby enabling the system 100, 200 to have diverse utility and allowing it to participate in a variety of different markets. Although flow 400 is described in conjunction with a computer control system, it is contemplated that flow 400 may proceed either manually or automatically.|[0064] At step 405, a computer control system may cause the system 100, 200 to operate in a first operating mode. In an embodiment, the system 100, 200 in the first operating mode may be configured to direct the energy produced by the turbine generator 236 to power a DAC carbon sequestration system that is integrated as part of the system 100, 200. In this regard, the power may be directed by actuating switching relays, as governed by the computer control system, to activate and power one or more air-contacting fans in the DAC bank 238 as well as the DAC CO2 compressor 246. Once activated, the DAC system may operate to capture and sequester atmospheric carbon. Furthermore, the system 100, 200 may configure itself or may manually be configured to provide heat from thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic power cycle) into the sorbent materials contained in the DAC bank 238 (e.g., via conduction heat provided by the exit flow from the recuperator heat exchanger 228, etc., as described above).|[0065] At step 410, the computer control system may determine whether a predetermined condition is satisfied. In an embodiment, satisfaction of the predetermined condition may initiate redirection of the power produced by the turbine generator 236 to a second destination, as described in steps 420 to 425. Alternatively, if the predetermined condition is not satisfied, the computer control system may maintain the system 100, 200 in the first operating mode, as described in step 415. A plurality of potential types of predetermined conditions are contemplated herein, and are further described below.|[0066] In an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether one or more other power sources are available to supply power to a power grid. For example, the predetermined condition may correspond to whether a power grid operator has access to another type of renewable energy to provide power to the power grid. The predetermined condition may be considered satisfied responsive to determining that the power grid operator entity does not have access to the other types of renewable energy. For context, and further to the foregoing, the cost of power may fluctuate throughout the day, with certain periods being more expensive than others. These fluctuations may be based, in part, on the types of renewable energy (e.g., solar energy, wind energy, etc.) that the power grid operator has access to. Specifically, renewable energy providers may be able to provide power to the power grid operator at a lower cost than conventional gas and/or coal-powered power plants are able to. Accordingly, when renewable energy sources are available, the cost of power may be relatively lower because the power grid operator may obtain power for their power grid at a lower cost. However, when conditions prevent the renewable energy providers from operating (e.g., due to no or low sunlight or wind, poor weather conditions, etc.), the power grid operator may need to obtain power for their power grid at a relatively higher cost because it may be relatively more expensive to derive energy from gas and/or coal powered plants. These periods of high electricity cost, or “peaker” periods, may be periods of time that occur daily (e.g., at night when solar power sources are unavailable) and/or may last for an extended time (e.g., several days or weeks depending on weather, etc.).|[0067] The computer control system may be configured to anticipate when the renewable energy providers will be unable to operate and generate renewable energy. For instance, in an embodiment, the computer control system may receive an indication from a timer or sensor that may be configured to provide an alert to the computer control system each day at a predetermined time. The predetermined time may be an estimated time by which the renewable energy providers are no longer able to provide power to the power grid. In an embodiment, the predetermined time may be static (i.e., the same each day) or may be dynamic and may adjust throughout the year. In another embodiment, the computer control system may have access to historical sunlight data for the relevant geographical region (e.g., stored in a database, accessible via an online source, etc.), which may provide indications of the average daily sunrise and sunset times throughout the year. Solar-based energy providers may be operable during the periods between sunrise and sunset and inoperable during the periods between sunset and sunrise. Accordingly, the computer control system may associate a known daily sunset time as the end of the power grid operator's ability to receive renewable energy for the day. In another embodiment, the computer control system may access weather forecast data (e.g., from an online source, etc.), which may provide indications of upcoming weather events that may affect a renewable energy provider's ability to produce renewable energy. For example, if the weather forecast data for an upcoming day predicts cloudy and/or stormy conditions, the computer control system may identify that a solar energy provider's ability to produce power may be limited during those times. In another example, if the weather forecast data predicts a severe storm or weather event (e.g., a winter storm, hurricane, tornado, etc.), then the computer control system may identify that a solar energy provider's ability to produce power may be impaired for an extended period of time (e.g., several days, etc.). In a further example, if the weather forecast data for an upcoming day predicts there to be little or no wind, the computer control system may identify that a wind energy provider's ability to produce power may be limited during those times.|[0068] Additionally or alternatively to the foregoing, in an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether an increased load is required by a power grid of a power grid operator. The predetermined condition may be considered satisfied responsive to determining that the increased load required by the power grid is greater than a predetermined threshold. More particularly, in an embodiment, various types of events may occur that place additional stress on a power grid. Some of these events may be scheduled, whereas others may not be. For instance, with respect to the former, a major concert, sporting event, festival, etc., occurring in a region may require additional power to be provided by the power grid. The computer control system may have access to a schedule of these events and may anticipate which event may place a load demand on the grid that is greater than the predetermined threshold. In another example, with respect to the latter, a weather event may occur that increases the load demand required by the power grid (e.g., unexpected heat wave that may cause individuals to run their air conditioners or fans more than usual, a cold stretch that may cause people to use more heat than usual, etc.). In these situations, the computer control system may receive an indication (e.g., from the power grid operator) or otherwise determine that the load demand on the power grid is greater than the predetermined threshold.|[0069] Additionally or alternatively to the foregoing, in an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether a power grid of a power grid operator is becoming destabilized. In an embodiment, destabilization of the power grid may occur, for instance, because various assets relied on by the power grid operator may fail (e.g., other power providers that are contracted to provide power to the grid are unable to do so). These assets may fail as a result of various situations such as experiencing operational issues, damage derived from weather, geological, and/or other natural disaster events (e.g., damage from fire, earthquake, flood, etc.), and the like. In an embodiment, the predetermined condition may be considered satisfied responsive to anticipating that the power grid will become destabilized within a predetermined time threshold or for greater than a predetermined time threshold.|[0070] Additionally or alternatively to the foregoing, in an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether a revenue projection for operating the system 100, 200 in a second operating mode is greater than operating the system 100, 200 in the first operating mode. The predetermined condition may be considered satisfied responsive to determining that operating the system 100, 200 in the second operating mode is more profitable. As further described herein, the system 100, 200 may operate in a first or second operating mode. When in the second operating mode, the system 100, 200 may be configured to redirect the power produced by the generator 236 to a power grid of a power grid operator. In an embodiment, the system 100, 200 may reconcile whether a first projected value generated by or derived from sequestering and selling CO2 (e.g., the collective revenue obtained from selling CO2 at a contract or spot price to a third party, from carbon sequestration tax breaks, etc.) may be greater than a second projected value generated from providing power to the power grid. Responsive to determining that the projected value is greater for operation in the second mode, e.g., in a mode that diverts generated power to the power grid, the predetermined condition may be considered satisfied.|[0071] Responsive to determining, at step 410, that the predetermined condition is not satisfied, the computer control system may, at step 415, maintain the operating mode of the system in the first operating mode. Conversely, responsive to determining, at step 410, that the predetermined condition is satisfied, the computer control system may, at step 420, initiate switching an operating mode of the system 100, 200 from the first operating mode to the second operating mode. Once switched to the second operating mode, the computer control system may cause, at step 425, the system 100, 200 to operate in the second operating mode to redirect the energy from the DAC system to a power grid.|[0072] In an embodiment, the system 100, 200 in the second operating mode may output power produced by the generator 236 in an electrical or mechanical form. For simplicity purposes, the majority of this disclosure is described with reference to examples in which electrical power is output and, more specifically, to situations in which the system 100, 200 may act as a power plant and may be configured to direct the power produced by the generator 236 directly to a power grid of a power grid operator, but any output of power is contemplated. Once switched to the second operating mode, the DAC system may be turned substantially off (i.e., only the fans that are needed to reject the heat from the CO2 stream at the bottom of the power cycle may be utilized), and the syngas low temperature steam may be utilized to preheat any of the fluids in the power cycle. Alternatively to the foregoing, the second operating mode of the system 100, 200 may be an “intermediate” mode in which the system 100, 200 is configured to direct a first portion of the energy produced by the generator 236 to components of the DAC system and a second portion of the energy to a power grid. In an embodiment, the system 100, 200 in the intermediate mode may only power a subset of the air-contacting fans in the DAC bank 238, and the CO2 compressor 246 may be run at a lower power condition according to the appropriate amount of CO2 collected in the DAC system.|[0073] In an embodiment, the switching, at step 420, may be facilitated by actuating a series of valves configured to control transport of the working fluid CO2 through the system 100, 200. More particularly, the valving may be used to direct the CO2 heat flows into more contactors or coolers, depending on the operating mode being switched to. In an embodiment, the system 100, 200 may be operable to switch back and forth between the two operating modes without changing the operation of the supercritical cycle. More particularly, the CO2 heat flows may be managed as the CO2 sorbent packs are regenerated in order to promote regular or constant heat rejection on the sCO2 cycle. For instance, switching the operating mode from a power plant or power supply mode to a carbon sequestration mode may involve a plurality of steps. In power plant mode, in which energy may be generated and, e.g., output to a power grid, the power cycle may reject heat using a subset of fans from the contactor bank. Responsive to detecting an indication to initiate the switch between modes, the system 100, 200 may begin directing more power to the DAC bank 238 (e.g., in a controlled manner following structural considerations set by the DAC system). As more power is directed away from the grid and to the DAC bank 238, the amount of air scrubbing performed by the system 100, 200 may correspondingly increase. CO2 working fluid from the cycle may be directed to the contactors while scrubbing of the air is performed. Additionally or alternatively, heat may also be sent from at least the low temperature heat exchanger 220 (i.e., the syngas cooling system) to the DAC bank 238. Upon detection that a predetermined number of contactors in the DAC bank 238 are saturated with CO2 from the atmosphere, the system 100, 200 may be configured to dynamically remove at least a subset of fans from operation and to start utilizing conduction to heat the sorbents to a predetermined temperature, thereby rejecting its heat to the sorbent and initiating the process to release CO2. Supplemental cooling of the CO2 working fluid in the cycle may be achieved by sending the CO2 working fluid to other saturated sorbent banks in series (if needed). More and more power may be directed to the DAC bank 238 until all power is directed to the DAC bank 238, and the system is in carbon sequestration mode.|[0074] In the reverse scenario, the system 100, 200 may initiate a switch from a carbon sequestration mode to a power plant mode. Upon detecting initiation of this switch, the system 100, 200 may begin reducing power to fan modules in the DAC bank 238, turning off banks of fans, and thereby reducing the air scrubbing potential of the system 100, 200. As the system is switched to the carbon sequestration mode and power in the fan modules is reduced, heat rejection may be concentrated on a subset of contactors, which are allowed to saturate with CO2. For example, valving may be utilized to direct hot CO2 (that which preheats the sorbent to regenerate) between separate fan modules of the DAC bank 238. When switching to power plant mode, one or more valves may iteratively close to keep the CO2 flow directed only to the condenser fans instead of the DAC bank 238. As the amount of air scrubbed CO2 falls, less and less power may be directed to the DAC bank 238, until DAC bank 238 is shut down. In some aspects, power to the DAC bank 238 may be stopped upon determining that the air scrubbing potential of the contactors falls below a predetermined threshold. As steady state power regeneration is achieved, power cycle heat loads may thereafter be ejected, and power previously utilized to power the contactor fans in the DAC bank 238 may be redirected to a power grid.|[0075] The exemplary switching process described above enables the system 100, 200 to operate during the “peaker” period of high electricity cost. More particularly, gas combined-cycle power plants and/or coal power plants may require a long startup period when turning on before they are ready to provide power to a power grid. As a result, fuel must be consumed for an extended period of time before any power can be provided to the power grid. This results in both additional CO2 and other forms of pollution being emitted into the atmosphere by traditional power plants, as well as wasted fuel, e.g., coal, resources and thus money. Because renewable energy sources are able to produce power for the power grid at a lower cost compared to conventional gas or coal plants for the reasons described above, it may not be feasible for owners of conventional power plants to operate throughout the day. As a result, conventional power plants may need to turn off and then back on again, e.g., at the end of the day when renewable sources of power may not be available or may be available in lower quantities. The need to come on line for only part of the day, combined with the long startup period, may lead to wasted energy and resources, as well as excess pollution.|[0076] However, the system 100, 200 may address one or more of these shortcomings by providing an integrated power generation system and carbon capture system that is configured to function continuously, or for longer periods of time, either as a power plant for supplying a power grid or as a carbon sequestration system. By being able to operate continuously and switch between a power plant and carbon sequestration system, system 100, 200 may avoid or reduce the startup penalties in terms of emissions or life of the engine components experienced by traditional power plants, because the CO2 cycle system components may continue to run even when not supplying power to the power grid, as it is just the load destination that changes. Systems of the present disclosure may thus conserve resources, reduce pollution, e.g., CO2 emission, and offer a carbon negative way of generating power. Systems 100, 200 may achieve carbon negative power generation by using biomass as fuel and CO2 as the working fluid, and the systems may function as even further carbon negative when the DAC system is incorporated.|[0077] While products of the systems described herein (e.g., heat, water, syngas, etc.) may be described as being reused within the system to promote efficiency of the system, reuse of products is not required.|[0078] The time period for facilitating the switching, at step 420, from the first operating mode to the second operating mode, or from the second operating mode to the first operating mode, at step 440, may vary. For example, in an embodiment, the computer controller system may cause the system 100, 200 to be switched between the operating modes in a first “regular” time period, e.g., in one hour or less. Alternatively, some situations may require the switching to be facilitated quicker (e.g., when a sudden load demand on the power grid is realized, when a power grid is about to become destabilized, etc.). In these situations, the system 100, 200 may undergo a “hard switch” from a carbon sequestration mode to a power supply mode in a matter of minutes. This type of hard switching, however, may result in a loss of captured CO2 mid-process or at the expense of component long-term life.|[0079] At step 430, the computer control system may determine whether the predetermined condition is no longer satisfied. This determination may vary based on the type of predetermined condition, as described below.|[0080] In an embodiment, the predetermined condition may be considered to no longer be satisfied responsive to determining that the power grid operator has access to the other types of renewable energy. In an embodiment, this determination may be facilitated by receiving a second indication from the aforementioned timer or sensor. More particularly, just as the timer or sensor described above provided an indication to the computer control system to switch from the first operating mode to the second operating mode at a predetermined time, the timer or sensor may similarly provide a second indication to the computer control system to switch from the second operating mode to the first operating mode. The second indication may be received, for example, when a predetermined scheduled time has arrived. Similar to the first indication, the receipt of the second indication may be static (e.g., provided at the same time each day) or dynamic (e.g., provided at different times throughout the year based on context). Additionally or alternatively, in another embodiment, the determination may be facilitated by leveraging the historical sunlight data for the relevant geographic region to identify a sunrise time, which may be associated with a power grid operator's ability to receive another type of renewable energy, e.g., solar power. Additionally or alternatively, in another embodiment, the determination may be facilitated by leveraging the weather forecast data to identify whether the upcoming weather conditions may be favorable for the generation of certain types of renewable energy. For example, the weather forecast may indicate that the following day may be sunny or windy, which may be favorable for the generation of solar power or wind power, respectively.|[0081] In an embodiment, the predetermined condition may be considered to no longer be satisfied responsive to determining that the increased load previously required by the power grid is no longer needed. In an embodiment, this determination may be facilitated by identifying that the increased load has fallen or is expected to fall below the predetermined threshold. In some aspects, the computer control system may receive an indication from the power grid operator that there is or will no longer a need for additional power. Additionally or alternatively, the computer control system may anticipate when the power grid will no longer have a need for the additional power. For example, the computer control system may identify, from available schedule information, a designated conclusion time of a scheduled stress-producing event (e.g., concert, sporting event, festival, etc.). As another example, the computer control system may dynamically anticipate the conclusion of the scheduled stress-producing event based on access to historical context data (e.g., the computer control system may anticipate the conclusion of a concert based on knowledge of the runtime lengths of previous concert performances in general or previous performances of that specific performance, etc.). With respect to weather events that generate stress on the power grid, the computer control system may identify that the anticipated conclusion of the weather event may cause the stress on the power grid, and thus the need for additional power, to be removed. For example, upon conclusion of a heat wave, individuals may resume normal habits with respect to the operation of energy-consuming devices (e.g., individuals may no longer run their air conditioners or fans more than normal, etc.).|[0082] In an embodiment, the predetermined condition may be considered to no longer be satisfied responsive to determining that the power grid has been stabilized. In an embodiment, this determination may be facilitated by receiving an indication from the power grid operator that the failed assets that caused the grid destabilization have been repaired and/or are now operational again (e.g., other power providers contracted to provide power to the grid have renewed their ability to provide power to the grid, etc.). Additionally or alternatively, in another embodiment, the determination may be dynamically facilitated by anticipating a time period that a failed asset may be unavailable for based upon knowledge of the operational issue and/or weather, geological, and/or natural disaster event that caused the asset to be unavailable. For example, the computer control system may identify that a certain operational issue affecting a power plant may be remedied in an X time period, wherein the conclusion of the X time period may approximately correspond to grid stabilization. In another example, the computer control system may estimate, from weather and/or historical event data, an amount of time after the conclusion of an event that caused the asset to fail when the asset may be operational again.|[0083] In another embodiment, the predetermined condition may be considered no longer satisfied responsive to determining that the value projection for operation of the system 100, 200 in the second operating mode is lower than the value projection for operation of the system 100, 200 in the first operating mode. Stated differently, the predetermined condition may no longer be considered satisfied responsive to determining that operating the system 100, 200 in the second operating mode is less valuable to society, e.g., profitable, than operating the system 100, 200 in the first operating mode. In an embodiment, this determination may be facilitated by identifying that the projected value generated from sequestering and selling CO2 is lower than the projected value for providing power to the grid (e.g., because a spot price to sell CO2 has increased, etc.).|[0084] Responsive to determining, at step 430, that the predetermined condition remains satisfied, the system may, at step 435, maintain the system 100, 200 in the second operating mode. In an embodiment, the second operating mode may be maintained for as long as the predetermined condition remains satisfied. Alternatively, in another embodiment, the second operating mode may only be maintained for a predetermined period of time or until a predetermined amount of power has been provided to the power grid, irrespective of whether the predetermined condition remains satisfied.|[0085] Responsive to determining, at step 430, that the predetermined condition is no longer satisfied, the system 100, 200 may, at step 440, initiate switching of the operating mode from the second operating mode to the first operating mode. Method 400 may be repeated a plurality of times during operation of system 100, 200. This switching may enable the system 100, 200 to cycle back and forth between the two operating modes based upon the demands of a particular situation or based upon whatever is most advantageous to the system (e.g., value in terms of operating costs, revenue production, carbon capture, power generation, etc.).|[0086] Provided below are a plurality of alternative systems that may be used as system 100—in place of system 200—for performing carbon sequestration and power generation. Each of these alternative systems contains one or more variations to the components and/or process operations detailed in system 200 of FIG. 2, and may be used in a manner similar to or interchangeable with system 200 as described herein. For example, the systems of FIGS. 5, 6, and 7 may be used to perform the methods of FIG. 4 or as described above with respect to system 200. Furthermore, although portions of the systems described herein designate component origins and destinations from where heat may be removed and directed to, respectively, these are not necessarily limiting, and heat may be removed from components of any of the systems and/or from the produced syngas and directed to portions of the systems that require heat to function.|[0087] Referring now to FIG. 5, an exemplary integrated carbon sequestration and power generation system is 500 is depicted. System 500 may use biomass as fuel. As discussed in regards to systems 100 and 200 above, biomass refers to any carbon neutral or carbon negative fuel. For instance, potential types of biomass may include, e.g., wood products, such as wood processing wastes (e.g., firewood, wood pellets, wood chips, lumber and sawdust waste, etc.), agricultural products, including crops and waste materials (e.g., corn, soybeans, sugar cane, woody plants, algae, etc.), biogenic materials in municipal solid waste (e.g., paper, cotton, wool products, food, yard waste, etc.), non-biogenic materials in municipal solid waste (e.g., plastics or petroleum-based products), animal manure, or human sewage (e.g., bio waste discharge from water treatment plants). In an aspect, suitable biomass may be pre-processed by a torrefaction process, e.g., performed at a torrefaction reactor 502. In other aspects, however, pre-torrefied or otherwise pre-processed or unprocessed biomass may be received by system 500, and system 500 may not include a torrefaction reactor 502.|[0088] If incorporated into system 500, the torrefaction process may include drying the biomass and heating it in an oxygen deprived environment. Once the biomass reaches approximately 250-350 degrees C., the reaction becomes exothermic, and the products of the reaction include water, oxygen, nitrogen in the biomass, and VOCs. The VOCs may be burned to generate heat for drying and initiating the biomass reaction (which may be burned in pure oxygen or air).|[0089] In an aspect, the biomass may come out of the torrefaction reactor 502 (if included) easier to grind and containing other beneficial properties, such as increased carbon content density. This torrefied biomass may be fed into a grinding system 504, which may be configured to prepare the biomass for pressurization and conveyance, e.g., via a lock hopper 506, into an injector 508 that subsequently conveys the ground, torrefied biomass into a gasifier 510, where the biomass is partially oxidized to separate it into its constituents, e.g., using oxygen at least obtained from an air separator unit 512. The CO2 may then be pressurized. In an embodiment, the main gaseous products of the foregoing reactions include hydrogen (H2), carbon monoxide (CO), and carbon dioxide (CO2), along with trace amounts of species formed due to trace elements in the biomass. The solid products that cannot be gasified in the reaction may be collected at the bottom of the gasifier 510 as molten slag, which may include solid elements and compounds within plant biomass, such as potassium, amongst others.|[0090] In an aspect, after the syngas is formed, it may be quenched down to usable temperatures. Such a process may be facilitated by introducing water or CO2 from the main cycle into the gasifier 510, which may allow for the formation of non-liquid ashes on the condensable species. The water may be removed after the syngas is out of the reactor, while the CO2 may be kept in the stream for oxyfuel combustion purposes and expanding in the turbine system downstream. In a fully pressurized system, the foregoing water removal step may not be needed. Once the syngas leaves the gasifier reactor vessel 510, it may be processed with one or more scrubbers, candle filters, and/or other available gas processing systems in order to produce a clean syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system. Thereafter, the syngas may then be fully oxidized (e.g., with an oxygen stream derived from an air separation unit 512) in the main combustion system (e.g., oxyfuel combustor 514), thereby creating a stream of mostly water and CO2. This stream may be combined with a recirculated stream of mostly CO2 that has passed through a recuperator 516, being preheated to an amenable temperature for the cycle to have acceptable thermodynamic efficiency. The combustion stream may be diluted and may then be expanded in a first turbine stage (e.g., a high-pressure turbine 518) that powers the main cycle recirculation pump 522. After the flow of CO2 goes through that turbine expansion, it may be injected into another set of turbine stages (e.g., a low-pressure turbine 520) to fully expand to its lowest pressure level in the cycle. This may provide the power to the generator/alternator 524 that is attached mechanically to the system.|[0091] In an aspect, once the combined recirculation and combustion streams are expanded, they may be passed through one or more heat exchanger(s) (e.g., the heat exchanger(s) located in the “recuperator” section, e.g., 516). This may allow the stream to exchange heat with the high-pressure cycle pump 522 discharge, thereby heating the pump discharge as it is directed to the main combustor system 514. The CO2 flow stream coming from the turbine loses most of its water in the heat exchanger system. It is then directed to a cooling bank 526 to remove the rest of the heat in order to return the flow to close to ambient temperature before siphoning the amount of CO2 that was created in the combustion process through a 3-way valve 528 or other suitable mechanism. This CO2 stream may then be inserted into a pipeline, e.g., for transport to an underground storage location, such as a well, at 530. In other aspects, the CO2 may be liquefied for transport via a highway into a well.|[0092] In an embodiment, the cooling bank system 526 may reject heat at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent materials 532, which may be solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. The stream of CO2 may be used to heat the sorbent material bank in order to regenerate the system once it captures CO2 from the atmosphere via a series of fans configured to cool the sorbent system and allow it to come into contact with air, thereby trapping its CO2 in a charge cycle. The material may discharge via using waste heat from the CO2 power system. The fan and the compression train for the collected CO2 may use energy in the form of electric power from the turbo expander. The condensate discharged from the sorbent materials may be provided to a pump 534 and returned, via passage through the 3-way valve 528 or other suitable device, back to the high-pressure cycle pump 522, from which it may be pressured, provided to recuperator 516, and provided to the oxyfuel combustor 514 as a recirculation stream.|[0093] Referring now to FIG. 6, an exemplary carbon sequestration and power generation system 600 is depicted that is configured for high temperature heat recovery. In an aspect, the components and process flow in system 600 may be substantially equivalent to system 200 downstream from the oxyfuel combustor. However, system 600 may contain two heat exchangers located in the syngas line. The first heat exchanger may be a high temperature heat exchanger positioned upstream of the scrubber, which may be configured to heat the syngas after it has been conditioned from the gasifier. This heating process may be used to increase heat input into the CO2 cycle (such as a supercritical CO2 cycle), e.g., via a discharge stream from this first heat exchanger to the main combustor. The first high temperature heat exchanger located upstream of the scrubber may allow for the delivery of high-quality heat to the topping end of the cycle 600. The second heat exchanger may be a low temperature heat exchanger positioned downstream of the scrubber, which may be configured to remove the water in the syngas due to the quench. This process may allow steam to be generated and used for DAC capture low temperature sorbent regeneration. In an aspect, the heat removed from the first and second heat exchangers may be redirected to other components of the system 600 according to electrical or carbon sequestration energy needs.|[0094] In system 600, biomass (e.g., any carbon neutral or carbon negative fuel (such as agricultural products or waste, wood, trees, or underbrush cleared from forests, other organic waste, other municipal waste, any combination of the foregoing, and the like, as described above) may be provided from a biomass conveyance system 602 to a feed hopper 604, which may be configured to convey the biomass into gasifier 606, e.g., at a predetermined controlled feed rate.|[0095] Any suitable type of gasifier 606 may be utilized in the system 600, e.g., a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier types. The biomass provided to the gasifier 606 may be reacted with oxygen (O2) and injected steam in a gasification reaction. In an embodiment, the oxygen may be provided to gasifier 606 from an air separation unit 608 via, e.g., pump 610. The air separation unit 608 may, for example, leverage vacuum pressure swing absorption (VPSA) or temperature swing adsorption (TSA) technology to separate air into its constituent components. In another embodiment, the oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 608 may be a cryogenic system. In yet another embodiment, the oxygen may be obtained from a dedicated oxygen delivery service or pipeline. In an embodiment, the injected steam may be derived from syngas condensate and may be provided to gasifier 606 from a “second” heat exchanger, e.g., a low temperature heat exchanger 612 via pump 614, as further described herein. The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H2), carbon monoxide (CO), and CO2, along with trace amounts of species formed as a result of trace elements in the biomass. The solid products that cannot be gasified in the reaction are collected at the bottom of the gasifier 606 as molten slag and ash (e.g., fly ash, bottom ash, etc.).|[0096] Syngas formed through the gasification reaction may then be passed to a “first” heat exchanger, e.g., a high temperature heat exchanger 616, which may be configured to heat the syngas. This heated syngas may be passed to a scrubber 618 that is configured to process the syngas in order to remove water from the syngas stream and/or other ash particulates and halides in order to produce a syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system.|[0097] After exiting the scrubber 618, the cleaned syngas may pass through the low temperature heat exchanger 612. The low temperature heat exchanger 612 may be configured to remove the water in the syngas due to the quench. The syngas may be sent to pump 614 to be reinjected in gasifier 606. With the energy of condensation, this process thus may create steam to be used for DAC capture low temperature sorbent regeneration and/or to be used for steam injection into the gasifier 606.|[0098] After exiting the low temperature heat exchanger 612, the syngas stream may be compressed to full pressure, if needed by, for example, a syngas boost compressor 620. After being compressed, the pressured syngas may be directed back to the high temperature heat exchanger 616, heated, and then subsequently utilized to increase heat input into the CO2 cycle (such as a supercritical CO2 cycle), e.g., via a discharge stream from the high temperature heat exchanger 616 to a combustor 622.|[0099] In an embodiment, the combustor 622 may be a bio syngas oxy combustor. The syngas provided to the combustor 622 may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 608 and compressed via an oxygen boost compressor 624), thereby creating a stream of mostly water and CO2. The stream resultant from the oxidation reaction between the syngas and oxygen stream may be combined in the combustor 622 with a recirculated stream of mostly CO2. The recirculated stream of CO2 may have been passed through a recuperator heat exchanger 626 to preheat it to an amenable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power is left to run all the supplemental power requirements of system 600).|[0100] In an embodiment, the combustion stream exiting the combustor 622 may be expanded in one or more turbines, e.g., a first turbine 628 (e.g., a high pressure turbine). The high pressure turbine 628 may be a direct fired turbine and may be designed to efficiently extract work out of the high pressure combustion stream, which may thereafter be utilized to power the main cycle recirculation pump 630. The turbine exhaust from the high pressure turbine 628 may be directed to a second turbine 632 (e.g., a low pressure turbine). The low pressure turbine expansion may provide power to a generator 634 (i.e., a turbo alternator) that may be attached mechanically to a rotor of the low pressure turbine 632 and to a low/intermediate pressure compressor 636.|[0101] Energy generated by the generator 634 may be utilized in a variety of different ways based on the operating mode of the system 600. For instance, in a first operating mode, the system 600 may behave as a power plant, and the power generated by the generator 634 may be output from the system 600. In a second operating mode, the system 600 may behave as a CO2 capture system, and the power generated by the generator 634 may be utilized to provide power to components of a DAC system (e.g., air-contacting fans and compressors). In a third operating mode, the system 600 may be configured to distribute the power from the generator 634 to both the power grid and to the DAC system.|[0102] The low pressure turbine discharge stream may then be passed to the recuperator heat exchanger 626. The recirculating CO2 stream from the high-pressure recirculation pump 630 may also be introduced to recuperator heat exchanger 626. This allows the low pressure turbine discharge stream to exchange heat with the recirculating CO2 stream pump from the high-pressure recirculation pump 630, thereby heating the recirculating CO2 stream as it is directed to the main combustor 622 and cooling the second turbine discharge stream as it is being directed to a DAC fan bank 638. In various embodiments, heat in the CO2 stream having passed through recuperator heat exchanger 626 may be used to boil water at the low temperature range of recuperator heat exchanger 626.|[0103] The cooled second turbine discharge stream may be directed to pass through the DAC fan bank 638. The DAC fan bank 638 may be configured to reject heat at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent materials, which may be solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. For the discharge cycle, the cooled second turbine discharge stream may be used to heat the sorbent material in the DAC bank 638 (e.g., via conduction). This preheats the sorbent material to allow it to accept the steam from the syngas heat rejected by the low temperature heat exchanger 612. This steam may be used to remove the CO2 gas from the sorbent materials.|[0104] The freed CO2-containing stream is passed through a condenser 640, in which water in the freed CO2-containing stream is removed and pumped, via pump 642, back to the low temperature heat exchanger 612 to be utilized in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in a CO2 compressor 644 and sent to a pipeline via valve 646 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated underground storage location. For example, the CO2 may be transported to a well 248, which may be a class VI well. In another embodiment, the pipeline may transport the sequestered CO2, e.g., to one or more other contracting entities.|[0105] In an embodiment, after passage through the direct air capture bank 638, the cooled CO2 stream may then be transported to a low/intermediate pressure compressor 636 to go through the critical point to form, in some embodiments, sCO2 before being injected into the high pressure recirculation pump 630, configured to increase the pressure of the CO2 stream to combustion injection pressures. In an embodiment, one or both of the cooled CO2 stream exiting the DAC bank 638 and the compressed CO2 stream exiting the low/intermediate pressure compressor 636 may be cooled by another cooler 650 to increase efficiency. The recirculating pump discharge stream may then be heated via passage through the recuperator heat exchanger 626 and then recycled back into the combustor 622. In an embodiment, the CO2 that was created in the combustion process may be siphoned through a 3-way valve or other suitable flow control mechanism (e.g., an orifice plate configured to throttle the amount being rejected, or via leakage passages inside the main pump flow region, etc.) at a pressure that is ready for pipeline injection or liquefied transport through highway into the well 648 (as directed, e.g., by valve 652 or other suitable flow control mechanism).|[0106] Referring now to FIG. 7, an exemplary carbon sequestration and power generation system 700 is depicted that is configured for low temperature heat recovery. In this configuration, only one heat exchanger is provided after the scrubber, which is configured to remove the syngas heat to generate steam to be used for DAC capture low temperature sorbent regeneration. This may facilitate or maximize DAC capture capacity.|[0107] In system 700, biomass (e.g., any carbon neutral or carbon negative fuel (such as agricultural products or waste, wood, trees, or underbrush cleared from forests, other organic waste, other municipal waste, any combination of the foregoing, and the like) may be provided from a biomass conveyance system 702 to a feed hopper 704, which may be configured to convey the biomass into gasifier 706, e.g., at a predetermined controlled feed rate.|[0108] Any suitable type of gasifier 706 may be utilized in the system 700, e.g., a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier types. The biomass provided to the gasifier 706 may be reacted with oxygen (O2) and injected steam in a gasification reaction. In an embodiment, the oxygen may be provided to gasifier 706 from an air separation unit 708 via pump 710. The air separation unit 708 may, for example, leverage vacuum pressure swing absorption (VPSA) or temperature swing adsorption (TSA) technology to separate air into its constituent components. In another embodiment, the oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 708 may be a cryogenic oxygen system. In yet another embodiment, the oxygen may be obtained from a dedicated oxygen delivery service or pipeline. In an embodiment, the injected steam may be derived from syngas condensate and may be provided to gasifier 706 from a low temperature heat exchanger 712 via pump 714, as further described herein. The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H2), carbon monoxide (CO), and CO2, along with trace amounts of species formed as a result of trace elements in the biomass. The solid products that cannot be gasified in the reaction are collected at the bottom of the gasifier 706 as molten slag and ash (e.g., fly ash, bottom ash, etc.).|[0109] Syngas formed through the gasification reaction may then be passed to a scrubber 716 that is configured to process the syngas in order to remove water from the syngas stream and/or other ash particulates and halides in order to produce a syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system.|[0110] After exiting the scrubber 716, the cleaned syngas may pass through the low temperature heat exchanger 712. The low temperature heat exchanger 712 may be configured to remove the water in the syngas due to the quench. The syngas may be sent to pump 714 to be reinjected in gasifier 706. With the energy of condensation, this process thus may create steam to be used for DAC capture low temperature sorbent regeneration and/or to be used for steam injection into the gasifier 706.|[0111] After exiting the low temperature heat exchanger 712, the syngas stream may be compressed to full pressure, if needed by, for example, a syngas boost compressor 718. After being compressed, the pressured syngas may be introduced into a combustor 720.|[0112] In an embodiment, the combustor 720 may be a bio syngas oxy combustor. The syngas provided to the combustor 720 may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 708 and compressed via an oxygen boost compressor 722), thereby creating a stream of mostly water and CO2. The stream resultant from the oxidation reaction between the syngas and oxygen stream may be combined in the combustor 720 with a recirculated stream of mostly CO2. The recirculated stream of CO2 may have been passed through a recuperator heat exchanger 724 to preheat it to an amenable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power is left to run all the supplemental power requirements of system 700).|[0113] In an embodiment, the combustion stream exiting the combustor 720 may be expanded in one or more turbines, e.g., a first turbine 726 (e.g., a high pressure turbine). The high pressure turbine 726 may be a direct fired turbine and may be designed to efficiently extract work out of the high pressure combustion stream, which may thereafter be utilized to power the main cycle recirculation pump 728. The turbine exhaust from the high pressure turbine 726 may be directed to a second turbine 730 (e.g., a low pressure turbine). The low pressure turbine expansion may provide power to a generator 732 (e.g., a turbo alternator) that may be attached mechanically to a rotor of the low pressure turbine 730 and to a low/intermediate pressure compressor 734.|[0114] Energy generated by the generator 732 may be utilized in a variety of different ways based on the operating mode of the system 700. For instance, in a first operating mode, the system 700 may behave as a power plant, and the power generated by the generator 732 may be output from the system 700. In a second operating mode, the system 700 may behave as a CO2 capture system, and the power generated by the generator 732 may be utilized to provide power to components of a DAC system (e.g., air-contacting fans and compressors). In a third operating mode, the system 700 may be configured to distribute the power from the generator 732 to both the power grid and to the DAC system.|[0115] The low pressure turbine discharge stream may then be passed to the recuperator heat exchanger 724. The recirculating CO2 stream from the high-pressure recirculation pump 728 may also be introduced to recuperator heat exchanger 724. This allows the low pressure turbine discharge stream to exchange heat with the recirculating CO2 stream pump from the high-pressure recirculation pump 728, thereby heating the recirculating CO2 stream as it is directed to the main combustor 720 and cooling the second turbine discharge stream as it is being directed to a DAC fan bank 736. In various embodiments, heat in the CO2 stream having passed through recuperator heat exchanger 724 may be used to boil water at the low temperature range of recuperator heat exchanger 724.|[0116] The cooled second turbine discharge stream may be directed to pass through the DAC fan bank 736. The DAC fan bank 736 may be configured to reject heat at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent materials, which may be solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. For the discharge cycle, the cooled second turbine discharge stream may be used to heat the sorbent material in the DAC bank 736 (e.g., via conduction). This preheats the sorbent material to allow it to accept the steam from the syngas heat rejected by the low temperature heat exchanger 712. This steam may be used to remove the CO2 gas from the sorbent materials.|[0117] The freed CO2-containing stream is passed through a condenser 738, in which water in the freed CO2-containing stream is removed and pumped, via pump 740, back to the low temperature heat exchanger 712 to be utilized in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in a CO2 compressor 742 and sent to a pipeline via valve 744 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated underground storage location. For example, the CO2 may be transported to a well 746, which may be a class VI well. In another embodiment, the pipeline may transport the sequestered CO2, e.g., to one or more other contracting entities.|[0118] In an embodiment, after passage through the direct air capture bank 736, the cooled CO2 stream may then be transported to a low/intermediate pressure compressor 734 to go through the critical point to form, in some embodiments, sCO2 before being injected into the high pressure recirculation pump 728, configured to increase the pressure of the CO2 stream to combustion injection pressures. In an embodiment, one or both of the cooled CO2 stream exiting the DAC bank 736 and the compressed CO2 stream exiting the low/intermediate pressure compressor 734 may be cooled by another cooler 748 to increase efficiency. The recirculating pump discharge stream may then be heated via passage through the recuperator heat exchanger 724 and then recycled back into the combustor 720. In an embodiment, the CO2 that was created in the combustion process may be siphoned through a 3-way valve or other suitable flow control mechanism (e.g., an orifice plate configured to throttle the amount being rejected, or via leakage passages inside the main pump flow region, etc.) at a pressure that is ready for pipeline injection or liquefied transport through highway into the well 746 (as directed, e.g., by valve 750 or other suitable flow control mechanism).|[0119] As described above, exemplary integrated carbon sequestration and power generation systems described herein may incorporate a Rankine cycle as the thermodynamic power cycle 110 (FIG. 1). A typical Rankine cycle may have backpressure well below ambient pressure so the temperature of condensing water is close to room temperature to promote efficiency of the system. There is a large amount of heat released due to condensation of water. The pressure of such systems tends to be approximately 0.1 bar, as that puts the saturation temperature close to normal ambient temperature.|[0120] Embodiments of the present disclosure that include a Rankine cycle as the thermodynamic power cycle may alter the backpressure of a steam turbine in the integrated carbon sequestration and power generation system to a value of approximately 0.5 bar to approximately 1.0 bar, e.g., of approximately 1 bar. At approximately 1 bar, the saturation temperature is 100 degrees Celsius, and there will be constant temperature heat rejection until all steam has condensed to water. As a result, maintaining the backpressure of a steam turbine at approximately 1 bar may have the benefit that sorbent in the DAC portion of the integrated system being regenerated will get to that temperature of 100 degrees Celsius. In this way, for some exemplary systems of the disclosure, the backpressure of a steam turbine may be chosen to target the temperature required for the sorbent, and steam may be bypassed around a secondary steam turbine so the amount of electrical power and thermal power is matched to what the DAC system requires. For example, a first portion of steam that has gone through a first steam turbine may be utilized to regenerate the sorbent of the integrated DAC system, and a second portion of steam (e.g., the remaining steam) may continue through a second steam turbine down to the normal Rankine backpressure. These two streams may come together after a pump brings the condensed 0.1 bar water back up to pressure.|[0121] Referring now collectively to FIGS. 8A and 8B and Table 2 above, plot diagrams are provided for illustrating the benefits of the pressure and temperature ranges described herein. One potential benefit of the system embodiments described herein is that the output power in the cycles occurring in systems 100, 200, 500, 600 and 700 may be adjusted while maintaining the turbomachinery “on-design” by adjusting the pressures on the flow. For example, if the output power of a system needs to be reduced, CO2 may be bled out from the system faster, correspondingly resulting in a drop of pressure. As an example of the foregoing, if CO2 is removed so that the low pressure compressor suction pressure is approximately 20 bar, then the high pressure compressor discharge would be approximately 96 bar, resulting in an approximately 40% reduction in power generation. The foregoing abilities enable flexibility with respect to gasification output, power demands, etc.|[0122] Furthermore, as the temperature of the system is increased, the pressure also correspondingly needs to be increased in order to maintain the temperature on the recuperator. This may provide for higher efficiency while using fundamentally the same cycle. For example, in this case, if the low end pressure is held at approximately 35 bar, but a variant was desired that operated at a higher efficiency, compression could be increased and subsequently the temperature could also be increased. As a result, in embodiments of the disclosure described herein, increasing the discharge pressure and the combustor temperature may boost efficiency but the cycle is generally equivalent.|[0123] In general, any process discussed in this disclosure that is computer-implementable may be performed manually or by one or more processors of a computer system. A process or process step performed by one or more processors may also be referred to as an operation. The one or more processors may be configured to perform such processes by having access to instructions (e.g., software or computer-readable code) that, when executed by the one or more processors, cause the one or more processors to perform the processes. The instructions may be stored in a memory of the computer server. A processor may be a central processing unit (CPU), a graphics processing unit (GPU), or any suitable types of processing unit.|[0124] A computer system, such as a computer control system associated with any of systems 100, 200, 500, 600, and 700 may include one or more computing devices. If the one or more processors of the computer system are implemented as a plurality of processors, the plurality of processors may be included in a single computing device or distributed among a plurality of computing devices. If a system environment comprises a plurality of computing devices, the memory of the computer system may include the respective memory of each computing device of the plurality of computing devices.|[0125] FIG. 9 is a simplified functional block diagram of a computer system 900 that may be configured as a computing device for executing the process illustrated in FIG. 4 and/or that may be compatible with any of systems 100, 200, 500, 600, and 700, according to exemplary embodiments of the present disclosure. FIG. 9 is a simplified functional block diagram of a computer that may be configured as according to exemplary embodiments of the present disclosure. In various embodiments, any of the systems herein may be an assembly of hardware including, for example, a data communication interface 920 for packet data communication. The platform also may include a central processing unit (“CPU”) 902, in the form of one or more processors, for executing program instructions. The platform may include an internal communication bus 908, and a storage unit 906 (such as ROM, HDD, SDD, etc.) that may store data on a computer readable medium 922, although the system 900 may receive programming and data via network communications via electronic network 925 (e.g., voice, video, audio, images, or any other data over the electronic network 925). The system 900 may also have a memory 904 (such as RAM) storing instructions 924 for executing techniques presented herein, although the instructions 924 may be stored temporarily or permanently within other modules of system 900 (e.g., processor 902 and/or computer readable medium 922). The system 900 also may include input and output ports 912 and/or a display 910 to connect with input and output devices such as keyboards, mice, touchscreens, monitors, displays, etc. The various system functions may be implemented in a distributed fashion on a number of similar platforms, to distribute the processing load. Alternatively, the systems may be implemented by appropriate programming of one computer hardware platform.|[0126] Program aspects of the technology may be thought of as “products” or “articles of manufacture” typically in the form of executable code and/or associated data that is carried on or embodied in a type of machine-readable medium. “Storage” type media include any or all of the tangible memory of the computers, processors or the like, or associated modules thereof, such as various semiconductor memories, tape drives, disk drives and the like, which may provide non-transitory storage at any time for the software programming. All or portions of the software may at times be communicated through the Internet or various other telecommunication networks. Such communications, for example, may enable loading of the software from one computer or processor into another, for example, from a management server or host computer of the mobile communication network into the computer platform of a server and/or from a server to the mobile device. Thus, another type of media that may bear the software elements includes optical, electrical and electromagnetic waves, such as used across physical interfaces between local devices, through wired and optical landline networks and over various air-links. The physical elements that carry such waves, such as wired or wireless links, optical links, or the like, also may be considered as media bearing the software. As used herein, unless restricted to non-transitory, tangible “storage” media, terms such as computer or machine “readable medium” refer to any medium that participates in providing instructions to a processor for execution.|[0127] While some embodiments described herein include some but not other features included in other embodiments, combinations of features of different embodiments are meant to be within the scope of the invention, and form different embodiments, as would be understood by those skilled in the art. For example, in the following claims, any of the claimed embodiments can be used in any combination.|[0128] Thus, while certain embodiments have been described, those skilled in the art will recognize that other and further modifications may be made thereto without departing from the spirit of the invention, and it is intended to claim all such changes and modifications as falling within the scope of the invention. For example, functionality may be added or deleted from the block diagrams and operations may be interchanged among functional blocks. Steps may be added or deleted to methods described within the scope of the present invention.|[0129] The above disclosed subject matter is to be considered illustrative, and not restrictive, and the appended claims are intended to cover all such modifications, enhancements, and other implementations, which fall within the true spirit and scope of the present disclosure. Thus, to the maximum extent allowed by law, the scope of the present disclosure is to be determined by the broadest permissible interpretation of the following claims and their equivalents, and shall not be restricted or limited by the foregoing detailed description. While various implementations of the disclosure have been described, it will be apparent to those of ordinary skill in the art that many more implementations are possible within the scope of the disclosure. Accordingly, the disclosure is not to be restricted except in light of the attached claims and their equivalents. | (US12359613)|CROSS REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to U.S. Provisional Application No. 63/479,875, filed on Jan. 13, 2023, and U.S. Provisional Application No. 63/535,990, filed on Aug. 31, 2023, which are both incorporated by reference herein in their entireties.|(US12359613)|TECHNICAL FIELD|[0002] Various embodiments of the present disclosure relate generally to an integrated carbon sequestration and power generation system and related methods of use, and, more particularly, to a biomass energy conversion cycle coupled with a direct air capture carbon system.|BACKGROUND|[0003] The anthropogenic emission of carbon dioxide (CO2) gases from thermal processes (combustion) over centuries has caused the atmospheric composition of the planet earth to change. This has led to a planetary warming effect that is causing the earth's climate systems to change at an unprecedented rate. The biome adaptation mechanisms are in danger of collapsing due to the rapid change in atmospheric boundary conditions. The Intergovernmental Panel on Climate Change (IPCC) has decreed that in order to keep the average atmospheric temperature increase to 1.5° C., humans must remove 100-1000 gigatonnes of CO2 in the 21st century from the atmosphere.|[0004] The present disclosure is accordingly directed to addressing the foregoing issue(s). The background description provided herein is for the purpose of generally presenting the context of the disclosure. Unless otherwise indicated herein, the materials described in this section are not prior art to the claims in this application and are not admitted to be prior art, or suggestions of the prior art, by inclusion in this section.|SUMMARY OF THE DISCLOSURE|[0005] According to certain aspects of the disclosure, an integrated carbon sequestration and power generation system is disclosed.|[0006] In accordance with an embodiment, an integrated carbon sequestration and power generation system is disclosed. The integrated carbon sequestration and power generation system includes a thermodynamic power cycle, such as a recuperated Brayton thermodynamic cycle, configured to receive biomass and to generate heat and power; and a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and the power generated by the thermodynamic power cycle, such as a recuperated Brayton thermodynamic cycle, to facilitate carbon sequestration.|[0007] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes generating syngas via a gasification reaction involving a biomass, oxygen, and steam occurring in a gasifier; passing the generated syngas through a scrubber to produce a cleaned syngas; and cooling the cleaned syngas via introduction into a low temperature heat exchanger, wherein syngas heat is removed in the low temperature heat exchanger to produce steam. The method further includes introducing the cooled syngas, oxygen, and a recirculation carbon dioxide (CO2) stream into a combustor; combusting the syngas to provide a combustion stream comprising CO2 and water; expanding the combustion stream across a first turbine to generate a first turbine discharge stream and power; and expanding the first turbine discharge stream across a second turbine to generate a second turbine discharge stream and power, wherein the power is supplied to a generator. The method further includes cooling at least a portion of the second turbine discharge stream by passing the second turbine discharge stream through a recuperator heat exchanger; and passing the cooled second turbine discharge stream into a cooling bank, wherein the cooling bank comprises sorbent material containing captured CO2, and wherein passage of the cooled second turbine discharge stream through the cooling bank heats the CO2 sorbent material. The method also includes passing the recirculation CO2 stream exiting the cooling bank through a compressor to produce a supercritical CO2 stream; passing a first portion of the supercritical CO2 stream to a storage location and passing a second portion of the supercritical CO2 stream through a recirculation pump to produce the recirculation CO2 stream; passing the recirculation CO2 stream through the recuperator heat exchanger, wherein the recirculation CO2 stream exchanges heat with the second turbine discharge stream at the recuperator heat exchanger; and passing the heated recirculation CO2 stream into the combustor.|[0008] In accordance with another embodiment, an integrated carbon sequestration and power generation system is disclosed. The integrated carbon sequestration and power generation system includes a gasifier configured to receive a biomass and configured to produce a syngas; a combustor configured to produce a combustion stream from the cleaned syngas, oxygen, and a recirculation carbon dioxide (CO2) stream; and at least one turbine, wherein the at least one turbine is operatively coupled to a direct air capture (DAC) carbon sequestration system and to a high pressure recirculation pump to optionally or simultaneously provide power produced by the at least one turbine to the DAC carbon sequestration system or to a power grid separate from the integrated carbon sequestration and power generation system.|[0009] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes operating, using one or more processors of a computer system, the integrated carbon sequestration and power generation system in a first operating mode, wherein power produced by a turbine generator of the integrated carbon sequestration and power generation system in the first operating mode is directed to power a direct air capture (DAC) carbon sequestration system; determining, using the one or more processors, that a predetermined condition is satisfied; switching, using the one or more processors and based on the determining, the operating mode of the integrated carbon sequestration and power generation system from the first operating mode to a second operating mode; and operating, subsequent to the switching, the integrated carbon sequestration and power generation system in the second operating mode, wherein the power produced by the turbine generator in the second operating mode is directed to a power grid of a power grid operator.|[0010] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes operating, using one or more processors of a computer system, the integrated carbon sequestration and power generation system in a first operating mode, wherein power produced by a turbine generator of the integrated carbon sequestration and power generation system in the first operating mode is directed to power a direct air capture (DAC) carbon sequestration system; determining, using the one or more processors, that a predetermined condition is satisfied; switching, using the one or more processors and based on the determining, the operating mode of the integrated carbon sequestration and power generation system from the first operating mode to a second operating mode; and operating, subsequent to the switching, the integrated carbon sequestration and power generation system in the second operating mode, wherein a first portion of the power produced by the turbine generator is directed to the DAC carbon sequestration system and a second portion of the power generated by the turbine generator is directed to a power grid of a power grid operator that is separate from the integrated carbon sequestration and power generation system.|[0011] In accordance with another embodiment, a method of supplying power produced by a turbine generator of an integrated carbon sequestration and power generation system to a power grid of a power grid operator is disclosed. The method includes determining, using one or more processors of a computing system, that a predetermined number or type of assets are unavailable to the power grid operator during a first time interval and are available to the power grid operator during a second time interval; causing, using the one or more processors, the power generated by the turbine generator to be transferred to the power grid of the power grid operator during the first time interval; and causing, using the one or more processors, the power generated by the turbine generator to be transferred to a direct air capture (DAC) carbon sequestration system of the integrated carbon sequestration and power generation system during the second time interval.|[0012] In accordance with another embodiment, a method of operating an integrated carbon sequestration and power generation system is disclosed. The method includes determining a first projected value derived from sequestration of carbon dioxide when operating the integrated carbon sequestration and power generation system in a first operating mode; determining a second projected value derived from provision of power to a third-party system when operating the integrated carbon sequestration and power generation system in a second operating mode; operating the integrated carbon sequestration and power generation system in the second operating mode responsive to determining that the second projected value is greater than the first projected value; and operating the integrated carbon sequestration and power generation system in the first operating mode responsive to determining that the second projected value is less than the first projected value.|[0013] It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the disclosed embodiments, as claimed.|(US12359613)|BRIEF DESCRIPTION OF THE DRAWINGS|[0014] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate the disclosed embodiments, and together with the description, serve to explain the principles of the disclosed embodiments. There are many aspects and embodiments described herein. Those of ordinary skill in the art will readily recognize that the features of a particular aspect or embodiment may be used in conjunction with the features of any or all of the other aspects or embodiments described in this disclosure. In the drawings:|[0015] FIG. 1 depicts a schematic illustration of an exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0016] FIG. 2 depicts a schematic illustration of an exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0017] FIG. 3 depicts exemplary thermodynamic states of pressure and temperature of the system of FIG. 2, according to various aspects of the present disclosure.|[0018] FIG. 4 depicts an exemplary flow of operating an integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0019] FIG. 5 depicts a schematic illustration of another exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0020] FIG. 6 depicts a schematic illustration of another exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0021] FIG. 7 depicts a schematic illustration of another exemplary integrated carbon sequestration and power generation system, according to various aspects of the present disclosure.|[0022] FIGS. 8A and 8B depict plot diagrams illustrating cycle efficiency of the power system, without including parasitic losses, according to various aspects of the present disclosure.|[0023] FIG. 9 depicts an exemplary computing system, according to various aspects of the present disclosure.|(US12359613)|DETAILED DESCRIPTION OF THE EMBODIMENTS|[0024] Both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the features, as claimed. In this disclosure, the term “based on” means “based at least in part on.” The singular forms “a,” “an,” and “the” include plural referents unless the context dictates otherwise. As used herein, the terms “comprises,” “comprising,” or other variations thereof, are intended to cover a non-exclusive inclusion such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements, but may include other elements not expressly listed or inherent to such a process, method, article, or apparatus. Additionally, the term “exemplary” is used herein in the sense of “example,” rather than “ideal.” An embodiment or implementation described herein as “exemplary” is not to be construed as preferred or advantageous, for example, over other embodiments or implementations; rather, it is intended to reflect or indicate that the embodiment(s) is/are “example” embodiment(s).|[0025] It should be noted that all numeric values disclosed or claimed herein (including all disclosed values, limits, and ranges) may have a variation of +/−10% (unless a different variation is specified) from the disclosed numeric value. Moreover, in the claims, values, limits, and/or ranges mean the value, limit, and/or range+/−10%. In addition, relative terms, such as “approximately” and “about” are generally used to indicate a possible variation of ±10% of a stated or understood value unless indicated otherwise in the specification. In addition, the term “between” used in describing ranges of values is intended to include the minimum and maximum values described herein. The use of the term “or” in the claims and specification is used to mean “and/or” unless explicitly indicated to refer to alternatives only, or the alternatives are mutually exclusive, although the disclosure supports a definition that refers to only alternatives and “and/or.” As used herein “another” may mean at least a second or more.|[0026] As used herein, certain terms, e.g., “working fuel,” “CO2 stream,” “syngas,” and other like terms may be used interchangeably throughout the description of the embodiments.|[0027] Additional objects and advantages of the embodiments will be set forth in part in the description that follows, and in part will be obvious from the description, or may be learned by practice of the embodiments. It is to be understood that both the foregoing general description and the following detailed description are exemplary and explanatory only and are not restrictive of the claims.|[0028] To achieve carbon sequestration, there are alternatives available, including: reforestation, direct air carbon capture and sequestration, Biomass with Carbon Removal and Storage (BiCRS), and other technologies that may be unproven (e.g., algae production and sinking, etc.). Afforestation/reforestation is low cost, difficult to model, and has a low time horizon for trapping the CO2 (e.g., potentially as soon as 50-100 years). Direct air carbon capture and sequestration is higher cost (e.g., as driven by energy demands), easy to model and quantify, and has a high time horizon for captured carbon (e.g., 1000+ years depending on capture medium). BiCRS is medium cost (e.g., as driven by equipment capital investment), easy to model and quantify, and has a high time horizon for captured carbon (e.g., 1000+ years depending on capture medium).|[0029] Most of the approaches described above require extensive energy use, which in our current society, typically comes from carbon emitting sources, thereby effectively reducing the amount of carbon sequestered. Additionally, the carbon drawdown effects of afforestration/reforestration are difficult to measure and verify, while the permanence is also highly uncertain. Although these afforestation/reforestration and other land and ocean capture methods may play a role in carbon-reduction efforts, they are unlikely to reach the scale and permanence required to avoid a climate crisis. Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation plants to compete in power grid markets.|[0030] In view of the foregoing, a solution is proposed for a system design that is made with BiCRS from the start, using oxyfuel combustion to generate a concentrated stream of CO2 that is used to power the system. Pairing this system with a bottoming temperature and pressure swing adsorption cycle that utilizes the waste heat to regenerate sorbents, a hybrid BiCRS+direct air carbon (DAC) sequestration system may be produced that has a larger carbon drawdown potential as compared to other engineered systems on an energy basis. More particularly, in some aspects, a carbon neutral or carbon negative fuel, such as waste biomass, may be converted into ready-to-sequester CO2, heat, and power, e.g., using a thermodynamic power cycle. Exemplary thermodynamic power cycles may include, e.g., a Brayton cycle, a recuperated Brayton thermodynamic cycle, a Rankine cycle, a steam turbine cycle with Rankine, etc. Such thermodynamic cycles may use CO2 and/or super critical CO2 (sCO2) as the main working fluid. At least some of the heat and power generated from the thermodynamic cycle may then be used to drive an integrated direct air carbon capture system, or the power may be used for one or more other purposes (e.g., the power may be electrical power that is utilized for grid integration, or the power may be output in the form of mechanical power). Such an exemplary system 100 is shown schematically in FIG. 1. It should be understood that FIG. 1 generally describes an overall integrated carbon sequestration and power generation system, of which systems 200, 500, 600, and 700 (discussed further herein) are exemplary embodiments.|[0031] As shown in FIG. 1, biomass 105 may be introduced into a thermodynamic power cycle 110 in which waste heat is used to power the DAC sequestration system and regenerate sorbent. In the context of this application, biomass 105 refers to any carbon neutral or carbon negative fuel. For instance, potential types of biomass 105 may include, e.g., wood products, such as wood processing wastes (e.g., firewood, wood pellets, wood chips, lumber and sawdust waste, etc.), agricultural products, including crops and waste materials (e.g., corn, soybeans, sugar cane, woody plants, algae, etc.), biogenic materials in municipal solid waste (e.g., paper, cotton, wool products, food, yard waste, etc.), non-biogenic materials in municipal solid waste (e.g., plastics or petroleum-based products), animal manure, or human sewage (e.g., bio waste discharge from water treatment plants). The biomass 105 may be broken down within the thermodynamic power cycle 110 to produce CO2. In an aspect, non-limiting types of possible thermodynamic power cycles that may be utilized include Brayton thermodynamic power cycles, recuperated Brayton thermodynamic power cycles, Rankine thermodynamic power cycles, etc. Specific examples of thermodynamic cycles and processes for breaking down biomass 105 are discussed in further detail below. It is important to note that although the examples described throughout the specification may refer to a recuperated Brayton thermodynamic power cycle, this designation is not limiting, and other thermodynamic power cycles may be utilized in lieu or, or in addition to, the recuperated Brayton thermodynamic power cycle.|[0032] In an aspect, the CO2 may be heated by combustion heat derived from a reaction of bio-syngas and oxygen in the thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic cycle) to form a CO2 working fluid. The CO2 working fluid may be a supercritical CO2 working fluid, subcritical CO2 working fluid, steam, or a combination thereof. The working fluid may be utilized to generate power and heat. In one configuration, the generated power may be provided to a direct air capture (DAC) system 115, which may be configured to capture CO2 directly from the atmosphere. More particularly, the DAC system 115 may contain sorbent materials, e.g., solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. The rejected heat from the thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic power cycle) may be used to extract the captured atmospheric CO2 and to regenerate the sorbent materials and the generated power may be used to compress the extracted CO2 captured from the DAC system 115. Once extracted, the captured CO2 may be permanently stored underground, reintroduced into the thermodynamic power cycle 110, and/or may be sold. In another operational configuration, the generated power produced by the thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic power cycle) may optionally be integrated to a power grid 120. In yet another operational configuration, a portion of the generated power may be integrated to the power grid 120, and another portion may be used to power the DAC system 115, allowing for the simultaneous supply of power to both power grid 120 and DAC system 115.|[0033] Accordingly, exemplary embodiments of the present disclosure provide for a power generation system that uses biomass as a fuel and uses CO2 as the working fluid. For example, a gasifier may be used to convert carbonaceous biomass into a useable fuel source for power generation. Such a system may utilize the CO2 working fluid to pressurize a biomass solids conveyance system, cool syngas reactor walls, or quench the syngas flow coming out of the gasifier reactor, as will be described further below.|[0034] This power generation system may further be integrated with a carbon sequestration system that is capable of directly capturing carbon from the air. Embodiments of the present disclosure provide for the integration of a CO2 power cycle with a Direct Air Capture (DAC) system, which may use CO2 and/or sCO2 thermodynamic power cycle waste heat as a sorbent regenerator for the CO2 sequestration cycle, as described in reference to FIG. 1. Additionally, power generation systems of the present disclosure may be used as “peaker plants,” or power plants that generate power for the power grid only when there is a higher demand for electricity, as will be described further below. In such an implementation, the energy generated by the disclosed systems may be used for multiple functions, e.g., for generating power for dispatch to the power grid, and for powering carbon sequestration via an integrated DAC system.|[0035] In some aspect, other embodiments of the present disclosure provide for selection of a high pressure cycle pump inlet to enable inlet flow robustness and independence from ambient conditions on the inlet of the pump system. Compressors may be sensitive to inlet conditions and may be forced to derate (i.e., reduce power) or turn off all together if conditions are not favorable. More particularly, the density of the CO2 may be sensitive to the temperature of the CO2 fluid at the bottom the pressure ladder. The temperature at the bottom of the pressure ladder may be affected by ambient temperature or may be close to the ambient temperature due to heat rejection methods. This density of the CO2 may affect the operation of the turbomachinery of the cycle. The temperature density sensitivity may be acute near the critical pressure of CO2 at 73.8 bar. In an aspect, by increasing the inlet pressure of the recirculation pump (which may be the lowest pressure in the recirculation loop), the first derivative of density and pressure at a given temperature may be decreased, thereby causing the CO2 density to be less dependent on its temperature, e.g., ambient conditions. This in turn may allow the system to operate in varied geographic locations, which may have hot, cold, or moderate ambient temperature conditions, without the need for bodies of water to conduct cooling. In some aspects, by operating above the critical pressure of CO2 (e.g., at above about 100 bar, from about 100 bar to about 150 bar, from about 120 bar to about 130 bar, or about 125 bar), normal temperature swings in ambient condition (e.g., changes in temperature from day to night or from summer to winter) may only change the CO2 density by about 20% or less, by about 15% or less, by about 10% or less, or by about 5% or less. Conversely to the foregoing, in another aspect, the system may be transcritical at a lowest pressure of, e.g., approximately 35 bar, so the inlet pressure of the recirculation pump may not need to be increased, as described above. Accordingly, aspects of the disclosure may be drawn to a more robust system that may be able to run under a wider range of ambient conditions compared to a system designed to operate near the critical pressure of CO2 will be able to.|[0036] The subject matter of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings, which form a part hereof, and which show, by way of illustration, specific exemplary embodiments. System 100 may take the form of any of the alternative embodiments described herein, e.g., in regards to FIGS. 2, 5, 6, and 7. Subject matter may be embodied in a variety of different forms and, therefore, covered or claimed subject matter is intended to be construed as not being limited to any exemplary embodiments set forth herein; exemplary embodiments are provided merely to be illustrative. Likewise, a reasonably broad scope for claimed or covered subject matter is intended. Among other things, for example, subject matter may be embodied as methods, devices, components, or systems. Accordingly, embodiments may, for example, take the form of hardware, software, firmware, or any combination thereof. The following detailed description is, therefore, not intended to be taken in a limiting sense.|[0037] Throughout the specification and claims, terms may have nuanced meanings suggested or implied in context beyond an explicitly stated meaning. Likewise, the phrase “in one embodiment” or “in some embodiments” as used herein does not necessarily refer to the same embodiment, and the phrase “in another embodiment” as used herein does not necessarily refer to a different embodiment. It is intended, for example, that claimed subject matter include combinations of exemplary embodiments in whole or in part.|[0038] The terminology used below may be interpreted in its broadest reasonable manner, even though it is being used in conjunction with a detailed description of certain specific examples of the present disclosure. Indeed, certain terms may even be emphasized below; however, any terminology intended to be interpreted in any restricted manner will be overtly and specifically defined as such in this Detailed Description section.|[0039] FIG. 2 is a diagram depicting an exemplary integrated carbon sequestration and power generation system 200 (“system”), according to one or more embodiments of the present disclosure. The system 200 may include a torrefaction reactor 202, a grinding system 204, a torrefied biomass conveyance system 206, a load and lock hopper 208, a feed hopper 210, a gasifier reactor vessel (“gasifier”) 212, an air separation unit 214, a first H2O recirculation pump 216, and a scrubber 218. Collectively, these components may prepare biomass for use as fuel. System 200 may further include a low temperature heat exchanger 220, a syngas boost compressor 222, an oxygen boost compressor 224, a combustor 226, a recuperator heat exchanger 228, a high pressure turbine 230, a high pressure CO2 recirculation pump 232, a low pressure turbine 234, and a generator 236 for producing power. In some aspects, system 200 may further include a direct action capture fan bank 238, a low/intermediate pressure compressor 240, a water condenser 242, a second H2O recirculation pump 244, a CO2 compressor 246, and a designated storage location 248 for sequestering CO2.|[0040] In an embodiment, suitable biomass, e.g., any carbon neutral or carbon negative fuel (such as agricultural products or waste, wood, trees, or underbrush cleared from forests, other organic waste, other municipal waste, any combination of the foregoing, and the like), may be pre-processed by a torrefaction process involving the torrefaction reactor 202. The torrefaction reactor 202 may be of any suitable type, including, but not limited to, a fixed bed reactor, a rotary drum reactor, a microwave reactor, a fluidized bed reactor, and/or a horizontal and vertical moving bed reactor. The torrefaction process may include drying, in the torrefaction reactor 202, the biomass and heating it in an oxygen-deprived environment. The heat generated by combustion of the torrefaction gas may be used for both torrefaction and drying of the biomass. Once the biomass reaches 200° C.-350° C., the reaction may become exothermic, and the products of the reaction may include water, oxygen, nitrogen in the biomass, and Volatile Organic Compounds (VOCs). The VOCs may be burned to generate heat for drying and initiating the biomass reaction. The VOCs may be burned in pure oxygen or air.|[0041] The biomass may come out of the torrefaction reactor 202 in a state that is easier to grind and may have other beneficial properties, such as increased carbon content density, hydrophobic behavior, higher heating value, more homogenous composition, removal of waste mass (e.g., water, or low-energy compounds) so that transport may be more efficient, etc. This torrefied biomass may be transferred into a grinding system 204 (e.g., a Stage-1 coarse grinder, a Stage-2 coarse grinder, bowl mill, impact hammer, jet mill, or other suitable systems utilized in coal grinding, or any combination thereof, etc.) in which the torrefied biomass is ground down to a suitable size and prepared for conveyance and pressurization into a gasifier injector, wherein the torrefied biomass may be partially oxidized to separate it into its constituents. More particularly, the ground, torrefied biomass may be conveyed from the grinding system 204 to a load and lock hopper 208 by components (e.g., conveyor belts, pneumatic systems, screws, buckets, etc.) of the torrefied biomass conveyance system 206. The pressurization into the gasifier injector may occur via pneumatic or mechanical modalities. Examples of mechanical pressurization include use of a solids conveyance pump, or a slurry formation of the ground biomass with other constituents to be pumped into the pressurized volume of the gasifier 212. If pneumatics are utilized, the biomass may be pressurized using an inert gas, such as CO2 or N2, which may be introduced into the load and lock hopper 208. For example, CO2 siphoned away from other portions of system 200 may be diverted toward the load and lock hopper 208 via actuation of a 3-way valve 254 or other suitable flow control mechanisms. As used herein, suitable flow control mechanisms may include, e.g., valves, orifice plates, manifolds, backpressure regulators, etc., used alone or in combination with one or more sensors. The pressurized ground torrefied biomass may then be provided to a feed hopper 210, which may be configured to convey the pressurized ground torrefied biomass into the gasifier 212 at a predetermined controlled feed rate, e.g., via the gasifier injector. Although the torrefaction reactor 202, grinding system 204, and torrefied biomass conveyance system 206 are described herein and are depicted in FIG. 2, it is contemplated that one or more of these components may be omitted from system 200 if, for example, previously torrefied biomass is received by the system 200. In such an instance, system 200 may not need to be capable of running a torrefaction process and may be operable without utilization of one or more of the foregoing components if the biomass received into the system 200 (e.g., provided to the gasifier 212) is in an already torrefied state. In other embodiments, biomass may be introduced to the system that is not torrefied, e.g., biomass that is either untreated or is treated in a manner that does not include torrefaction.|[0042] In an embodiment, one of a variety of different types of gasifiers 212 may be utilized in the system 200, e.g., a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier types. The pressurized biomass constituents may be injected into the gasifier 212 and may be reacted with oxygen (O2) and injected steam in a gasification reaction. In an embodiment, the oxygen used in the gasification reaction may be obtained from an air separation unit 214 fluidly coupled to the gasifier 212 and provided to the gasifier 212. The air separation unit 214 may, for example, leverage vacuum pressure swing absorption (VPSA) or temperature swing adsorption (TSA) technology to separate air into its constituent components. In another embodiment, the oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 214 may be a cryogenic oxygen system. In yet another embodiment, the oxygen may be obtained from a dedicated oxygen delivery service or pipeline. The injected steam may be derived from one or more different sources. For example, water may be extracted from synthesis gas (syngas) prior to insertion into one or more compressors, as further described herein, and used as a basis for the injected steam. In addition or alternatively, water generated during combustion may be removed from the system, vaporized (e.g., with heat from the gasifier or a low temperature heat exchanger, etc.), and injected into the gasifier as steam.|[0043] The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H2), carbon monoxide (CO), and CO2, along with trace amounts of species formed as a result of trace elements in the biomass. The solid products that cannot be gasified in the reaction are collected at the bottom of the gasifier 212 as molten slag and ash (e.g., fly ash, bottom ash, etc.). The solid products are the result of solid elements and compounds within the biomass, such as potassium, calcium, silica, etc. These solid products may be collected and repurposed for other utilizations, e.g., as fertilizer. For example, the molten slag may be utilized in the production of cement concrete for roads.|[0044] After the syngas is formed within the gasifier 212, it must be quenched down to usable temperatures before it can be sent downstream. These temperatures may be determined, at least in part, by the composition of the downstream components, such as scrubber 218. More particularly, the temperatures may be chosen so as to cool the syngas so that water may condense in scrubber 218 in order to remove dirty chemicals. Such a process may be facilitated by introducing water or CO2 from other portions of system 200 into the gasifier 212. For example, the water may be derived from the low temperature heat exchanger 220 or the recuperator heat exchanger 228 and provided to the gasifier, e.g., via pump 216. As another example, water extracted from the biomass drying in the torrefaction reactor 202 may be utilized. If water from within system 200 is reused, this water may need to be cleaned or otherwise processed prior to use. Alternatively or additionally, water may be supplied from an external source, such as a water plant or a body of water. In an embodiment, CO2 may be introduced into the gasifier 212, e.g., from the low pressure compressor 240. In other embodiments in which the gasifier is run at a higher pressure, the CO2 may be introduced into the gasifier from the high pressure recirculation pump 232. The introduction of water or CO2 to quench the syngas may enable formation of non-liquid ashes on the condensable species. The ashes may be recovered and removed from the main flowpath of the machinery that makes power, which may allow for longer operation of the machinery. The non-liquid ash is biogenic in nature and may be mostly composed of minerals and compounds used by the biomass. These can be delivered back into the biodome where they were taken from. Additionally or alternatively, they may be extracted and utilized as fertilizer. After the syngas leaves the gasifier 212, the water may be removed, e.g., via the scrubber 216 or the low temperature heat exchanger 220. The CO2 may be kept in the stream for oxyfuel combustion purposes and expanding in the turbine system downstream.|[0045] In an embodiment, the syngas may leave the gasifier 212 and be transported into the scrubber 216, where it may be processed in order to remove ash particulates and halides in order to produce a syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system. Additionally or alternatively, the syngas may be processed with one or more candle filters or other available gas processing systems to remove particulate contaminants.|[0046] After exiting the scrubber 216, the syngas may pass through a low temperature heat exchanger 220. The syngas heat from the gasification oxidation reaction may be removed at the low temperature heat exchanger 220, which may be placed at a low temperature suitable for steam extraction, thereby acting as a syngas cooler. In an embodiment, this steam may be utilized to remove captured CO2 from sorbent material in a direct air capture fan bank 238 of an integrated direct air capture carbon system, as further described herein. For instance, after the scrubber, there may be a large amount of steam and/or saturated water in the syngas. This steam and/or saturated water may be used to boil another, lower pressure water stream (e.g., one that is situated at ambient pressure) to steam in the low temperature heat exchanger 220, which may then be routed to regenerate the sorbent in the direct air capture fan bank 238. In some aspects, this steam may be introduced into gasifier 212 to promote hydrogen formation in the gasifier and, specifically, to use water shift to change how much H2 and CO are in the syngas. Additionally or alternatively, the extracted heat from the syngas may be provided to the CO2 cycle (e.g., in which CO2 and/or sCO2 is used as the working fluid, etc.) to increase efficiency. It is important to note that although FIG. 2 only illustrates that the syngas passes through a single heat exchanger (i.e., the low temperature heat exchanger 220), such a designation is not limiting. For example, in an embodiment, the system 200 may contain two heat exchangers that may be configured to pull and cool the syngas (e.g., the low temperature heat exchanger 220 and another heat exchanger positioned between the gasifier 212 and the scrubber 218, as illustrated in FIG. 6, which is later described herein). The other heat exchanger may be a high-temperature heat exchanger, which may be operable to generate more steam.|[0047] Additionally or alternatively, in some implementations, the gasifier 212 may have cooling water in its jacket/liner and may contain an integrated heat exchanger inside. In some embodiments of the systems described herein (e.g., systems 100, 200, 500, 600, 700), heat may be additionally or alternatively removed from the cooling elements of the gasifier jacket/liner, or from cooling elements associated with one or more other components of the system. In such an embodiment, heat may be removed directly through cooling of a component of the disclosed systems (e.g., a gasifier liner of, for example, system 100, 200, 500, 600, 700), in conjunction with or as opposed to removing heat by cooling the syngas product (e.g., cooling may be achieved via the liner, the syngas, or a combination thereof). The removed heat may be directed to other components of the disclosed systems in order to increase the efficiency of the systems. For example, steam from syngas heat rejected by the low temperature heat exchanger 220 may be directed to a DAC bank 238 to remove the CO2 gas from the sorbent materials, as further described herein. Systems described herein provide examples of where heat may be pulled from and re-directed to in order to increase the overall efficiency of such systems.|[0048] Once the syngas is fully cooled and dried, it may be compressed to full pressure (which is a suitable combustion injection pressure, e.g., approximately 415 bar) if needed by, for example, a syngas boost compressor 222, which is configured to increase the temperature and pressure of the syngas. For example, in an exemplary flow, the cooled syngas leaving the low temperature heat exchanger 220 may enter the syngas boost compressor 222 at a pressure of approximately 40 bar and a temperature of approximately 350° K. The compressed syngas stream exiting the syngas boost compressor 222 may have a pressure of approximately 413 bar and a temperature of approximately 685° K.|[0049] After being compressed, the syngas may be introduced into a combustor 226 (e.g., a bio syngas oxy combustor) where it may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 214 and compressed via an oxygen boost compressor 224), thereby creating a stream of mostly water and CO2. The stream resultant from the oxidation reaction between the syngas and oxygen stream may be combined in the combustor 226 with a recirculated stream of mostly CO2. The recirculated stream of CO2 may have been passed through a recuperator heat exchanger 228 to preheat it to an amenable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power is left to run all the supplemental power requirements of system 200). More particularly, an inlet of recuperator heat exchanger 228 may be configured to receive CO2 streams having temperatures of about 800° K to about 900° K. The CO2 exhaust stream exiting recuperator heat exchanger 228 may have a temperature in the range of about 725° K to about 825° K.|[0050] In an embodiment, a pressure and temperature of an exemplary combustion stream exiting the combustion outlet of the combustor 226 may be approximately 375 bar and approximately 1036° K, respectively. The combustion stream may be diluted and may then be expanded in a turbine, e.g., a first turbine 230 (i.e., a high pressure turbine). The high pressure turbine 230 may be a direct fired turbine and is the first main engine turbine to receive the combustion stream from the combustor 226. It is designed to efficiently extract work out of the high pressure combustion stream, which is thereafter utilized to power the main cycle recirculation pump 232, the operation of which is further described below.|[0051] In an embodiment, after the combustion stream goes through expansion at the first turbine 230, a pressure and temperature of an exemplary first turbine exhaust stream may be approximately 281.3 bar and approximately 995° K, respectively. The turbine exhaust stream may be injected into a second turbine 234 (i.e., a low pressure turbine) to fully expand to its lowest pressure level in the cycle. The second turbine expansion may provide power to a generator 236 (i.e., a turbo alternator) that is attached mechanically to a rotor of the second turbine 234 and to a low/intermediate pressure compressor 240.|[0052] While a first turbine and a second turbine are described herein, it is contemplated that one, two, or three or more turbines may be incorporated.|[0053] Energy generated by the generator 236 may be utilized in a variety of different ways based on the operating mode of the system 200. For instance, in a first operating mode, the system 200 may behave as a power plant, and the power generated by the generator 236 may be output from the system 200. For example, power may be output in the form of electricity and sent to a power grid, which may be associated with a third party (e.g., an energy provider). In some aspects, power may be output in the form of mechanical power. In a second operating mode, the system 200 may behave as a CO2 capture system, and the power generated by the generator 236 may be utilized to provide power to components of a DAC system (e.g., air-contacting fans and compressors). In a third operating mode, the system 200 may be configured to distribute the power from the generator 236 to both the power grid and to the DAC system. Additional details regarding the various operating modes of the system 200 and the power redirection paths are further described herein.|[0054] In an embodiment, after the combustion stream goes through expansion at the second turbine 234 (if more than one turbine is used), a pressure and temperature of an exemplary second turbine exhaust stream may be approximately 63 bar and approximately 800° K. The second turbine discharge stream is then passed through a recuperator heat exchanger 228. Although one recuperator heat exchanger 228 is depicted in FIG. 2, more than one heat exchanger may be incorporated in system 200. The recirculating CO2 stream from the high-pressure recirculation pump 232 may also be introduced to recuperator heat exchanger 228. This allows the second turbine discharge stream to exchange heat with the recirculating CO2 stream pump from the high-pressure recirculation pump 232, thereby heating the recirculating CO2 stream as it is directed to the main combustor 226 and cooling the second turbine discharge stream as it is being directed to a DAC fan bank 238. In various embodiments described herein, heat in the CO2 stream having passed through recuperator heat exchanger 228 may be used to boil water at the low temperature range of recuperator heat exchanger 228. In some aspects, heat may be pulled from recuperator heat exchanger 228 directly, instead of pulling heat from a CO2 stream. In still other aspects, heat may be pulled from low or high pressure heat exchanger streams. Pulling heat in this manner may increase thermal power at lower quality temperatures, increasing the efficiency of system 200. Referring back to the embodiment of FIG. 2, the second turbine discharge stream may lose the majority of its water upon passage through the recuperator heat exchanger 228. This water may be repurposed for utilization in other aspects of the system 200 (e.g., as quench water provided to the gasifier 212, as steam provided to sorbent material of a direct air capture system, etc.).|[0055] In an embodiment, after passage through the recuperator heat exchanger 228, a pressure and temperature of an exemplary second turbine discharge stream (i.e., the recuperator exhaust stream) may be approximately 60 bar and approximately 360° K to approximately 375° K. The cooled second turbine discharge stream may be directed to pass through the DAC bank 238. An outlet of the DAC bank 238 may be held at approximately 320° K to remove the rest of the heat in order to return the stream to approximately ambient temperature, e.g., of about 320° K or less. In an embodiment, the DAC bank 238 may reject heat via conduction at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration (e.g., 300° K-322° K). More particularly, the DAC bank 238 may include a piping manifold that is interconnected with low temperature CO2 sorbents. In an embodiment, one type of CO2 sorbent may be a metal-organic Framework (MOF), e.g., “mmen-Mg2(dobpdc).” The MOF sorbents have been shown to be suitable in the regeneration process (i.e., the process by which the sorbent materials are made reusable for another cycle). For example, MOF-based technology may be capable of regenerating at temperatures of about 353.15° K to about 393.15° K, which may be less energy intensive and costly. Other embodiments may leverage other types of low temperature CO2 sorbents, such as zeolite materials or ammonia based sorbents. Non-limiting types of low temperature CO2 sorbents may include, for example, liquid amines (e.g., monoethanolamine (MEA)), solid amines (e.g., amine-functionalized cellulose, amine-functionalized silicas), zeolites (e.g., Zeliote 13X (Na86[(AlO2)86(SiO2)106]·nH2O), Zeliote 4A (Na12[(AlO2)12(SiO2)12]·nH2O)), covalent organic frameworks (COFS) (e.g., COF-609), or one or more other types of MOFs (e.g., MOF-74).|[0056] In an embodiment, to facilitate the carbon capture, atmospheric air may be passed through a plurality of fans of the DAC bank 238 to cool the sorbent and allow it to come in contact with the air. In some embodiments, the fans of DAC bank 238 may be used as fans for condenser units utilized in the CO2 loop, thereby increasing system efficiency by taking advantage of the power utilized to run DAC bank 238. As the air comes in contact with the sorbents, CO2 from the air is trapped in a charge cycle. For the discharge cycle, the cooled second turbine discharge stream may be used to heat the sorbent material in the DAC bank 238 (e.g., via conduction). This preheats the sorbent material to allow it to accept the steam from the syngas heat rejected by the low temperature heat exchanger 220. This steam is used to remove the CO2 gas from the sorbent materials. Preheating the sorbent material, using heat from the system to generate steam, or using already produced steam from the system may reduce the amount of energy needed to perform carbon capture, and may increase the efficiency of the system. In some embodiments, instead of just preheating the sorbent material, aspects of the system may be configured to enable the cooled second turbine discharge stream—or heat pulled from other heat sources within system 200—to provide substantially all heat necessary to run the DAC bank 238. The freed CO2-containing stream is passed through a condenser 242, in which water in the freed CO2-containing stream is removed and pumped, via pump 244, back to the low temperature heat exchanger 220 to be utilized in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in a CO2 compressor 246 and sent to a pipeline via valve 252 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated underground storage location. For example, the CO2 may be transported to a well 248, which may be a class VI well. In another embodiment, the pipeline may transport the sequestered CO2, e.g., to one or more other contracting entities. In some aspects, at least a portion of the CO2 released from the sorbent may be directed to other components of system 200, e.g., to the lock and load hopper 208, as opposed to a pipeline or storage. For example, CO2 diverted to lock and load hopper 208 may be used to pressurize biomass prior to introduction into gasifier 212. The three-way valve 254 or other component may be used to optionally direct CO2 to either a pipeline/storage or to load and lock hopper 208.|[0057] In an embodiment, after passage through the direct air capture bank 238, a pressure and temperature of an exemplary cooled CO2 stream may be approximately 131 bar and approximately 360° K. The cooled CO2 stream may then be transported to a low/intermediate pressure compressor 240 to go through the critical point to form, in some embodiments, sCO2 before being injected into the high pressure recirculation pump 232, configured to increase the pressure of the CO2 stream to combustion injection pressures. For example, the recirculating pump discharge stream may have a pressure and temperature of approximately 417 bar and approximately 360° K. In an embodiment, one or both of the cooled CO2 stream exiting the DAC bank 238 and the compressed CO2 stream exiting the low/intermediate pressure compressor 240 may be cooled by another cooler 256 to increase efficiency. The recirculating pump discharge stream may then be heated via passage through the recuperator heat exchanger 228 and then recycled back into the combustor 226. After passing through the recuperator heat exchanger 228, the stream may have a pressure and temperature of, e.g., approximately 396 bar and approximately 730° K. In an embodiment, the CO2 that was created in the combustion process may be siphoned through a 3-way valve or other suitable flow control mechanism (e.g., an orifice plate configured to throttle the amount being rejected, or via leakage passages inside the main pump flow region, etc.) at a pressure that is ready for pipeline injection or liquefied transport through highway into the well 248 (as directed, e.g., by valves 250 and 254 or other suitable flow control mechanism). Suitable pipeline injection pressures may be approximately 142 bar. In an embodiment, the low/intermediate pressure compressor sections may utilize intercooling to increase cycle efficiency (however this is not necessary for the system 200 to operate).|[0058] It is important to note that effective operation of the system 200 may be achieved with fewer or greater components. Stated differently, the number and type of components illustrated in FIG. 2 is only exemplary, and other embodiments may be viable in which fewer components are present but may nevertheless accomplish the same outcome.|[0059] FIG. 3 depicts a simplified version of power generating portions of system 200 of FIG. 2. Additionally, Tables 1 and 2 depicted below provide exemplary thermodynamic states at various locations throughout system 200. It is important to note that the provided temperatures and pressures are only examples, and they may change, e.g., depending on the size of the power plant, the type of biomass being used, variation in carbon content of the syngas, the efficiency of the power cycle, or other factors or combinations of factors. In an embodiment, this cycle may allow for operation at high pressures to avoid the CO2 density gradients above the vapor dome, which may cause operation problems in the turbomachinery systems if the heat rejection step is done to atmosphere. If the pressure entering the pump is close to the vapor dome of the CO2 (when it becomes gas, and is out of the supercritical state), the temperature that the inlet of the pump is cooled to may affect the density of the fluid to the point that the pump system in the cycle cannot function. Accordingly, the inlet pressure condition of the pump may be placed at a higher pressure than the critical pressure of CO2, as the fluid density gradients may be less sensitive to inlet temperature conditions. This may allow system 200 to operate with heat rejection that is independent of water requirements (i.e., uses air to cool the cycle).|[0060] TABLE 1 Point Pressure Temperature Mass Flow Units Bar K. kg/s 1 125 313 105 2 395 357 105 3 375 750 105 4 355 916 112.89 5 258 872 112.89 6 137.5 790 112.89 7 130.6 365 110.92 8 55 300 5.05 9 390 472 5.05 10 55 300 2.84 11 390 Not modeled 2.84 12 1 365 1.97 13 150 320 5.92 |[0061] TABLE 2 Pressure Temperature Point Temperature Range Range Units K. bar K. Compressor 1 313 30-65 —Suction Compressor 2 381 140-400 —Discharge Recuperator 3 807 140-400 700-950 Outlet Combustor 4 1054 130-200 900-1350 Outlet HP Turbine 5 935 70-200 —Outlet Power Turbine 6 839 30-65 700-950 Outlet Recuperator 7 391 30-40 300-400 Outlet Syngas from 8 320 30-50 —Gasifier Syngas to 9 370 140-400 —Combustor Oxygen from 10 290 40-80 —ASU Oxygen to 11 365 140-400 —Combustor Water from 12 313 20-40 —Cycle Product CO2 13 320 35-150 — |[0062] Referring now to FIG. 4, an exemplary method of operating an integrated carbon sequestration and power generation system, e.g., switching an operating mode of an integrated carbon sequestration and power generation system, is disclosed. The exemplary process flow 400 may be implemented by the components of the system 100, 200.|[0063] As previously described above, the system 100, 200 may be capable of operating in a variety of different operating modes, wherein the power produced by the generator 236 of the system 100, 200 (e.g., as a result of expansion of the combustion stream across the low-pressure turbine 234) may be provided to a specific destination and may be utilized to divert power to specific components based on the selected operating mode. The system 100, 200 may switch between the operating modes without changing the operation of the cycle, thereby enabling the system 100, 200 to have diverse utility and allowing it to participate in a variety of different markets. Although flow 400 is described in conjunction with a computer control system, it is contemplated that flow 400 may proceed either manually or automatically.|[0064] At step 405, a computer control system may cause the system 100, 200 to operate in a first operating mode. In an embodiment, the system 100, 200 in the first operating mode may be configured to direct the energy produced by the turbine generator 236 to power a DAC carbon sequestration system that is integrated as part of the system 100, 200. In this regard, the power may be directed by actuating switching relays, as governed by the computer control system, to activate and power one or more air-contacting fans in the DAC bank 238 as well as the DAC CO2 compressor 246. Once activated, the DAC system may operate to capture and sequester atmospheric carbon. Furthermore, the system 100, 200 may configure itself or may manually be configured to provide heat from thermodynamic power cycle 110 (e.g., a recuperated Brayton thermodynamic power cycle) into the sorbent materials contained in the DAC bank 238 (e.g., via conduction heat provided by the exit flow from the recuperator heat exchanger 228, etc., as described above).|[0065] At step 410, the computer control system may determine whether a predetermined condition is satisfied. In an embodiment, satisfaction of the predetermined condition may initiate redirection of the power produced by the turbine generator 236 to a second destination, as described in steps 420 to 425. Alternatively, if the predetermined condition is not satisfied, the computer control system may maintain the system 100, 200 in the first operating mode, as described in step 415. A plurality of potential types of predetermined conditions are contemplated herein, and are further described below.|[0066] In an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether one or more other power sources are available to supply power to a power grid. For example, the predetermined condition may correspond to whether a power grid operator has access to another type of renewable energy to provide power to the power grid. The predetermined condition may be considered satisfied responsive to determining that the power grid operator entity does not have access to the other types of renewable energy. For context, and further to the foregoing, the cost of power may fluctuate throughout the day, with certain periods being more expensive than others. These fluctuations may be based, in part, on the types of renewable energy (e.g., solar energy, wind energy, etc.) that the power grid operator has access to. Specifically, renewable energy providers may be able to provide power to the power grid operator at a lower cost than conventional gas and/or coal-powered power plants are able to. Accordingly, when renewable energy sources are available, the cost of power may be relatively lower because the power grid operator may obtain power for their power grid at a lower cost. However, when conditions prevent the renewable energy providers from operating (e.g., due to no or low sunlight or wind, poor weather conditions, etc.), the power grid operator may need to obtain power for their power grid at a relatively higher cost because it may be relatively more expensive to derive energy from gas and/or coal powered plants. These periods of high electricity cost, or “peaker” periods, may be periods of time that occur daily (e.g., at night when solar power sources are unavailable) and/or may last for an extended time (e.g., several days or weeks depending on weather, etc.).|[0067] The computer control system may be configured to anticipate when the renewable energy providers will be unable to operate and generate renewable energy. For instance, in an embodiment, the computer control system may receive an indication from a timer or sensor that may be configured to provide an alert to the computer control system each day at a predetermined time. The predetermined time may be an estimated time by which the renewable energy providers are no longer able to provide power to the power grid. In an embodiment, the predetermined time may be static (i.e., the same each day) or may be dynamic and may adjust throughout the year. In another embodiment, the computer control system may have access to historical sunlight data for the relevant geographical region (e.g., stored in a database, accessible via an online source, etc.), which may provide indications of the average daily sunrise and sunset times throughout the year. Solar-based energy providers may be operable during the periods between sunrise and sunset and inoperable during the periods between sunset and sunrise. Accordingly, the computer control system may associate a known daily sunset time as the end of the power grid operator's ability to receive renewable energy for the day. In another embodiment, the computer control system may access weather forecast data (e.g., from an online source, etc.), which may provide indications of upcoming weather events that may affect a renewable energy provider's ability to produce renewable energy. For example, if the weather forecast data for an upcoming day predicts cloudy and/or stormy conditions, the computer control system may identify that a solar energy provider's ability to produce power may be limited during those times. In another example, if the weather forecast data predicts a severe storm or weather event (e.g., a winter storm, hurricane, tornado, etc.), then the computer control system may identify that a solar energy provider's ability to produce power may be impaired for an extended period of time (e.g., several days, etc.). In a further example, if the weather forecast data for an upcoming day predicts there to be little or no wind, the computer control system may identify that a wind energy provider's ability to produce power may be limited during those times.|[0068] Additionally or alternatively to the foregoing, in an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether an increased load is required by a power grid of a power grid operator. The predetermined condition may be considered satisfied responsive to determining that the increased load required by the power grid is greater than a predetermined threshold. More particularly, in an embodiment, various types of events may occur that place additional stress on a power grid. Some of these events may be scheduled, whereas others may not be. For instance, with respect to the former, a major concert, sporting event, festival, etc., occurring in a region may require additional power to be provided by the power grid. The computer control system may have access to a schedule of these events and may anticipate which event may place a load demand on the grid that is greater than the predetermined threshold. In another example, with respect to the latter, a weather event may occur that increases the load demand required by the power grid (e.g., unexpected heat wave that may cause individuals to run their air conditioners or fans more than usual, a cold stretch that may cause people to use more heat than usual, etc.). In these situations, the computer control system may receive an indication (e.g., from the power grid operator) or otherwise determine that the load demand on the power grid is greater than the predetermined threshold.|[0069] Additionally or alternatively to the foregoing, in an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether a power grid of a power grid operator is becoming destabilized. In an embodiment, destabilization of the power grid may occur, for instance, because various assets relied on by the power grid operator may fail (e.g., other power providers that are contracted to provide power to the grid are unable to do so). These assets may fail as a result of various situations such as experiencing operational issues, damage derived from weather, geological, and/or other natural disaster events (e.g., damage from fire, earthquake, flood, etc.), and the like. In an embodiment, the predetermined condition may be considered satisfied responsive to anticipating that the power grid will become destabilized within a predetermined time threshold or for greater than a predetermined time threshold.|[0070] Additionally or alternatively to the foregoing, in an embodiment, the determination of whether the predetermined condition is satisfied may correspond to an identification of whether a revenue projection for operating the system 100, 200 in a second operating mode is greater than operating the system 100, 200 in the first operating mode. The predetermined condition may be considered satisfied responsive to determining that operating the system 100, 200 in the second operating mode is more profitable. As further described herein, the system 100, 200 may operate in a first or second operating mode. When in the second operating mode, the system 100, 200 may be configured to redirect the power produced by the generator 236 to a power grid of a power grid operator. In an embodiment, the system 100, 200 may reconcile whether a first projected value generated by or derived from sequestering and selling CO2 (e.g., the collective revenue obtained from selling CO2 at a contract or spot price to a third party, from carbon sequestration tax breaks, etc.) may be greater than a second projected value generated from providing power to the power grid. Responsive to determining that the projected value is greater for operation in the second mode, e.g., in a mode that diverts generated power to the power grid, the predetermined condition may be considered satisfied.|[0071] Responsive to determining, at step 410, that the predetermined condition is not satisfied, the computer control system may, at step 415, maintain the operating mode of the system in the first operating mode. Conversely, responsive to determining, at step 410, that the predetermined condition is satisfied, the computer control system may, at step 420, initiate switching an operating mode of the system 100, 200 from the first operating mode to the second operating mode. Once switched to the second operating mode, the computer control system may cause, at step 425, the system 100, 200 to operate in the second operating mode to redirect the energy from the DAC system to a power grid.|[0072] In an embodiment, the system 100, 200 in the second operating mode may output power produced by the generator 236 in an electrical or mechanical form. For simplicity purposes, the majority of this disclosure is described with reference to examples in which electrical power is output and, more specifically, to situations in which the system 100, 200 may act as a power plant and may be configured to direct the power produced by the generator 236 directly to a power grid of a power grid operator, but any output of power is contemplated. Once switched to the second operating mode, the DAC system may be turned substantially off (i.e., only the fans that are needed to reject the heat from the CO2 stream at the bottom of the power cycle may be utilized), and the syngas low temperature steam may be utilized to preheat any of the fluids in the power cycle. Alternatively to the foregoing, the second operating mode of the system 100, 200 may be an “intermediate” mode in which the system 100, 200 is configured to direct a first portion of the energy produced by the generator 236 to components of the DAC system and a second portion of the energy to a power grid. In an embodiment, the system 100, 200 in the intermediate mode may only power a subset of the air-contacting fans in the DAC bank 238, and the CO2 compressor 246 may be run at a lower power condition according to the appropriate amount of CO2 collected in the DAC system.|[0073] In an embodiment, the switching, at step 420, may be facilitated by actuating a series of valves configured to control transport of the working fluid CO2 through the system 100, 200. More particularly, the valving may be used to direct the CO2 heat flows into more contactors or coolers, depending on the operating mode being switched to. In an embodiment, the system 100, 200 may be operable to switch back and forth between the two operating modes without changing the operation of the supercritical cycle. More particularly, the CO2 heat flows may be managed as the CO2 sorbent packs are regenerated in order to promote regular or constant heat rejection on the sCO2 cycle. For instance, switching the operating mode from a power plant or power supply mode to a carbon sequestration mode may involve a plurality of steps. In power plant mode, in which energy may be generated and, e.g., output to a power grid, the power cycle may reject heat using a subset of fans from the contactor bank. Responsive to detecting an indication to initiate the switch between modes, the system 100, 200 may begin directing more power to the DAC bank 238 (e.g., in a controlled manner following structural considerations set by the DAC system). As more power is directed away from the grid and to the DAC bank 238, the amount of air scrubbing performed by the system 100, 200 may correspondingly increase. CO2 working fluid from the cycle may be directed to the contactors while scrubbing of the air is performed. Additionally or alternatively, heat may also be sent from at least the low temperature heat exchanger 220 (i.e., the syngas cooling system) to the DAC bank 238. Upon detection that a predetermined number of contactors in the DAC bank 238 are saturated with CO2 from the atmosphere, the system 100, 200 may be configured to dynamically remove at least a subset of fans from operation and to start utilizing conduction to heat the sorbents to a predetermined temperature, thereby rejecting its heat to the sorbent and initiating the process to release CO2. Supplemental cooling of the CO2 working fluid in the cycle may be achieved by sending the CO2 working fluid to other saturated sorbent banks in series (if needed). More and more power may be directed to the DAC bank 238 until all power is directed to the DAC bank 238, and the system is in carbon sequestration mode.|[0074] In the reverse scenario, the system 100, 200 may initiate a switch from a carbon sequestration mode to a power plant mode. Upon detecting initiation of this switch, the system 100, 200 may begin reducing power to fan modules in the DAC bank 238, turning off banks of fans, and thereby reducing the air scrubbing potential of the system 100, 200. As the system is switched to the carbon sequestration mode and power in the fan modules is reduced, heat rejection may be concentrated on a subset of contactors, which are allowed to saturate with CO2. For example, valving may be utilized to direct hot CO2 (that which preheats the sorbent to regenerate) between separate fan modules of the DAC bank 238. When switching to power plant mode, one or more valves may iteratively close to keep the CO2 flow directed only to the condenser fans instead of the DAC bank 238. As the amount of air scrubbed CO2 falls, less and less power may be directed to the DAC bank 238, until DAC bank 238 is shut down. In some aspects, power to the DAC bank 238 may be stopped upon determining that the air scrubbing potential of the contactors falls below a predetermined threshold. As steady state power regeneration is achieved, power cycle heat loads may thereafter be ejected, and power previously utilized to power the contactor fans in the DAC bank 238 may be redirected to a power grid.|[0075] The exemplary switching process described above enables the system 100, 200 to operate during the “peaker” period of high electricity cost. More particularly, gas combined-cycle power plants and/or coal power plants may require a long startup period when turning on before they are ready to provide power to a power grid. As a result, fuel must be consumed for an extended period of time before any power can be provided to the power grid. This results in both additional CO2 and other forms of pollution being emitted into the atmosphere by traditional power plants, as well as wasted fuel, e.g., coal, resources and thus money. Because renewable energy sources are able to produce power for the power grid at a lower cost compared to conventional gas or coal plants for the reasons described above, it may not be feasible for owners of conventional power plants to operate throughout the day. As a result, conventional power plants may need to turn off and then back on again, e.g., at the end of the day when renewable sources of power may not be available or may be available in lower quantities. The need to come on line for only part of the day, combined with the long startup period, may lead to wasted energy and resources, as well as excess pollution.|[0076] However, the system 100, 200 may address one or more of these shortcomings by providing an integrated power generation system and carbon capture system that is configured to function continuously, or for longer periods of time, either as a power plant for supplying a power grid or as a carbon sequestration system. By being able to operate continuously and switch between a power plant and carbon sequestration system, system 100, 200 may avoid or reduce the startup penalties in terms of emissions or life of the engine components experienced by traditional power plants, because the CO2 cycle system components may continue to run even when not supplying power to the power grid, as it is just the load destination that changes. Systems of the present disclosure may thus conserve resources, reduce pollution, e.g., CO2 emission, and offer a carbon negative way of generating power. Systems 100, 200 may achieve carbon negative power generation by using biomass as fuel and CO2 as the working fluid, and the systems may function as even further carbon negative when the DAC system is incorporated.|[0077] While products of the systems described herein (e.g., heat, water, syngas, etc.) may be described as being reused within the system to promote efficiency of the system, reuse of products is not required.|[0078] The time period for facilitating the switching, at step 420, from the first operating mode to the second operating mode, or from the second operating mode to the first operating mode, at step 440, may vary. For example, in an embodiment, the computer controller system may cause the system 100, 200 to be switched between the operating modes in a first “regular” time period, e.g., in one hour or less. Alternatively, some situations may require the switching to be facilitated quicker (e.g., when a sudden load demand on the power grid is realized, when a power grid is about to become destabilized, etc.). In these situations, the system 100, 200 may undergo a “hard switch” from a carbon sequestration mode to a power supply mode in a matter of minutes. This type of hard switching, however, may result in a loss of captured CO2 mid-process or at the expense of component long-term life.|[0079] At step 430, the computer control system may determine whether the predetermined condition is no longer satisfied. This determination may vary based on the type of predetermined condition, as described below.|[0080] In an embodiment, the predetermined condition may be considered to no longer be satisfied responsive to determining that the power grid operator has access to the other types of renewable energy. In an embodiment, this determination may be facilitated by receiving a second indication from the aforementioned timer or sensor. More particularly, just as the timer or sensor described above provided an indication to the computer control system to switch from the first operating mode to the second operating mode at a predetermined time, the timer or sensor may similarly provide a second indication to the computer control system to switch from the second operating mode to the first operating mode. The second indication may be received, for example, when a predetermined scheduled time has arrived. Similar to the first indication, the receipt of the second indication may be static (e.g., provided at the same time each day) or dynamic (e.g., provided at different times throughout the year based on context). Additionally or alternatively, in another embodiment, the determination may be facilitated by leveraging the historical sunlight data for the relevant geographic region to identify a sunrise time, which may be associated with a power grid operator's ability to receive another type of renewable energy, e.g., solar power. Additionally or alternatively, in another embodiment, the determination may be facilitated by leveraging the weather forecast data to identify whether the upcoming weather conditions may be favorable for the generation of certain types of renewable energy. For example, the weather forecast may indicate that the following day may be sunny or windy, which may be favorable for the generation of solar power or wind power, respectively.|[0081] In an embodiment, the predetermined condition may be considered to no longer be satisfied responsive to determining that the increased load previously required by the power grid is no longer needed. In an embodiment, this determination may be facilitated by identifying that the increased load has fallen or is expected to fall below the predetermined threshold. In some aspects, the computer control system may receive an indication from the power grid operator that there is or will no longer a need for additional power. Additionally or alternatively, the computer control system may anticipate when the power grid will no longer have a need for the additional power. For example, the computer control system may identify, from available schedule information, a designated conclusion time of a scheduled stress-producing event (e.g., concert, sporting event, festival, etc.). As another example, the computer control system may dynamically anticipate the conclusion of the scheduled stress-producing event based on access to historical context data (e.g., the computer control system may anticipate the conclusion of a concert based on knowledge of the runtime lengths of previous concert performances in general or previous performances of that specific performance, etc.). With respect to weather events that generate stress on the power grid, the computer control system may identify that the anticipated conclusion of the weather event may cause the stress on the power grid, and thus the need for additional power, to be removed. For example, upon conclusion of a heat wave, individuals may resume normal habits with respect to the operation of energy-consuming devices (e.g., individuals may no longer run their air conditioners or fans more than normal, etc.).|[0082] In an embodiment, the predetermined condition may be considered to no longer be satisfied responsive to determining that the power grid has been stabilized. In an embodiment, this determination may be facilitated by receiving an indication from the power grid operator that the failed assets that caused the grid destabilization have been repaired and/or are now operational again (e.g., other power providers contracted to provide power to the grid have renewed their ability to provide power to the grid, etc.). Additionally or alternatively, in another embodiment, the determination may be dynamically facilitated by anticipating a time period that a failed asset may be unavailable for based upon knowledge of the operational issue and/or weather, geological, and/or natural disaster event that caused the asset to be unavailable. For example, the computer control system may identify that a certain operational issue affecting a power plant may be remedied in an X time period, wherein the conclusion of the X time period may approximately correspond to grid stabilization. In another example, the computer control system may estimate, from weather and/or historical event data, an amount of time after the conclusion of an event that caused the asset to fail when the asset may be operational again.|[0083] In another embodiment, the predetermined condition may be considered no longer satisfied responsive to determining that the value projection for operation of the system 100, 200 in the second operating mode is lower than the value projection for operation of the system 100, 200 in the first operating mode. Stated differently, the predetermined condition may no longer be considered satisfied responsive to determining that operating the system 100, 200 in the second operating mode is less valuable to society, e.g., profitable, than operating the system 100, 200 in the first operating mode. In an embodiment, this determination may be facilitated by identifying that the projected value generated from sequestering and selling CO2 is lower than the projected value for providing power to the grid (e.g., because a spot price to sell CO2 has increased, etc.).|[0084] Responsive to determining, at step 430, that the predetermined condition remains satisfied, the system may, at step 435, maintain the system 100, 200 in the second operating mode. In an embodiment, the second operating mode may be maintained for as long as the predetermined condition remains satisfied. Alternatively, in another embodiment, the second operating mode may only be maintained for a predetermined period of time or until a predetermined amount of power has been provided to the power grid, irrespective of whether the predetermined condition remains satisfied.|[0085] Responsive to determining, at step 430, that the predetermined condition is no longer satisfied, the system 100, 200 may, at step 440, initiate switching of the operating mode from the second operating mode to the first operating mode. Method 400 may be repeated a plurality of times during operation of system 100, 200. This switching may enable the system 100, 200 to cycle back and forth between the two operating modes based upon the demands of a particular situation or based upon whatever is most advantageous to the system (e.g., value in terms of operating costs, revenue production, carbon capture, power generation, etc.).|[0086] Provided below are a plurality of alternative systems that may be used as system 100—in place of system 200—for performing carbon sequestration and power generation. Each of these alternative systems contains one or more variations to the components and/or process operations detailed in system 200 of FIG. 2, and may be used in a manner similar to or interchangeable with system 200 as described herein. For example, the systems of FIGS. 5, 6, and 7 may be used to perform the methods of FIG. 4 or as described above with respect to system 200. Furthermore, although portions of the systems described herein designate component origins and destinations from where heat may be removed and directed to, respectively, these are not necessarily limiting, and heat may be removed from components of any of the systems and/or from the produced syngas and directed to portions of the systems that require heat to function.|[0087] Referring now to FIG. 5, an exemplary integrated carbon sequestration and power generation system is 500 is depicted. System 500 may use biomass as fuel. As discussed in regards to systems 100 and 200 above, biomass refers to any carbon neutral or carbon negative fuel. For instance, potential types of biomass may include, e.g., wood products, such as wood processing wastes (e.g., firewood, wood pellets, wood chips, lumber and sawdust waste, etc.), agricultural products, including crops and waste materials (e.g., corn, soybeans, sugar cane, woody plants, algae, etc.), biogenic materials in municipal solid waste (e.g., paper, cotton, wool products, food, yard waste, etc.), non-biogenic materials in municipal solid waste (e.g., plastics or petroleum-based products), animal manure, or human sewage (e.g., bio waste discharge from water treatment plants). In an aspect, suitable biomass may be pre-processed by a torrefaction process, e.g., performed at a torrefaction reactor 502. In other aspects, however, pre-torrefied or otherwise pre-processed or unprocessed biomass may be received by system 500, and system 500 may not include a torrefaction reactor 502.|[0088] If incorporated into system 500, the torrefaction process may include drying the biomass and heating it in an oxygen deprived environment. Once the biomass reaches approximately 250-350 degrees C., the reaction becomes exothermic, and the products of the reaction include water, oxygen, nitrogen in the biomass, and VOCs. The VOCs may be burned to generate heat for drying and initiating the biomass reaction (which may be burned in pure oxygen or air).|[0089] In an aspect, the biomass may come out of the torrefaction reactor 502 (if included) easier to grind and containing other beneficial properties, such as increased carbon content density. This torrefied biomass may be fed into a grinding system 504, which may be configured to prepare the biomass for pressurization and conveyance, e.g., via a lock hopper 506, into an injector 508 that subsequently conveys the ground, torrefied biomass into a gasifier 510, where the biomass is partially oxidized to separate it into its constituents, e.g., using oxygen at least obtained from an air separator unit 512. The CO2 may then be pressurized. In an embodiment, the main gaseous products of the foregoing reactions include hydrogen (H2), carbon monoxide (CO), and carbon dioxide (CO2), along with trace amounts of species formed due to trace elements in the biomass. The solid products that cannot be gasified in the reaction may be collected at the bottom of the gasifier 510 as molten slag, which may include solid elements and compounds within plant biomass, such as potassium, amongst others.|[0090] In an aspect, after the syngas is formed, it may be quenched down to usable temperatures. Such a process may be facilitated by introducing water or CO2 from the main cycle into the gasifier 510, which may allow for the formation of non-liquid ashes on the condensable species. The water may be removed after the syngas is out of the reactor, while the CO2 may be kept in the stream for oxyfuel combustion purposes and expanding in the turbine system downstream. In a fully pressurized system, the foregoing water removal step may not be needed. Once the syngas leaves the gasifier reactor vessel 510, it may be processed with one or more scrubbers, candle filters, and/or other available gas processing systems in order to produce a clean syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system. Thereafter, the syngas may then be fully oxidized (e.g., with an oxygen stream derived from an air separation unit 512) in the main combustion system (e.g., oxyfuel combustor 514), thereby creating a stream of mostly water and CO2. This stream may be combined with a recirculated stream of mostly CO2 that has passed through a recuperator 516, being preheated to an amenable temperature for the cycle to have acceptable thermodynamic efficiency. The combustion stream may be diluted and may then be expanded in a first turbine stage (e.g., a high-pressure turbine 518) that powers the main cycle recirculation pump 522. After the flow of CO2 goes through that turbine expansion, it may be injected into another set of turbine stages (e.g., a low-pressure turbine 520) to fully expand to its lowest pressure level in the cycle. This may provide the power to the generator/alternator 524 that is attached mechanically to the system.|[0091] In an aspect, once the combined recirculation and combustion streams are expanded, they may be passed through one or more heat exchanger(s) (e.g., the heat exchanger(s) located in the “recuperator” section, e.g., 516). This may allow the stream to exchange heat with the high-pressure cycle pump 522 discharge, thereby heating the pump discharge as it is directed to the main combustor system 514. The CO2 flow stream coming from the turbine loses most of its water in the heat exchanger system. It is then directed to a cooling bank 526 to remove the rest of the heat in order to return the flow to close to ambient temperature before siphoning the amount of CO2 that was created in the combustion process through a 3-way valve 528 or other suitable mechanism. This CO2 stream may then be inserted into a pipeline, e.g., for transport to an underground storage location, such as a well, at 530. In other aspects, the CO2 may be liquefied for transport via a highway into a well.|[0092] In an embodiment, the cooling bank system 526 may reject heat at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent materials 532, which may be solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. The stream of CO2 may be used to heat the sorbent material bank in order to regenerate the system once it captures CO2 from the atmosphere via a series of fans configured to cool the sorbent system and allow it to come into contact with air, thereby trapping its CO2 in a charge cycle. The material may discharge via using waste heat from the CO2 power system. The fan and the compression train for the collected CO2 may use energy in the form of electric power from the turbo expander. The condensate discharged from the sorbent materials may be provided to a pump 534 and returned, via passage through the 3-way valve 528 or other suitable device, back to the high-pressure cycle pump 522, from which it may be pressured, provided to recuperator 516, and provided to the oxyfuel combustor 514 as a recirculation stream.|[0093] Referring now to FIG. 6, an exemplary carbon sequestration and power generation system 600 is depicted that is configured for high temperature heat recovery. In an aspect, the components and process flow in system 600 may be substantially equivalent to system 200 downstream from the oxyfuel combustor. However, system 600 may contain two heat exchangers located in the syngas line. The first heat exchanger may be a high temperature heat exchanger positioned upstream of the scrubber, which may be configured to heat the syngas after it has been conditioned from the gasifier. This heating process may be used to increase heat input into the CO2 cycle (such as a supercritical CO2 cycle), e.g., via a discharge stream from this first heat exchanger to the main combustor. The first high temperature heat exchanger located upstream of the scrubber may allow for the delivery of high-quality heat to the topping end of the cycle 600. The second heat exchanger may be a low temperature heat exchanger positioned downstream of the scrubber, which may be configured to remove the water in the syngas due to the quench. This process may allow steam to be generated and used for DAC capture low temperature sorbent regeneration. In an aspect, the heat removed from the first and second heat exchangers may be redirected to other components of the system 600 according to electrical or carbon sequestration energy needs.|[0094] In system 600, biomass (e.g., any carbon neutral or carbon negative fuel (such as agricultural products or waste, wood, trees, or underbrush cleared from forests, other organic waste, other municipal waste, any combination of the foregoing, and the like, as described above) may be provided from a biomass conveyance system 602 to a feed hopper 604, which may be configured to convey the biomass into gasifier 606, e.g., at a predetermined controlled feed rate.|[0095] Any suitable type of gasifier 606 may be utilized in the system 600, e.g., a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier types. The biomass provided to the gasifier 606 may be reacted with oxygen (O2) and injected steam in a gasification reaction. In an embodiment, the oxygen may be provided to gasifier 606 from an air separation unit 608 via, e.g., pump 610. The air separation unit 608 may, for example, leverage vacuum pressure swing absorption (VPSA) or temperature swing adsorption (TSA) technology to separate air into its constituent components. In another embodiment, the oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 608 may be a cryogenic system. In yet another embodiment, the oxygen may be obtained from a dedicated oxygen delivery service or pipeline. In an embodiment, the injected steam may be derived from syngas condensate and may be provided to gasifier 606 from a “second” heat exchanger, e.g., a low temperature heat exchanger 612 via pump 614, as further described herein. The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H2), carbon monoxide (CO), and CO2, along with trace amounts of species formed as a result of trace elements in the biomass. The solid products that cannot be gasified in the reaction are collected at the bottom of the gasifier 606 as molten slag and ash (e.g., fly ash, bottom ash, etc.).|[0096] Syngas formed through the gasification reaction may then be passed to a “first” heat exchanger, e.g., a high temperature heat exchanger 616, which may be configured to heat the syngas. This heated syngas may be passed to a scrubber 618 that is configured to process the syngas in order to remove water from the syngas stream and/or other ash particulates and halides in order to produce a syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system.|[0097] After exiting the scrubber 618, the cleaned syngas may pass through the low temperature heat exchanger 612. The low temperature heat exchanger 612 may be configured to remove the water in the syngas due to the quench. The syngas may be sent to pump 614 to be reinjected in gasifier 606. With the energy of condensation, this process thus may create steam to be used for DAC capture low temperature sorbent regeneration and/or to be used for steam injection into the gasifier 606.|[0098] After exiting the low temperature heat exchanger 612, the syngas stream may be compressed to full pressure, if needed by, for example, a syngas boost compressor 620. After being compressed, the pressured syngas may be directed back to the high temperature heat exchanger 616, heated, and then subsequently utilized to increase heat input into the CO2 cycle (such as a supercritical CO2 cycle), e.g., via a discharge stream from the high temperature heat exchanger 616 to a combustor 622.|[0099] In an embodiment, the combustor 622 may be a bio syngas oxy combustor. The syngas provided to the combustor 622 may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 608 and compressed via an oxygen boost compressor 624), thereby creating a stream of mostly water and CO2. The stream resultant from the oxidation reaction between the syngas and oxygen stream may be combined in the combustor 622 with a recirculated stream of mostly CO2. The recirculated stream of CO2 may have been passed through a recuperator heat exchanger 626 to preheat it to an amenable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power is left to run all the supplemental power requirements of system 600).|[0100] In an embodiment, the combustion stream exiting the combustor 622 may be expanded in one or more turbines, e.g., a first turbine 628 (e.g., a high pressure turbine). The high pressure turbine 628 may be a direct fired turbine and may be designed to efficiently extract work out of the high pressure combustion stream, which may thereafter be utilized to power the main cycle recirculation pump 630. The turbine exhaust from the high pressure turbine 628 may be directed to a second turbine 632 (e.g., a low pressure turbine). The low pressure turbine expansion may provide power to a generator 634 (i.e., a turbo alternator) that may be attached mechanically to a rotor of the low pressure turbine 632 and to a low/intermediate pressure compressor 636.|[0101] Energy generated by the generator 634 may be utilized in a variety of different ways based on the operating mode of the system 600. For instance, in a first operating mode, the system 600 may behave as a power plant, and the power generated by the generator 634 may be output from the system 600. In a second operating mode, the system 600 may behave as a CO2 capture system, and the power generated by the generator 634 may be utilized to provide power to components of a DAC system (e.g., air-contacting fans and compressors). In a third operating mode, the system 600 may be configured to distribute the power from the generator 634 to both the power grid and to the DAC system.|[0102] The low pressure turbine discharge stream may then be passed to the recuperator heat exchanger 626. The recirculating CO2 stream from the high-pressure recirculation pump 630 may also be introduced to recuperator heat exchanger 626. This allows the low pressure turbine discharge stream to exchange heat with the recirculating CO2 stream pump from the high-pressure recirculation pump 630, thereby heating the recirculating CO2 stream as it is directed to the main combustor 622 and cooling the second turbine discharge stream as it is being directed to a DAC fan bank 638. In various embodiments, heat in the CO2 stream having passed through recuperator heat exchanger 626 may be used to boil water at the low temperature range of recuperator heat exchanger 626.|[0103] The cooled second turbine discharge stream may be directed to pass through the DAC fan bank 638. The DAC fan bank 638 may be configured to reject heat at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent materials, which may be solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. For the discharge cycle, the cooled second turbine discharge stream may be used to heat the sorbent material in the DAC bank 638 (e.g., via conduction). This preheats the sorbent material to allow it to accept the steam from the syngas heat rejected by the low temperature heat exchanger 612. This steam may be used to remove the CO2 gas from the sorbent materials.|[0104] The freed CO2-containing stream is passed through a condenser 640, in which water in the freed CO2-containing stream is removed and pumped, via pump 642, back to the low temperature heat exchanger 612 to be utilized in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in a CO2 compressor 644 and sent to a pipeline via valve 646 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated underground storage location. For example, the CO2 may be transported to a well 248, which may be a class VI well. In another embodiment, the pipeline may transport the sequestered CO2, e.g., to one or more other contracting entities.|[0105] In an embodiment, after passage through the direct air capture bank 638, the cooled CO2 stream may then be transported to a low/intermediate pressure compressor 636 to go through the critical point to form, in some embodiments, sCO2 before being injected into the high pressure recirculation pump 630, configured to increase the pressure of the CO2 stream to combustion injection pressures. In an embodiment, one or both of the cooled CO2 stream exiting the DAC bank 638 and the compressed CO2 stream exiting the low/intermediate pressure compressor 636 may be cooled by another cooler 650 to increase efficiency. The recirculating pump discharge stream may then be heated via passage through the recuperator heat exchanger 626 and then recycled back into the combustor 622. In an embodiment, the CO2 that was created in the combustion process may be siphoned through a 3-way valve or other suitable flow control mechanism (e.g., an orifice plate configured to throttle the amount being rejected, or via leakage passages inside the main pump flow region, etc.) at a pressure that is ready for pipeline injection or liquefied transport through highway into the well 648 (as directed, e.g., by valve 652 or other suitable flow control mechanism).|[0106] Referring now to FIG. 7, an exemplary carbon sequestration and power generation system 700 is depicted that is configured for low temperature heat recovery. In this configuration, only one heat exchanger is provided after the scrubber, which is configured to remove the syngas heat to generate steam to be used for DAC capture low temperature sorbent regeneration. This may facilitate or maximize DAC capture capacity.|[0107] In system 700, biomass (e.g., any carbon neutral or carbon negative fuel (such as agricultural products or waste, wood, trees, or underbrush cleared from forests, other organic waste, other municipal waste, any combination of the foregoing, and the like) may be provided from a biomass conveyance system 702 to a feed hopper 704, which may be configured to convey the biomass into gasifier 706, e.g., at a predetermined controlled feed rate.|[0108] Any suitable type of gasifier 706 may be utilized in the system 700, e.g., a fixed-bed gasifier, an entrained-flow gasifier, a fluidized-bed gasifier, or other suitable gasifier types. The biomass provided to the gasifier 706 may be reacted with oxygen (O2) and injected steam in a gasification reaction. In an embodiment, the oxygen may be provided to gasifier 706 from an air separation unit 708 via pump 710. The air separation unit 708 may, for example, leverage vacuum pressure swing absorption (VPSA) or temperature swing adsorption (TSA) technology to separate air into its constituent components. In another embodiment, the oxygen may be obtained from a cryogenic oxygen separator. In another embodiment, the air separation unit 708 may be a cryogenic oxygen system. In yet another embodiment, the oxygen may be obtained from a dedicated oxygen delivery service or pipeline. In an embodiment, the injected steam may be derived from syngas condensate and may be provided to gasifier 706 from a low temperature heat exchanger 712 via pump 714, as further described herein. The product of the foregoing reaction is a syngas mixture containing gaseous hydrogen (H2), carbon monoxide (CO), and CO2, along with trace amounts of species formed as a result of trace elements in the biomass. The solid products that cannot be gasified in the reaction are collected at the bottom of the gasifier 706 as molten slag and ash (e.g., fly ash, bottom ash, etc.).|[0109] Syngas formed through the gasification reaction may then be passed to a scrubber 716 that is configured to process the syngas in order to remove water from the syngas stream and/or other ash particulates and halides in order to produce a syngas that is clean burning and will not negatively affect the machinery downstream of the main combustion system.|[0110] After exiting the scrubber 716, the cleaned syngas may pass through the low temperature heat exchanger 712. The low temperature heat exchanger 712 may be configured to remove the water in the syngas due to the quench. The syngas may be sent to pump 714 to be reinjected in gasifier 706. With the energy of condensation, this process thus may create steam to be used for DAC capture low temperature sorbent regeneration and/or to be used for steam injection into the gasifier 706.|[0111] After exiting the low temperature heat exchanger 712, the syngas stream may be compressed to full pressure, if needed by, for example, a syngas boost compressor 718. After being compressed, the pressured syngas may be introduced into a combustor 720.|[0112] In an embodiment, the combustor 720 may be a bio syngas oxy combustor. The syngas provided to the combustor 720 may be fully oxidized (e.g., with an oxygen stream derived from the air separation unit 708 and compressed via an oxygen boost compressor 722), thereby creating a stream of mostly water and CO2. The stream resultant from the oxidation reaction between the syngas and oxygen stream may be combined in the combustor 720 with a recirculated stream of mostly CO2. The recirculated stream of CO2 may have been passed through a recuperator heat exchanger 724 to preheat it to an amenable temperature for the cycle to have acceptable thermodynamic efficiency (e.g., a thermodynamic efficiency that ensures that power is left to run all the supplemental power requirements of system 700).|[0113] In an embodiment, the combustion stream exiting the combustor 720 may be expanded in one or more turbines, e.g., a first turbine 726 (e.g., a high pressure turbine). The high pressure turbine 726 may be a direct fired turbine and may be designed to efficiently extract work out of the high pressure combustion stream, which may thereafter be utilized to power the main cycle recirculation pump 728. The turbine exhaust from the high pressure turbine 726 may be directed to a second turbine 730 (e.g., a low pressure turbine). The low pressure turbine expansion may provide power to a generator 732 (e.g., a turbo alternator) that may be attached mechanically to a rotor of the low pressure turbine 730 and to a low/intermediate pressure compressor 734.|[0114] Energy generated by the generator 732 may be utilized in a variety of different ways based on the operating mode of the system 700. For instance, in a first operating mode, the system 700 may behave as a power plant, and the power generated by the generator 732 may be output from the system 700. In a second operating mode, the system 700 may behave as a CO2 capture system, and the power generated by the generator 732 may be utilized to provide power to components of a DAC system (e.g., air-contacting fans and compressors). In a third operating mode, the system 700 may be configured to distribute the power from the generator 732 to both the power grid and to the DAC system.|[0115] The low pressure turbine discharge stream may then be passed to the recuperator heat exchanger 724. The recirculating CO2 stream from the high-pressure recirculation pump 728 may also be introduced to recuperator heat exchanger 724. This allows the low pressure turbine discharge stream to exchange heat with the recirculating CO2 stream pump from the high-pressure recirculation pump 728, thereby heating the recirculating CO2 stream as it is directed to the main combustor 720 and cooling the second turbine discharge stream as it is being directed to a DAC fan bank 736. In various embodiments, heat in the CO2 stream having passed through recuperator heat exchanger 724 may be used to boil water at the low temperature range of recuperator heat exchanger 724.|[0116] The cooled second turbine discharge stream may be directed to pass through the DAC fan bank 736. The DAC fan bank 736 may be configured to reject heat at a given temperature that is amenable to use in direct air carbon sequestration sorbent regeneration. The cooling bank system may be interconnected with a bank of sorbent materials, which may be solid sorbent materials (e.g., Metal Organic Frameworks (MOFs), zeolites, silica, activated carbon, etc.), and/or liquid sorbent materials containing aqueous inorganic bases or aqueous organic amines, etc., that are capable of effectively adsorbing or absorbing and storing atmospheric CO2, and which have a low temperature or high energy requirement for CO2 regeneration. For the discharge cycle, the cooled second turbine discharge stream may be used to heat the sorbent material in the DAC bank 736 (e.g., via conduction). This preheats the sorbent material to allow it to accept the steam from the syngas heat rejected by the low temperature heat exchanger 712. This steam may be used to remove the CO2 gas from the sorbent materials.|[0117] The freed CO2-containing stream is passed through a condenser 738, in which water in the freed CO2-containing stream is removed and pumped, via pump 740, back to the low temperature heat exchanger 712 to be utilized in a continuous loop. The CO2 stream formed by the CO2 released from the sorbent may then be compressed in a CO2 compressor 742 and sent to a pipeline via valve 744 or other suitable flow control mechanism. In one embodiment, the pipeline may transport the sequestered CO2 to a designated underground storage location. For example, the CO2 may be transported to a well 746, which may be a class VI well. In another embodiment, the pipeline may transport the sequestered CO2, e.g., to one or more other contracting entities.|[0118] In an embodiment, after passage through the direct air capture bank 736, the cooled CO2 stream may then be transported to a low/intermediate pressure compressor 734 to go through the critical point to form, in some embodiments, sCO2 before being injected into the high pressure recirculation pump 728, configured to increase the pressure of the CO2 stream to combustion injection pressures. In an embodiment, one or both of the cooled CO2 stream exiting the DAC bank 736 and the compressed CO2 stream exiting the low/intermediate pressure compressor 734 may be cooled by another cooler 748 to increase efficiency. The recirculating pump discharge stream may then be heated via passage through the recuperator heat exchanger 724 and then recycled back into the combustor 720. In an embodiment, the CO2 that was created in the combustion process may be siphoned through a 3-way valve or other suitable flow control mechanism (e.g., an orifice plate configured to throttle the amount being rejected, or via leakage passages inside the main pump flow region, etc.) at a pressure that is ready for pipeline injection or liquefied transport through highway into the well 746 (as directed, e.g., by valve 750 or other suitable flow control mechanism).|[0119] As described above, exemplary integrated carbon sequestration and power generation systems described herein may incorporate a Rankine cycle as the thermodynamic power cycle 110 (FIG. 1). A typical Rankine cycle may have backpressure well below ambient pressure so the temperature of condensing water is close to room temperature to promote efficiency of the system. There is a large amount of heat released due to condensation of water. The pressure of such systems tends to be approximately 0.1 bar, as that puts the saturation temperature close to normal ambient temperature.|[0120] Embodiments of the present disclosure that include a Rankine cycle as the thermodynamic power cycle may alter the backpressure of a steam turbine in the integrated carbon sequestration and power generation system to a value of approximately 0.5 bar to approximately 1.0 bar, e.g., of approximately 1 bar. At approximately 1 bar, the saturation temperature is 100 degrees Celsius, and there will be constant temperature heat rejection until all steam has condensed to water. As a result, maintaining the backpressure of a steam turbine at approximately 1 bar may have the benefit that sorbent in the DAC portion of the integrated system being regenerated will get to that temperature of 100 degrees Celsius. In this way, for some exemplary systems of the disclosure, the backpressure of a steam turbine may be chosen to target the temperature required for the sorbent, and steam may be bypassed around a secondary steam turbine so the amount of electrical power and thermal power is matched to what the DAC system requires. For example, a first portion of steam that has gone through a first steam turbine may be utilized to regenerate the sorbent of the integrated DAC system, and a second portion of steam (e.g., the remaining steam) may continue through a second steam turbine down to the normal Rankine backpressure. These two streams may come together after a pump brings the condensed 0.1 bar water back up to pressure.|[0121] Referring now collectively to FIGS. 8A and 8B and Table 2 above, plot diagrams are provided for illustrating the benefits of the pressure and temperature ranges described herein. One potential benefit of the system embodiments described herein is that the output power in the cycles occurring in systems 100, 200, 500, 600 and 700 may be adjusted while maintaining the turbomachinery “on-design” by adjusting the pressures on the flow. For example, if the output power of a system needs to be reduced, CO2 may be bled out from the system faster, correspondingly resulting in a drop of pressure. As an example of the foregoing, if CO2 is removed so that the low pressure compressor suction pressure is approximately 20 bar, then the high pressure compressor discharge would be approximately 96 bar, resulting in an approximately 40% reduction in power generation. The foregoing abilities enable flexibility with respect to gasification output, power demands, etc.|[0122] Furthermore, as the temperature of the system is increased, the pressure also correspondingly needs to be increased in order to maintain the temperature on the recuperator. This may provide for higher efficiency while using fundamentally the same cycle. For example, in this case, if the low end pressure is held at approximately 35 bar, but a variant was desired that operated at a higher efficiency, compression could be increased and subsequently the temperature could also be increased. As a result, in embodiments of the disclosure described herein, increasing the discharge pressure and the combustor temperature may boost efficiency but the cycle is generally equivalent.|[0123] In general, any process discussed in this disclosure that is computer-implementable may be performed manually or by one or more processors of a computer system. A process or process step performed by one or more processors may also be referred to as an operation. The one or more processors may be configured to perform such processes by having access to instructions (e.g., software or computer-readable code) that, when executed by the one or more processors, cause the one or more processors to perform the processes. The instructions may be stored in a memory of the computer server. A processor may be a central processing unit (CPU), a graphics processing unit (GPU), or any suitable types of processing unit.|[0124] A computer system, such as a computer control system associated with any of systems 100, 200, 500, 600, and 700 may include one or more computing devices. If the one or more processors of the computer system are implemented as a plurality of processors, the plurality of processors may be included in a single computing device or distributed among a plurality of computing devices. If a system environment comprises a plurality of computing devices, the memory of the computer system may include the respective memory of each computing device of the plurality of computing devices.|[0125] FIG. 9 is a simplified functional block diagram of a computer system 900 that may be configured as a computing device for executing the process illustrated in FIG. 4 and/or that may be compatible with any of systems 100, 200, 500, 600, and 700, according to exemplary embodiments of the present disclosure. FIG. 9 is a simplified functional block diagram of a computer that may be configured as according to exemplary embodiments of the present disclosure. In various embodiments, any of the systems herein may be an assembly of hardware including, for example, a data communication interface 920 for packet data communication. The platform also may include a central processing unit (“CPU”) 902, in the form of one or more processors, for executing program instructions. The platform may include an internal communication bus 908, and a storage unit 906 (such as ROM, HDD, SDD, etc.) that may store data on a computer readable medium 922, although the system 900 may receive programming and data via network communications via electronic network 925 (e.g., voice, video, audio, images, or any other data over the electronic network 925). The system 900 may also have a memory 904 (such as RAM) storing instructions 924 for executing techniques presented herein, although the instructions 924 may be stored temporarily or permanently within other modules of system 900 (e.g., processor 902 and/or computer readable medium 922). The system 900 also may include input and output ports 912 and/or a display 910 to connect with input and output devices such as keyboards, mice, touchscreens, monitors, displays, etc. The various system functions may be implemented in a distributed fashion on a number of similar platforms, to distribute the processing load. Alternatively, the systems may be implemented by appropriate programming of one computer hardware platform.|[0126] Program aspects of the technology may be thought of as “products” or “articles of manufacture” typically in the form of executable code and/or associated data that is carried on or embodied in a type of machine-readable medium. “Storage” type media include any or all of the tangible memory of the computers, processors or the like, or associated modules thereof, such as various semiconductor memories, tape drives, disk drives and the like, which may provide non-transitory storage at any time for the software programming. All or portions of the software may at times be communicated through the Internet or various other telecommunication networks. Such communications, for example, may enable loading of the software from one computer or processor into another, for example, from a management server or host computer of the mobile communication network into the computer platform of a server and/or from a server to the mobile device. Thus, another type of media that may bear the software elements includes optical, electrical and electromagnetic waves, such as used across physical interfaces between local devices, through wired and optical landline networks and over various air-links. The physical elements that carry such waves, such as wired or wireless links, optical links, or the like, also may be considered as media bearing the software. As used herein, unless restricted to non-transitory, tangible “storage” media, terms such as computer or machine “readable medium” refer to any medium that participates in providing instructions to a processor for execution.|[0127] While some embodiments described herein include some but not other features included in other embodiments, combinations of features of different embodiments are meant to be within the scope of the invention, and form different embodiments, as would be understood by those skilled in the art. For example, in the following claims, any of the claimed embodiments can be used in any combination.|[0128] Thus, while certain embodiments have been described, those skilled in the art will recognize that other and further modifications may be made thereto without departing from the spirit of the invention, and it is intended to claim all such changes and modifications as falling within the scope of the invention. For example, functionality may be added or deleted from the block diagrams and operations may be interchanged among functional blocks. Steps may be added or deleted to methods described within the scope of the present invention.|[0129] The above disclosed subject matter is to be considered illustrative, and not restrictive, and the appended claims are intended to cover all such modifications, enhancements, and other implementations, which fall within the true spirit and scope of the present disclosure. Thus, to the maximum extent allowed by law, the scope of the present disclosure is to be determined by the broadest permissible interpretation of the following claims and their equivalents, and shall not be restricted or limited by the foregoing detailed description. While various implementations of the disclosure have been described, it will be apparent to those of ordinary skill in the art that many more implementations are possible within the scope of the disclosure. Accordingly, the disclosure is not to be restricted except in light of the attached claims and their equivalents. | Family Number|(110578690)|110578690|Advantages / Prev. Drawbacks|(US20240240619 A1)|Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation (...) |(US12359613 B2)|Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation (...) |(WO2024152006 A1)|Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation (...) |(US20250154895 A1)|Additionally, current BiCRS, also known as Bio Energy with Carbon Capture and Sequestration (BECCS) systems, are not generally designed with scalability in mind and are the product of trying to retrofit existing biomass power plants with carbon sequestration systems, which may be prohibitively expensive and may not allow these power generation (...) | | Chemical engineering|Civil engineering|Engines, pumps, turbines|Environmental technology|Materials, metallurgy | B01D-053/14/75|C01B-032/50|C01B-2203/86|E21B-041/00/64|F01K-003/18/8|F01K-023/06/7|F02C-003/28|F02C-003/30|F02C-003/34|F03G-004/033|F25J-003/02/66|Y02E-020/34|Y02E-050/30 | B01D-053/14/75|C01B-032/50|C01B-2203/86|E21B-041/00/64|F01K-003/18/8|F01K-023/06/7|F02C-003/28|F02C-003/30|F02C-003/34|F03G-004/033|F25J-003/02/66|Y02E-020/34|Y02E-050/30 | B01D-053/02|B01D-053/14|C01B-032/50|E21B-041/00|F01K-003/18|F01K-023/06|F02C-003/28|F02C-003/30|F02C-003/34|F03G-004/00|F03G-007/00|F23G-005/027|F25J-003/02 | B01D-053/02|B01D-053/14|C01B-032/50|E21B-041/00|F01K-003/18|F01K-023/06|F02C-003/28|F02C-003/30|F02C-003/34|F03G-004/00|F03G-007/00|F23G-005/027|F25J-003/02 | 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|NAME=Smith Aaron Ezekiel, CITY=Hermosa Beach, STATE=CA , COUNTRY=US|(US20240240619)|NAME=GARCIA-CLARK Andres Jose, CITY=San Pedro, STATE=CA , COUNTRY=US |NAME=HARTWIG Bradley, CITY=Manhattan Beach, STATE=CA , COUNTRY=US |NAME=SMITH Aaron Ezekiel, CITY=Hermosa Beach, STATE=CA , COUNTRY=US|(US20250154895)|NAME=GARCIA-CLARK Andres Jose, CITY=San Pedro, STATE=CA , COUNTRY=US |NAME=HARTWIG Bradley, CITY=Manhattan Beach, STATE=CA , COUNTRY=US |NAME=SMITH Aaron Ezekiel, CITY=Hermosa Beach, STATE=CA , COUNTRY=US|(WO2024/152006)|NAME=GARCIA-CLARK, Andres Jose c/o Arbor Energy and Resources Corporation 129 Sierra Street El Segundo, California 90245, POSTCODE=90245, COUNTRY=US |NAME=HARTWIG, Bradley c/o Arbor Energy and Resources Corporation 129 Sierra Street El Segundo, California 90245, POSTCODE=90245, COUNTRY=US |NAME=SMITH, Aaron Ezekiel c/o Arbor Energy and Resources Corporation 129 Sierra Street El Segundo, California 90245, POSTCODE=90245, COUNTRY=US | (US20250154895)|8|(WO2024/152006)|9|(JP2026505712)|6|(US12359613)|8 | 5 | 5 | (EP4649228)|WO2024/152006|(JP2026505712)|WO2024/152006 | (US12359613)|Number of Claims: NCL=20|Number of Drawings: NDR=12|Number of Figures: NFG=10|Independent Claim Number: ICL=1,10,15,18|Number of Independent Claims: NICL=4|Exemplary Claim Number: ECL=1|Extended under 35 USC 154(b) the following days: EXTD=0|Primary examiner: Dounis Laert|Art Unit.: ART =3746||(US20240240619)|Number of Claims: NCL=20|Number of Drawings: NDR=12|Number of Figures: NFG=10|Independent Claim Number: ICL=1,16|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1|Primary examiner: Dounis Laert|Art Unit.: ART =3746||(US20250154895)|Number of Claims: NCL=20|Number of Drawings: NDR=12|Number of Figures: NFG=10|Independent Claim Number: ICL=1,16|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1||(WO2024/152006)|Number of Claims: NCL=20|Extended kind: EXTK=x||(JP2026505712)|Number of Claims: NCL=20|Request for examination: REQEXA=false| | (US12359613)|Provisional Appl: US63/535,990 FDD=2023-08-31 [2023US-63535990]|Provisional Appl: US63/479,875 FDD=2023-01-13 [2023US-63479875]|Previous publication: US20240240619 A1 2024-07-18 [US20240240619]|(US20250154895)|Continuation of: US18/412,241 FDD=2024-01-12 [2024US-18412241]|Provisional Appl: US63/479,875 FDD=2023-01-13 [2023US-63479875]|Provisional Appl: US63/535,990 FDD=2023-08-31 [2023US-63535990] | (EP4649228)|ENGLISH (ENG) | (JP2026505712)|Patent|(EP4649228)|Patent|(US12359613)|Patent|(US20250154895)|Patent|(US20240240619)|Patent|(WO2024152006)|Patent | Titre: (EP4649228)|Integrated carbon sequestration and power generation system and methods of use Résumé: (EP4649228)|Systems and methods for providing an integrated carbon sequestration and power generation system are disclosed. The integrated carbon sequestration and power generation system may include: a thermodynamic cycle configured to receive biomass and to output heat and power; and a direct air capture system configured to receive at least some of the heat and the power output from the thermodynamic cycle. Other aspects are described and claimed. Autre: (US12359613)|We claim:|1. An integrated carbon sequestration and power generation system, comprising:| a thermodynamic cycle configured to receive biomass and to generate heat and power; and| a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration;| wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system;| wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied;| wherein the determining whether the predetermined condition is satisfied comprises determining whether a threshold number or type of power sources associated with the power grid are available.|2. The integrated carbon sequestration and power generation system of claim 1, wherein the biomass includes at least one of: plant matter or municipal waste.|3. The integrated carbon sequestration and power generation system of claim 1, wherein sorbent material of the DAC carbon sequestration system includes a solid sorbent or a liquid sorbent configured to adsorb carbon dioxide (CO2).|4. The integrated carbon sequestration and power generation system of claim 3, wherein at least some of the heat produced by the thermodynamic cycle is utilized to regenerate the sorbent material after carbon capture.|5. The integrated carbon sequestration and power generation system of claim 1, wherein at least one of a sensor or a timer is used to determine whether the predetermined condition is satisfied.|6. The integrated carbon sequestration and power generation system of claim 1, wherein the determining whether the predetermined condition is satisfied further comprises receiving information from a power grid operator that the predetermined condition is satisfied.|7. The integrated carbon sequestration and power generation system of claim 1, wherein the determining whether the predetermined condition is satisfied further comprises determining whether an increased load is required by the power grid.|8. The integrated carbon sequestration and power generation system of claim 1, wherein the determining whether the predetermined condition is satisfied further comprises determining whether a first projected value derived from operation of the integrated carbon sequestration and power generation system in the first operating mode is greater or less than a second projected value derived from operation of the integrated carbon sequestration and power generation system in the second operating mode.|9. The integrated carbon sequestration and power generation system of claim 1, wherein the power generation system includes at least one of a Brayton cycle, a recuperated Brayton cycle, or a Rankine cycle.|10. An integrated carbon sequestration and power generation system, comprising:| a gasifier configured to receive a biomass and configured to produce a syngas;| a combustor configured to produce a combustion stream from the cleaned syngas, oxygen, and a recirculation carbon dioxide (CO2) stream;| at least one turbine, wherein the at least one turbine is operatively coupled to a direct air capture (DAC) carbon sequestration system and to a high pressure recirculation pump to optionally or simultaneously provide power produced by the at least one turbine to the DAC carbon sequestration system in a first operating mode or to a power grid separate from the integrated carbon sequestration and power generation system in a second operating mode;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and;| wherein the determining whether the predetermined condition is satisfied comprises determining whether a threshold number or type of power sources associated with the power grid are available.|11. The integrated carbon sequestration and power generation system of claim 10, wherein the biomass is a torrefied biomass.|12. The integrated carbon sequestration and power generation system of claim 10, further comprising:| a scrubber, fluidly coupled to the gasifier, configured to clean the syngas.|13. The integrated carbon sequestration and power generation system of claim 12, further comprising:| a low temperature heat exchanger, fluidly coupled to the scrubber, configured to cool the cleaned syngas.|14. The integrated carbon sequestration and power generation system of claim 10, wherein the power generation system includes at least one of a Brayton cycle, a recuperated Brayton cycle, or a Rankine cycle.|15. An integrated carbon sequestration and power generation system, comprising:| a thermodynamic cycle configured to receive biomass and to generate heat and power; and| a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration;| wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system;| wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and| wherein the determining whether the predetermined condition is satisfied comprises assessing a weather forecast.|16. The integrated carbon sequestration and power generation system of claim 15, wherein the determining comprises determining that the predetermined condition is satisfied responsive to:| identifying, from data associated with the weather forecast, that an upcoming weather event will affect an ability of a renewable energy provider to provide power provided to the power grid for a predetermined period of time.|17. The integrated carbon sequestration and power generation system of claim 16, wherein the integrated carbon sequestration and power generation system is configured to switch to and remain in the second operating mode during at least a portion of the predetermined period of time.|18. An integrated carbon sequestration and power generation system, comprising:| a thermodynamic cycle configured to receive biomass and to generate heat and power; and| a direct air capture (DAC) carbon sequestration system configured to receive at least some of the heat and at least some of the power generated by the thermodynamic cycle to facilitate carbon sequestration;| wherein the integrated carbon sequestration and power generation system is configured to provide at least some of the power produced by the thermodynamic cycle to a power grid that is separate from the integrated carbon sequestration and power generation system;| wherein the integrated carbon sequestration and power generation system is configured to switch between a first operating mode, in which at least some of the power produced by the thermodynamic cycle is used to power the DAC carbon sequestration system, and a second operating mode, in which at least some of the power produced by the thermodynamic cycle is provided to the power grid;| wherein the integrated carbon sequestration and power generation system is configured to switch between the first operating mode and the second operating mode based at least in part on whether a predetermined condition is determined to be satisfied; and| wherein the determining whether the predetermined condition is satisfied comprises determining whether a power grid operator has access to renewable energy from a renewable energy provider.|19. The integrated carbon sequestration and power generation system of claim 1, wherein the determining comprises determining that the predetermined condition is satisfied responsive to:| identifying that the threshold number or type of power sources associated with the power grid are not available; and| determining, responsive to identifying, that the power grid will become destabilized within a predetermined timed threshold.|20. The integrated carbon sequestration and power generation system of claim 19, wherein the integrated carbon sequestration and power generation system is configured to switch to the second operating mode prior to the predetermined time threshold. | 15 | Abstract | gpt-4o-mini | uncertain | The article mentions an integrated carbon sequestration and power generation system that includes biomass, but it also involves a direct air capture system, which is not aligned with the BECCS definition. | ||||||||||||||||
| 18 | CN202210668058 | CN202210668058 | CN114950121|CN114950121 | 101539929 | CN114950121 B 2023-08-15 [CN114950121B]|CN114950121 A 2022-08-30 [CN114950121] | 2022-06-14 | 2022-06-14 | 2023-08-15|2022-08-30 | (CN114950121B)|2023-08-15 | (CN114950121)|2042-06-14 | (CN114950121)|CO for direct air capture 2 Microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system | (CN114950121)|A microalgae-carbonic anhydrase double-sided composite membrane carbon sequestration system for direct air capture of CO2 comprises a reactor for loading a microalgae solution, at least one part of the bottom of the reactor is a breathable fixing device, and at least one part of the top or side wall of the reactor is a light-transmitting wall surface; a double-sided composite film is carried on the fixing device, microalgae particles are attached to the upper surface of the double-sided composite film, namely the microalgae side, and carbonic anhydrase is attached to the lower surface of the double-sided composite film, namely the air side. One side of the double-sided composite membrane is in contact with air, the other side of the double-sided composite membrane is in contact with a microalgae solution, low-concentration CO2 in the air is catalyzed to be converted into HCO3 <->, the HCO3 <-> is supplied to the microalgae solution, the microalgae side can be subjected to hydrophilic modification, the attachment characteristic of microalgae is enhanced, and the problems that CO2 at low concentration is low in mass transfer coefficient and insufficient in contact with the microalgae are solved; the method has the characteristics of low cost, convenience in microalgae harvesting, high carbon sequestration efficiency and the like, can effectively capture and immobilize low-concentration CO2 in the air, and has important significance for realizing a carbon neutralization target. | XIAN JIAOTONG UNIVERSITY | (CN114950121)|XI'AN JIAOTONG UNIVERSITY ([CN])|(CN114950121)|XI'AN JIAOTONG UNIVERSITY ([CN]) | LI MINGJIA|LI GUANGMEI|WANG RUILONG|YANG YIWEN | (CN114950121)|LI MINGJIA|LI GUANGMEI|WANG RUILONG|YANG YIWEN|(CN114950121)|LI MINGJIA|LI GUANGMEI|WANG RUILONG|YANG YIWEN | (CN114950121)|DUAN JUNTAO;XI AN CYDA INTELLECTUAL PROPERTY AGENCY|Reg. Nb: 61215 | (CN114950121)|In the DACCS and BECCS technologies, microalgae are taken as one of microorganisms with higher photosynthesis rate, have the advantages of high carbon fixation rate, small occupied area, cleanness, no pollution and the like, can be taken as a production platform of third-generation bioenergy, and are considered as one of high-efficiency carbon fixation paths with development prospects in recent years.|Microalgae are used for direct air CO 2 At the time of capturing, due to CO 2 The concentration is low (about 0.04%) and is preferably for the most partCO grown by microalgae species 2 The concentration is about 5-20%, so that the photosynthesis rate of microalgae is low and CO is low when the air is directly trapped 2 Both solubility in water and conversion to bicarbonate efficiency are difficult to meet the high-rate carbon sequestration requirements.| | (CN114950121)|1. CO for direct air capture 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system is characterized by comprising a reactor for loading microalgae solution (1), wherein at least one part of the bottom of the reactor is a breathable fixing device (2), and at least one part of the top or the side wall of the reactor is a light-permeable wall surface (4); the fixing device (2) is provided with a double-sided composite film (3), wherein microalgae particles (6) are attached to the upper surface of the double-sided composite film (3), namely the microalgae side, and carbonic anhydrase (5) is attached to the lower surface of the double-sided composite film (3), namely the air side;the fixing device (2) is a metal net for supporting and fixing the double-sided composite membrane (3), and CO in the air 2 The gas contacts with a double-sided composite membrane (3) through metal mesh pores to provide a carbon source required by a reactor, and the double-sided composite membrane (3) is a high-molecular porous fiber membrane manufactured by adopting an electrostatic spinning method;the carbonic anhydrase (5) is attached to the electrostatic spinning fiber bundle on the lower surface of the double-sided composite membrane (3) in a chemical modification mode, so that CO on the surface of the membrane is improved 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- The method comprises the steps of carrying out a first treatment on the surface of the The microalgae particles (6) are uniformly adhered to the upper surface of the double-sided composite membrane (3) based on the action of gravity, and CO 2 And HCO 3 Through the membraneThe microporous structure of the (2) is contacted with microalgae particles to complete photosynthesis reaction;the reactor adopts a natural convection air supply mode, and CO in the air 2 Enters the reactor from the fixing device (2) and the double-sided composite film (3) in a diffusion mode.| | (CN114950121)|As shown in FIG. 1, the present invention is a method for direct air captureCO collection 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system comprises a reactor.|CO for direct air capture 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system comprises a reactor for loading microalgae solution, wherein at least one part of the bottom of the reactor is a breathable fixing device, and at least one part of the top or the side wall is a light-transmitting wall surface; the fixing device is provided with a double-sided composite film, the upper surface of the double-sided composite film, namely the microalgae side is used for attaching microalgae particles, and the lower surface of the double-sided composite film, namely the air side is used for attaching carbonic anhydrase.| | (CN114950121)|COMPOSITE MEMBRANE(100,38)|CARBON FIXATION(100,17)|MICROALGAE CARBONIC ANHYDRASE(100,15)|DIRECT AIR CAPTURE(100,11)|COMPOSITE MEMBRANE CARBON FIXATION(100,9)|CARBON FIXING(100,5)|COMPOSITE MEMBRANE CARBON FIXING(100,5)|MICROALGAE PARTICLE(50,14)|DOUBLE SIDED COMPOSITE MEMBRANE(43,23)|BREATHABLE FIXING(43,4)|LOADING MICROALGAE SOLUTION(34,3)|ELECTROSTATIC SPINNING(30,15)|ELECTROSTATIC SPINNING FIBER BUNDLE(30,2)|ATTACHING CARBONIC ANHYDRASE(29,2)|MICROALGAE(26,11)|MICROALGAE HARVESTING(26,3)|GENERATION BIOENERGY(26,1)|MESH PORE(26,1)|REACTOR(25,19)|DEVELOPMENT PROSPECT(25,1)|MEMBRANETHE MICROPOROUS STRUCTURE(25,1)|HYDROPHILIC MODIFICATION(24,2)|MICROALGAE SPECIES(24,2)|FIBER MEMBRANE(24,1)|DOUBLE SIDED COMPOSITE FILM(23,18)|MICROALGAE ADHESION PISTON ROD(23,1)|PHOTOSYNTHESIS REACTION(21,3)|SPINNING FIBER BUNDLE(21,2)|AIR CAPTURECO(19,1)|BECCS(19,1)|CARBONIC ANHYDRASE(18,19)|CARBON SEQUESTRATION REQUIREMENT(18,1)|MICROORGANISM(18,1)|PHOTOSYNTHESIS RATE(18,1)|COMPOSITE FILM(17,20)|CLEANNESS(15,1)|CONTAMINATION(15,1)|DACCS(15,1)|MICROALGAE PARTICLE SURFACE(15,1)|CARBON NEUTRALIZATION(14,2)|DIFFUSION MODE(14,2)|PHOTOSYNTHESIS(14,2)|SOLUBILITY(14,1)|SIGNIFICANCE(13,1)|METAL MESH PORE(12,3)|HCO(11,5)|PROMOTION(11,5)|BICARBONATE(11,2)|CARBON FIXATION PATH(11,1)|MEMBRANE PREPARATION LIQUID(11,1)|MICROALGAE SIDE(10,4)|METALLIC NET(10,2)|CARBON SEQUESTRATION(9,2)|NATURAL CONVECTION(8,4)|PRODUCTION PLATFORM(8,1)|CHEMICAL MODIFICATION MODE(7,2)|ELECTROSTATIC SPINNING NEEDLE(7,2)|INSUFFICIENT CONTACT(7,2)|WALL SURFACE(6,4)|PVDF MASS RATIO(6,3)|MICROALGAE BIOLOGICAL CULTURE REACTOR(6,1)|MICROALGAE EXPANSION CULTIVATION(6,1)|ELECTROSTATIC SPINNING TREATMENT(5,2)|CARBONIC ANHYDRASE CATALYSIS(5,1)|ELECTROSTATIC SPINNING COMPOSITE MEMBRANE(5,1)|MICROALGAE PARTICLE ADHESION(5,1)|MICROALGAE PHOTOSYNTHESIS(5,1)|SMALL AREA OCCUPATION(5,1)|UPPER SURFACE(4,13)|AIR SUPPLY MODE(4,3)|MEMBRANE MATERIAL VENTILATION RATE(4,1)|PVDF PVP COMPOSITE MEMBRANE(4,1)|STRENGTHENING DISSOLUTION(4,1)|CARBON SOURCE(3,5)|ALUMINUM FOIL PAPER(3,3)|STAINLESS STEEL MESH(3,3)|TRANSPARENT ORGANIC GLASS MATERIAL(3,3)|BICARBONATE ION(3,2)|PVDF CONTENT(3,2)|PVP CONTENT(3,2)|ALGAE SEED(3,1)|CARBONIC ANHYDRASE ATTACHMENT(3,1)|DRIVEN PUMP(3,1)|DUPLEX WIRESFACE COMPOSITE FILM(3,1)|ELECTROSPUN FIBER BUNDLE(3,1)|ELECTROSTATIC SPINNING FIBER FILM(3,1)|ELECTROSTATIC SPINNING FILM(3,1)|ELECTROSTATIC SPINNING VOLTAGE(3,1)|FERRIC AMMONIUM CITRATE(3,1)|HIGH CARBON FIXATION RATE(3,1)|ION CHROMATOGRAPH(3,1)|LIGHT PERMEABLE WALL SURFACE(3,1)|MICROALGAE CARBON FIXATION(3,1)|POROSITY POROUS FIBROUS MEMBRANE(3,1)|PVDF PROPORTION(3,1)|PVDF PVP MEMBRANE(3,1)|AERATION(2,2)|LABORATORY(2,2)|LIGHT TRANSMITTING WALL SURFACE(2,2)|MEMBRANE PREPARATION SOLUTION(2,2)|NEEDLE HEAD(2,2)|NUTRIENT SOLUTION(2,2)|SYRINGE(2,2)|ULTRAPURE WATER(2,2)|CONTACT MEMBRANE PHOTOBIOREACTOR(2,1)|DENITRIFICATION(2,1)|DIMETHYLACETAMIDE SOLUTION(2,1)|ELECTROSTATIC SPINNING COMPOSITE FILM(2,1)|EMBODIMENTWHEREIN(2,1)|EXPERIMENTAL TEST(2,1)|FINE BUBBLE(2,1)|GAS DISPERSER(2,1)|INTEGRATED ELECTROSTATIC SPINNING MACHINE(2,1)|NUTRIENT ION(2,1)|PREPARED PVDF PVP(2,1)|PVP POWDER(2,1)|SCENEDESMUS OBLIQUUS(2,1)|VENTILATION VOLUME(2,1)|AERATOR(1,1)|AGGREGATION(1,1)|CARBONIC ANHYDRASE ASSISTED(1,1)|CATALYTIC CONVERSION EFFICIENCY(1,1)|CATHETER(1,1)|CONCENTRATION CARBON FIXATION(1,1)||(CN114950121)|COMPOSITE MEMBRANE(100,55)|DOUBLE SIDED COMPOSITE MEMBRANE(100,44)|MICROALGAE CARBONIC ANHYDRASE(100,20)|DIRECT AIR CAPTURE(100,19)|CARBON FIXATION(100,18)|COMPOSITE MEMBRANE CARBON FIXATION(100,10)|CARBON FIXING CONNECTION(100,7)|PHONE CARBONIC ANHYDRASE(33,4)|BREATHABLE FIXING(33,3)|MICROALGAE PARTICLE(32,14)|MICROALGAE(30,13)|LOADING MICROALGAE SOLUTION(24,3)|MICROALGAE HARVESTING(24,2)|MICROALGAE SPECIES(22,2)|DEVELOPMENT PROSPECT(22,1)|HYDROPHILIC MODIFICATION(17,4)|REACTOR(16,17)|BECCS(16,1)|MICROORGANISM(16,1)|PHOTOSYNTHESIS RATE(16,1)|ELECTROSTATIC SPINNING FIBER BUNDLE(15,3)|MODIFIED MICROALGAE(15,1)|PVDF CONTENT(14,8)|CLEANNESS(13,1)|CONTAMINATION(13,1)|DACCS(13,1)|HYDROPHILICITY(12,6)|CARBON NEUTRALIZATION(12,2)|PHOTOSYNTHESIS(12,2)|HYDROPHOBICITY(11,4)|PHOTOSYNTHESIS REACTION(11,3)|GENERATION BIOLOGICAL ENERGY(11,1)|PVP CONTENT(10,3)|SOLUBILITY(10,2)|BICARBONATE(9,3)|SIGNIFICANCE(9,2)|MEMBRANETHE CARBON CONNECTION(9,1)|HCO(8,5)|MICROALGAE SIDE(8,5)|DOUBLE SIDED COMPOSITE FILM(7,8)|PROMOTION(7,4)|CARBON SEQUESTRATION(7,3)|CONVERSION EFFICIENCY(7,1)|MICROALGAE BIOLOGICAL CULTURE REACTORIN(7,1)|PRODUCTION PLATFORM(7,1)|ELECTROSTATIC SPINNING COMPOSITE MEMBRANE(6,2)|ELECTROSTATIC SPINNING MEMBRANE(6,2)|INSUFFICIENT CONTACT(6,2)|PVDF MASS RATIO(6,2)|METAL MESH(5,3)|MASS TRANSFER(5,2)|METAL NET(5,2)|MICROALGAE PHOTOSYNTHESIS(5,1)|PVP MATERIAL(5,1)|TRANSPARENT WALL SURFACE(5,1)|DIFFUSION ERROR SIGNAL(4,2)|MICROPOROUS STRUCTURE CONTACT(4,2)|ELECTROSTATIC SPINNING FIBER MEMBRANE(4,1)|SMALL AREA OCCUPATION(4,1)|BICARBONATE ION(3,2)|CONTACT MEMBRANE PHOTOBIOREACTOR(3,2)|MEMBRANE MATERIAL VENTILATION RATE(3,2)|TRANSPARENT ORGANIC GLASS MATERIAL(3,2)|ATTACHING CARBONIC ANHYDRASE(3,1)|CARBONIC ANHYDRASE CATALYTIC ACTION(3,1)|ELECTROSTATIC SPINNING NEEDLE HEAD(3,1)|ELECTROSTATIC SPINNING RAPID(3,1)|ELECTROSTATIC SPINNING TREATMENT(3,1)|ELECTROSTATIC SPINNING VOLTAGE(3,1)|HIGH CARBON SEQUESTRATION RATE(3,1)|MICROALGAE PARTICLE ADHESION PERFORMANCE(3,1)|POLYMER MEMBRANE PHONE MICROPORE(3,1)|PVDF PVP COMPOSITE MEMBRANE(3,1)|STRENGTHENING DISSOLUTION(3,1)|UPPER SURFACE(2,13)|INJECTOR(2,3)|ALUMINUM FOIL PAPER(2,2)|CHEMICAL MODIFICATION ERROR SIGNAL(2,2)|HIGH CARBON FIXATION(2,2)|LABORATORY(2,2)|NUTRIENT SOLUTION(2,2)|POROSITY(2,2)|ALGAE SPECIES(2,1)|DEMOULDING(2,1)|DENITRIFICATION(2,1)|DIMETHYLACETAMIDE SOLUTION(2,1)|FERRIC AMMONIUM CITRATE(2,1)|FINE BUBBLE(2,1)|GAS DISPERSER(2,1)|INTEGRATED ELECTROSTATIC SPINNING MACHINE(2,1)|ION CHROMATOGRAPH(2,1)|MEMBRANE FLUX(2,1)|MICROALGAE CARBON SEQUESTRATION(2,1)|MICROALGAE SOLUTION GRAVITY(2,1)|NUTRIENT ION(2,1)|PREPARED MEMBRANE PERFORMANCE SUPERIORITY(2,1)|PROPULSION PUMP(2,1)|PVP POWDER(2,1)|SCENEDESMUS OBLIQUUS(2,1)|SPINNING MEMBRANE PREPARATION LIQUID(2,1)|VENTILATION CAPACITY(2,1)|WRAPPING ALUMINUM FOIL(2,1)|AERATOR(1,1)|AGGREGATION(1,1)| | (CN114950121)|1. CO for direct air capture 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system is characterized by comprising a reactor for loading microalgae solution (1), wherein at least one part of the bottom of the reactor is a breathable fixing device (2), and at least one part of the top or the side wall of the reactor is a light-permeable wall surface (4); the fixing device (2) is provided with a double-sided composite film (3), wherein microalgae particles (6) are attached to the upper surface of the double-sided composite film (3), namely the microalgae side, and carbonic anhydrase (5) is attached to the lower surface of the double-sided composite film (3), namely the air side;|the fixing device (2) is a metal net for supporting and fixing the double-sided composite membrane (3), and CO in the air 2 The gas contacts with a double-sided composite membrane (3) through metal mesh pores to provide a carbon source required by a reactor, and the double-sided composite membrane (3) is a high-molecular porous fiber membrane manufactured by adopting an electrostatic spinning method;|the carbonic anhydrase (5) is attached to the electrostatic spinning fiber bundle on the lower surface of the double-sided composite membrane (3) in a chemical modification mode, so that CO on the surface of the membrane is improved 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- The method comprises the steps of carrying out a first treatment on the surface of the The microalgae particles (6) are uniformly adhered to the upper surface of the double-sided composite membrane (3) based on the action of gravity, and CO 2 And HCO 3 Through the membraneThe microporous structure of the (2) is contacted with microalgae particles to complete photosynthesis reaction;|the reactor adopts a natural convection air supply mode, and CO in the air 2 Enters the reactor from the fixing device (2) and the double-sided composite film (3) in a diffusion mode.|2. The method for direct air capture of CO according to claim 1 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the double-sided composite membrane (3) is prepared from PVDF and PVP by an electrostatic spinning method.|3. The method for direct air capture of CO according to claim 2 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the mass ratio of PVDF to PVP is 1:2.|4. A method according to claim 2 or 3 for direct air capture of CO 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the upper surface of the double-sided composite membrane (3) is subjected to hydrophilic modification, and the ventilation rate of the membrane material is improved by mixing PVP material into the membrane preparation liquid.|5. The method for direct air capture of CO according to claim 1 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the wall surface (4) is made of transparent organic glass material. | (CN114950121)|TECHNICAL FIELD|[0001] The invention belongs to the technical field of microalgae carbon fixation, relates to a membrane contact type microalgae biological culture reactor, and in particular relates to a reactor for directly capturing CO in air 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system.|BACKGROUND ART|[0002] For CO in air 2 The prospect of capturing and greatly developing direct air capturing and sealing technology is quite considerable. In the DACCS and BECCS technologies, microalgae are taken as one of microorganisms with higher photosynthesis rate, have the advantages of high carbon fixation rate, small occupied area, cleanness, no pollution and the like, can be taken as a production platform of third-generation bioenergy, and are considered as one of high-efficiency carbon fixation paths with development prospects in recent years. Microalgae are used for direct air CO 2 At the time of capturing, due to CO 2 The concentration is low (about 0.04%) and is preferably for the most partCO grown by microalgae species 2 The concentration is about 5-20%, so that the photosynthesis rate of microalgae is low and CO is low when the air is directly trapped 2 Both solubility in water and conversion to bicarbonate efficiency are difficult to meet the high-rate carbon sequestration requirements. Therefore, to promote direct air capture of CO by microalgae 2 Is to CO 2 Is the focus of research.|[0003] In the prior art, the application of the membrane photobioreactor mainly uses a membrane for a gas disperser or an aerator, and adopts a hollow fiber membrane structure to provide fine bubbles and higher CO for the reactor 2 Mass transfer efficiency, and is mostly used for carbon fixation and denitrification in flue gas or sewage treatment of power plants, and is characterized in that CO in the solution 2 The concentration is high, which is more beneficial to photosynthesis of microalgae. However, due to CO in the air 2 The concentration is low, and the carbon fixation efficiency is low by adopting the traditional hollow fiber membrane structure.|DISCLOSURE|Disclosure of Invention|[0004] Solves the problem of CO at low concentration in the prior art 2 The invention aims to provide a method for directly capturing CO in air, which has the problems of low mass transfer coefficient, insufficient contact with microalgae and the like 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system has the characteristics of low cost, convenient harvesting of microalgae, high carbon fixing efficiency and the like, and can effectively capture and fix low-concentration CO in the air 2 Improve the air CO 2 The efficiency of trapping is of great importance to achieving the goal of carbon neutralization.|[0005] In order to achieve the above purpose, the technical scheme adopted by the invention is as follows:|[0006] CO for direct air capture 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system comprises a reactor for loading microalgae solution, wherein at least one part of the bottom of the reactor is a breathable fixing device, and at least one part of the top or the side wall of the reactor is a light-transmitting wall surface; the fixing device is provided with a double-sided composite film, the upper surface of the double-sided composite film, namely the microalgae side, is used for attaching microalgae particles, and the lower surface of the double-sided composite film, namely the air side, is attached with carbonic anhydrase.|[0007] In one embodimentWherein the fixing device is a metal net for supporting and fixing the double-sided composite film, and CO in the air 2 The gas contacts the double-sided composite membrane through the pores of the metal mesh to provide the carbon source required by the reactor.|[0008] In one embodiment, the double-sided composite membrane is a high molecular high porosity porous fibrous membrane made by an electrostatic spinning method.|[0009] In one embodiment, the double-sided composite film is made of PVDF and PVP by an electrospinning process, preferably the mass ratio of PVDF to PVP is 1:2.|[0010] In one embodiment, the carbonic anhydrase is attached to the electrospun fiber bundle on the lower surface of the double-sided composite membrane by chemical modification to improve the CO on the membrane surface 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- 。|[0011] In one embodiment, the microalgae particles are uniformly adhered on the upper surface of the double-sided composite membrane based on the action of gravity, and CO 2 And HCO 3 The photosynthesis reaction is completed by the contact of the microporous structure on the membrane with the microalgae particles.|[0012] In one embodiment, the upper surface of the double-sided composite membrane is hydrophilically modified, and CO is promoted on the air side by attaching a catalytic material such as carbonic anhydrase 2 And improving the aeration rate of the membrane material by mixing PVP material into the membrane preparation solution.|[0013] In one embodiment, the membrane surface hydrophilicity was varied by controlling the PVDF and PVP content, and experiments have shown that the material exhibits hydrophobicity when PVP content is dominant and hydrophilicity when PVDF content is dominant.|[0014] In one embodiment, the wall is a transparent organic glass material.|[0015] In one embodiment, the reactor adopts a natural convection air supply mode, and CO in the air 2 Enters the reactor from the fixing device and the double-sided composite membrane in a diffusion mode.|[0016] Compared with the prior art, the invention has the beneficial effects that:|[0017] (1) Greatly improves the direct air trapping C of microalgaeO 2 Carbon sequestration rate of (2). By adopting the contact membrane type photo-bioreactor, the original CO is improved 2 Carbon transmission mode in gas-liquid-solid three-phase transmission process of solution-microalgae cells is changed into CO 2 And bicarbonate ions are directly contacted with microalgae cells on the electrostatic spinning polymer fiber membrane, so that CO is greatly reduced 2 Mass transfer coefficient of (c).|[0018] (2) The preparation process of the polymer membrane of the membrane reactor is optimized. The electrostatic spinning composite membrane prepared by adopting the electrostatic spinning method to prepare PVDF/PVP mixture has the characteristics of high air permeability and good hydrophilicity, and can effectively transmit CO 2 And nutrient ions and loading microalgae on the surface of the membrane, so as to optimize the contact condition of a carbon source and algae seeds.|[0019] (3) Promote CO under the condition of capturing low-concentration air 2 Is a solvent for the polymer. Promotion of CO by carbonic anhydrase-assisted methods 2 Catalytic conversion efficiency, strengthening dissolution and absorption processes;|[0020] (4) The harvesting efficiency of microalgae is improved. The contact membrane photo-bioreactor is used for carbon fixation and cultivation of microalgae, and the harvesting and the expansion cultivation of the microalgae can be conveniently realized by changing membrane materials due to the attachment effect of the membrane, so that the contact membrane photo-bioreactor has more practical value.|DRAWINGS DESCRIPTION|[0021] FIG. 1 is a direct air capture CO 2 A schematic diagram of a microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system.|[0022] FIG. 2 is a schematic diagram of the attachment of carbonic anhydrase and microalgae to a double-sided composite membrane structure established in the present invention.|[0023] FIG. 3 is a bottom view of a membrane bioreactor constructed in accordance with an embodiment of the present invention.|[0024] FIG. 4 shows direct air CO capture by microalgae in an embodiment of the invention 2 The operation system diagram of the double-sided composite film carbon fixation reaction device.|[0025] FIG. 5 is a flow chart of film preparation and system performance testing in an embodiment of the invention.|INVENTION MODE|Detailed Description|[0026] Embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples.|[0027] As shown in FIG. 1, the present invention is a method for direct air captureCO collection 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system comprises a reactor. The reactor is used for loading microalgae solution 1 and is a contact type photobioreactor.|[0028] To obtain a light source, the reactor should have a light-transmitting wall 4, and in the present invention, at least a part of the top or side wall of the reactor is the light-transmitting wall 4, and in general, it is more reasonable to see that the entire top and side wall are the light-transmitting wall 4. For example, the wall 4 may be made of a transparent organic glass material, ensuring good light transmission properties of the reactor.|[0029] In the invention, the breathable fixing device 2 is adopted in all or part of the bottom of the reactor, the area of the fixing device 2 can be set according to the needs, and in general, the whole bottom is obviously more reasonable to be the fixing device 2.|[0030] In the present invention, a double-sided composite film 3 is mounted on a fixing device 2, and microalgae particles 6 are attached to the upper surface of the double-sided composite film 3, i.e., the microalgae side, and carbonic anhydrase 5 is attached to the lower surface of the double-sided composite film 3, i.e., the air side. Carbonic anhydrase 5 catalyzes low concentration of CO in air 2 Conversion to HCO 3- And then fed into the microalgae solution 1.|[0031] The reason why the fixing device 2 is provided at the bottom of the reactor is that the microalgae particles 6 are attached to the upper surface of the double-sided composite membrane 3 by using the gravity thereof, and thus, although the fixing device 2 can be provided on any one side in theory, the arrangement on other sides is not particularly suitable in consideration of the gravity factor of the microalgae solution 1.|[0032] Thus, the invention realizes a flat contact type photobioreactor, CO 2 Can better contact with microalgae particles 6 in the double-sided composite membrane 3 to promote the mass transfer coefficient, on the other hand, carbonic anhydrase 5 promotes CO 2 Dissolving, absorbing and lifting CO in air 2 Has obvious advantages in the aspect of aggregation property, thereby effectively improving CO 2 Mass transfer characteristics, and finally effectively promote air CO 2 Is not limited, and the trapping efficiency of the device is improved.|[0033] Illustratively, in the present invention, the securing device 2 is a metal mesh structure, such as a stainless steel mesh, may be used to support and secure the duplex wiresFace composite film 3, CO in air 2 The gas contacts the double-sided composite membrane 3 through the pores of the metal mesh to provide the carbon source required for the reactor.|[0034] The double-sided composite membrane 3 is a high-molecular porous fibrous membrane prepared by adopting an electrostatic spinning method, and has higher porosity. CO 2 And HCO 3- Through the permeation of the polymer film with micropores, microalgae particles 6 are uniformly attached to the upper surface of the double-sided composite film 3 based on the action of gravity, and photosynthesis reaction is carried out with the permeated carbon source.|[0035] The double-sided composite film 3 is an electrostatic spinning fiber film prepared from PVDF and PVP by an electrostatic spinning method, and an integrated electrostatic spinning machine is used, wherein the mass ratio of PVDF to PVP is preferably 1:2, so that the hydrophilicity and the air permeability of the film surface can be effectively improved. The electrostatic spinning method comprises the steps of selecting a spinning voltage of 15kV, injecting a prepared PVDF/PVP solution into an electrostatic spinning needle head through an injector at a speed of 20 microliters/min, arranging a roller structure coated by aluminum foil paper at a position 15cm away from the needle head, rotating at a speed of 150 revolutions/min, carrying out electrostatic spinning for 8 hours, immersing the obtained product into ultra-pure water to remove the aluminum foil paper, and immersing the obtained PVDF/PVP electrostatic spinning composite film into water for later use. The PVDF/PVP film material prepared by adopting the electrostatic spinning method can better improve the ventilation rate due to the pore-forming property of PVP.|[0036] In the invention, carbonic anhydrase 5 is attached to the electrostatic spinning fiber bundle on the lower surface of the double-sided composite membrane 3 in a chemical modification mode, so that CO on the surface of the membrane can be effectively improved 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- 。|[0037] In the present invention, the upper surface of the double-sided composite film 3 is hydrophilically modified to improve the adhesion properties of the microalgae particles 6. Promotion of CO on the air side by adhesion of catalytic materials such as carbonic anhydrase 2 And improving the aeration rate of the membrane material by mixing PVP material into the membrane preparation solution.|[0038] According to the invention, the hydrophilic and hydrophobic properties of the surface of the membrane are changed by controlling the PVDF and PVP contents, and through experimental tests, the material presents hydrophobicity when the PVP content is majority, and the material presents hydrophilicity when the PVDF content is majority.|[0039] Illustratively, the reactor adopts a natural convection air supply mode, and CO in the air 2 From the fixture 2 and the double-sided composite membrane 3 into the reactor by diffusion.|[0040] In one embodiment of the invention, the preparation of the laboratory-sized microalgae-carbonic anhydrase PVDF/PVP double-sided composite membrane comprises the following steps:|[0041] 1) Preparing PVDF/PVP electrostatic spinning film-forming liquid, preparing film-forming liquid (the parameters which are optimized by a control test in the earlier stage) by adopting the proportion of PVDF and PVP powder with the mass ratio of 2:1 and the solid mass fraction of 20wt.% and mixing with dimethylacetamide solution to prepare 25mL of film-forming liquid. Placing the mixture into a reagent bottle, setting stirring temperature in a constant-temperature magnetic stirrer to be 75 ℃, stirring at 400rpm for 2 hours at constant temperature, standing for 30 minutes after stirring is completed, and defoaming;|[0042] 2) And carrying out electrostatic spinning treatment, wherein the electrostatic spinning treatment is carried out in a laboratory by using an electrostatic spinning emergency uniform speed injection pump. The prepared PVDF/PVP film-making liquid is sucked into a syringe, the syringe, a propelling pump, a catheter and an electrostatic spinning needle are connected in sequence, and aluminum foil paper with the width of 20cm is wrapped on a roller to be used as a carrier for spinning. The electrostatic spinning voltage is 15kV, the distance between the needle head and the roller is 15cm, the rotating speed of the roller is 760rpm, and the spinning needle head transversely and uniformly moves in the width direction of the roller to spin and prepare films, so that film preparation can be completed in about 16 hours;|[0043] 3) And (3) surface treatment of the electrostatic spinning film. The electrostatic spinning film loaded on the aluminum foil paper is soaked in ultra-pure water to finish demoulding, and the film is trimmed to a size of 16cm multiplied by 16cm for standby. Attaching carbonic anhydrase to the fiber bundle on one side of the electrostatic spinning film by using a chemical modification method, and soaking the fiber bundle in water for standby;|[0044] 4) Film performance test. Performing performance test on the prepared PVDF/PVP film attached with carbonic anhydrase by using equipment such as a Scanning Electron Microscope (SEM), a specific surface area measuring instrument (BET) film flux test instrument, a surface contact angle measuring instrument and the like, and testing parameters such as surface pore diameter, fiber bundle diameter, ventilation volume, specific surface area, porosity and the like, so as to ensure the performance superiority of the prepared film;|[0045] 5) Manufacturing processThe schematic diagram of the prepared PVDF/PVP composite membrane material with carbonic anhydrase attached to microalgae and carbonic anhydrase is shown in figure 2, microalgae particles 6 are uniformly attached to the upper surface of the double-sided composite membrane 3, and carbonic anhydrase 5 is attached to the fiber bundles on the lower surface of the double-sided composite membrane, so that CO in the air is removed 2 The low-concentration carbon dioxide in the air enters the reactor under the action of natural convection and is converted into bicarbonate under the catalysis of carbonic anhydrase 5, photosynthesis is realized through microalgae particles 6 and solution attached to the upper surface, and a carbon source is converted into oxygen to be discharged. Wherein the carbonic anhydrase 5 is attached in the form of particles.|[0046] In one embodiment of the invention, laboratory-sized direct air capture of CO 2 The construction and performance test of the microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system comprise the following steps:|[0047] 1) Preparing microalgae solution and nutrient solution. Microalgae species according to low concentration carbon fixation requirement and room temperature culture condition, scenedesmus obliquus is selected as the species, 0.1g/L microalgae solution is prepared, and BG11 nutrient solution is added, wherein the specific formula is 1.5g/L NaNO 3 ,0.04g/L K 2 HPO 4 ,0.075g/L MgSO 4 ·7H 2 O,0.036g/L CaCl 2 ·2H 2 O,0.006g/L citric acid, 0.006g/L ferric ammonium citrate, 0.001g/L EDTANa 2 ,0.02g/L Na 2 CO 3 Macroelements and 1ml of A5 microelements (0.222 g/L ZnSO 4 ·7H 2 O,0.079g/L CuSO 4 ·5H 2 O,0.015g/L MoO 3 ,0.036g/L CaCl 2 ·2H 2 O,2.86g/L H 3 BO 3 ,0.006g/L MnCl 2 ·4H 2 O)|[0048] 2) Putting the prepared PVDF/PVP composite film attached with carbonic anhydrase into direct air to trap CO 2 In the microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system, a schematic diagram of a specific device is shown in figure 1, a relationship between a stainless steel mesh fixing structure and a membrane is shown in a bottom surface diagram of the device in figure 3, wherein 7 is a screw fixing structure, 8 is a stainless steel mesh fixing structure, and 9 is a PVDF/PVP membrane attached with carbonic anhydrase。|[0049] 3) The flow chart of the overall construction and performance test of the device is shown in figure 5, the oxygen concentration of the outlet is measured by using an oxygen concentration measuring instrument, the concentration of bicarbonate ions in the solution is measured by using an ion chromatograph, and the carbonic anhydrase is converted into CO 2 And the carbon fixation efficiency of the whole reaction system.|[0050] The foregoing embodiments are merely illustrative of the technical solutions and laboratory application features of the present invention, and are intended to describe the contents and technical solutions of the present invention in detail, so that it is easy to understand, and the scope of protection of the present invention should not be limited thereby. All equivalent changes according to the spirit of the invention should be included in the scope of the present invention. | (CN114950121)|TECHNICAL FIELD|[0001] The invention belongs to the technical field of microalgae carbon fixation, relates to a membrane contact type microalgae biological culture reactor, and in particular relates to a reactor for directly capturing CO in air 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system.|BACKGROUND ART|[0002] For CO in air 2 The prospect of capturing and greatly developing direct air capturing and sealing technology is quite considerable. In the DACCS and BECCS technologies, microalgae are taken as one of microorganisms with higher photosynthesis rate, have the advantages of high carbon fixation rate, small occupied area, cleanness, no pollution and the like, can be taken as a production platform of third-generation bioenergy, and are considered as one of high-efficiency carbon fixation paths with development prospects in recent years. Microalgae are used for direct air CO 2 At the time of capturing, due to CO 2 The concentration is low (about 0.04%) and is preferably for the most partCO grown by microalgae species 2 The concentration is about 5-20%, so that the photosynthesis rate of microalgae is low and CO is low when the air is directly trapped 2 Both solubility in water and conversion to bicarbonate efficiency are difficult to meet the high-rate carbon sequestration requirements. Therefore, to promote direct air capture of CO by microalgae 2 Is to CO 2 Is the focus of research.|[0003] In the prior art, the application of the membrane photobioreactor mainly uses a membrane for a gas disperser or an aerator, and adopts a hollow fiber membrane structure to provide fine bubbles and higher CO for the reactor 2 Mass transfer efficiency, and is mostly used for carbon fixation and denitrification in flue gas or sewage treatment of power plants, and is characterized in that CO in the solution 2 The concentration is high, which is more beneficial to photosynthesis of microalgae. However, due to CO in the air 2 The concentration is low, and the carbon fixation efficiency is low by adopting the traditional hollow fiber membrane structure.|DISCLOSURE|Disclosure of Invention|[0004] Solves the problem of CO at low concentration in the prior art 2 The invention aims to provide a method for directly capturing CO in air, which has the problems of low mass transfer coefficient, insufficient contact with microalgae and the like 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system has the characteristics of low cost, convenient harvesting of microalgae, high carbon fixing efficiency and the like, and can effectively capture and fix low-concentration CO in the air 2 Improve the air CO 2 The efficiency of trapping is of great importance to achieving the goal of carbon neutralization.|[0005] In order to achieve the above purpose, the technical scheme adopted by the invention is as follows:|[0006] CO for direct air capture 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system comprises a reactor for loading microalgae solution, wherein at least one part of the bottom of the reactor is a breathable fixing device, and at least one part of the top or the side wall of the reactor is a light-transmitting wall surface; the fixing device is provided with a double-sided composite film, the upper surface of the double-sided composite film, namely the microalgae side, is used for attaching microalgae particles, and the lower surface of the double-sided composite film, namely the air side, is attached with carbonic anhydrase.|[0007] In one embodimentWherein the fixing device is a metal net for supporting and fixing the double-sided composite film, and CO in the air 2 The gas contacts the double-sided composite membrane through the pores of the metal mesh to provide the carbon source required by the reactor.|[0008] In one embodiment, the double-sided composite membrane is a high molecular high porosity porous fibrous membrane made by an electrostatic spinning method.|[0009] In one embodiment, the double-sided composite film is made of PVDF and PVP by an electrospinning process, preferably the mass ratio of PVDF to PVP is 1:2.|[0010] In one embodiment, the carbonic anhydrase is attached to the electrospun fiber bundle on the lower surface of the double-sided composite membrane by chemical modification to improve the CO on the membrane surface 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- 。|[0011] In one embodiment, the microalgae particles are uniformly adhered on the upper surface of the double-sided composite membrane based on the action of gravity, and CO 2 And HCO 3 The photosynthesis reaction is completed by the contact of the microporous structure on the membrane with the microalgae particles.|[0012] In one embodiment, the upper surface of the double-sided composite membrane is hydrophilically modified, and CO is promoted on the air side by attaching a catalytic material such as carbonic anhydrase 2 And improving the aeration rate of the membrane material by mixing PVP material into the membrane preparation solution.|[0013] In one embodiment, the membrane surface hydrophilicity was varied by controlling the PVDF and PVP content, and experiments have shown that the material exhibits hydrophobicity when PVP content is dominant and hydrophilicity when PVDF content is dominant.|[0014] In one embodiment, the wall is a transparent organic glass material.|[0015] In one embodiment, the reactor adopts a natural convection air supply mode, and CO in the air 2 Enters the reactor from the fixing device and the double-sided composite membrane in a diffusion mode.|[0016] Compared with the prior art, the invention has the beneficial effects that:|[0017] (1) Greatly improves the direct air trapping C of microalgaeO 2 Carbon sequestration rate of (2). By adopting the contact membrane type photo-bioreactor, the original CO is improved 2 Carbon transmission mode in gas-liquid-solid three-phase transmission process of solution-microalgae cells is changed into CO 2 And bicarbonate ions are directly contacted with microalgae cells on the electrostatic spinning polymer fiber membrane, so that CO is greatly reduced 2 Mass transfer coefficient of (c).|[0018] (2) The preparation process of the polymer membrane of the membrane reactor is optimized. The electrostatic spinning composite membrane prepared by adopting the electrostatic spinning method to prepare PVDF/PVP mixture has the characteristics of high air permeability and good hydrophilicity, and can effectively transmit CO 2 And nutrient ions and loading microalgae on the surface of the membrane, so as to optimize the contact condition of a carbon source and algae seeds.|[0019] (3) Promote CO under the condition of capturing low-concentration air 2 Is a solvent for the polymer. Promotion of CO by carbonic anhydrase-assisted methods 2 Catalytic conversion efficiency, strengthening dissolution and absorption processes;|[0020] (4) The harvesting efficiency of microalgae is improved. The contact membrane photo-bioreactor is used for carbon fixation and cultivation of microalgae, and the harvesting and the expansion cultivation of the microalgae can be conveniently realized by changing membrane materials due to the attachment effect of the membrane, so that the contact membrane photo-bioreactor has more practical value.|DRAWINGS DESCRIPTION|[0021] FIG. 1 is a direct air capture CO 2 A schematic diagram of a microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system.|[0022] FIG. 2 is a schematic diagram of the attachment of carbonic anhydrase and microalgae to a double-sided composite membrane structure established in the present invention.|[0023] FIG. 3 is a bottom view of a membrane bioreactor constructed in accordance with an embodiment of the present invention.|[0024] FIG. 4 shows direct air CO capture by microalgae in an embodiment of the invention 2 The operation system diagram of the double-sided composite film carbon fixation reaction device.|[0025] FIG. 5 is a flow chart of film preparation and system performance testing in an embodiment of the invention.|INVENTION MODE|Detailed Description|[0026] Embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples.|[0027] As shown in FIG. 1, the present invention is a method for direct air captureCO collection 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system comprises a reactor. The reactor is used for loading microalgae solution 1 and is a contact type photobioreactor.|[0028] To obtain a light source, the reactor should have a light-transmitting wall 4, and in the present invention, at least a part of the top or side wall of the reactor is the light-transmitting wall 4, and in general, it is more reasonable to see that the entire top and side wall are the light-transmitting wall 4. For example, the wall 4 may be made of a transparent organic glass material, ensuring good light transmission properties of the reactor.|[0029] In the invention, the breathable fixing device 2 is adopted in all or part of the bottom of the reactor, the area of the fixing device 2 can be set according to the needs, and in general, the whole bottom is obviously more reasonable to be the fixing device 2.|[0030] In the present invention, a double-sided composite film 3 is mounted on a fixing device 2, and microalgae particles 6 are attached to the upper surface of the double-sided composite film 3, i.e., the microalgae side, and carbonic anhydrase 5 is attached to the lower surface of the double-sided composite film 3, i.e., the air side. Carbonic anhydrase 5 catalyzes low concentration of CO in air 2 Conversion to HCO 3- And then fed into the microalgae solution 1.|[0031] The reason why the fixing device 2 is provided at the bottom of the reactor is that the microalgae particles 6 are attached to the upper surface of the double-sided composite membrane 3 by using the gravity thereof, and thus, although the fixing device 2 can be provided on any one side in theory, the arrangement on other sides is not particularly suitable in consideration of the gravity factor of the microalgae solution 1.|[0032] Thus, the invention realizes a flat contact type photobioreactor, CO 2 Can better contact with microalgae particles 6 in the double-sided composite membrane 3 to promote the mass transfer coefficient, on the other hand, carbonic anhydrase 5 promotes CO 2 Dissolving, absorbing and lifting CO in air 2 Has obvious advantages in the aspect of aggregation property, thereby effectively improving CO 2 Mass transfer characteristics, and finally effectively promote air CO 2 Is not limited, and the trapping efficiency of the device is improved.|[0033] Illustratively, in the present invention, the securing device 2 is a metal mesh structure, such as a stainless steel mesh, may be used to support and secure the duplex wiresFace composite film 3, CO in air 2 The gas contacts the double-sided composite membrane 3 through the pores of the metal mesh to provide the carbon source required for the reactor.|[0034] The double-sided composite membrane 3 is a high-molecular porous fibrous membrane prepared by adopting an electrostatic spinning method, and has higher porosity. CO 2 And HCO 3- Through the permeation of the polymer film with micropores, microalgae particles 6 are uniformly attached to the upper surface of the double-sided composite film 3 based on the action of gravity, and photosynthesis reaction is carried out with the permeated carbon source.|[0035] The double-sided composite film 3 is an electrostatic spinning fiber film prepared from PVDF and PVP by an electrostatic spinning method, and an integrated electrostatic spinning machine is used, wherein the mass ratio of PVDF to PVP is preferably 1:2, so that the hydrophilicity and the air permeability of the film surface can be effectively improved. The electrostatic spinning method comprises the steps of selecting a spinning voltage of 15kV, injecting a prepared PVDF/PVP solution into an electrostatic spinning needle head through an injector at a speed of 20 microliters/min, arranging a roller structure coated by aluminum foil paper at a position 15cm away from the needle head, rotating at a speed of 150 revolutions/min, carrying out electrostatic spinning for 8 hours, immersing the obtained product into ultra-pure water to remove the aluminum foil paper, and immersing the obtained PVDF/PVP electrostatic spinning composite film into water for later use. The PVDF/PVP film material prepared by adopting the electrostatic spinning method can better improve the ventilation rate due to the pore-forming property of PVP.|[0036] In the invention, carbonic anhydrase 5 is attached to the electrostatic spinning fiber bundle on the lower surface of the double-sided composite membrane 3 in a chemical modification mode, so that CO on the surface of the membrane can be effectively improved 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- 。|[0037] In the present invention, the upper surface of the double-sided composite film 3 is hydrophilically modified to improve the adhesion properties of the microalgae particles 6. Promotion of CO on the air side by adhesion of catalytic materials such as carbonic anhydrase 2 And improving the aeration rate of the membrane material by mixing PVP material into the membrane preparation solution.|[0038] According to the invention, the hydrophilic and hydrophobic properties of the surface of the membrane are changed by controlling the PVDF and PVP contents, and through experimental tests, the material presents hydrophobicity when the PVP content is majority, and the material presents hydrophilicity when the PVDF content is majority.|[0039] Illustratively, the reactor adopts a natural convection air supply mode, and CO in the air 2 From the fixture 2 and the double-sided composite membrane 3 into the reactor by diffusion.|[0040] In one embodiment of the invention, the preparation of the laboratory-sized microalgae-carbonic anhydrase PVDF/PVP double-sided composite membrane comprises the following steps:|[0041] 1) Preparing PVDF/PVP electrostatic spinning film-forming liquid, preparing film-forming liquid (the parameters which are optimized by a control test in the earlier stage) by adopting the proportion of PVDF and PVP powder with the mass ratio of 2:1 and the solid mass fraction of 20wt.% and mixing with dimethylacetamide solution to prepare 25mL of film-forming liquid. Placing the mixture into a reagent bottle, setting stirring temperature in a constant-temperature magnetic stirrer to be 75 ℃, stirring at 400rpm for 2 hours at constant temperature, standing for 30 minutes after stirring is completed, and defoaming;|[0042] 2) And carrying out electrostatic spinning treatment, wherein the electrostatic spinning treatment is carried out in a laboratory by using an electrostatic spinning emergency uniform speed injection pump. The prepared PVDF/PVP film-making liquid is sucked into a syringe, the syringe, a propelling pump, a catheter and an electrostatic spinning needle are connected in sequence, and aluminum foil paper with the width of 20cm is wrapped on a roller to be used as a carrier for spinning. The electrostatic spinning voltage is 15kV, the distance between the needle head and the roller is 15cm, the rotating speed of the roller is 760rpm, and the spinning needle head transversely and uniformly moves in the width direction of the roller to spin and prepare films, so that film preparation can be completed in about 16 hours;|[0043] 3) And (3) surface treatment of the electrostatic spinning film. The electrostatic spinning film loaded on the aluminum foil paper is soaked in ultra-pure water to finish demoulding, and the film is trimmed to a size of 16cm multiplied by 16cm for standby. Attaching carbonic anhydrase to the fiber bundle on one side of the electrostatic spinning film by using a chemical modification method, and soaking the fiber bundle in water for standby;|[0044] 4) Film performance test. Performing performance test on the prepared PVDF/PVP film attached with carbonic anhydrase by using equipment such as a Scanning Electron Microscope (SEM), a specific surface area measuring instrument (BET) film flux test instrument, a surface contact angle measuring instrument and the like, and testing parameters such as surface pore diameter, fiber bundle diameter, ventilation volume, specific surface area, porosity and the like, so as to ensure the performance superiority of the prepared film;|[0045] 5) Manufacturing processThe schematic diagram of the prepared PVDF/PVP composite membrane material with carbonic anhydrase attached to microalgae and carbonic anhydrase is shown in figure 2, microalgae particles 6 are uniformly attached to the upper surface of the double-sided composite membrane 3, and carbonic anhydrase 5 is attached to the fiber bundles on the lower surface of the double-sided composite membrane, so that CO in the air is removed 2 The low-concentration carbon dioxide in the air enters the reactor under the action of natural convection and is converted into bicarbonate under the catalysis of carbonic anhydrase 5, photosynthesis is realized through microalgae particles 6 and solution attached to the upper surface, and a carbon source is converted into oxygen to be discharged. Wherein the carbonic anhydrase 5 is attached in the form of particles.|[0046] In one embodiment of the invention, laboratory-sized direct air capture of CO 2 The construction and performance test of the microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system comprise the following steps:|[0047] 1) Preparing microalgae solution and nutrient solution. Microalgae species according to low concentration carbon fixation requirement and room temperature culture condition, scenedesmus obliquus is selected as the species, 0.1g/L microalgae solution is prepared, and BG11 nutrient solution is added, wherein the specific formula is 1.5g/L NaNO 3 ,0.04g/L K 2 HPO 4 ,0.075g/L MgSO 4 ·7H 2 O,0.036g/L CaCl 2 ·2H 2 O,0.006g/L citric acid, 0.006g/L ferric ammonium citrate, 0.001g/L EDTANa 2 ,0.02g/L Na 2 CO 3 Macroelements and 1ml of A5 microelements (0.222 g/L ZnSO 4 ·7H 2 O,0.079g/L CuSO 4 ·5H 2 O,0.015g/L MoO 3 ,0.036g/L CaCl 2 ·2H 2 O,2.86g/L H 3 BO 3 ,0.006g/L MnCl 2 ·4H 2 O)|[0048] 2) Putting the prepared PVDF/PVP composite film attached with carbonic anhydrase into direct air to trap CO 2 In the microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system, a schematic diagram of a specific device is shown in figure 1, a relationship between a stainless steel mesh fixing structure and a membrane is shown in a bottom surface diagram of the device in figure 3, wherein 7 is a screw fixing structure, 8 is a stainless steel mesh fixing structure, and 9 is a PVDF/PVP membrane attached with carbonic anhydrase。|[0049] 3) The flow chart of the overall construction and performance test of the device is shown in figure 5, the oxygen concentration of the outlet is measured by using an oxygen concentration measuring instrument, the concentration of bicarbonate ions in the solution is measured by using an ion chromatograph, and the carbonic anhydrase is converted into CO 2 And the carbon fixation efficiency of the whole reaction system.|[0050] The foregoing embodiments are merely illustrative of the technical solutions and laboratory application features of the present invention, and are intended to describe the contents and technical solutions of the present invention in detail, so that it is easy to understand, and the scope of protection of the present invention should not be limited thereby. All equivalent changes according to the spirit of the invention should be included in the scope of the present invention. | Family Number|(101539929)|101539929|Advantages / Prev. Drawbacks|(CN114950121B B)|In the DACCS and BECCS technologies , microalgae are taken as one of microorganisms with higher photosynthesis rate , have the advantages of high carbon fixation rate , small occupied area , cleanness , no pollution and the like , can be taken as a production platform ( . . . ) |(CN114950121 A)|In the DACCS and BECCS technologies , microalgae , which is one of microorganisms with high photosynthesis rate , has the advantages of high carbon sequestration rate , small occupied area , cleanness , no pollution and the like , can be used as a third - generation biological ( . . . ) | | Environmental technology | B01D-053/62|B01D-053/84|B01D-2251/95|B01D-2257/504|Y02P-020/59 | B01D-053/62|B01D-053/84|B01D-2251/95|B01D-2257/504|Y02P-020/59 | B01D-053/62|B01D-053/84 | B01D-053/62|B01D-053/84 | CN116515625|CN118267844 | CN116515625 105948650 WHO=Examiner SELF=N CAT=Y|CN118267844 110433228 WHO=Examiner SELF=N CAT=A | WO201834565|CN112899125|CN111647501|CN110479079|CN109868208|CN109879409|CN109136082|CN106237834|WO2013121365|CN104169427|CN103773695|US20140295531|KR20130137759|CN103316582 | WO201834565 78821828 WHO=Examiner SELF=N CAT=A|CN112899125 94552561 WHO=Examiner SELF=Y|CN111647501 90586278 WHO=Examiner SELF=N|CN110479079 86740476 WHO=Examiner SELF=N|CN109868208 84814271 WHO=Examiner SELF=N|CN109879409 84856373 WHO=Examiner SELF=N|CN109136082 82885209 WHO=Examiner SELF=N|CN106237834 74958434 WHO=Examiner SELF=N|WO2013121365 45849538 WHO=Examiner SELF=N|CN104169427 45663463 WHO=Examiner SELF=N|CN103773695 65427879 WHO=Examiner SELF=N|US20140295531 15077448 WHO=Examiner SELF=N|KR20130137759 61161500 WHO=Examiner SELF=N|CN103316582 46050394 WHO=Examiner SELF=N | WO201834565; CN103773695; CN109136082; CN109879409; WO2013121365; KR20130137759; CN110479079; CN111647501; WO2018034565; US20140295531; CN109868208; CN112899125; CN103316582; CN104169427; CN106237834 | GRANTED | (CN114950121)|GRANTED | ALIVE | (CN114950121)|ALIVE | (CN114950121)|LEGAL DETAILS FOR CN114950121|Actual or expected expiration date=2042-06-14|Legal state=ALIVE|Status=GRANTED|Event publication date=2022-06-14|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN202210668058|Application date=2022-06-14|Standardized application number=2022CN-0668058|Event publication date=2022-08-30|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN114950121|Publication stage code=A|Publication date=2022-08-30|Standardized publication number=CN114950121|Event publication date=2022-08-30|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2022-09-16|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|Event publication date=2023-08-15|Event code=CN/B|Event indicator=Pos|Event group=Event indicating In Force|Granted patent for invention|Publication country=CN|Publication number=CN114950121|Publication stage code=B|Publication date=2023-08-15|Standardized publication number=CN114950121B|Event publication date=2023-08-15|Event code=CN/GR01|Event indicator=Pos|Event group=Event indicating In Force|Grant of patent right | (CN114950121)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=hXP7Q1+dwoRNHAas1JoTwRj8BQAJLzMlbZEW38EL5eC5GkWmuuS7QKXL31I9s5RZSNnPjhgoLnPBB0W7Jy7i6Q==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000069056718&ekey=2155&xpn=CN114950121B&kind=B | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=X1QvmN8ANLBZ%252FiNIC2zb4bmsLuw%252FR4oY%252BQgpgFzVRnM%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN114950121)|CN|(CN114950121)|CN | (CN114950121)|NAME=XI'AN JIAOTONG UNIVERSITY , COUNTRY=CN|(CN114950121)|NAME=XI'AN JIAOTONG UNIVERSITY , COUNTRY=CN | (CN114950121)|NAME=DUAN JUNTAO;XI AN CYDA INTELLECTUAL PROPERTY AGENCY , REG=61215|(CN114950121)|NAME=DUAN JUNTAO;XI AN CYDA INTELLECTUAL PROPERTY AGENCY , REG=61215 | (CN114950121)|NAME=LI MINGJIA|NAME=LI GUANGMEI|NAME=WANG RUILONG|NAME=YANG YIWEN|(CN114950121)|NAME=LI MINGJIA|NAME=LI GUANGMEI|NAME=WANG RUILONG|NAME=YANG YIWEN | (CN114950121)|5 | 1 | 1 | (CN114950121)|Number of Claims: NCL=5|Gazette date: GAZDATE=2023-08-15|Gazette number: GAZNUM=39-3301|Number of Pages: NPAGES=8|Primary examiner: 司会芳|Primary examiner: Si Huifang||(CN114950121)|Number of Claims: NCL=10|Gazette date: GAZDATE=2022-08-30|Gazette number: GAZNUM=38-3501|Number of Pages: NPAGES=8|Primary examiner: 司会芳|Primary examiner: Si Huifang| | (CN114950121)|Previous publication: CN114950121 A 2022-08-30 [CN114950121] | (CN114950121)|CHINESE (CHI) | (CN114950121B)|Patent|(CN114950121)|Patent | Titre: (CN114950121)|CO for direct air capture 2 Microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system Résumé: (CN114950121)|A microalgae-carbonic anhydrase double-sided composite membrane carbon sequestration system for direct air capture of CO2 comprises a reactor for loading a microalgae solution, at least one part of the bottom of the reactor is a breathable fixing device, and at least one part of the top or side wall of the reactor is a light-transmitting wall surface; a double-sided composite film is carried on the fixing device, microalgae particles are attached to the upper surface of the double-sided composite film, namely the microalgae side, and carbonic anhydrase is attached to the lower surface of the double-sided composite film, namely the air side. One side of the double-sided composite membrane is in contact with air, the other side of the double-sided composite membrane is in contact with a microalgae solution, low-concentration CO2 in the air is catalyzed to be converted into HCO3 <->, the HCO3 <-> is supplied to the microalgae solution, the microalgae side can be subjected to hydrophilic modification, the attachment characteristic of microalgae is enhanced, and the problems that CO2 at low concentration is low in mass transfer coefficient and insufficient in contact with the microalgae are solved; the method has the characteristics of low cost, convenience in microalgae harvesting, high carbon sequestration efficiency and the like, can effectively capture and immobilize low-concentration CO2 in the air, and has important significance for realizing a carbon neutralization target. Autre: (CN114950121)|1. CO for direct air capture 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixing system is characterized by comprising a reactor for loading microalgae solution (1), wherein at least one part of the bottom of the reactor is a breathable fixing device (2), and at least one part of the top or the side wall of the reactor is a light-permeable wall surface (4); the fixing device (2) is provided with a double-sided composite film (3), wherein microalgae particles (6) are attached to the upper surface of the double-sided composite film (3), namely the microalgae side, and carbonic anhydrase (5) is attached to the lower surface of the double-sided composite film (3), namely the air side;|the fixing device (2) is a metal net for supporting and fixing the double-sided composite membrane (3), and CO in the air 2 The gas contacts with a double-sided composite membrane (3) through metal mesh pores to provide a carbon source required by a reactor, and the double-sided composite membrane (3) is a high-molecular porous fiber membrane manufactured by adopting an electrostatic spinning method;|the carbonic anhydrase (5) is attached to the electrostatic spinning fiber bundle on the lower surface of the double-sided composite membrane (3) in a chemical modification mode, so that CO on the surface of the membrane is improved 2 Adsorption characteristics and promotion of CO 2 Conversion to HCO 3- The method comprises the steps of carrying out a first treatment on the surface of the The microalgae particles (6) are uniformly adhered to the upper surface of the double-sided composite membrane (3) based on the action of gravity, and CO 2 And HCO 3 Through the membraneThe microporous structure of the (2) is contacted with microalgae particles to complete photosynthesis reaction;|the reactor adopts a natural convection air supply mode, and CO in the air 2 Enters the reactor from the fixing device (2) and the double-sided composite film (3) in a diffusion mode.|2. The method for direct air capture of CO according to claim 1 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the double-sided composite membrane (3) is prepared from PVDF and PVP by an electrostatic spinning method.|3. The method for direct air capture of CO according to claim 2 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the mass ratio of PVDF to PVP is 1:2.|4. A method according to claim 2 or 3 for direct air capture of CO 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the upper surface of the double-sided composite membrane (3) is subjected to hydrophilic modification, and the ventilation rate of the membrane material is improved by mixing PVP material into the membrane preparation liquid.|5. The method for direct air capture of CO according to claim 1 2 The microalgae-carbonic anhydrase double-sided composite membrane carbon fixation system is characterized in that the wall surface (4) is made of transparent organic glass material. | 19 | Abstract | gpt-4o-mini | no | The article focuses on direct air capture of CO2 using microalgae, which does not involve biomass energy production or carbon capture and storage from biomass. | |||||||||||||||||||
| 19 | US63/358,602|US63/358,602P|US18/348,112|WOUS2023/069701 | WOUS2023/069701|IN202517003741|CN202380061019|JP2025500367|EP23748683|AU2023303026|CA3261222|US18/348,112 | CN120390667|JP2025522936|EP4551306|IN202517003741|AU2023303026|CA3261222|US20240009617|WO2024/011170 | 108035748 | WO2024/011170 A1 2024-01-11 [WO202411170]|IN202517003741 A 2025-04-25 [IN202517003741]|CN120390667 A 2025-07-29 [CN120390667]|JP2025522936 A 2025-07-17 [JP2025522936]|EP4551306 A1 2025-05-14 [EP4551306]|AU2023303026 A1 2025-01-30 [AU2023303026]|CA3261222 A1 2024-01-11 [CA3261222]|US20240009617 A1 2024-01-11 [US20240009617] | 2022-07-06|2023-07-06 | 2023-07-06|2025-01-16|2023-07-06|2023-07-06|2023-07-06|2023-07-06|2023-07-06|2023-07-06 | 2025-07-29|2025-07-17|2025-05-14|2025-04-25|2025-01-30|2024-01-11|2024-01-11|2024-01-11 | (EP4551306)|2043-07-06|(US20240009617)|2043-07-06|(WO2024/011170)|2026-01-06|(JP2025522936)|2043-07-06|(CN120390667)|2043-07-06|(IN202517003741)|2043-07-06|(AU2023303026)|2043-07-06|(CA3261222)|2043-07-06 | (EP4551306)|Direct air capture contactor for carbon uptake, and methods of operating the same | (EP4551306)|Embodiments described herein relate to systems, devices, and methods for uptake of CO2 from ambient air. In some aspects, a device can include a platform with a top portion and a bottom portion, an elevation mechanism configured to move the platform vertically, a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray, and an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally. In some embodiments, the bottom portion can support the tray as the tray moves laterally. In some embodiments, the elevation mechanism can include at least one of a chain or a linear actuator driven by a motor. | CHUANJIABAO CARBON TECHNOLOGY|HEIRLOOM CARBON TECHNOLOGIES|HEIRLOOM CARBON TECHNOLOGY | (EP4551306)|Heirloom Carbon Technologies, Inc. ([US])|(US20240009617)|Heirloom Carbon Technologies, Inc. ([US])|(WO2024/011170)|HEIRLOOM CARBON TECHNOLOGIES, INC. ([US])|(JP2025522936)|Heirloom Carbon Technologies, Inc.|(CN120390667)|CHUANJIABAO CARBON TECHNOLOGY CO., LTD. ([US])|(IN202517003741)|HEIRLOOM CARBON TECHNOLOGIES INC|(AU2023303026)|HEIRLOOM CARBON TECHNOLOGIES, INC.|(CA3261222)|HEIRLOOM CARBON TECHNOLOGIES, INC. ([US]) | DUBEL ANDREW|KARR CHARLES|KALRA JUHI|DRENNAN DAVID|PAUL-GIN NOAH|GUEBLE ISABEL|ELAHI SHAZIB | (EP4551306)|DUBEL, Andrew|KARR, Charles|KALRA, Juhi|DRENNAN, David|PAUL-GIN, Noah|GUEBLE, Isabel|ELAHI, Shazib | (EP4551306)|Cooley (UK) LLP ([GB])|Reg. Nb: 101544956|(WO2024/011170)|HILTON, Ramsey et al. ([US])|(JP2025522936)|AOKI ATSUSHI|Reg. Nb: 100099759|MITSUHASHI, Shinji et al.|Reg. Nb: 100123582|Shigeki Hirose|Reg. Nb: 100112357|MINAMIYAMA TOMOHIRO|Reg. Nb: 100114018|Yuichi Morimoto|Reg. Nb: 100153729|(CN120390667)|CENG XIANGSHENG;CCPIT PATENT AND TRADEMARK LAW OFFICE|Reg. Nb: 11038|(AU2023303026)|Pizzeys Patent and Trade Mark Attorneys Pty Ltd ([AU])|(CA3261222)|SMART & BIGGAR LP ([CA])|Reg. Nb: 9975a484-2887-4ac6-98ad-669ac5f8e9dd | (US20240009617)|Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | (US20240009617)|1 . A device, comprising: a platform including a top portion and a bottom portion; an elevation mechanism configured to move the platform vertically; a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray; and an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally, wherein the bottom portion is configured to support the tray as the tray moves laterally.|13 . An apparatus, comprising: a frame including a plurality of vertically oriented bars and a plurality of horizontally oriented bars; a plurality of cables including beads, the plurality of cables coupled to and suspended from the horizontally oriented bars in tension; a plurality of shelves coupled to the cables and supported by the beads, the plurality of shelves configured to support a plurality of trays; and a plurality of distributors, each distributor of the plurality of distributors configured to move vertically, each distributor of the plurality of distributors configured to contact a tray from the plurality of trays and urge the tray to move horizontally into and out of the distributor.|20 . A method, comprising: moving a distributor in a vertical direction, the distributor including an actuator and an orifice; fixing a vertical position of the distributor; securing the actuator to a tray positioned on a shelf, the tray including a carbonation medium; urging, via the actuator, the tray in a horizontal direction toward a centerline of the distributor; and dispensing, via the orifice, a liquid onto the carbonation medium in the tray;| | (US20240009617)|Embodiments described herein relate to systems, devices, and methods for uptake of CO2 from ambient air. In some aspects, a device can include a platform with a top portion and a bottom portion, an elevation mechanism configured to move the platform vertically, a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray, and an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally.| | (EP4551306)|CARBON UPTAKE(100,1)|DIRECT AIR CAPTURE(100,1)|DIRECT AIR CAPTURE CONTACTOR(100,1)||(US20240009617)|AGITATOR(100,1)|PLATFORM(63,2)|CONTACTOR(49,7)|MOUNTING BRACKET(48,6)|DISTRIBUTOR(39,7)|ORIFICE(30,4)|CARBONATION MEDIUM TRAY(30,1)|CABLE MANAGEMENT(25,1)|CHAINLINK FENCE(20,1)|GEOMETRIC RELATIONSHIP(20,1)|RELEASE TRAY(20,1)|SPACING INTERVAL(20,1)|TRAY ALIGNMENT(20,1)|AIR CONVEYOR(15,1)|BACKSTOP(15,1)|DISPENSATION(15,1)|DUMPING(15,1)||(WO2024/011170)|TRAY(100,199)|DIRECT AIR CAPTURE(100,8)|CARBON UPTAKE(100,2)|DIRECT AIR CAPTURE CONTACTOR(100,2)|DISTRIBUTOR CENTERLINE(95,23)|OCEAN CO2 UPTAKE(88,1)|TERRESTRIAL BIOSPHERE(81,1)|BAR ORIENTATION(76,8)|DISTRIBUTOR(74,114)|PLATFORM(69,33)|FUTURE CO2 EMISSION(63,1)|ORIFICE(61,40)|CO2 UPTAKE(60,6)|GLOBAL RELIANCE(58,1)|SHELF(55,94)|CARBONATION MEDIUM(53,40)|NATURAL ACCELERATION(47,1)|IRRIGATION IMPLEMENT(44,1)|ENTERPRISE USER(39,1)|PORTFOLIO(36,1)|SHELF REST(35,1)|CUSTOMIZATION(34,1)|DESIRE(34,1)|CARBONATION(31,17)|CABLE PUCK(31,5)|DISPENSING(31,4)|BIOENERGY(31,1)|DATABASE CONFIGURATION(31,1)|BEAD(30,32)|AGITATION(27,11)|FOREST(27,1)|FRAMEWORK(27,1)|BECCS(26,1)|FOSSIL FUEL(25,1)|HORIZONTAL DIRECTION(24,22)|MINERAL(23,1)|RELATIONAL MODEL(23,1)|FIDUCIAL(22,3)|SYNTAX STRUCTURE(22,1)|CARBONATION PLOT(21,6)|SPRAY NOZZLE(21,2)|ALIGNMENT FEATURE(21,1)|CABLE MOUNTING(21,1)|DATA TRANSMISSION(21,1)|COUNTERWEIGHT(19,8)|CO2 MITIGATION DIVERSE PORTFOLIO(19,1)|UNLOADING(19,1)|CADDY DOCK(18,4)|CABLE MANAGEMENT(17,7)|CARBONATION MEDIUM TRAY(17,5)|DOLOMITIC LIME(17,4)|VIBRATION(17,3)|VARIABLE SPRAY ANGLE(17,2)|CONVEYING AIR(16,5)|DUMPING STATION(16,5)|CABLE HORIZONTAL MOVEMENT(15,2)|LINEAR ACTUATOR(13,4)|MOUNTING BRACKET WHEEL(13,4)|TRAY ALIGNMENT(12,5)|CALCIUM HYDROXIDE(11,4)|MAGNESIUM HYDROXIDE(11,4)|CARBONATION AUTOMATED COLLECTION(11,1)|VIBRATING PAN FEEDER(11,1)|CARBON CAPTURE(10,4)|SODIUM HYDROXIDE(10,4)|CARBONATION AUTOMATED FILLING(10,1)|CARBONATION MEDIUM CO2 UPTAKE(10,1)|SOLAR IRRADIANCE SENSOR(10,1)|SHELF ILLUSTRATION(9,3)|BRACING INTERVAL(9,2)|CONTACTOR ILLUSTRATION(9,2)|DISTRIBUTOR ILLUSTRATION(9,2)|ELEVATED BORDER(9,2)|MINIMAL BENDING RADIUS(9,2)|ACCELERATED CARBONATION(9,1)|BENT TRAY PICKUP(9,1)|CONTACTOR FILL STATION(9,1)|NONCONTIGUOUS PLOT(9,1)|UNLISTED ITEM(9,1)|AMBIENT AIR(8,8)|INTRUSION PREVENTION(8,5)|COLLECTION STATION(8,2)|HORIZONTAL BAR(7,36)|CALCIUM OXIDE(7,5)|LIP HEIGHT(7,4)|REACTION EXTENT(7,4)|CONTRACTOR(7,2)|INTERLOCKING FEATURE(7,2)|NONLINEARITY(7,2)|CABLE MINIMAL BEND RADIUS(7,1)|CANTILEVER BEAN(7,1)|CONTACTOR NETWORK(7,1)|DIRECTION PARALLEL(7,1)|DISTRIBUTOR GRAVITY(7,1)|EDUCTOR NOZZLE(7,1)|ELEVATED CO2 CAPTURE(7,1)|MISTING NOZZLE(7,1)|PLURAL REFERENT(7,1)|TRAY HANDOFF(7,1)|UNDESIRED COLLISION(7,1)|LOAD CELL(6,6)|SODIUM OXIDE(6,4)|CALCIUM MAGNESIUM OXIDE(6,3)|MEDIAN(6,3)|ARTICULATION CABLE CARRIER(6,1)|COLLECTED CARBONATION MEDIUM(6,1)|CONTACTOR BAR(6,1)|CURVED ELLIPTICAL PATTERN(6,1)|DEDICATED ACTUATOR(6,1)|DUMPING MODULE(6,1)|EXCLUSIVITY TERM(6,1)|FORCED AIRFLOW(6,1)|HOLLOW CONE NOZZLE(6,1)|MINIMAL STIFFNESS(6,1)|ROTARY DOSER(6,1)|SATURATED CARBONATION MEDIUM(6,1)|SIMPLIFY INSTALLATION(6,1)|TIE BEAN(6,1)|TRAY SECURE PLACEMENT(6,1)|TRUSSED BEAM(6,1)|ACTUATOR HORIZONTAL MOVEMENT(5,2)|BACKSTOP(5,2)|CALCINATION(5,2)|CALCINER(5,2)|CO2 REMOVAL(5,2)|CONTACTOR BLOCK DIAGRAM(5,2)|CROSSBAR(5,2)|FULL TRAY(5,2)|MOVING MODULE(5,2)|RECTANGULAR PATTERN(5,2)|SHELF HORIZONTAL CENTER(5,2)|SQUARE PATTERN(5,2)|TARGET COMPOUND(5,2)|TRAY PROCESSING(5,2)|CARBONATION MEDIUM PROCESSING(5,1)|CHAINLINK FENCE(5,1)|COMPOSITE BEAM(5,1)|CURVE CIRCLE PATTERN(5,1)|DEEP DRAW(5,1)|DISTRIBUTOR MASS FORCE(5,1)|EXCLUSION LIMIT(5,1)|FILL TRAY(5,1)|FILLING MODULE(5,1)|FLAT FAN NOZZLE(5,1)|FULL CONE NOZZLE(5,1)|GEOMETRIC RELATIONSHIP(5,1)|GRAY CAST IRON(5,1)|HIP BEAM(5,1)|HOLLOW CONDUIT(5,1)|HORIZONTAL BRACING(5,1)|HORIZONTAL RIBBING(5,1)|INTERACTION BENEFIT(5,1)|IRRIGATION(5,1)|LINEAR ACTUATION(5,1)|MEDIUM CARBONATION(5,1)|PRECIPITATION SENSOR(5,1)|REINFORCED CONCRETE BEAM(5,1)|RELEASE TRAY(5,1)|RELEASING TENSION(5,1)|SHELF VOID SPACE(5,1)|SINGULAR FEATURE(5,1)|SPACING INTERVAL(5,1)|STATIONARY ACTUATOR(5,1)|TERM ORDINARY MEANING(5,1)|TIMBER BEAM(5,1)|TRAY FILLING STATION(5,1)|UNINTENTIONAL WALL(5,1)|ACTUATING POSITION(4,10)|ACRYLONITRILE BUTADIENE STYRENE(4,2)|BALLSCREW(3,1)|BREADTH(3,1)|CARBON DIOXIDE UPTAKE(3,1)|CARBONATION MEDIUM LAYER(3,1)|CIRCULAR PATTERN(3,1)|COATED WIRE ROPE(3,1)|COMPOSITE PLASTIC(3,1)|CONVEYER(3,1)|CRIMPING(3,1)|CURVED BEAM(3,1)|DETENTION(3,1)||(JP2025522936)|TRAY(100,196)|DISTRIBUTOR(100,108)|ACTUATOR(100,67)|PLATFORM(100,25)|MOTOR(100,10)|CHAIN(100,7)|LOAD CELL(100,6)|LINEAR ACTUATOR(100,4)|TRAY WEIGHT(100,3)|CARBON UPTAKE(100,2)|PLATFORM BOTTOM(100,1)|RECOVERY CONTACTOR(100,1)|DISTRIBUTOR CENTERLINE(93,23)|BAR ORIENTATION(69,5)|CAPTURING CO2(64,1)|CARBONATING MEDIUM(55,26)|GLOBAL DEPENDANCE(55,1)|TRAY PRESSING(54,2)|SHELF(51,93)|BIOENERGY(43,2)|NATURAL ACCELERATION(43,1)|ORIFICE(41,38)|ENTERPRISE USER(39,1)|DIAGONAL BRACE(36,5)|PORTFOLIO(35,1)|CARBON COLLECTION(33,1)|CUSTOMIZATION(33,1)|DOLOMITE LIME(32,4)|BIOSPHERE(32,1)|DATABASE CONFIGURATION(30,1)|BEAD(29,32)|AIR COLLECTION(29,1)|SEA(29,1)|AGITATION(26,10)|FOREST(26,1)|FRAMEWORK(26,1)|IRRIGATOR(26,1)|CARBONIZATION MEDIUM(25,2)|LIQUID DISCHARGE(25,2)|BECCS(25,1)|HORIZONTAL BRACE(24,6)|FOSSIL FUEL(24,1)|LOAD REQUIREMENT(23,1)|MINERAL(23,1)|RELATIONAL MODEL(23,1)|SYNTAX STRUCTURE(23,1)|HORIZONTAL DIRECTION(20,15)|SPRAY NOZZLE(20,2)|DATA TRANSMISSION(20,1)|GROUND(20,1)|MEDIUM CARBONATION(19,15)|COUNTERWEIGHT(19,7)|UPTAKE(19,4)|DUMPING STATION(18,7)|ALIGNMENT FUNCTION(18,2)|VARIABLE SPRAY ANGLE(17,2)|CABLE MANAGEMENT(16,7)|CONVEYING AIR(16,5)|PREVENT TRAY(16,1)|CARBONATING MEDIUM TRAY(15,4)|CARBONATED CHLORIDE PLOT(15,3)|CABLE HORIZONTAL MOVEMENT(15,2)|CHEMICAL SUBSTANCE(15,1)|FLEXIBILITY NUMBER(15,1)|DISCHARGING(14,2)|AMBIENT AIR(12,5)|CONTACTOR SHELF(12,2)|MOUNTING BRACKET WHEEL(11,4)|CARBON CAPTURE(11,3)|CARBON DIOXIDE(11,2)|VIBRATING PAN FEEDER(11,1)|CALCIUM HYDROXIDE(10,4)|SODIUM HYDROXIDE(10,4)|CALCINING FURNACE(10,2)|SEMICONTINUOUS PLOT(10,1)|SOLAR IRRADIANCE SENSOR(10,1)|TRAY ALIGNMENT(9,2)|SHELF HORIZONTAL CENTER(8,5)|TRAY TREATMENT(8,3)|MOBILE MODULE(8,2)|ACCELERATED CARBONIZATION(8,1)|CARBONATED MEDIA TRAY(8,1)|CARBONATION COMPARTMENT(8,1)|CARBONIZATION COMPARTMENT(8,1)|CONTACTOR TRAY(8,1)|DAC CONTACTOR(8,1)|DIVERSE PORTFOLIO(8,1)|SATURATED CARBONATED MEDIA(8,1)|SUCKING CARBONATED MEDIUM(8,1)|HORIZONTAL BAR(7,36)|CABLE MOUNTING(7,5)|INTRUSION PREVENTION(7,4)|CALCIUM OXIDE(7,3)|HORIZONTAL RIB(7,3)|RAISED BOUNDARY(7,2)|RECOVERY STATION(7,2)|CATCHING TRAY(7,1)|CONTACTOR NETWORK(7,1)|DIRECTION PARALLEL(7,1)|DISCONTINUOUS PLOT(7,1)|DISTRIBUTOR BALANCE(7,1)|EJECTOR NOZZLE(7,1)|INTERNATIONAL GAZETTE(7,1)|MIST BLOWING(7,1)|PLOT CARBONATION(7,1)|SHELF DEFLECTION(7,1)|SHELF VOID(7,1)|TRANSITION CLAUSE(7,1)|SODIUM OXIDE(6,4)|BULLETIN(6,3)|CALCIUM MAGNESIUM OXIDE(6,3)|MEDIAN(6,3)|RETURN STOP(6,3)|SHELF HORIZONTAL EDGE(6,3)|ARTICULATION CABLE CARRIER(6,1)|BEAD INTERVAL(6,1)|BRACE SPACING(6,1)|CARBONATED MEDIUM AUTOMATIC FILLING(6,1)|CARBONATED MEDIUM AUTOMATIC RECOVERY(6,1)|CONTACTOR BAR(6,1)|CONTACTOR FILLING STATION(6,1)|CURVED ELLIPTICAL PATTERN(6,1)|DEDICATED ACTUATOR(6,1)|DISTRIBUTOR GEOMETRICAL CONFIGURATION(6,1)|DUMPING MODULE(6,1)|ENTRY PREVENTION(6,1)|FOG NOZZLE(6,1)|FORCED AIRFLOW(6,1)|HOLLOW CONE NOZZLE(6,1)|PLACING CARBONATING MEDIUM(6,1)|RAINFALL SENSOR(6,1)|RECOVERED CARBONATED MEDIUM(6,1)|STIRRING CARBONATED MEDIUM(6,1)|TENSION BRACE(6,1)|REACTION LEVEL(5,4)|ACTUATOR HORIZONTAL MOVEMENT(5,2)|BACKSTOP(5,2)|CALCINATION(5,2)|CARBON RECOVERY MEDIUM(5,2)|CONTACTOR BLOCK DIAGRAM(5,2)|CROSSBAR(5,2)|DISTRIBUTOR DIAGRAM(5,2)|FULL TRAY(5,2)|RECTANGULAR PATTERN(5,2)|SQUARE PATTERN(5,2)|TARGET COMPOUND(5,2)|BENT TRAY(5,1)|BORDER HEIGHT(5,1)|CADDY DOCK TOP(5,1)|CARBONATED MEDIA LAYER(5,1)|CARBONATED MEDIUM TREATMENT(5,1)|CHAINLINK FENCE(5,1)|CIRCULAR DAC(5,1)|COMPOSITE BEAM(5,1)|DISTRIBUTOR MASS FORCE(5,1)|EXCLUSION LIMIT(5,1)|EXCLUSIVITY TERM(5,1)|FILLED TRAY(5,1)|FILLING MODULE(5,1)|FLAT FAN NOZZLE(5,1)|FULL CONE NOZZLE(5,1)|GEOMETRIC RELATIONSHIP(5,1)|GRAY CAST IRON(5,1)|HIP BEAM(5,1)|HOLLOW CONDUIT(5,1)|IRRIGATION(5,1)|LINEAR ACTUATING(5,1)|MINIMAL RIGIDITY(5,1)|OMITTED SHALL(5,1)|REBAR CONCRETE BEAM(5,1)|ROTATING DOSER(5,1)|STATIONARY ACTUATOR(5,1)|TERM ORDINARY MEANING(5,1)|TILT BEAM(5,1)|TRAY FILLING STATION(5,1)|TRAY ROTATION(5,1)|TRAY SURE ARRANGEMENT(5,1)|TRUSS BEAM(5,1)|ACTUATING POSITION(4,10)|DIRECT AIR CAPTURE(4,3)|TRAY HOLE(4,3)|ACRYLONITRILE BUTADIENE STYRENE(4,2)|ACTUATOR REMAINS(3,1)|ADSORBENT(3,1)|AIR UPTAKE(3,1)|CALCIUM MAGNESIUM HYDROXIDE(3,1)|CAPTURING CARBON DIOXIDE(3,1)|CEILING(3,1)|CIRCULAR CURVE PATTERN(3,1)|CIRCULAR PATTERN(3,1)|CLEAR INDICATION(3,1)|COATED WIRE ROPE(3,1)|COLLISION(3,1)|COMPOSITE PLASTIC(3,1)|CONVEYER(3,1)||(CN120390667)|CONTACTOR(100,51)|DISPENSER CENTERLINE(100,23)|AIR(100,5)|CARBON UPTAKE(100,3)|TRAY(99,186)|PLATFORM(73,33)|BAR ORIENTATION(73,3)|DISPENSER(69,101)|SHELF(64,97)|GLOBAL RELIANCE(61,1)|FLUSHING APPLIANCE(53,1)|MEDIUM CARBONATION(47,18)|MOVING TRAY(41,3)|ROD ORIENTATION(38,3)|CARBONATION MEDIUM(36,20)|BIOSPHERE(35,1)|BIOENERGY(33,1)|BEAD(32,32)|STIRRER(31,3)|ORIFICE(30,17)|FOREST(29,1)|BECCS(28,1)|HORIZONTAL DIRECTION(26,23)|LIFT(26,4)|FOSSIL FUEL(26,1)|MARINE(26,1)|INTAKE(25,1)|MINERAL(25,1)|CARBONATION FACILITY(24,6)|DUMPING(23,4)|LOAD REQUIREMENT(23,1)|ALIGNMENT FEATURE(22,1)|GROUND(22,1)|COUNTERWEIGHT(20,8)|SPRAY NOZZLE(20,3)|CARBONATED MEDIUM TRAY(18,5)|DOLOMITIC LIME(18,4)|VARIABLE SPRAY ANGLE(18,2)|CABLE MOUNTING(17,6)|CONVEYING AIR(17,3)|DISPENSING(17,3)|FILLING STATION(16,16)|CABLE HORIZONTAL MOVEMENT(16,2)|NATURAL(15,1)|CABLE MANAGEMENT(14,4)|LINEAR ACTUATOR(14,4)|MOUNTING BRACKET WHEEL(14,4)|TRAY ALIGNMENT(13,5)|DUMPING STATION(12,3)|PAN VIBRATION FEEDER(12,1)|AGITATION(11,8)|DISTRIBUTOR(11,8)|CABLE TRAY(11,4)|CALCIUM HYDROXIDE(11,4)|CARBON CAPTURE(11,4)|MAGNESIUM HYDROXIDE(11,4)|SODIUM HYDROXIDE(11,4)|REGENERATED CARBONATION(11,1)|SOLAR IRRADIANCE SENSOR(11,1)|INTRUSION PREVENTION(9,5)|SHELF HORIZONTAL CENTER(9,5)|CALCINATION(9,4)|COLLECTED CARBONATION MEDIA(9,1)|SATURATED CARBONATION MEDIA(9,1)|UNLISTED ITEM(9,1)|AMBIENT AIR(8,8)|SHELF HORIZONTAL EDGE(8,4)|HORIZONTAL RIB(8,3)|COLLECTION STATION(8,2)|DIRECTION PARALLEL(8,1)|DISCONTINUOUS FACILITY(8,1)|DISPENSER GEOMETRY(8,1)|DISPENSER INTERACTION(8,1)|PLURAL REFERENT(8,1)|RAIN 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DIOXIDE(4,1)|CEILING(4,1)|CIRCULAR SCALE(4,1)|COATED STEEL WIRE ROPE(4,1)|COMPOSITE PLASTIC(4,1)|CONCRETE PRODUCTION(4,1)|CONVEYER(4,1)|CRIMPING(4,1)|CYCLING(4,1)|DATABASE CONFIGURATION(4,1)|DETENT WALL(4,1)|DICTIONARY DEFINITION(4,1)||(IN202517003741)|TRAY(100,199)|DIRECT AIR CAPTURE(100,7)|CARBON UPTAKE(100,1)|DIRECT AIR CAPTURE CONTACTOR(100,1)|DISTRIBUTOR CENTERLINE(95,23)|OCEAN CO2 UPTAKE(88,1)|TERRESTRIAL BIOSPHERE(81,1)|BAR ORIENTATION(76,8)|DISTRIBUTOR(74,114)|PLATFORM(69,33)|FUTURE CO2 EMISSION(63,1)|ORIFICE(61,40)|CO2 UPTAKE(60,6)|GLOBAL RELIANCE(58,1)|SHELF(55,94)|CARBONATION MEDIUM(53,40)|NATURAL ACCELERATION(47,1)|IRRIGATION IMPLEMENT(44,1)|ENTERPRISE USER(39,1)|PORTFOLIO(36,1)|SHELF REST(35,1)|CUSTOMIZATION(34,1)|DESIRE(34,1)|CARBONATION(31,17)|CABLE PUCK(31,5)|DISPENSING(31,4)|BIOENERGY(31,1)|DATABASE CONFIGURATION(31,1)|BEAD(30,32)|AGITATION(27,11)|FOREST(27,1)|FRAMEWORK(27,1)|BECCS(26,1)|FOSSIL FUEL(25,1)|HORIZONTAL DIRECTION(24,22)|MINERAL(23,1)|RELATIONAL MODEL(23,1)|FIDUCIAL(22,3)|SYNTAX STRUCTURE(22,1)|CARBONATION PLOT(21,6)|SPRAY NOZZLE(21,2)|ALIGNMENT FEATURE(21,1)|CABLE MOUNTING(21,1)|DATA TRANSMISSION(21,1)|COUNTERWEIGHT(19,8)|CO2 MITIGATION DIVERSE PORTFOLIO(19,1)|UNLOADING(19,1)|CADDY DOCK(18,4)|CABLE MANAGEMENT(17,7)|CARBONATION MEDIUM TRAY(17,5)|DOLOMITIC LIME(17,4)|VIBRATION(17,3)|VARIABLE SPRAY ANGLE(17,2)|CONVEYING AIR(16,5)|DUMPING STATION(16,5)|CABLE HORIZONTAL MOVEMENT(15,2)|LINEAR ACTUATOR(13,4)|MOUNTING BRACKET WHEEL(13,4)|TRAY ALIGNMENT(12,5)|CALCIUM HYDROXIDE(11,4)|MAGNESIUM HYDROXIDE(11,4)|CARBONATION AUTOMATED COLLECTION(11,1)|VIBRATING PAN FEEDER(11,1)|CARBON CAPTURE(10,4)|SODIUM HYDROXIDE(10,4)|CARBONATION AUTOMATED FILLING(10,1)|CARBONATION MEDIUM CO2 UPTAKE(10,1)|SOLAR IRRADIANCE SENSOR(10,1)|SHELF ILLUSTRATION(9,3)|BRACING INTERVAL(9,2)|CONTACTOR ILLUSTRATION(9,2)|DISTRIBUTOR ILLUSTRATION(9,2)|ELEVATED BORDER(9,2)|MINIMAL BENDING RADIUS(9,2)|ACCELERATED CARBONATION(9,1)|BENT TRAY PICKUP(9,1)|CONTACTOR FILL STATION(9,1)|NONCONTIGUOUS PLOT(9,1)|UNLISTED ITEM(9,1)|AMBIENT AIR(8,8)|INTRUSION PREVENTION(8,5)|COLLECTION STATION(8,2)|HORIZONTAL BAR(7,36)|CALCIUM OXIDE(7,5)|LIP HEIGHT(7,4)|REACTION EXTENT(7,4)|CONTRACTOR(7,2)|INTERLOCKING FEATURE(7,2)|NONLINEARITY(7,2)|CABLE MINIMAL BEND RADIUS(7,1)|CANTILEVER BEAN(7,1)|CONTACTOR NETWORK(7,1)|DIRECTION PARALLEL(7,1)|DISTRIBUTOR GRAVITY(7,1)|EDUCTOR NOZZLE(7,1)|ELEVATED CO2 CAPTURE(7,1)|MISTING NOZZLE(7,1)|PLURAL REFERENT(7,1)|TRAY HANDOFF(7,1)|UNDESIRED COLLISION(7,1)|LOAD CELL(6,6)|SODIUM OXIDE(6,4)|CALCIUM MAGNESIUM OXIDE(6,3)|MEDIAN(6,3)|ARTICULATION CABLE CARRIER(6,1)|COLLECTED CARBONATION MEDIUM(6,1)|CONTACTOR BAR(6,1)|CURVED ELLIPTICAL PATTERN(6,1)|DEDICATED ACTUATOR(6,1)|DUMPING MODULE(6,1)|EXCLUSIVITY TERM(6,1)|FORCED AIRFLOW(6,1)|HOLLOW CONE NOZZLE(6,1)|MINIMAL STIFFNESS(6,1)|ROTARY DOSER(6,1)|SATURATED CARBONATION MEDIUM(6,1)|SIMPLIFY INSTALLATION(6,1)|TIE BEAN(6,1)|TRAY SECURE PLACEMENT(6,1)|TRUSSED BEAM(6,1)|ACTUATOR HORIZONTAL MOVEMENT(5,2)|BACKSTOP(5,2)|CALCINATION(5,2)|CALCINER(5,2)|CO2 REMOVAL(5,2)|CONTACTOR BLOCK DIAGRAM(5,2)|CROSSBAR(5,2)|FULL TRAY(5,2)|MOVING MODULE(5,2)|RECTANGULAR PATTERN(5,2)|SHELF HORIZONTAL CENTER(5,2)|SQUARE PATTERN(5,2)|TARGET COMPOUND(5,2)|TRAY PROCESSING(5,2)|CARBONATION MEDIUM PROCESSING(5,1)|CHAINLINK FENCE(5,1)|COMPOSITE BEAM(5,1)|CURVE CIRCLE PATTERN(5,1)|DEEP DRAW(5,1)|DISTRIBUTOR MASS FORCE(5,1)|EXCLUSION LIMIT(5,1)|FILL TRAY(5,1)|FILLING MODULE(5,1)|FLAT FAN NOZZLE(5,1)|FULL CONE NOZZLE(5,1)|GEOMETRIC RELATIONSHIP(5,1)|GRAY CAST IRON(5,1)|HIP BEAM(5,1)|HOLLOW CONDUIT(5,1)|HORIZONTAL BRACING(5,1)|HORIZONTAL RIBBING(5,1)|INTERACTION BENEFIT(5,1)|IRRIGATION(5,1)|LINEAR ACTUATION(5,1)|MEDIUM CARBONATION(5,1)|PRECIPITATION SENSOR(5,1)|REINFORCED CONCRETE BEAM(5,1)|RELEASE TRAY(5,1)|RELEASING TENSION(5,1)|SHELF VOID SPACE(5,1)|SINGULAR FEATURE(5,1)|SPACING INTERVAL(5,1)|STATIONARY ACTUATOR(5,1)|TERM ORDINARY MEANING(5,1)|TIMBER BEAM(5,1)|TRAY FILLING STATION(5,1)|UNINTENTIONAL WALL(5,1)|ACTUATING POSITION(4,10)|ACRYLONITRILE BUTADIENE STYRENE(4,2)|BALLSCREW(3,1)|BREADTH(3,1)|CARBON DIOXIDE UPTAKE(3,1)|CARBONATION MEDIUM LAYER(3,1)|CIRCULAR PATTERN(3,1)|COATED WIRE ROPE(3,1)|COMPOSITE PLASTIC(3,1)|CONVEYER(3,1)|CRIMPING(3,1)|CURVED BEAM(3,1)|DETENTION(3,1)||(AU2023303026)|DISTRIBUTOR CENTERLINE(100,23)|DIRECT AIR CAPTURE(100,7)|CARBON UPTAKE(100,1)|DIRECT AIR CAPTURE CONTACTOR(100,1)|TRAY(97,195)|OCEAN CO2 UPTAKE(92,1)|TERRESTRIAL BIOSPHERE(85,1)|BAR ORIENTATION(79,8)|DISTRIBUTOR(77,114)|ANDAN ACTUATOR(68,1)|FUTURE CO2 EMISSION(66,1)|GLOBAL RELIANCE(60,1)|SHELF(57,94)|CARBONATION MEDIUM(55,40)|ORIFICE(50,38)|PLATFORM(50,29)|NATURAL ACCELERATION(49,1)|IRRIGATION IMPLEMENT(46,1)|ENTERPRISE USER(41,1)|CO2 UPTAKE(38,5)|PORTFOLIO(38,1)|SHELF REST(37,1)|CUSTOMIZATION(35,1)|DESIRE(35,1)|CABLE PUCK(33,5)|DISPENSING(33,4)|BIOENERGY(33,1)|DATABASE CONFIGURATION(33,1)|UPTAKE(33,1)|CARBONATION(32,17)|BEAD(31,32)|AGITATION(28,11)|FOREST(28,1)|FRAMEWORK(28,1)|BECCS(27,1)|FOSSIL FUEL(26,1)|HORIZONTAL DIRECTION(25,22)|MINERAL(24,1)|RELATIONAL MODEL(24,1)|FIDUCIAL(23,3)|SYNTAX STRUCTURE(23,1)|CARBONATION PLOT(22,6)|SPRAY NOZZLE(22,2)|ALIGNMENT FEATURE(22,1)|CABLE MOUNTING(22,1)|DATA TRANSMISSION(22,1)|COUNTERWEIGHT(20,8)|CO2 MITIGATION DIVERSE PORTFOLIO(20,1)|UNLOADING(20,1)|CADDY DOCK(19,4)|CABLE MANAGEMENT(18,7)|CARBONATION MEDIUM TRAY(18,5)|DOLOMITIC LIME(18,4)|VIBRATION(18,3)|VARIABLE SPRAY ANGLE(18,2)|CONVEYING AIR(17,5)|DUMPING STATION(17,5)|CABLE HORIZONTAL MOVEMENT(16,2)|SEMIOR NONCONTIGUOUS PLOT(16,1)|TRAY ALIGNMENT(13,5)|MOUNTING BRACKET WHEEL(13,4)|CARBONATION AUTOMATED COLLECTION(12,1)|VIBRATING PAN FEEDER(12,1)|CALCIUM HYDROXIDE(11,4)|CARBON CAPTURE(11,4)|MAGNESIUM HYDROXIDE(11,4)|SODIUM HYDROXIDE(11,4)|CARBONATION AUTOMATED FILLING(11,1)|CARBONATION MEDIUM CO2 UPTAKE(11,1)|SOLAR IRRADIANCE SENSOR(11,1)|INTRUSION PREVENTION(9,5)|SHELF ILLUSTRATION(9,3)|BRACING INTERVAL(9,2)|CONTACTOR ILLUSTRATION(9,2)|DISTRIBUTOR ILLUSTRATION(9,2)|ELEVATED BORDER(9,2)|MINIMAL BENDING RADIUS(9,2)|ACCELERATED CARBONATION(9,1)|BENT TRAY PICKUP(9,1)|CONTACTOR FILL STATION(9,1)|UNLISTED ITEM(9,1)|HORIZONTAL BAR(8,36)|LIP HEIGHT(8,4)|REACTION EXTENT(8,4)|LINEAR ACTUATOR(8,3)|COLLECTION STATION(8,2)|CABLE MINIMAL BEND RADIUS(8,1)|CANTILEVER BEAN(8,1)|CONTACTOR NETWORK(8,1)|DIRECTION PARALLEL(8,1)|DISTRIBUTOR GRAVITY(8,1)|EDUCTOR NOZZLE(8,1)|ELEVATED CO2 CAPTURE(8,1)|MISTING NOZZLE(8,1)|PLURAL REFERENT(8,1)|TRAY HANDOFF(8,1)|UNDESIRED COLLISION(8,1)|CALCIUM OXIDE(7,5)|CALCIUM MAGNESIUM OXIDE(7,3)|MEDIAN(7,3)|CONTRACTOR(7,2)|INTERLOCKING FEATURE(7,2)|NONLINEARITY(7,2)|LOAD CELL(6,6)|SODIUM OXIDE(6,4)|ARTICULATION CABLE CARRIER(6,1)|COLLECTED CARBONATION MEDIUM(6,1)|CONTACTOR BAR(6,1)|CURVED ELLIPTICAL PATTERN(6,1)|DEDICATED ACTUATOR(6,1)|DUMPING MODULE(6,1)|EXCLUSIVITY TERM(6,1)|FORCED AIRFLOW(6,1)|HOLLOW CONE NOZZLE(6,1)|MINIMAL STIFFNESS(6,1)|ROTARY DOSER(6,1)|SATURATED CARBONATION MEDIUM(6,1)|SIMPLIFY INSTALLATION(6,1)|TIE BEAN(6,1)|TRAY SECURE PLACEMENT(6,1)|TRUSSED BEAM(6,1)|ACTUATOR HORIZONTAL MOVEMENT(5,2)|BACKSTOP(5,2)|CALCINATION(5,2)|CALCINER(5,2)|CO2 REMOVAL(5,2)|CONTACTOR BLOCK DIAGRAM(5,2)|CROSSBAR(5,2)|FULL TRAY(5,2)|MOVING MODULE(5,2)|RECTANGULAR PATTERN(5,2)|SHELF HORIZONTAL CENTER(5,2)|SQUARE PATTERN(5,2)|TARGET COMPOUND(5,2)|TRAY PROCESSING(5,2)|CARBONATION MEDIUM PROCESSING(5,1)|CHAINLINK FENCE(5,1)|COMPOSITE BEAM(5,1)|CURVE CIRCLE PATTERN(5,1)|DEEP DRAW(5,1)|DISTRIBUTOR MASS FORCE(5,1)|EXCLUSION LIMIT(5,1)|FILL TRAY(5,1)|FILLING MODULE(5,1)|FLAT FAN NOZZLE(5,1)|FULL CONE NOZZLE(5,1)|GEOMETRIC RELATIONSHIP(5,1)|GRAY CAST IRON(5,1)|HIP BEAM(5,1)|HOLLOW CONDUIT(5,1)|HORIZONTAL BRACING(5,1)|HORIZONTAL RIBBING(5,1)|INTERACTION BENEFIT(5,1)|IRRIGATION(5,1)|LINEAR ACTUATION(5,1)|MEDIUM CARBONATION(5,1)|PRECIPITATION SENSOR(5,1)|REINFORCED CONCRETE BEAM(5,1)|RELEASE TRAY(5,1)|RELEASING TENSION(5,1)|SHELF VOID SPACE(5,1)|SINGULAR FEATURE(5,1)|SPACING INTERVAL(5,1)|STATIONARY ACTUATOR(5,1)|TERM ORDINARY MEANING(5,1)|TIMBER BEAM(5,1)|TRAY FILLING STATION(5,1)|UNINTENTIONAL WALL(5,1)|ACTUATING POSITION(4,10)|ACRYLONITRILE BUTADIENE STYRENE(4,2)|BALLSCREW(4,1)|BREADTH(4,1)|CARBON DIOXIDE UPTAKE(4,1)|CARBONATION MEDIUM LAYER(4,1)|CIRCULAR PATTERN(4,1)|COATED WIRE ROPE(4,1)|COMPOSITE PLASTIC(4,1)|CONVEYER(4,1)|CRIMPING(4,1)|CURVED BEAM(4,1)| | (US20240009617)|1. A device, comprising:| a platform including a top portion and a bottom portion;| an elevation mechanism configured to move the platform vertically;| a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray; and| an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally,| wherein the bottom portion is configured to support the tray as the tray moves laterally.|2. The device of claim 1, wherein the elevation mechanism includes at least one of a chain or a linear actuator driven by a motor.|3. The device of claim 1, wherein the tray includes a carbonation medium disposed therein.|4. The device of claim 3, wherein the carbonation medium includes at least one of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide).|5. The device of claim 1, wherein the plurality of orifices include spray nozzles configured to spray the liquid onto the tray.|6. The device of claim 5, wherein the spray nozzles have variable spray angles.|7. The device of claim 1, wherein the actuator includes a pin, the pin configured to secure into a hole on the tray to engage the actuator with the tray.|8. The device of claim 7, wherein the pin is a first pin and the tray is a first tray, the actuator further including a second pin, the second pin configured to secure into a hole on a second tray to engage the actuator with the second tray and urge the second tray to move in a direction parallel to the movement of the first tray, the second tray located opposite the first tray relative to the actuator.|9. The device of claim 2, further comprising:| a counterweight configured to minimize loading requirements on the motor.|10. The device of claim 1, wherein the bottom portion of the platform includes a load cell configured to measure a weight of the tray.|11. The device of claim 1, wherein the platform includes a mechanical agitator configured to agitate contents of the tray.|12. The device of claim 11, wherein the mechanical agitator includes at least one of an irrigation implement, a stirring element, and/or a vibration element.|13. An apparatus, comprising:| a frame including a plurality of vertically oriented bars and a plurality of horizontally oriented bars;| a plurality of cables including beads, the plurality of cables coupled to and suspended from the horizontally oriented bars in tension;| a plurality of shelves coupled to the cables and supported by the beads, the plurality of shelves configured to support a plurality of trays; and| a plurality of distributors, each distributor of the plurality of distributors configured to move vertically, each distributor of the plurality of distributors configured to contact a tray from the plurality of trays and urge the tray to move horizontally into and out of the distributor.|14. The apparatus of claim 13, wherein each of the plurality of shelves includes a cable mounting feature configured to couple to the beads.|15. The apparatus of claim 13, further comprising:| a plurality of cable pucks placed upon the beads and configured to increase the surface area upon which each of the plurality of shelves rest.|16. The apparatus of claim 13, wherein each of the plurality of shelves includes an alignment feature configured to engage a tray from the plurality of trays and prevent horizontal sliding of the tray.|17. The apparatus of claim 13, further comprising:| an air conveyor configured to force air through the plurality of shelves and the plurality of trays.|18. The apparatus of claim 13, wherein each of the plurality of vertically oriented bars includes a series of fiducials configured to fix heights along the vertically oriented bars, at which the plurality of distributors are fixed while loading and unloading.|19. The apparatus of claim 13, further comprising:| at least one of a horizontal bracing element or a diagonal bracing element configured to contact at least a portion of the plurality of cables to minimize horizontal movement of the plurality of cables and the plurality of shelves.|20. A method, comprising:| moving a distributor in a vertical direction, the distributor including an actuator and an orifice;| fixing a vertical position of the distributor;| securing the actuator to a tray positioned on a shelf, the tray including a carbonation medium;| urging, via the actuator, the tray in a horizontal direction toward a centerline of the distributor; and| dispensing, via the orifice, a liquid onto the carbonation medium in the tray;|21. The method of claim 20, further comprising: urging, via the actuator, the tray in a horizontal direction onto the shelf.|22. The method of claim 20, further comprising:| disengaging the actuator from the tray and moving the actuator horizontally toward the centerline of the distributor.|23. The method of claim 20, further comprising:| before securing the actuator to the tray, moving the actuator horizontally away from the centerline of the distributor.|24. The method of claim 20, wherein urging the tray in the horizontal direction toward the centerline of the distributor occurs at least partially concurrent with the dispensing.|25. The method of claim 20, wherein the tray is a first tray, the shelf is a first shelf, and the horizontal direction is a first horizontal direction, the method further comprising:| urging, via the actuator, a second tray in a second horizontal direction toward the centerline of the distributor.|26. The method of claim 25, wherein urging the first tray and urging the second tray are at least partially concurrent.|27. The method of claim 25, wherein the second horizontal direction forms an angle of about 180 degrees with the first horizontal direction. | (US20240009617)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to U.S. Provisional Application No. 63/358,602, filed Jul. 6, 2022 and titled “Direct Air Capture Contactor For Carbon Uptake, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety.|(US20240009617)|TECHNICAL FIELD|[0002] Embodiments described herein relate systems and methods for uptake of carbon dioxide (CO2) from ambient air.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. Inclusion of moisture in air capture medium can improve the uptake of CO2. Efficiency of water delivery to the carbon capture medium affects the overall efficiency of a system employing a carbon capture medium.|SUMMARY|[0004] Embodiments described herein relate to systems, devices, and methods for uptake of CO2 from ambient air. In some aspects, a device can include a platform with a top portion and a bottom portion, an elevation mechanism configured to move the platform vertically, a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray, and an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally. In some embodiments, the bottom portion can support the tray as the tray moves laterally. In some embodiments, the elevation mechanism can include at least one of a chain or a linear actuator driven by a motor. In some embodiments, the tray can include a carbonation medium disposed therein. In some embodiments, the carbonation medium can include at least one of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide).|(US20240009617)|BRIEF DESCRIPTION OF THE DRAWINGS|[0005] FIG. 1 is a block diagram of a contactor unit for direct air capture (DAC), according to an embodiment.|[0006] FIG. 2 is a block diagram of a distributor incorporated into a DAC system, according to an embodiment.|[0007] FIGS. 3A-3G are illustrations of a contactor unit and various components thereof, according to an embodiment.|[0008] FIG. 4 is an illustration of a network of contactor units, according to an embodiment.|[0009] FIG. 5 is an illustration of a distributor, according to an embodiment.|[0010] FIG. 6 is an illustration of a distributor, according to an embodiment.|[0011] FIGS. 7A-7E are illustrations of a shelf and its interactions with cables, according to an embodiment.|[0012] FIG. 8 is an illustration of a shelf, according to an embodiment.|[0013] FIG. 9 is a block diagram of a method of operating a distributor, according to an embodiment.|(US20240009617)|DETAILED DESCRIPTION|[0014] DAC contactors are used to hold, process, distribute, and/or re-collect carbonation medium in a cyclic DAC process. Contactors described herein can hold trays, move trays within a system, process carbonation medium in trays to maintain high CO2 uptake, fill trays, dispense, and/or dispense/collect saturated carbonation medium for regeneration. A fill station of a contactor can distribute a thin layer of capture material onto a tray. The tray is then picked up by a distributor. The distributor can pick up, move, dispense, and process trays and materials. Contactors can include a collection of vertical bars, and the distributors can traverse the bars of the contactor. Processing of carbonation medium can include addition of water to the carbonation medium to improve the CO2 uptake of the carbonation medium.|[0015] Distributors described herein can include mechanisms to pick trays, process trays, and release trays to a specified location inside the contactor. Distributors described herein can also measure weights of trays. In some embodiments, distributors described herein can encase a weighing platform. The processing of the trays can include adding water, agitating the carbonation medium, and/or any other form of processing. The distributor can pick the tray from a tray filling station or tray filling location and use the picking mechanism to move the tray into the body of the distributor. The distributor can then move vertically to align the tray to a proper rack and shelf location on the contactor, where the distributor delivers the tray to the proper location. This can be repeated until each shelf on the contactor has a tray.|[0016] The frequency of the processing of trays can be dictated by software and control algorithms. Processing can continue until the carbonation medium reaches a suitable reaction extent. In some embodiments, processing the trays can include misting a carbonation medium in the trays or other methods for controlled water distribution, or mechanical agitation of the materials. Processing can continue until the carbonation medium reaches a suitable reaction extent. In some embodiments, processing the trays can include misting water onto the carbonation medium in the trays or other methods for controlled water distribution or mechanical agitation of the materials. Processing can continue until the carbonation medium reaches a suitable reaction extent. Once the material has reacted sufficiently, the distributor can pick each tray individually and move it to a collection station. In the collection station, material can be removed from each tray. The tray can then be sent back to the filling station. The collected material can be sent to a regeneration process.|[0017] In some embodiments, the contact between the carbonation medium and the ambient air can include any of the strategies described in U.S. patent application Ser. No. 18/067,896 (“the '897 application”), filed Dec. 19, 2022, and titled, “Systems and Methods of Carbon Capture from Cement Production Processes,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2020/263910 (“the '910 publication”), filed Jun. 24, 2020, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. WO2022187336 (“the '336 publication”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. Benefits of interactions between water and carbonation medium are described in greater detail in the '910 publication and the '336 publication.|[0018] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions. In some embodiments, carbonation plots can include a composition that sequesters a target compound.|[0019] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0020] As used herein, “carbonation medium” refers to a medium that can take on carbon dioxide when exposed to ambient air. This can include but is not limited to calcium oxide (CaO), calcium hydroxide (Ca(OH)2), magnesium oxide (MgO), magnesium hydroxide (MgOH), sodium oxide (Na2O), sodium hydroxide (NaOH), and/or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation medium can originate from a natural source (e.g., limestone). Carbonation medium can also be regenerated or recycled (i.e., a regenerated carbonated medium from a calciner).|[0021] As used herein, “carbonated medium” refers to a carbonation medium that has taken up carbon dioxide from ambient air. This can include but is not limited to calcium carbonate (CaCO3), magnesium carbonate (MgCO3), sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), mixed calcium-magnesium carbonate phases ((Ca,Mg)CO3). Carbonated medium can be converted back to a carbonation medium (e.g., via the use of a calciner, a dissolution/precipitation-based system, and/or an electrochemical system).|[0022] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0023] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0024] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0025] As used herein, the term “about” and “approximately” generally means plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0026] FIG. 1 is a block diagram of a contactor unit 100 for DAC, according to an embodiment. The contactor unit includes a frame 110 having a horizontal bar 120 and a vertical bar 130, a cable 140, and a distributor 150. In some embodiments, the horizontal bar 120 is stacked on top of the vertical bar 130. In some embodiments, the frame 110 can include multiple horizontal bars 120 and/or vertical bars 130. In some embodiments, the frame 110 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, about 20, about 25, about 30, about 35, about 40, about 45, about 50, about 55, about 60, about about 70, about 75, about 80, about 85, about 90, about 95, or about 100 horizontal bars 120 and/or vertical bars 130, inclusive of all values and ranges therebetween.|[0027] In some embodiments, the horizontal bars 120 and/or the vertical bars 130 can include beams. In some embodiments, the horizontal bars 120 and/or the vertical bars 130 can include I-beams (universal beams), hip beams, trussed beams, composite beams, lattice beams, chilled beams, reinforced concrete beams, steel beams, timber beams, curved beams, straight beams, tie beans, cantilever beans, or any other suitable beam type or combinations thereof. In some embodiments, the horizontal bars 120 and/or the vertical bars 130 can be composed of metal, steel, carbon steel, iron, aluminum, stainless steel, laminate wood, timber, or any combination thereof. In some embodiments, multiple horizontal bars 120 can be arranged atop the vertical bars 130 in a geometric pattern (e.g., a square pattern, a rectangular pattern, a curved elliptical pattern, a curved circle pattern, etc.). In some embodiments, the ratio of vertical bars 130 to horizontal bars 120 can be based on the number of supports needed for the distributors 150. In some embodiments, the ratio of horizontal bars to vertical bars can be about 1:10, about 1:9, about 1:8, about 1:7, about 1:6, about 1:5, about 1:4, about 1:3, about 1:2, about 1:1, about 2:1, about 3:1, about 4:1, about 5:1, about 6:1, about 7:1, about 8:1, about 9:1, or about 10:1, inclusive of all values and ranges therebetween.|[0028] In some embodiments, the cable 140 is suspended from the horizontal bar 120. The cable 140 can include beads for engagement with a shelf 144 suspended from the horizontal bar 120. The cable 140 can be robust and taut. In some embodiments, the cable 140 can be composed of steel, carbon steel, non-alloy carbon steel, copper, coated wire rope, or any combination thereof. In some embodiments, the cable 140 can have a thickness of at least about 1 mm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 1.5 cm, at least about 2 cm, at least about 2.5 cm, at least about 3 cm, at least about 3.5 cm, at least about 4 cm, or at least about 4.5 cm. In some embodiments, the cable 140 can have a thickness of no more than about 5 cm, no more than about 4.5 cm, no more than about 4 cm, no more than about 3.5 cm, no more than about 3 cm, no more than about 2.5 cm, no more than about 2 cm, no more than about 1.5 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, or no more than about 2 mm. Combinations of the above-referenced thicknesses of the cable 140 are also possible (e.g., at least about 1 mm and no more than about cm or at least about 5 mm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the cable 140 can have a thickness of about 1 mm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 1.5 cm, about 2 cm, about 2.5 cm, about 3 cm, about 3.5 cm, about 4 cm, about 4.5 cm, or about 5 cm.|[0029] In some embodiments, the beads 142 can be placed along the length of the cable 140 at predetermined spacing intervals. In some embodiments, the beads 142 can be spaced apart at intervals of at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, or at least about 90 cm. In some embodiments, the beads 142 can be spaced apart at intervals of no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, or no more than about 2 cm. Combinations of the above-referenced spacings of the beads 142 are also possible (e.g., at least about 1 cm and no more than about 1 m or at least about 3 cm and no more than about cm), inclusive of all values and ranges therebetween. In some embodiments, the beads 142 can be spaced apart at intervals of about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, or about 1 m.|[0030] In some embodiments, the bead 142 supports the shelf 144. In some embodiments, the shelf 144 can snap, bolt, and/or bond to the bead 142. In some embodiments, multiple shelves 144 can be placed on multiple beads 142. In some embodiments, the shelves 144 can have holes with a larger section and a smaller section, such that the beads 142 can be threaded through the larger sections and moved relative to the hole to be under the smaller sections of the holes. This enables the smaller sections of the holes to support the beads 142 such that the shelves 144 can rest on the beads 142. In some embodiments, the beads 142 can have grooves into which holes on the shelves 144 can fit. In some embodiments, the beads 142 can be distinct pieces of material attached to the cable 140 by crimping, welding, brazing, soldering, adhesive, or any other suitable attachment method or combinations thereof. In some embodiments, a casting or coating can be applied around the outside of the beads 142 and the cable 140 to form a permanent assembly or a permanent connection between the beads 142 and the cable 140. In some embodiments, the casting material can be composed of zinc, tin, aluminum, copper, magnesium, tin, iron, low carbon steel, high carbon steel, white cast iron, gray cast iron, ductile cast iron, or any combination thereof. In some embodiments, the shelves 144 can be removably coupled to the cable 140. In other words, the shelves 144 can be replaceable.|[0031] The distributor 150 collects a tray with the carbonation medium disposed therein and pulls the tray into the body of the distributor 150. In some embodiments, the distributor 150 can move vertically along the vertical bar 130. In some embodiments, the contactor unit 100 can include multiple distributors 150 disposed therein. In some embodiments, the contactor unit 100 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, about 20, about 25, about 30, about 35, about 40, about 45, about 50, about 55, about 60, about 65, about 70, about 75, about 80, about 85, about 90, about 95, or about 100 distributors 150, inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can include a sorbent. In some embodiments, the carbonation medium can include calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide). In some embodiments, the carbonation medium can be in a powder form. In some embodiments, the carbonation medium can have any of the properties described in the '910 publication or the '336 publication.|[0032] In some embodiments, the contactor unit 100 can include an air conveyor (not shown), which forces air through the trays and the shelves 144. The air conveyor can include a fan, a louver, and/or any other similar air movement system. In some embodiments, the air conveyor can be attached to the vertical bar 130. In some embodiments, the air conveyor can be attached to the horizontal bar 120.|[0033] FIG. 2 is a block diagram of a distributor 250, according to an embodiment. In some embodiments, the distributor 250 includes a platform 260 with a top portion 270, a bottom portion 280, and an elevation mechanism 290. The top portion 270 can include orifices 272a, 272b (collectively referred to as orifices 272), and an actuator 274. In some embodiments, the top portion 270 can include an optional agitator 276. In some embodiments, the distributor 250 can be the same or substantially similar to the distributor 150, as described above with reference to FIG. 1. Thus, certain aspects of the distributor 250 are not described in greater detail herein.|[0034] In some embodiments, the platform 260 includes the top portion 270 (also referred to as ceiling) as well as the bottom portion 280 (also referred to as floor). In some embodiments, the platform 260 can be hollow, such that it includes a void space between the bottom portion 280 and the top portion 270. In some embodiments, the top portion 270 can include a plurality of bars extending along the top of the platform 260. In some embodiments, the bars can be arranged parallel to each other. In some embodiments, the bars can include hollow conduits for the movement of liquid therethrough. Liquid passes through the top portion 270 and is released from the orifices 272a, 272b in the top portion 270 onto the trays, such that the liquid interacts with the carbonation medium in the trays. The bottom portion 280 supports the trays when they get pulled into the center of the platform 260. In some embodiments, the bottom portion 280 can include a plurality of bars. In some embodiments, the plurality of bars in the bottom portion 280 can be arranged parallel to one another. In some embodiments, a portion of the bars in the bottom portion 280 can be arranged perpendicular to one another.|[0035] In some embodiments, two orifices 272 are included in the top portion 270. In some embodiments, the top portion 270 can include at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, or at least about 90 orifices 272. In some embodiments, the top portion 270 can include no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, or no more than about 2 orifices 272.|[0036] Combinations of the above-referenced numbers of orifices 272 are also possible (e.g., at least about 1 and no more than about 100 or at least about 10 and no more than about 60), inclusive of all values and ranges therebetween. In some embodiments, the top portion 270 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, or about 100 orifices 272. In some embodiments, the orifices 272 can include nozzles. In some embodiments, the nozzles can have variable spray angles. In some embodiments, the nozzles can aim downward and can be adjusted to aim diagonally and/or horizontally. In some embodiments, the orifices 272 can include flat fan nozzles, hollow cone nozzles, full cone nozzles, misting nozzles, solid stream nozzles, air atomizing nozzles, spillback nozzles, eductor nozzles, or any combination thereof.|[0037] In some embodiments, when in use, the total flow rate of liquid through the orifices 372 can be at least about 1 mL/min, at least about 2 mL/min, at least about 3 mL/min, at least about 4 mL/min, at least about 5 mL/min, at least about 6 mL/min, at least about 7 mL/min, at least about 8 mL/min, at least about 9 mL/min, at least about 10 mL/min, at least about 20 mL/min, at least about 30 mL/min, at least about 40 mL/min, at least about 50 mL/min, at least about 60 mL/min, at least about 70 mL/min, at least about 80 mL/min, at least about 90 mL/min, at least about 100 mL/min, at least about 150 mL/min, at least about 200 mL/min, at least about 250 mL/min, at least about 300 mL/min, at least about 350 mL/min, at least about 400 mL/min, or at least about 450 mL/min. In some embodiments, when in use, the total flow rate of liquid through the orifices 272 can be no more than about 500 mL/min, no more than about 450 mL/min, no more than about 400 mL/min, no more than about 350 mL/min, no more than about 300 mL/min, no more than about 250 mL/min, no more than about 200 mL/min, no more than about 150 mL/min, no more than about 150 mL/min, no more than about 100 mL/min, no more than about 90 mL/min, no more than about 80 mL/min, no more than about mL/min, no more than about 60 mL/min, no more than about 50 mL/min, no more than about 40 mL/min, no more than about 30 mL/min, no more than about 20 mL/min, no more than about 10 mL/min, no more than about 9 mL/min, no more than about 8 mL/min, no more than about 7 mL/min, no more than about 6 mL/min, no more than about 5 mL/min, no more than about 4 mL/min, no more than about 3 mL/min, or no more than about 2 mL/min.|[0038] Combinations of the above-referenced flow rates of the liquid through the orifices 272 are also possible (e.g., at least about 1 mL/min and no more than about 500 mL/min or at least about 10 mL/min and no more than about 150 mL/min), inclusive of all values and ranges therebetween. In some embodiments, when in use, the total flow rate of liquid through the orifices 272 can be about 1 mL/min, about 2 mL/min, about 3 mL/min, about 4 mL/min, about mL/min, about 6 mL/min, about 7 mL/min, about 8 mL/min, about 9 mL/min, about 10 mL/min, about 20 mL/min, about 30 mL/min, about 40 mL/min, about 50 mL/min, about 60 mL/min, about 70 mL/min, about 80 mL/min, about 90 mL/min, about 100 mL/min, about 150 mL/min, about 200 mL/min, about 250 mL/min, about 300 mL/min, about 350 mL/min, about 400 mL/min, about 450 mL/min, or about 500 mL/min.|[0039] The actuator 274 engages with trays on either side and transfers the trays into the body of the platform 260. In some embodiments, the actuator 274 can include arms and/or fingers that extend outward to engage with the trays to bring them into the body of the platform 260. In some embodiments, the actuator 274 can be mounted to the top portion 270 of the platform 260. In some embodiments, the actuator 274 engages with trays on two sides. In some embodiments, the actuator 274 can engage with trays on 1 side, 2 sides, 3 sides, 4 sides, or more than 4 sides if the geometric configuration of the distributor 250 and the contactor unit (not shown) allows for such collection. In some embodiments, the platform 260 includes one actuator 274. In some embodiments, the platform 260 can include multiple actuators 274. In some embodiments, the platform 260 can include an actuator for each side of the platform 260. In some embodiments, the platform 260 can include about 1, about 2, about 3, about 4, about about 6, about 7, about 8, about 9, or about 10 actuators 274, inclusive of all values and ranges therebetween.|[0040] In some embodiments, the optional agitator 276 can agitate the carbonation medium in the trays to promote interaction between the liquid and the carbonation medium. In some embodiments, the agitator 276 can include a blade, an impeller, a stirring element, an irrigation element, a stir bar, a vibration element, or any other stirring or agitation mechanism, or combinations thereof. In some embodiments, the agitator 276 is suspended from the top portion 270 of the platform 260. In some embodiments, the agitator 276 can be appended to the bottom portion 280 of the platform 260. For example, the agitator 276 can include a vibration element that makes contact with trays and shakes the trays. In some embodiments, the bottom portion 280 can include a load cell or a scale configured to measure a weight of the tray with the carbonation medium therein. In some embodiments, the bottom portion 280 can include a weighing platform.|[0041] The elevation mechanism 290 aids in moving the platform 260 vertically. In some embodiments, the elevation mechanism 290 can include an engagement mechanism that engages with a cable (e.g., the cable 140) or multiple cables. In some embodiments, the elevation mechanism 290 can include one or more wheels configured to engage with the cable or multiple cables. In some embodiments, the elevation mechanism 290 can engage with vertical bars (e.g., the vertical bars 130). In some embodiments, the elevation mechanism 290 can include one or more wheels that engage with vertical bars. In some embodiments, the elevation mechanism 290 can include a chain driven by a motor. In some embodiments, the elevation mechanism 290 can include a linear actuator driven by a motor.|[0042] FIGS. 3A-3G are illustrations of a contactor unit 300 and various components thereof, according to an embodiment. As shown, the contactor unit 300 includes a frame 310 with horizontal bars 320a, 320b, 320c, 320d (collectively referred to as horizontal bars 320), a filling station 312, a dumping station 314, support bars 325a, 325b (collectively referred to as support bars 325), vertical bars 330a, 330b (collectively referred to as vertical bars 330), cables 340, shelves 344, and a distributor 350. The distributor 350 includes a cable management mechanism 352, mounting brackets 354a, 354b, 354c, 354d (collectively referred to mounting brackets 354), a platform 360 with a top portion 370 and a bottom portion 380, orifices 372a, 372b, 372c, 372d (collectively referred to as orifices 372), an actuator 374 including an arm 375 and a finger or pin 377. In some embodiments, the frame 310, the horizontal bars 320, the vertical bars 330, and the cables 340 can be the same or substantially similar to the frame 110, the horizontal bars 120, the vertical bars 130, and the cables 140, as described above with reference to FIG. 1. In some embodiments, the distributor 350, the platform 360, the top portion 370, the orifices 372, the actuator 374, and the bottom portion 380 can be the same or substantially similar to the distributor 250, the platform 260, the top portion 270, the orifices 272, the actuator 274, and the bottom portion 280, as described above with reference to FIG. 2. Thus, certain aspects of the frame 310, the horizontal bars 320, the vertical bars 330, the cables 340, the distributor 350, the platform 360, the top portion 370, the orifices 372, the actuator 374, and the bottom portion 380 are not described in greater detail herein. FIG. 3A shows the distributor 350 incorporated into the frame 310 and engaging with trays T. FIG. 3B shows the distributor 350 in the frame 310 and the shelf 344 and tray T in greater detail. FIG. 3C shows the distributor 350 in greater detail. FIG. 3D shows the actuator 374 engaging with a tray T. FIG. 3E shows a cross-sectional view of the distributor 350 interacting with the trays T in the frame 310.|[0043] FIG. 3A shows the contactor unit 300 with the distributor 350. The frame 310 includes the base support bars 325 supporting the vertical bars 330 and the horizontal bars 320. The support bars 325 have a breadth significant enough to prevent rocking and loss of balance by the frame 310. In some embodiments, the frame 310 can include the same number of support bars 325 as vertical bars 330. In some embodiments, the frame 310 can include multiple vertical bars 330 attached to each of the support bars 325. As shown, the horizontal bars 320 are oriented in a rectangular pattern. In some embodiments, the horizontal bars 320 can be oriented in a square pattern, a circular pattern, an elliptical pattern, or any other suitable pattern. In some embodiments, the contactor unit 300 can include an intrusion prevention mechanism surrounding the frame 310. In some embodiments, the intrusion prevention mechanism can prevent external influences from contacting the trays T and the distributor(s) 350. In some embodiments, the intrusion prevention mechanism can include a sheet of material that can block wind or rain from intruding or interacting with the carbonation medium in the trays T. In some embodiments, the intrusion prevention mechanism can include a barrier to prevent vandalism. In some embodiments, the intrusion prevention mechanism can include a mesh, a netting, a fence, and/or a chain link fence.|[0044] FIG. 3B shows greater detail of the shelf 344. In some embodiments, the frame 310 can include many shelves 344. The shelf 344 provides support for trays T. The vertical arrangement of the shelves 344 allows material to be stacked vertically, minimizing land area requirements. In some embodiments, each set of the vertical bars 330 can include at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, or at least about 900 shelves 344. In some embodiments, each set of the vertical bars 330 can include no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, or no more than about 3 shelves 344. Combinations of the above-referenced numbers of shelves 344 are also possible (e.g., at least about 2 shelves 344 and no more than about 1,000 shelves 344 or at least about 10 shelves 344 and no more than about 100 shelves 344), inclusive of all values and ranges therebetween. In some embodiments, each of the vertical bars 330 can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, or about 1,000 shelves 344.|[0045] In some embodiments, the shelves 344 can be spaced apart by at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, or at least about 90 cm. In some embodiments, the shelves 344 can be spaced apart by no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, or no more than about 2 cm. Combinations of the above-referenced spacings of the shelves 344 are also possible (e.g., at least about 1 cm and no more than about 1 m or at least about 10 cm and no more than about 50 cm), inclusive of all values and ranges therebetween. In some embodiments, the shelves 344 can be spaced apart by about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, or about 1 m. In some embodiments, the shelves can be spaced apart to allow for the trays T to sit on the shelves 344 with an air gap of at least about 1 mm or at least about 2 mm.|[0046] In some embodiments, the shelves 344 can each have lengths and/or widths of at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, or at least about 4.5 m. In some embodiments, the shelves 344 can each have lengths and/or widths of no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.5 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about cm, or no more than about 20 cm. Combinations of the above-referenced dimensions of the shelves 344 are also possible (e.g., at least about 10 cm and no more than about 5 m or at least about 50 cm and no more than about 4 m), inclusive of all values and ranges therebetween. In some embodiments, the shelve 344 can each have lengths and/or widths of about 10 cm, about cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about cm, about 1 m, about 1.5 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, or about 5 m.|[0047] In some embodiments, the shelves 344 can be composed of plastic, metal, aluminum, stainless steel, or any other weather resistant material. In some embodiments, the shelves 344 can include stiffening features of various patterns, such as horizontal ribbing, diagonal X-ribbing, and/or deep draws to provide structural integrity to the shelves 344. In some embodiments, the shelves 344 can include features such as locating walls and detents to capture the tray T at a specific location. The locating walls can include an elevated border on one or more sides of the shelves 344 (i.e., on one side, two sides, three sides, four sides, etc.). This can effectively create a cavity that matches the exterior shape of the tray T in order to locate the tray T in a horizontal aspect. In some embodiments, the detent can include a threshold at a lower height than the elevated border or the locating walls, such that the detent allows the tray T to pass over the detention, but offers resistance to an undesired collision or an unintentional wall.|[0048] In some embodiments, the carbonation medium held in the trays T can have a thickness of about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 10 mm, about 11 mm, about 12 mm, about 13 mm, about 14 mm, about 15 mm, about 16 mm, about 17 mm, about 18 mm, about 19 mm, or about 20 mm, inclusive of all values and ranges therebetween. In some embodiments, the trays T can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 layers of carbonation medium, inclusive of all values and ranges therebetween.|[0049] In some embodiments, the trays T can each have lengths and/or widths of at least about cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, or at least about 4.5 m. In some embodiments, the trays T can each have lengths and/or widths of no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.5 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, or no more than about 20 cm. Combinations of the above-referenced dimensions of the trays T are also possible (e.g., at least about 10 cm and no more than about 5 m or at least about 50 cm and no more than about 4 m), inclusive of all values and ranges therebetween. In some embodiments, the trays T can each have lengths and/or widths of about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.5 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, or about 5 m.|[0050] In some embodiments, the trays T can have a lip height of at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 1.5 cm, at least about 2 cm, at least about 2.5 cm, at least about 3 cm, at least about 3.5 cm, at least about 4 cm, or at least about 4.5 cm. In some embodiments, the trays T can have a lip height of no more than about 5 cm, no more than about 4.5 cm, no more than about 4 cm, no more than about 3.5 cm, no more than about 3 cm, no more than about 2.5 cm, no more than about 2 cm, no more than about 1.5 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, or no more than about 2 mm. Combinations of the above-referenced lip heights of the trays T are also possible (e.g., at least about 1 mm and no more than about 5 cm or at least about 4 mm and no more than about 3 cm), inclusive of all values and ranges therebetween. In some embodiments, the trays T can have a lip height of about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 1.5 cm, about 2 cm, about 2.5 cm, about 3 cm, about 3.5 cm, about 4 cm, about 4.5 cm, or about 5 cm. In some embodiments, the trays T can have a pattern that allows them to fit directly onto the shelves 344 and inhibit movement of the trays T once in place.|[0051] In some embodiments, the cables 340 can move to elevate and lower the trays T. In some embodiments, the cables 340 can be coupled to an advancement mechanism (not shown) housed in the frame 310 that can advance the cables 340 to elevate and lower the trays T. As shown, the cables 340 include the beads 342 for engagement with the shelves 344. The cables 342 are threaded through holes on the shelves 344 and the shelves 344 rest on top of the beads 342. In some embodiments, the shelves 344 can move vertically to elevate or descend to the same height as the distributor 350. As shown, the cable management mechanism 352 is incorporated into the distributor 350. As shown, the cable management mechanism 352 includes a chain. In some embodiments, the cable management mechanism 352 can include an articulated cable carrier. In some embodiments, the cable management mechanism 352 can include an articulated cable protection device. In some embodiments, the cable management mechanism 352 can include an e-Chain®. The cable management mechanism 352 ensures that the cable 340 is not bent more than its minimal bend radius while the distributor 350 moves vertically. In some embodiments, the minimal bend radius of the cable 340 can be about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, or about 1 m, inclusive of all values and ranges therebetween.|[0052] In some embodiments, the cable(s) 340 can be coupled to a horizontal bracing element (not shown) and/or a diagonal bracing element (not shown). The horizontal and/or diagonal bracing elements can minimize horizontal movement of the cable(s) 340 and prevent disturbance to the trays T and the carbonation medium. In some embodiments, the horizontal and/or diagonal bracing elements can include braces or splints. In some embodiments, the horizontal and/or diagonal bracing elements can be planted in the ground near the frame 310 or under the frame 310. As shown, the contactor unit 300 includes four cables 340 per distributor 350. In some embodiments, the contactor unit 300 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, or about 20 cables 340 per distributor 350, inclusive of all values and ranges therebetween. The cables 340 can be held in tension, minimizing the movement of the cables 340 and the distributor 350. In some embodiments, the cables 340 can include horizontal bracing at bracing intervals. In some embodiments, the bracing intervals can be about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.1 m, about 1.2 m, about 1.3 m, about 1.4 m, or about 1.5 m, inclusive of all values and ranges therebetween. In some embodiments, the cables 340 can include diagonal or X-bracing from the top of the contactor unit 300 to the bottom of the contactor unit 300|[0053] In some embodiments, the distributor 350 can include an elevation mechanism (not shown). In some embodiments, the elevation mechanism can include a motor. In some embodiments, the vertical bars 330 can include one or more counterweights disposed therein. The counterweights are masses that work in the opposite direction of force applied by the distributor 350. By incorporating a counterweight into the vertical bars 330, the loading on the motor in the elevation mechanism can be reduced. For example, while the motor works to elevate the distributor 350, the counterweight moves downward through the vertical bar 330 such that the mass force provided by the counterweight opposes the mass force of the distributor 350, which enables the use of a smaller motor in the elevation mechanism since the total loading on the motor is less than it would be without a counterweight. In other words, use of the counterweight decreases the amount of energy needed to move the distributor 350. In some embodiments, the vertical bars 330 can include one or more fiducials configured to fix heights along the vertically oriented bars, at which the distributor 350 or multiple distributors 350 are fixed while loading the trays T into the distributors 350 and unloading the trays T from the distributors 350.|[0054] FIG. 3C shows the distributor 350 in greater detail. As shown, the distributor 350 includes the orifices 372. As shown the orifices 372 disperse liquid over the trays T with carbonation medium disposed in the trays T. The mounting brackets 354 keep the distributor level when the distributor 350 moves vertically. As shown, the wheels mounting brackets 354 are facing away from a centerline or a center of gravity of the distributor 350. The mounting brackets 354 contact the trays T on either side of the distributor and the trays T act as a backstop that the wheels of the mounting brackets 354 interact with to maintain balance. In some embodiments, the wheels of the mounting brackets 354 can face inward such that the mounting brackets 354 contact the vertical bars 330. In such a configuration, the vertical bars 330 provide a backstop that the wheels of the mounting brackets 354 interact with to maintain balance.|[0055] FIG. 3D shows a detailed interaction between the actuator 374 and a tray T. As shown, the actuator 374 includes the arm 375 and the finger or pin 377 attached to the arm 375. The arm 375 extends outward from the center of the actuator 374 and the finger 377 points downward and is lowered into a hole H in the tray T. In some embodiments, the finger 377 can point upward and the finger 377 can engage with the hole H from below the hole H. As shown, the actuator 374 includes a single finger 377 and the tray T includes a single hole H. In some embodiments, the actuator 374 can include multiple fingers 377 to engage with multiple holes H on the tray T. In some embodiments, the actuator 374 can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 fingers 377, inclusive of all values and ranges therebetween. In some embodiments, the tray can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 holes H, inclusive of all values and ranges therebetween.|[0056] After engaging the tray T, the actuator 374 urges the tray T toward the center of the distributor 350, such that the orifices 372 dispose the liquid onto the tray T. In some embodiments, the arm 375 can extend relative to a stationary actuator 374, such that the finger 377 lines up with the hole H to engage the tray T. In some embodiments, the arm 375 can have a fixed length relative to the center of the actuator 374 and the actuator 374 can move relative to the center of the distributor 350 to engage the tray T. As shown, the actuator 374 includes two arms 375 and two fingers 377. In some embodiments, a first finger can be positioned to engage with a tray on a first side of the distributor 350 and a second finger can be positioned opposite the first finger, such that the second pin can engage with a tray on a second side of the distributor 350, the second side opposite the first side. In some embodiments, the distributor 350 can include multiple actuators 374, and each of the actuators 374 can include a single arm 375 and a single finger 377. In some embodiments, the movement of the distributor 350, the orifices 372, and the actuator 374 can be automated and guided by algorithms.|[0057] FIG. 3E shows a cross-sectional view of the contactor unit 300 with the filling station 312 and the dumping station 314. In use, the distributor 350 migrates trays T from the filling station 312 to dumping station 314. In some embodiments, the distributor 350 can pull trays from the filling station 312 and push them into the dumping station 314. The filling station 312 and the dumping station 314 are optional features that can aid in efficient movement of the trays T. In some embodiments, the contactor unit 300 can include a caddy dock (not shown). The caddy dock can be integrated into the filling station 312 or in close proximity to the filling station 312. The caddy dock can serve as a location where filled trays T can be deposited or docked onto the contactor 300 before the distributor 350 places the trays T within the contactor unit 300.|[0058] In use, a thin layer of carbonation medium is distributed onto each of the trays T in the filling station 312. The distributor 350 transports the tray T from the filling station 312 to a specified location in the contactor unit 300 (e.g., the dumping station 314). In some embodiments, the distributor 350 can move vertically to align the tray T with the desired shelf 344, where the distributor 350 dispenses the tray T onto the shelf 344. In some embodiments, this can be repeated until every shelf 344 has a tray T placed thereon. The distributor 350 then brings trays T into the body of the distributor 350 and processes the trays T (e.g., via addition of water, agitation, and/or other methods) at a frequency that can be dictated by software and a controls algorithm. Processing continues until the carbonation medium reaches a suitable reaction extent. Once the carbonation medium has reacted sufficiently, the distributor 350 can retrieve each tray T individually and move each tray T to the dumping station 314. In the dumping station 314, carbonation medium is removed from each tray T. Each tray T is then sent back to the filling station 312. The collected carbonation medium can then be sent to carbonation plot (e.g., the carbonation plots described in the '336 publication) for carbon capture of ambient air.|[0059] In some embodiments, the filling station 312 can include a feeding mechanism to dispose carbonation medium into the trays T. In some embodiments, the filling station 312 can include a vibrating pan feeder, a rotary doser, and/or linearly translating rolling shafts. In some embodiments, the contactor unit 300 can include equipment to collect material from the trays T. This can include one or more rotating arms to rotate the trays T between about 0 degrees and about 180 degrees, agitators to agitate the carbonation medium in the trays T, and/or a vacuum to vacuum the carbonation medium off of the trays T.|[0060] In some embodiments, the filling station 312 and/or the dumping station 314 can be positioned outside of the contactor unit 300. In some embodiments, the filling station 312 and/or the dumping station 314 can be placed on a moving platform (e.g., an automated guided vehicle) and service multiple contractor units. In such a setup, the distributor 350 can place a tray T in a moving module to fill the tray T with carbonation medium or dump carbonation medium from the tray T, and then the tray T would be placed back into the contactor unit 310. Alternatively, two moving modules (e.g., one filling module and one dumping module) can approach the contractor unit 310, and the distributor 350 can load a full tray T into the dumping module and a full tray from the filling module can move into the distributor 350.|[0061] The design of the contactor unit 300 allows the carbonation medium to contact ambient air, maximizing the exposed surface area of carbonation medium and limiting land usage. The shelf-and-tray configuration of the contactor unit 300 can be absent of forced airflow, rather allowing the carbonation medium to take up CO2 using natural convection across earth's surface (i.e., wind). Additionally, the contactor unit 300 enables processing of carbonation medium periodically, in an automated manner, to maintain elevated CO2 capture (i.e., accelerated carbonation rates). The contactor unit 300 also enables automated filling of carbonation medium into the trays T and automated collection of the carbonation medium from the trays. This enables bulk material movement through the contactor unit 300 rather than individual trays T.|[0062] In some embodiments, the contactor unit 300 can include one or more sensors (not shown). In some embodiments, the sensors can be internal and/or external to the frame 310. In some embodiments, the sensor(s) can be mounted to the frame 310, shelves 344, trays T, vertical bars 330, horizontal bars 320, and/or the distributor 350. In some embodiments, the sensor(s) can include a load cell, a temperature sensor, an air velocity sensor, a humidity sensor, a precipitation sensor, and/or a solar irradiance sensor.|[0063] FIG. 3F shows a detailed view of the shelf 344. As shown, the shelf 344 includes tray alignment features 345 and cable mounting features 343. The tray alignment features 345 allow for secure placement of a tray onto the shelf 344. The tray alignment features 345 can include ridges that fit into grooves on the bottom of a tray. The cable mounting features 343 secure onto the beads 342 of the cables 340. In some embodiments, the cable mounting features 343 can include snap-in features, such that the shelf 344 can snap into the cables 340.|[0064] In some embodiments, the mass of the trays T can be measured on the contactor unit 300 (e.g., while the trays T are suspended from the cables 340 and placed on the shelf 344). For example, a sensor can be placed on the horizontal bars 320, the vertical bars 330, and/or the cables 340 to measure deformation and corresponding weight. In some embodiments, a load cell can be integrated into the distributor 350 to measure the mass of the trays T. In some embodiments, a load cell can be placed on top of a caddy dock. In some embodiments, the load cell can be co-located with a tray T on the shelf 344. In some embodiments, the mass of the trays T can be measured external to the contactor unit 300.|[0065] FIG. 4 shows a network 4000 of contactor units 400a, 400b, 400c, 400d (collectively referred to as contactor units 400), according to an embodiment. As shown, the contactor units 400 include horizontal bars 420, crossbars 421, vertical bars 430, cables 440, shelves 444, and a distributor 450. In some embodiments, the horizontal bars 420, the vertical bars 430, the cables 440, the shelves 444, and the distributor 450 can be the same or substantially similar to the horizontal bars 320, the vertical bars 330, the cables 340, the shelves 344, and the distributor 350, as described above with reference to FIGS. 3A-3E. Thus, certain aspects of the horizontal bars 420, the vertical bars 430, the cables 440, the shelves 444, and the distributor 450 are not described in greater detail herein.|[0066] The crossbars connect the contactor units 400 to one another. A person in shown in FIG. 4 for scale. As shown, the contactor units 400 have a height of about 10 m. In some embodiments, the contactor units 400 can have a height of at least about 1 m, at least about 2 m, at least about 3 m, at least about 4 m, at least about 5 m, at least about 6 m, at least about 7 m, at least about 8 m, at least about 9 m, at least about 10 m, at least about 20 m, at least about m, at least about 40 m, at least about 50 m, at least about 60 m, at least about 70 m, at least about 80 m, or at least about 90 m. In some embodiments, the contactor units 400 can have a height of no more than about 100 m, no more than about 90 m, no more than about 80 m, no more than about 70 m, no more than about 60 m, no more than about 50 m, no more than about m, no more than about 30 m, no more than about 20 m, no more than about 10 m, no more than about 9 m, no more than about 8 m, no more than about 7 m, no more than about 6 m, no more than about 5 m, no more than about 4 m, no more than about 3 m, or no more than about 2 m. Combinations of the above-referenced heights of the contactor units 400 are also possible (e.g., at least about 1 m and no more than about 100 m or at least about 5 m and no more than about 50 m), inclusive of all values and ranges therebetween. In some embodiments, the about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, about 10 m, about 20 m, about 30 m, about 40 m, about 50 m, about 60 m, about 70 m, about m, about 90 m, or about 100 m. At greater heights, the contactor units 400 can include tension bracing to support the frame material of the contactor units 400. In some embodiments, the contactor units 400 can rely on one another for structural support.|[0067] FIG. 5 shows a distributor 550 interacting with vertical bars 530a, 530b (collectively referred to as vertical bars 530) and trays T suspended from cables 540, according to an embodiment. As shown, the distributor 550 includes mounting brackets 554a, 554b, 554c, 554d (collectively referred to as mounting brackets 554), and orifices 572. In some embodiments, the vertical bars 530, the cables 540, the distributor 550, the mounting brackets 554, and the orifices 572 can be the same or substantially similar to the vertical bars 330, the cables 340, the distributor 350, the mounting brackets 354, and the orifices 372, as described above with reference to FIGS. 3A-3E. Thus, certain aspects of the vertical bars 530, the cables 540, the distributor 550, the mounting brackets 554, and the orifices 572 are not described in greater detail herein.|[0068] As shown, the mounting brackets contact the vertical bars 530. The distributor 550 moves vertically up and down the vertical bars 530, and the wheels on the mounting brackets 554 contact the vertical bars 530 to maintain balance in the distributor 550. As shown, the mounting brackets 554 are in a fixed position relative to the distributor 550. As shown, the wheels of the mounting brackets 554 face toward the center of the distributor 550. As shown, the distributor 550 includes 4 mounting brackets 554. In some embodiments, the distributor 550 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, or about 20 mounting brackets 554, inclusive of all values and ranges therebetween.|[0069] FIG. 6 shows a distributor 650, according to an embodiment. As shown, the distributor engages with a cable 640 that supports trays T. In some embodiments, the distributor 650 and the cable 640 can be the same or substantially similar to the distributor 350 and the cable 340, as described above with reference to FIGS. 3A-3E. Thus, certain aspects of the distributor 650 and the cable 640 are not described in greater detail herein. As shown, the distributor 650 includes a position actuator 653. The position actuator 653 defines a position of a shelf (not shown) with respect to the distributor 650 in a horizontal aspect. In some embodiments, the distributor 650 can remain in a fixed position and urge a shelf to move via a dedicated actuator to achieve a desired shelf position. In other words, the position actuator 653 can detect if the distributor is a desired distance from the trays T, such that an actuator (not shown) can reach out and engage with the trays T. In some embodiments, the horizontal position of the distributor 650 can be adjusted if the position actuator 653 detects that the distributor 650 is not in a desired position relative to the trays T. In some embodiments, the position actuator 653 can include a rotary electric motor driving a linear actuation mechanism, including a belt, chain, linkage, leadscrew, ballscrew, and/or any other suitable components. In some embodiments, the position actuator 653 can include a linear electric motor. In some embodiments, the position actuator 653 can include a linear pneumatic cylinder. In some embodiments, a second position actuator (not shown) can facilitate horizontal movement of the distributor 650 to move the distributor 650 to a desired horizontal position.|[0070] FIGS. 7A-7E are illustrations of a shelf 744 and its interactions with cables 740, according to an embodiment. As shown, the cables 740 are suspended from horizontal bars 720a, 720b (collectively referred to as horizontal bars 720). Beads 742 are attached to the cables 740 and provide supports for the shelf 744. The shelf 744 includes cable mounting features 743a, 743b, 743c, 743d (collectively referred to as cable mounting features 743). In some embodiments, the horizontal bars 720, the cables 740, the beads 742, the cable mounting features 743, and the shelf 744 can be the same or substantially similar to the horizontal bars 320, the cables 340, the beads 342, the cable mounting features 343, and the shelf 344, as described above with reference to FIGS. 3A-3G. Thus, certain aspects of the horizontal bars 720, the cables 740, the beads 742, the cable mounting features 743, and the shelf 744 are not described in greater detail herein.|[0071] FIG. 7A shows the interaction between the shelf 744 and the cables 740. As shown, the shelf 744 is suspended from the cables 740 via placement on the beads 742. As shown, four cables 740 are hung from the horizontal bars 720 (with two cables 740 hanging from each of the horizontal bars 720). In some embodiments, the shelf 744 can be supported by about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 cables 740. As shown, the beads 742 are swaged onto the cables 740 at a specific pitch.|[0072] FIG. 7B shows a detailed view of the cable 740. As shown, the beads 742 are swaged onto the cable 740 while cable pucks 749 are positioned over the beads 742 to increase the surface area that the shelf 744 rests upon. In some embodiments, the cable pucks 749 can be snapped into place over the beads 742. As shown, the cable pucks 749 have a round shape with a groove for placement onto the beads 742. In some embodiments, the cable pucks 749 can have a rectangular or square shape. In some embodiments, the cable pucks 749 can have an elliptical shape.|[0073] FIG. 7C shows a profile view of the shelf 744. The design of the shelf 744 can be tailored to optimize for weight, stiffness, durability, and cost. As shown, the horizontal center of the shelf 744 is thicker than the horizontal edges of the shelf 744. This can minimize deflection in the shelf 744 and alleviate concerns associated with pickup of bent trays without requiring significant reinforcing materials.|[0074] In some embodiments, the ratio of the thickness of the shelf 744 at its horizontal center to the thickness of the shelf 744 at its horizontal edges can be at least about 1, at least about 1.1, at least about 1.2, at least about 1.3, at least about 1.4, at least about 1.5, at least about 1.6, at least about 1.7, at least about 1.8, at least about 1.9, at least about 2, at least about 2.5, at least about 3, at least about 3.5, at least about 4, at least about 4.5, at least about 5, at least about at least about 6, at least about 6.5, at least about 7, at least about 7.5, at least about 8, at least about 8.5, at least about 9, or at least about 9.5. In some embodiments, the ratio of the thickness of the shelf 744 at its horizontal center to the thickness of the shelf 744 at its horizontal edges can be no more than about 10, no more than about 9.5, no more than about 9, no more than about 8.5, no more than about 8, no more than about 7.5, no more than about 7, no more than about 6.5, no more than about 6, no more than about 5.5, no more than about 5, no more than about 4.5, no more than about 4, no more than about 3.5, no more than about 3, no more than about 2.5, no more than about 2, no more than about 1.9, no more than about 1.8, no more than about 1.7, no more than about 1.6, no more than about 1.5, no more than about 1.4, no more than about 1.3, no more than about 1.2, or no more than about 1.1. Combinations of the above-referenced ratios are also possible (e.g., at least about 1 and no more than about or at least about 1.5 and no more than about 5), inclusive of all values and ranges therebetween. In some embodiments, the ratio of the thickness of the shelf 744 at its horizontal center to the thickness of the shelf 744 at its horizontal edges can be about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.5, about 3, about 3.5, about 4, about 4.5, about 5, about 5.5, about 6, about 6.5, about 7, about 7.5, about 8, about 8.5, about 9, about 9.5, or about 10.|[0075] FIG. 7D shows a top view of the shelf 744 and the cable mounting features 743. The cable mounting features 743 are designed to simplify installation and removal of the shelf 744 from the stack of shelves. As shown, the cable mounting features 743c, 743d are positioned further from the horizontal center of the shelf 744 than the cable mounting features 743a, 743b. This allows the shelf 744 to be slid into and out of the stack of shelves without releasing tension from the cables 740 or removing any other part of the contactor.|[0076] FIG. 7E shows a tray T positioned on the shelf 744. In some embodiments, the shelf 744 can be composed of acrylonitrile butadiene styrene (ABS) or any other suitable material. In some embodiments, the shelf 744 can be thermoformed. The shelf 744 can have ribs shaped and optimized for ease of manufacturing and reduction of material weight and cost. The trays can be designed to have minimal stiffness while maximizing surface area. In some embodiments, the trays can be designed to maintain uniformity of powder thickness in the tray. In some embodiments, the tray T can rest on the shelf 744 without any interlocking features between the shelf 744 and the tray. Interlocking features can potentially constrain the tray handoff between the distributor and the shelf 744. In some embodiments, the tray T can include radio frequency identification (RFID) stickers that can identify each tray. The trays can accordingly be tracked through software, and the software can store metadata about the trays. In some embodiments, the tray T can include slots machined on its lip that enable pickup and placement between the distributor and the shelf 744 for all tolerance stack-up cases.|[0077] FIG. 8 shows a design of a shelf 844, according to an embodiment. As shown, the tray 844 includes horizontal ribs 841 and cable mounting features 843. In some embodiments, the cable mounting features 843 can be the same or substantially similar to the cable mounting features 743, as described above with reference to FIG. 7A-7E. Thus, certain aspects of the cable mounting features 843 are not described in greater detail herein. As shown, the horizontal ribs 841 enable support of trays placed on the shelf 844 without a large amount of material. The void space of the shelf 844 aids in minimizing the amount of material used to produce the shelf 844. In some embodiments, the tray 844 can be composed of a composite plastic. In some embodiments, the tray 844 can be composed of glass-filled polypropylene.|[0078] FIG. 9 is a block diagram of a method 10 of operating a distributor, according to an embodiment. As shown, the method 10 includes moving the distributor in a vertical direction along a vertically oriented bar at step 11 and fixing a vertical position of the distributor along the vertically oriented bar at step 12. The method 10 optionally includes moving the actuator horizontally away from a centerline of the distributor at step 13. The method 10 further includes securing the actuator to a tray positioned on a shelf at step 14, urging the tray in a horizontal direction toward the centerline of the distributor at step 15, dispensing, via the orifice, a liquid onto the carbonation medium tray at step 16, and urging the tray in a horizontal direction onto the shelf at step 17. The method 10 optionally includes again dispensing the liquid onto the carbonation medium tray at step 18 and disengaging the actuator from the tray and moving the actuator horizontally toward the centerline of the distributor at step 19.|[0079] Step 11 includes moving the distributor in a vertical direction along the vertically oriented bar. In some embodiments, the movement of the distributor can be upward movement. In some embodiments, the movement of the distributor can be downward movement. In some embodiments, the movement of the distributor can be guided by cables attached to the distributor that move the distributor upward and downward. In some embodiments, vertical movement of the distributor can include balancing the distributor via one or more guide wheels. In some embodiments, the distributor can include one or more mounting brackets to orient the guide wheel(s) in a working position.|[0080] Step 12 includes fixing the vertical position of the distributor along the vertically oriented bar. In some embodiments, the fixed vertical position can be such that the distributor is aligned vertically with a shelf in the contactor. In some embodiments, the vertical position of the distributor can be detected by a position encoder. In some embodiments, the position actuator can reach outward from the distributor and the vertical position of the distributor relative to a shelf and/or a tray can be detected via the position actuator. In some embodiments, the vertical position of the distributor can be detected via a global positioning system (GPS) device. In some embodiments, the vertical position of the distributor can be detected via one or more fiducials. In some embodiments, the vertical position of the distributor can be detected via a pressure sensor. In some embodiments, the vertical position of the distributor can be detected via a camera or an optical sensor. In some embodiments, fixing the vertical position of the distributor can be done via a locking or a latching mechanism.|[0081] Step 13 is optional and includes moving the actuator horizontally away from the centerline of the distributor. In some embodiments, the actuator can remain in contact with a top portion of the distributor as it moves away from the centerline of this distributor. Moving the actuator horizontally away from the centerline of the distributor can aid in capturing a tray. The tray can have carbonation medium disposed therein. In some embodiments, the horizontal movement of the actuator can be in a direction toward the tray to capture the tray. In some embodiments, the movement of the actuator can be toward an outer edge of the distributor. In some embodiments, the movement of the actuator can be beyond the outer edge of the distributor. In some embodiments, step 13 can include moving a first actuator or a first portion of the actuator in a first horizontal direction away from the centerline of the distributor and moving a second actuator or a second portion of the actuator in a second direction away from the centerline of the distributor. In some embodiments, the second horizontal direction can form an angle of about 180 degrees with the first horizontal direction.|[0082] Step 14 includes securing the actuator to a tray positioned on a shelf. In some embodiments, the shelf can be suspended from a cable. In some embodiments, the actuator can engage with the tray via an arm and finger mechanism included in the actuator. In some embodiments, the finger of the actuator can engage with a hole in the tray and adjoin the actuator with the tray. In some embodiments, the finger can point downward and the finger can engage with the hole in the tray by first moving horizontally until the finger is positioned over the hole of the tray, and the finger can then be inserted into the hole by lowering the finger into the hole. In some embodiments, step 14 can include securing a first actuator or a first portion of the actuator to a first tray and securing a second actuator or a second portion of the actuator to a second tray. In some embodiments, the second tray can be positioned on an opposite side of the centerline from the first tray.|[0083] Step 15 includes urging the tray in a horizontal direction toward the centerline of the distributor. In other words, the tray is pushed and/or pulled into the body of the distributor. In some embodiments, the tray can slide along the bottom portion of the distributor toward the centerline of the distributor. In some embodiments, the movement of the tray in the horizontal direction can be perpetuated by horizontal movement of the finger relative to the centerline of the distributor. In some embodiments, the movement of the tray in the horizontal direction can be perpetuated by horizontal movement of the actuator relative to the centerline of the distributor. In some embodiments, step 15 can include urging the first tray in a first horizontal direction toward the centerline of the distributor and urging the second tray in a second horizontal direction toward the centerline of the distributor. In some embodiments, the second horizontal direction can form an angle of about 180 degrees with the first horizontal direction.|[0084] Step 16 includes dispensing via one or more orifices, a liquid onto the carbonation medium tray. Upon dispensation, the liquid interacts with carbonation medium in the tray. In some embodiments, the liquid can include water. In some embodiments, the dispensation of the liquid can be via spraying, misting, dripping, pouring, and/or any other suitable means of conveyance of the liquid. In some embodiments, the liquid can be pressurized upon being released from the orifice(s). In some embodiments, the liquid can be at atmospheric pressure upon being released from the orifice(s). In some embodiments, the liquid can be dispensed at an angle of about 5 degrees, about 10 degrees, about 15 degrees, about 20 degrees, about 25 degrees, about 30 degrees, about 35 degrees, about 40 degrees, about 45 degrees, about 50 degrees, about 55 degrees, about 60 degrees, about 65 degrees, about 70 degrees, about 75 degrees, about 80 degrees, about 85 degrees, about 90 degrees relative to a downward vertical direction, inclusive of all values and ranges therebetween. In some embodiments, the liquid can be dispensed at controlled intervals.|[0085] In some embodiments, urging the tray in the horizontal direction toward the centerline of the distributor can occur at least partially concurrent with dispensing the liquid onto the carbonation medium tray. In other words, step 16 can be at least partially concurrent with step 15. In some embodiments, step 16 can be fully concurrent with step 15.|[0086] Step 17 includes urging the tray in a horizontal direction back onto the shelf. After the liquid delivery is completed, they tray is placed back onto a shelf. In some embodiments, the tray can be placed back onto the same shelf it was retrieved from at steps 14-15. In some embodiments, the tray can be placed back onto a different shelf from the shelf it was retrieved from at steps 14-15.|[0087] Step 18 is optional and includes dispensing via the orifice, the liquid onto the carbonation medium tray. The liquid can be dispensed onto the carbonation medium after the tray is back into its original position on the shelf. In some embodiments, the dispensing can be in a horizontal or diagonal direction away from the centerline of the distributor, such that the liquid can fall into the trays and interact with the carbonation medium.|[0088] Step 19 is optional and includes disengaging the actuator from the tray and moving the actuator horizontally toward the centerline of the distributor. In some embodiments, step 19 can include placing the actuator back in its original position. In some embodiments, the actuator can remain in its original position throughout the method 10 and the arm and finger of the actuator can be retracted back toward the centerline of the distributor.|[0089] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0090] In addition, the disclosure may include other innovations not presently described. Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0091] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0092] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0093] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0094] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0095] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of” “only one of” or “exactly one of” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0096] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0097] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0098] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | (US20240009617)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to U.S. Provisional Application No. 63/358,602, filed Jul. 6, 2022 and titled “Direct Air Capture Contactor For Carbon Uptake, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety.|(US20240009617)|TECHNICAL FIELD|[0002] Embodiments described herein relate systems and methods for uptake of carbon dioxide (CO2) from ambient air.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. Inclusion of moisture in air capture medium can improve the uptake of CO2. Efficiency of water delivery to the carbon capture medium affects the overall efficiency of a system employing a carbon capture medium.|SUMMARY|[0004] Embodiments described herein relate to systems, devices, and methods for uptake of CO2 from ambient air. In some aspects, a device can include a platform with a top portion and a bottom portion, an elevation mechanism configured to move the platform vertically, a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray, and an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally. In some embodiments, the bottom portion can support the tray as the tray moves laterally. In some embodiments, the elevation mechanism can include at least one of a chain or a linear actuator driven by a motor. In some embodiments, the tray can include a carbonation medium disposed therein. In some embodiments, the carbonation medium can include at least one of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide).|(US20240009617)|BRIEF DESCRIPTION OF THE DRAWINGS|[0005] FIG. 1 is a block diagram of a contactor unit for direct air capture (DAC), according to an embodiment.|[0006] FIG. 2 is a block diagram of a distributor incorporated into a DAC system, according to an embodiment.|[0007] FIGS. 3A-3G are illustrations of a contactor unit and various components thereof, according to an embodiment.|[0008] FIG. 4 is an illustration of a network of contactor units, according to an embodiment.|[0009] FIG. 5 is an illustration of a distributor, according to an embodiment.|[0010] FIG. 6 is an illustration of a distributor, according to an embodiment.|[0011] FIGS. 7A-7E are illustrations of a shelf and its interactions with cables, according to an embodiment.|[0012] FIG. 8 is an illustration of a shelf, according to an embodiment.|[0013] FIG. 9 is a block diagram of a method of operating a distributor, according to an embodiment.|(US20240009617)|DETAILED DESCRIPTION|[0014] DAC contactors are used to hold, process, distribute, and/or re-collect carbonation medium in a cyclic DAC process. Contactors described herein can hold trays, move trays within a system, process carbonation medium in trays to maintain high CO2 uptake, fill trays, dispense, and/or dispense/collect saturated carbonation medium for regeneration. A fill station of a contactor can distribute a thin layer of capture material onto a tray. The tray is then picked up by a distributor. The distributor can pick up, move, dispense, and process trays and materials. Contactors can include a collection of vertical bars, and the distributors can traverse the bars of the contactor. Processing of carbonation medium can include addition of water to the carbonation medium to improve the CO2 uptake of the carbonation medium.|[0015] Distributors described herein can include mechanisms to pick trays, process trays, and release trays to a specified location inside the contactor. Distributors described herein can also measure weights of trays. In some embodiments, distributors described herein can encase a weighing platform. The processing of the trays can include adding water, agitating the carbonation medium, and/or any other form of processing. The distributor can pick the tray from a tray filling station or tray filling location and use the picking mechanism to move the tray into the body of the distributor. The distributor can then move vertically to align the tray to a proper rack and shelf location on the contactor, where the distributor delivers the tray to the proper location. This can be repeated until each shelf on the contactor has a tray.|[0016] The frequency of the processing of trays can be dictated by software and control algorithms. Processing can continue until the carbonation medium reaches a suitable reaction extent. In some embodiments, processing the trays can include misting a carbonation medium in the trays or other methods for controlled water distribution, or mechanical agitation of the materials. Processing can continue until the carbonation medium reaches a suitable reaction extent. In some embodiments, processing the trays can include misting water onto the carbonation medium in the trays or other methods for controlled water distribution or mechanical agitation of the materials. Processing can continue until the carbonation medium reaches a suitable reaction extent. Once the material has reacted sufficiently, the distributor can pick each tray individually and move it to a collection station. In the collection station, material can be removed from each tray. The tray can then be sent back to the filling station. The collected material can be sent to a regeneration process.|[0017] In some embodiments, the contact between the carbonation medium and the ambient air can include any of the strategies described in U.S. patent application Ser. No. 18/067,896 (“the '897 application”), filed Dec. 19, 2022, and titled, “Systems and Methods of Carbon Capture from Cement Production Processes,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2020/263910 (“the '910 publication”), filed Jun. 24, 2020, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. WO2022187336 (“the '336 publication”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. Benefits of interactions between water and carbonation medium are described in greater detail in the '910 publication and the '336 publication.|[0018] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions. In some embodiments, carbonation plots can include a composition that sequesters a target compound.|[0019] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0020] As used herein, “carbonation medium” refers to a medium that can take on carbon dioxide when exposed to ambient air. This can include but is not limited to calcium oxide (CaO), calcium hydroxide (Ca(OH)2), magnesium oxide (MgO), magnesium hydroxide (MgOH), sodium oxide (Na2O), sodium hydroxide (NaOH), and/or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation medium can originate from a natural source (e.g., limestone). Carbonation medium can also be regenerated or recycled (i.e., a regenerated carbonated medium from a calciner).|[0021] As used herein, “carbonated medium” refers to a carbonation medium that has taken up carbon dioxide from ambient air. This can include but is not limited to calcium carbonate (CaCO3), magnesium carbonate (MgCO3), sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), mixed calcium-magnesium carbonate phases ((Ca,Mg)CO3). Carbonated medium can be converted back to a carbonation medium (e.g., via the use of a calciner, a dissolution/precipitation-based system, and/or an electrochemical system).|[0022] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0023] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0024] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0025] As used herein, the term “about” and “approximately” generally means plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0026] FIG. 1 is a block diagram of a contactor unit 100 for DAC, according to an embodiment. The contactor unit includes a frame 110 having a horizontal bar 120 and a vertical bar 130, a cable 140, and a distributor 150. In some embodiments, the horizontal bar 120 is stacked on top of the vertical bar 130. In some embodiments, the frame 110 can include multiple horizontal bars 120 and/or vertical bars 130. In some embodiments, the frame 110 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, about 20, about 25, about 30, about 35, about 40, about 45, about 50, about 55, about 60, about about 70, about 75, about 80, about 85, about 90, about 95, or about 100 horizontal bars 120 and/or vertical bars 130, inclusive of all values and ranges therebetween.|[0027] In some embodiments, the horizontal bars 120 and/or the vertical bars 130 can include beams. In some embodiments, the horizontal bars 120 and/or the vertical bars 130 can include I-beams (universal beams), hip beams, trussed beams, composite beams, lattice beams, chilled beams, reinforced concrete beams, steel beams, timber beams, curved beams, straight beams, tie beans, cantilever beans, or any other suitable beam type or combinations thereof. In some embodiments, the horizontal bars 120 and/or the vertical bars 130 can be composed of metal, steel, carbon steel, iron, aluminum, stainless steel, laminate wood, timber, or any combination thereof. In some embodiments, multiple horizontal bars 120 can be arranged atop the vertical bars 130 in a geometric pattern (e.g., a square pattern, a rectangular pattern, a curved elliptical pattern, a curved circle pattern, etc.). In some embodiments, the ratio of vertical bars 130 to horizontal bars 120 can be based on the number of supports needed for the distributors 150. In some embodiments, the ratio of horizontal bars to vertical bars can be about 1:10, about 1:9, about 1:8, about 1:7, about 1:6, about 1:5, about 1:4, about 1:3, about 1:2, about 1:1, about 2:1, about 3:1, about 4:1, about 5:1, about 6:1, about 7:1, about 8:1, about 9:1, or about 10:1, inclusive of all values and ranges therebetween.|[0028] In some embodiments, the cable 140 is suspended from the horizontal bar 120. The cable 140 can include beads for engagement with a shelf 144 suspended from the horizontal bar 120. The cable 140 can be robust and taut. In some embodiments, the cable 140 can be composed of steel, carbon steel, non-alloy carbon steel, copper, coated wire rope, or any combination thereof. In some embodiments, the cable 140 can have a thickness of at least about 1 mm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 1.5 cm, at least about 2 cm, at least about 2.5 cm, at least about 3 cm, at least about 3.5 cm, at least about 4 cm, or at least about 4.5 cm. In some embodiments, the cable 140 can have a thickness of no more than about 5 cm, no more than about 4.5 cm, no more than about 4 cm, no more than about 3.5 cm, no more than about 3 cm, no more than about 2.5 cm, no more than about 2 cm, no more than about 1.5 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, or no more than about 2 mm. Combinations of the above-referenced thicknesses of the cable 140 are also possible (e.g., at least about 1 mm and no more than about cm or at least about 5 mm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the cable 140 can have a thickness of about 1 mm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 1.5 cm, about 2 cm, about 2.5 cm, about 3 cm, about 3.5 cm, about 4 cm, about 4.5 cm, or about 5 cm.|[0029] In some embodiments, the beads 142 can be placed along the length of the cable 140 at predetermined spacing intervals. In some embodiments, the beads 142 can be spaced apart at intervals of at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, or at least about 90 cm. In some embodiments, the beads 142 can be spaced apart at intervals of no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, or no more than about 2 cm. Combinations of the above-referenced spacings of the beads 142 are also possible (e.g., at least about 1 cm and no more than about 1 m or at least about 3 cm and no more than about cm), inclusive of all values and ranges therebetween. In some embodiments, the beads 142 can be spaced apart at intervals of about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, or about 1 m.|[0030] In some embodiments, the bead 142 supports the shelf 144. In some embodiments, the shelf 144 can snap, bolt, and/or bond to the bead 142. In some embodiments, multiple shelves 144 can be placed on multiple beads 142. In some embodiments, the shelves 144 can have holes with a larger section and a smaller section, such that the beads 142 can be threaded through the larger sections and moved relative to the hole to be under the smaller sections of the holes. This enables the smaller sections of the holes to support the beads 142 such that the shelves 144 can rest on the beads 142. In some embodiments, the beads 142 can have grooves into which holes on the shelves 144 can fit. In some embodiments, the beads 142 can be distinct pieces of material attached to the cable 140 by crimping, welding, brazing, soldering, adhesive, or any other suitable attachment method or combinations thereof. In some embodiments, a casting or coating can be applied around the outside of the beads 142 and the cable 140 to form a permanent assembly or a permanent connection between the beads 142 and the cable 140. In some embodiments, the casting material can be composed of zinc, tin, aluminum, copper, magnesium, tin, iron, low carbon steel, high carbon steel, white cast iron, gray cast iron, ductile cast iron, or any combination thereof. In some embodiments, the shelves 144 can be removably coupled to the cable 140. In other words, the shelves 144 can be replaceable.|[0031] The distributor 150 collects a tray with the carbonation medium disposed therein and pulls the tray into the body of the distributor 150. In some embodiments, the distributor 150 can move vertically along the vertical bar 130. In some embodiments, the contactor unit 100 can include multiple distributors 150 disposed therein. In some embodiments, the contactor unit 100 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, about 20, about 25, about 30, about 35, about 40, about 45, about 50, about 55, about 60, about 65, about 70, about 75, about 80, about 85, about 90, about 95, or about 100 distributors 150, inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can include a sorbent. In some embodiments, the carbonation medium can include calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide). In some embodiments, the carbonation medium can be in a powder form. In some embodiments, the carbonation medium can have any of the properties described in the '910 publication or the '336 publication.|[0032] In some embodiments, the contactor unit 100 can include an air conveyor (not shown), which forces air through the trays and the shelves 144. The air conveyor can include a fan, a louver, and/or any other similar air movement system. In some embodiments, the air conveyor can be attached to the vertical bar 130. In some embodiments, the air conveyor can be attached to the horizontal bar 120.|[0033] FIG. 2 is a block diagram of a distributor 250, according to an embodiment. In some embodiments, the distributor 250 includes a platform 260 with a top portion 270, a bottom portion 280, and an elevation mechanism 290. The top portion 270 can include orifices 272a, 272b (collectively referred to as orifices 272), and an actuator 274. In some embodiments, the top portion 270 can include an optional agitator 276. In some embodiments, the distributor 250 can be the same or substantially similar to the distributor 150, as described above with reference to FIG. 1. Thus, certain aspects of the distributor 250 are not described in greater detail herein.|[0034] In some embodiments, the platform 260 includes the top portion 270 (also referred to as ceiling) as well as the bottom portion 280 (also referred to as floor). In some embodiments, the platform 260 can be hollow, such that it includes a void space between the bottom portion 280 and the top portion 270. In some embodiments, the top portion 270 can include a plurality of bars extending along the top of the platform 260. In some embodiments, the bars can be arranged parallel to each other. In some embodiments, the bars can include hollow conduits for the movement of liquid therethrough. Liquid passes through the top portion 270 and is released from the orifices 272a, 272b in the top portion 270 onto the trays, such that the liquid interacts with the carbonation medium in the trays. The bottom portion 280 supports the trays when they get pulled into the center of the platform 260. In some embodiments, the bottom portion 280 can include a plurality of bars. In some embodiments, the plurality of bars in the bottom portion 280 can be arranged parallel to one another. In some embodiments, a portion of the bars in the bottom portion 280 can be arranged perpendicular to one another.|[0035] In some embodiments, two orifices 272 are included in the top portion 270. In some embodiments, the top portion 270 can include at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, or at least about 90 orifices 272. In some embodiments, the top portion 270 can include no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, or no more than about 2 orifices 272.|[0036] Combinations of the above-referenced numbers of orifices 272 are also possible (e.g., at least about 1 and no more than about 100 or at least about 10 and no more than about 60), inclusive of all values and ranges therebetween. In some embodiments, the top portion 270 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, or about 100 orifices 272. In some embodiments, the orifices 272 can include nozzles. In some embodiments, the nozzles can have variable spray angles. In some embodiments, the nozzles can aim downward and can be adjusted to aim diagonally and/or horizontally. In some embodiments, the orifices 272 can include flat fan nozzles, hollow cone nozzles, full cone nozzles, misting nozzles, solid stream nozzles, air atomizing nozzles, spillback nozzles, eductor nozzles, or any combination thereof.|[0037] In some embodiments, when in use, the total flow rate of liquid through the orifices 372 can be at least about 1 mL/min, at least about 2 mL/min, at least about 3 mL/min, at least about 4 mL/min, at least about 5 mL/min, at least about 6 mL/min, at least about 7 mL/min, at least about 8 mL/min, at least about 9 mL/min, at least about 10 mL/min, at least about 20 mL/min, at least about 30 mL/min, at least about 40 mL/min, at least about 50 mL/min, at least about 60 mL/min, at least about 70 mL/min, at least about 80 mL/min, at least about 90 mL/min, at least about 100 mL/min, at least about 150 mL/min, at least about 200 mL/min, at least about 250 mL/min, at least about 300 mL/min, at least about 350 mL/min, at least about 400 mL/min, or at least about 450 mL/min. In some embodiments, when in use, the total flow rate of liquid through the orifices 272 can be no more than about 500 mL/min, no more than about 450 mL/min, no more than about 400 mL/min, no more than about 350 mL/min, no more than about 300 mL/min, no more than about 250 mL/min, no more than about 200 mL/min, no more than about 150 mL/min, no more than about 150 mL/min, no more than about 100 mL/min, no more than about 90 mL/min, no more than about 80 mL/min, no more than about mL/min, no more than about 60 mL/min, no more than about 50 mL/min, no more than about 40 mL/min, no more than about 30 mL/min, no more than about 20 mL/min, no more than about 10 mL/min, no more than about 9 mL/min, no more than about 8 mL/min, no more than about 7 mL/min, no more than about 6 mL/min, no more than about 5 mL/min, no more than about 4 mL/min, no more than about 3 mL/min, or no more than about 2 mL/min.|[0038] Combinations of the above-referenced flow rates of the liquid through the orifices 272 are also possible (e.g., at least about 1 mL/min and no more than about 500 mL/min or at least about 10 mL/min and no more than about 150 mL/min), inclusive of all values and ranges therebetween. In some embodiments, when in use, the total flow rate of liquid through the orifices 272 can be about 1 mL/min, about 2 mL/min, about 3 mL/min, about 4 mL/min, about mL/min, about 6 mL/min, about 7 mL/min, about 8 mL/min, about 9 mL/min, about 10 mL/min, about 20 mL/min, about 30 mL/min, about 40 mL/min, about 50 mL/min, about 60 mL/min, about 70 mL/min, about 80 mL/min, about 90 mL/min, about 100 mL/min, about 150 mL/min, about 200 mL/min, about 250 mL/min, about 300 mL/min, about 350 mL/min, about 400 mL/min, about 450 mL/min, or about 500 mL/min.|[0039] The actuator 274 engages with trays on either side and transfers the trays into the body of the platform 260. In some embodiments, the actuator 274 can include arms and/or fingers that extend outward to engage with the trays to bring them into the body of the platform 260. In some embodiments, the actuator 274 can be mounted to the top portion 270 of the platform 260. In some embodiments, the actuator 274 engages with trays on two sides. In some embodiments, the actuator 274 can engage with trays on 1 side, 2 sides, 3 sides, 4 sides, or more than 4 sides if the geometric configuration of the distributor 250 and the contactor unit (not shown) allows for such collection. In some embodiments, the platform 260 includes one actuator 274. In some embodiments, the platform 260 can include multiple actuators 274. In some embodiments, the platform 260 can include an actuator for each side of the platform 260. In some embodiments, the platform 260 can include about 1, about 2, about 3, about 4, about about 6, about 7, about 8, about 9, or about 10 actuators 274, inclusive of all values and ranges therebetween.|[0040] In some embodiments, the optional agitator 276 can agitate the carbonation medium in the trays to promote interaction between the liquid and the carbonation medium. In some embodiments, the agitator 276 can include a blade, an impeller, a stirring element, an irrigation element, a stir bar, a vibration element, or any other stirring or agitation mechanism, or combinations thereof. In some embodiments, the agitator 276 is suspended from the top portion 270 of the platform 260. In some embodiments, the agitator 276 can be appended to the bottom portion 280 of the platform 260. For example, the agitator 276 can include a vibration element that makes contact with trays and shakes the trays. In some embodiments, the bottom portion 280 can include a load cell or a scale configured to measure a weight of the tray with the carbonation medium therein. In some embodiments, the bottom portion 280 can include a weighing platform.|[0041] The elevation mechanism 290 aids in moving the platform 260 vertically. In some embodiments, the elevation mechanism 290 can include an engagement mechanism that engages with a cable (e.g., the cable 140) or multiple cables. In some embodiments, the elevation mechanism 290 can include one or more wheels configured to engage with the cable or multiple cables. In some embodiments, the elevation mechanism 290 can engage with vertical bars (e.g., the vertical bars 130). In some embodiments, the elevation mechanism 290 can include one or more wheels that engage with vertical bars. In some embodiments, the elevation mechanism 290 can include a chain driven by a motor. In some embodiments, the elevation mechanism 290 can include a linear actuator driven by a motor.|[0042] FIGS. 3A-3G are illustrations of a contactor unit 300 and various components thereof, according to an embodiment. As shown, the contactor unit 300 includes a frame 310 with horizontal bars 320a, 320b, 320c, 320d (collectively referred to as horizontal bars 320), a filling station 312, a dumping station 314, support bars 325a, 325b (collectively referred to as support bars 325), vertical bars 330a, 330b (collectively referred to as vertical bars 330), cables 340, shelves 344, and a distributor 350. The distributor 350 includes a cable management mechanism 352, mounting brackets 354a, 354b, 354c, 354d (collectively referred to mounting brackets 354), a platform 360 with a top portion 370 and a bottom portion 380, orifices 372a, 372b, 372c, 372d (collectively referred to as orifices 372), an actuator 374 including an arm 375 and a finger or pin 377. In some embodiments, the frame 310, the horizontal bars 320, the vertical bars 330, and the cables 340 can be the same or substantially similar to the frame 110, the horizontal bars 120, the vertical bars 130, and the cables 140, as described above with reference to FIG. 1. In some embodiments, the distributor 350, the platform 360, the top portion 370, the orifices 372, the actuator 374, and the bottom portion 380 can be the same or substantially similar to the distributor 250, the platform 260, the top portion 270, the orifices 272, the actuator 274, and the bottom portion 280, as described above with reference to FIG. 2. Thus, certain aspects of the frame 310, the horizontal bars 320, the vertical bars 330, the cables 340, the distributor 350, the platform 360, the top portion 370, the orifices 372, the actuator 374, and the bottom portion 380 are not described in greater detail herein. FIG. 3A shows the distributor 350 incorporated into the frame 310 and engaging with trays T. FIG. 3B shows the distributor 350 in the frame 310 and the shelf 344 and tray T in greater detail. FIG. 3C shows the distributor 350 in greater detail. FIG. 3D shows the actuator 374 engaging with a tray T. FIG. 3E shows a cross-sectional view of the distributor 350 interacting with the trays T in the frame 310.|[0043] FIG. 3A shows the contactor unit 300 with the distributor 350. The frame 310 includes the base support bars 325 supporting the vertical bars 330 and the horizontal bars 320. The support bars 325 have a breadth significant enough to prevent rocking and loss of balance by the frame 310. In some embodiments, the frame 310 can include the same number of support bars 325 as vertical bars 330. In some embodiments, the frame 310 can include multiple vertical bars 330 attached to each of the support bars 325. As shown, the horizontal bars 320 are oriented in a rectangular pattern. In some embodiments, the horizontal bars 320 can be oriented in a square pattern, a circular pattern, an elliptical pattern, or any other suitable pattern. In some embodiments, the contactor unit 300 can include an intrusion prevention mechanism surrounding the frame 310. In some embodiments, the intrusion prevention mechanism can prevent external influences from contacting the trays T and the distributor(s) 350. In some embodiments, the intrusion prevention mechanism can include a sheet of material that can block wind or rain from intruding or interacting with the carbonation medium in the trays T. In some embodiments, the intrusion prevention mechanism can include a barrier to prevent vandalism. In some embodiments, the intrusion prevention mechanism can include a mesh, a netting, a fence, and/or a chain link fence.|[0044] FIG. 3B shows greater detail of the shelf 344. In some embodiments, the frame 310 can include many shelves 344. The shelf 344 provides support for trays T. The vertical arrangement of the shelves 344 allows material to be stacked vertically, minimizing land area requirements. In some embodiments, each set of the vertical bars 330 can include at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, or at least about 900 shelves 344. In some embodiments, each set of the vertical bars 330 can include no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, or no more than about 3 shelves 344. Combinations of the above-referenced numbers of shelves 344 are also possible (e.g., at least about 2 shelves 344 and no more than about 1,000 shelves 344 or at least about 10 shelves 344 and no more than about 100 shelves 344), inclusive of all values and ranges therebetween. In some embodiments, each of the vertical bars 330 can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, or about 1,000 shelves 344.|[0045] In some embodiments, the shelves 344 can be spaced apart by at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, or at least about 90 cm. In some embodiments, the shelves 344 can be spaced apart by no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, or no more than about 2 cm. Combinations of the above-referenced spacings of the shelves 344 are also possible (e.g., at least about 1 cm and no more than about 1 m or at least about 10 cm and no more than about 50 cm), inclusive of all values and ranges therebetween. In some embodiments, the shelves 344 can be spaced apart by about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, or about 1 m. In some embodiments, the shelves can be spaced apart to allow for the trays T to sit on the shelves 344 with an air gap of at least about 1 mm or at least about 2 mm.|[0046] In some embodiments, the shelves 344 can each have lengths and/or widths of at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, or at least about 4.5 m. In some embodiments, the shelves 344 can each have lengths and/or widths of no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.5 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about cm, or no more than about 20 cm. Combinations of the above-referenced dimensions of the shelves 344 are also possible (e.g., at least about 10 cm and no more than about 5 m or at least about 50 cm and no more than about 4 m), inclusive of all values and ranges therebetween. In some embodiments, the shelve 344 can each have lengths and/or widths of about 10 cm, about cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about cm, about 1 m, about 1.5 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, or about 5 m.|[0047] In some embodiments, the shelves 344 can be composed of plastic, metal, aluminum, stainless steel, or any other weather resistant material. In some embodiments, the shelves 344 can include stiffening features of various patterns, such as horizontal ribbing, diagonal X-ribbing, and/or deep draws to provide structural integrity to the shelves 344. In some embodiments, the shelves 344 can include features such as locating walls and detents to capture the tray T at a specific location. The locating walls can include an elevated border on one or more sides of the shelves 344 (i.e., on one side, two sides, three sides, four sides, etc.). This can effectively create a cavity that matches the exterior shape of the tray T in order to locate the tray T in a horizontal aspect. In some embodiments, the detent can include a threshold at a lower height than the elevated border or the locating walls, such that the detent allows the tray T to pass over the detention, but offers resistance to an undesired collision or an unintentional wall.|[0048] In some embodiments, the carbonation medium held in the trays T can have a thickness of about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 10 mm, about 11 mm, about 12 mm, about 13 mm, about 14 mm, about 15 mm, about 16 mm, about 17 mm, about 18 mm, about 19 mm, or about 20 mm, inclusive of all values and ranges therebetween. In some embodiments, the trays T can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 layers of carbonation medium, inclusive of all values and ranges therebetween.|[0049] In some embodiments, the trays T can each have lengths and/or widths of at least about cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, or at least about 4.5 m. In some embodiments, the trays T can each have lengths and/or widths of no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.5 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, or no more than about 20 cm. Combinations of the above-referenced dimensions of the trays T are also possible (e.g., at least about 10 cm and no more than about 5 m or at least about 50 cm and no more than about 4 m), inclusive of all values and ranges therebetween. In some embodiments, the trays T can each have lengths and/or widths of about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.5 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, or about 5 m.|[0050] In some embodiments, the trays T can have a lip height of at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 1.5 cm, at least about 2 cm, at least about 2.5 cm, at least about 3 cm, at least about 3.5 cm, at least about 4 cm, or at least about 4.5 cm. In some embodiments, the trays T can have a lip height of no more than about 5 cm, no more than about 4.5 cm, no more than about 4 cm, no more than about 3.5 cm, no more than about 3 cm, no more than about 2.5 cm, no more than about 2 cm, no more than about 1.5 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, or no more than about 2 mm. Combinations of the above-referenced lip heights of the trays T are also possible (e.g., at least about 1 mm and no more than about 5 cm or at least about 4 mm and no more than about 3 cm), inclusive of all values and ranges therebetween. In some embodiments, the trays T can have a lip height of about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 1.5 cm, about 2 cm, about 2.5 cm, about 3 cm, about 3.5 cm, about 4 cm, about 4.5 cm, or about 5 cm. In some embodiments, the trays T can have a pattern that allows them to fit directly onto the shelves 344 and inhibit movement of the trays T once in place.|[0051] In some embodiments, the cables 340 can move to elevate and lower the trays T. In some embodiments, the cables 340 can be coupled to an advancement mechanism (not shown) housed in the frame 310 that can advance the cables 340 to elevate and lower the trays T. As shown, the cables 340 include the beads 342 for engagement with the shelves 344. The cables 342 are threaded through holes on the shelves 344 and the shelves 344 rest on top of the beads 342. In some embodiments, the shelves 344 can move vertically to elevate or descend to the same height as the distributor 350. As shown, the cable management mechanism 352 is incorporated into the distributor 350. As shown, the cable management mechanism 352 includes a chain. In some embodiments, the cable management mechanism 352 can include an articulated cable carrier. In some embodiments, the cable management mechanism 352 can include an articulated cable protection device. In some embodiments, the cable management mechanism 352 can include an e-Chain®. The cable management mechanism 352 ensures that the cable 340 is not bent more than its minimal bend radius while the distributor 350 moves vertically. In some embodiments, the minimal bend radius of the cable 340 can be about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, or about 1 m, inclusive of all values and ranges therebetween.|[0052] In some embodiments, the cable(s) 340 can be coupled to a horizontal bracing element (not shown) and/or a diagonal bracing element (not shown). The horizontal and/or diagonal bracing elements can minimize horizontal movement of the cable(s) 340 and prevent disturbance to the trays T and the carbonation medium. In some embodiments, the horizontal and/or diagonal bracing elements can include braces or splints. In some embodiments, the horizontal and/or diagonal bracing elements can be planted in the ground near the frame 310 or under the frame 310. As shown, the contactor unit 300 includes four cables 340 per distributor 350. In some embodiments, the contactor unit 300 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, or about 20 cables 340 per distributor 350, inclusive of all values and ranges therebetween. The cables 340 can be held in tension, minimizing the movement of the cables 340 and the distributor 350. In some embodiments, the cables 340 can include horizontal bracing at bracing intervals. In some embodiments, the bracing intervals can be about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.1 m, about 1.2 m, about 1.3 m, about 1.4 m, or about 1.5 m, inclusive of all values and ranges therebetween. In some embodiments, the cables 340 can include diagonal or X-bracing from the top of the contactor unit 300 to the bottom of the contactor unit 300|[0053] In some embodiments, the distributor 350 can include an elevation mechanism (not shown). In some embodiments, the elevation mechanism can include a motor. In some embodiments, the vertical bars 330 can include one or more counterweights disposed therein. The counterweights are masses that work in the opposite direction of force applied by the distributor 350. By incorporating a counterweight into the vertical bars 330, the loading on the motor in the elevation mechanism can be reduced. For example, while the motor works to elevate the distributor 350, the counterweight moves downward through the vertical bar 330 such that the mass force provided by the counterweight opposes the mass force of the distributor 350, which enables the use of a smaller motor in the elevation mechanism since the total loading on the motor is less than it would be without a counterweight. In other words, use of the counterweight decreases the amount of energy needed to move the distributor 350. In some embodiments, the vertical bars 330 can include one or more fiducials configured to fix heights along the vertically oriented bars, at which the distributor 350 or multiple distributors 350 are fixed while loading the trays T into the distributors 350 and unloading the trays T from the distributors 350.|[0054] FIG. 3C shows the distributor 350 in greater detail. As shown, the distributor 350 includes the orifices 372. As shown the orifices 372 disperse liquid over the trays T with carbonation medium disposed in the trays T. The mounting brackets 354 keep the distributor level when the distributor 350 moves vertically. As shown, the wheels mounting brackets 354 are facing away from a centerline or a center of gravity of the distributor 350. The mounting brackets 354 contact the trays T on either side of the distributor and the trays T act as a backstop that the wheels of the mounting brackets 354 interact with to maintain balance. In some embodiments, the wheels of the mounting brackets 354 can face inward such that the mounting brackets 354 contact the vertical bars 330. In such a configuration, the vertical bars 330 provide a backstop that the wheels of the mounting brackets 354 interact with to maintain balance.|[0055] FIG. 3D shows a detailed interaction between the actuator 374 and a tray T. As shown, the actuator 374 includes the arm 375 and the finger or pin 377 attached to the arm 375. The arm 375 extends outward from the center of the actuator 374 and the finger 377 points downward and is lowered into a hole H in the tray T. In some embodiments, the finger 377 can point upward and the finger 377 can engage with the hole H from below the hole H. As shown, the actuator 374 includes a single finger 377 and the tray T includes a single hole H. In some embodiments, the actuator 374 can include multiple fingers 377 to engage with multiple holes H on the tray T. In some embodiments, the actuator 374 can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 fingers 377, inclusive of all values and ranges therebetween. In some embodiments, the tray can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 holes H, inclusive of all values and ranges therebetween.|[0056] After engaging the tray T, the actuator 374 urges the tray T toward the center of the distributor 350, such that the orifices 372 dispose the liquid onto the tray T. In some embodiments, the arm 375 can extend relative to a stationary actuator 374, such that the finger 377 lines up with the hole H to engage the tray T. In some embodiments, the arm 375 can have a fixed length relative to the center of the actuator 374 and the actuator 374 can move relative to the center of the distributor 350 to engage the tray T. As shown, the actuator 374 includes two arms 375 and two fingers 377. In some embodiments, a first finger can be positioned to engage with a tray on a first side of the distributor 350 and a second finger can be positioned opposite the first finger, such that the second pin can engage with a tray on a second side of the distributor 350, the second side opposite the first side. In some embodiments, the distributor 350 can include multiple actuators 374, and each of the actuators 374 can include a single arm 375 and a single finger 377. In some embodiments, the movement of the distributor 350, the orifices 372, and the actuator 374 can be automated and guided by algorithms.|[0057] FIG. 3E shows a cross-sectional view of the contactor unit 300 with the filling station 312 and the dumping station 314. In use, the distributor 350 migrates trays T from the filling station 312 to dumping station 314. In some embodiments, the distributor 350 can pull trays from the filling station 312 and push them into the dumping station 314. The filling station 312 and the dumping station 314 are optional features that can aid in efficient movement of the trays T. In some embodiments, the contactor unit 300 can include a caddy dock (not shown). The caddy dock can be integrated into the filling station 312 or in close proximity to the filling station 312. The caddy dock can serve as a location where filled trays T can be deposited or docked onto the contactor 300 before the distributor 350 places the trays T within the contactor unit 300.|[0058] In use, a thin layer of carbonation medium is distributed onto each of the trays T in the filling station 312. The distributor 350 transports the tray T from the filling station 312 to a specified location in the contactor unit 300 (e.g., the dumping station 314). In some embodiments, the distributor 350 can move vertically to align the tray T with the desired shelf 344, where the distributor 350 dispenses the tray T onto the shelf 344. In some embodiments, this can be repeated until every shelf 344 has a tray T placed thereon. The distributor 350 then brings trays T into the body of the distributor 350 and processes the trays T (e.g., via addition of water, agitation, and/or other methods) at a frequency that can be dictated by software and a controls algorithm. Processing continues until the carbonation medium reaches a suitable reaction extent. Once the carbonation medium has reacted sufficiently, the distributor 350 can retrieve each tray T individually and move each tray T to the dumping station 314. In the dumping station 314, carbonation medium is removed from each tray T. Each tray T is then sent back to the filling station 312. The collected carbonation medium can then be sent to carbonation plot (e.g., the carbonation plots described in the '336 publication) for carbon capture of ambient air.|[0059] In some embodiments, the filling station 312 can include a feeding mechanism to dispose carbonation medium into the trays T. In some embodiments, the filling station 312 can include a vibrating pan feeder, a rotary doser, and/or linearly translating rolling shafts. In some embodiments, the contactor unit 300 can include equipment to collect material from the trays T. This can include one or more rotating arms to rotate the trays T between about 0 degrees and about 180 degrees, agitators to agitate the carbonation medium in the trays T, and/or a vacuum to vacuum the carbonation medium off of the trays T.|[0060] In some embodiments, the filling station 312 and/or the dumping station 314 can be positioned outside of the contactor unit 300. In some embodiments, the filling station 312 and/or the dumping station 314 can be placed on a moving platform (e.g., an automated guided vehicle) and service multiple contractor units. In such a setup, the distributor 350 can place a tray T in a moving module to fill the tray T with carbonation medium or dump carbonation medium from the tray T, and then the tray T would be placed back into the contactor unit 310. Alternatively, two moving modules (e.g., one filling module and one dumping module) can approach the contractor unit 310, and the distributor 350 can load a full tray T into the dumping module and a full tray from the filling module can move into the distributor 350.|[0061] The design of the contactor unit 300 allows the carbonation medium to contact ambient air, maximizing the exposed surface area of carbonation medium and limiting land usage. The shelf-and-tray configuration of the contactor unit 300 can be absent of forced airflow, rather allowing the carbonation medium to take up CO2 using natural convection across earth's surface (i.e., wind). Additionally, the contactor unit 300 enables processing of carbonation medium periodically, in an automated manner, to maintain elevated CO2 capture (i.e., accelerated carbonation rates). The contactor unit 300 also enables automated filling of carbonation medium into the trays T and automated collection of the carbonation medium from the trays. This enables bulk material movement through the contactor unit 300 rather than individual trays T.|[0062] In some embodiments, the contactor unit 300 can include one or more sensors (not shown). In some embodiments, the sensors can be internal and/or external to the frame 310. In some embodiments, the sensor(s) can be mounted to the frame 310, shelves 344, trays T, vertical bars 330, horizontal bars 320, and/or the distributor 350. In some embodiments, the sensor(s) can include a load cell, a temperature sensor, an air velocity sensor, a humidity sensor, a precipitation sensor, and/or a solar irradiance sensor.|[0063] FIG. 3F shows a detailed view of the shelf 344. As shown, the shelf 344 includes tray alignment features 345 and cable mounting features 343. The tray alignment features 345 allow for secure placement of a tray onto the shelf 344. The tray alignment features 345 can include ridges that fit into grooves on the bottom of a tray. The cable mounting features 343 secure onto the beads 342 of the cables 340. In some embodiments, the cable mounting features 343 can include snap-in features, such that the shelf 344 can snap into the cables 340.|[0064] In some embodiments, the mass of the trays T can be measured on the contactor unit 300 (e.g., while the trays T are suspended from the cables 340 and placed on the shelf 344). For example, a sensor can be placed on the horizontal bars 320, the vertical bars 330, and/or the cables 340 to measure deformation and corresponding weight. In some embodiments, a load cell can be integrated into the distributor 350 to measure the mass of the trays T. In some embodiments, a load cell can be placed on top of a caddy dock. In some embodiments, the load cell can be co-located with a tray T on the shelf 344. In some embodiments, the mass of the trays T can be measured external to the contactor unit 300.|[0065] FIG. 4 shows a network 4000 of contactor units 400a, 400b, 400c, 400d (collectively referred to as contactor units 400), according to an embodiment. As shown, the contactor units 400 include horizontal bars 420, crossbars 421, vertical bars 430, cables 440, shelves 444, and a distributor 450. In some embodiments, the horizontal bars 420, the vertical bars 430, the cables 440, the shelves 444, and the distributor 450 can be the same or substantially similar to the horizontal bars 320, the vertical bars 330, the cables 340, the shelves 344, and the distributor 350, as described above with reference to FIGS. 3A-3E. Thus, certain aspects of the horizontal bars 420, the vertical bars 430, the cables 440, the shelves 444, and the distributor 450 are not described in greater detail herein.|[0066] The crossbars connect the contactor units 400 to one another. A person in shown in FIG. 4 for scale. As shown, the contactor units 400 have a height of about 10 m. In some embodiments, the contactor units 400 can have a height of at least about 1 m, at least about 2 m, at least about 3 m, at least about 4 m, at least about 5 m, at least about 6 m, at least about 7 m, at least about 8 m, at least about 9 m, at least about 10 m, at least about 20 m, at least about m, at least about 40 m, at least about 50 m, at least about 60 m, at least about 70 m, at least about 80 m, or at least about 90 m. In some embodiments, the contactor units 400 can have a height of no more than about 100 m, no more than about 90 m, no more than about 80 m, no more than about 70 m, no more than about 60 m, no more than about 50 m, no more than about m, no more than about 30 m, no more than about 20 m, no more than about 10 m, no more than about 9 m, no more than about 8 m, no more than about 7 m, no more than about 6 m, no more than about 5 m, no more than about 4 m, no more than about 3 m, or no more than about 2 m. Combinations of the above-referenced heights of the contactor units 400 are also possible (e.g., at least about 1 m and no more than about 100 m or at least about 5 m and no more than about 50 m), inclusive of all values and ranges therebetween. In some embodiments, the about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, about 10 m, about 20 m, about 30 m, about 40 m, about 50 m, about 60 m, about 70 m, about m, about 90 m, or about 100 m. At greater heights, the contactor units 400 can include tension bracing to support the frame material of the contactor units 400. In some embodiments, the contactor units 400 can rely on one another for structural support.|[0067] FIG. 5 shows a distributor 550 interacting with vertical bars 530a, 530b (collectively referred to as vertical bars 530) and trays T suspended from cables 540, according to an embodiment. As shown, the distributor 550 includes mounting brackets 554a, 554b, 554c, 554d (collectively referred to as mounting brackets 554), and orifices 572. In some embodiments, the vertical bars 530, the cables 540, the distributor 550, the mounting brackets 554, and the orifices 572 can be the same or substantially similar to the vertical bars 330, the cables 340, the distributor 350, the mounting brackets 354, and the orifices 372, as described above with reference to FIGS. 3A-3E. Thus, certain aspects of the vertical bars 530, the cables 540, the distributor 550, the mounting brackets 554, and the orifices 572 are not described in greater detail herein.|[0068] As shown, the mounting brackets contact the vertical bars 530. The distributor 550 moves vertically up and down the vertical bars 530, and the wheels on the mounting brackets 554 contact the vertical bars 530 to maintain balance in the distributor 550. As shown, the mounting brackets 554 are in a fixed position relative to the distributor 550. As shown, the wheels of the mounting brackets 554 face toward the center of the distributor 550. As shown, the distributor 550 includes 4 mounting brackets 554. In some embodiments, the distributor 550 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 11, about 12, about 13, about 14, about 15, about 16, about 17, about 18, about 19, or about 20 mounting brackets 554, inclusive of all values and ranges therebetween.|[0069] FIG. 6 shows a distributor 650, according to an embodiment. As shown, the distributor engages with a cable 640 that supports trays T. In some embodiments, the distributor 650 and the cable 640 can be the same or substantially similar to the distributor 350 and the cable 340, as described above with reference to FIGS. 3A-3E. Thus, certain aspects of the distributor 650 and the cable 640 are not described in greater detail herein. As shown, the distributor 650 includes a position actuator 653. The position actuator 653 defines a position of a shelf (not shown) with respect to the distributor 650 in a horizontal aspect. In some embodiments, the distributor 650 can remain in a fixed position and urge a shelf to move via a dedicated actuator to achieve a desired shelf position. In other words, the position actuator 653 can detect if the distributor is a desired distance from the trays T, such that an actuator (not shown) can reach out and engage with the trays T. In some embodiments, the horizontal position of the distributor 650 can be adjusted if the position actuator 653 detects that the distributor 650 is not in a desired position relative to the trays T. In some embodiments, the position actuator 653 can include a rotary electric motor driving a linear actuation mechanism, including a belt, chain, linkage, leadscrew, ballscrew, and/or any other suitable components. In some embodiments, the position actuator 653 can include a linear electric motor. In some embodiments, the position actuator 653 can include a linear pneumatic cylinder. In some embodiments, a second position actuator (not shown) can facilitate horizontal movement of the distributor 650 to move the distributor 650 to a desired horizontal position.|[0070] FIGS. 7A-7E are illustrations of a shelf 744 and its interactions with cables 740, according to an embodiment. As shown, the cables 740 are suspended from horizontal bars 720a, 720b (collectively referred to as horizontal bars 720). Beads 742 are attached to the cables 740 and provide supports for the shelf 744. The shelf 744 includes cable mounting features 743a, 743b, 743c, 743d (collectively referred to as cable mounting features 743). In some embodiments, the horizontal bars 720, the cables 740, the beads 742, the cable mounting features 743, and the shelf 744 can be the same or substantially similar to the horizontal bars 320, the cables 340, the beads 342, the cable mounting features 343, and the shelf 344, as described above with reference to FIGS. 3A-3G. Thus, certain aspects of the horizontal bars 720, the cables 740, the beads 742, the cable mounting features 743, and the shelf 744 are not described in greater detail herein.|[0071] FIG. 7A shows the interaction between the shelf 744 and the cables 740. As shown, the shelf 744 is suspended from the cables 740 via placement on the beads 742. As shown, four cables 740 are hung from the horizontal bars 720 (with two cables 740 hanging from each of the horizontal bars 720). In some embodiments, the shelf 744 can be supported by about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, or about 10 cables 740. As shown, the beads 742 are swaged onto the cables 740 at a specific pitch.|[0072] FIG. 7B shows a detailed view of the cable 740. As shown, the beads 742 are swaged onto the cable 740 while cable pucks 749 are positioned over the beads 742 to increase the surface area that the shelf 744 rests upon. In some embodiments, the cable pucks 749 can be snapped into place over the beads 742. As shown, the cable pucks 749 have a round shape with a groove for placement onto the beads 742. In some embodiments, the cable pucks 749 can have a rectangular or square shape. In some embodiments, the cable pucks 749 can have an elliptical shape.|[0073] FIG. 7C shows a profile view of the shelf 744. The design of the shelf 744 can be tailored to optimize for weight, stiffness, durability, and cost. As shown, the horizontal center of the shelf 744 is thicker than the horizontal edges of the shelf 744. This can minimize deflection in the shelf 744 and alleviate concerns associated with pickup of bent trays without requiring significant reinforcing materials.|[0074] In some embodiments, the ratio of the thickness of the shelf 744 at its horizontal center to the thickness of the shelf 744 at its horizontal edges can be at least about 1, at least about 1.1, at least about 1.2, at least about 1.3, at least about 1.4, at least about 1.5, at least about 1.6, at least about 1.7, at least about 1.8, at least about 1.9, at least about 2, at least about 2.5, at least about 3, at least about 3.5, at least about 4, at least about 4.5, at least about 5, at least about at least about 6, at least about 6.5, at least about 7, at least about 7.5, at least about 8, at least about 8.5, at least about 9, or at least about 9.5. In some embodiments, the ratio of the thickness of the shelf 744 at its horizontal center to the thickness of the shelf 744 at its horizontal edges can be no more than about 10, no more than about 9.5, no more than about 9, no more than about 8.5, no more than about 8, no more than about 7.5, no more than about 7, no more than about 6.5, no more than about 6, no more than about 5.5, no more than about 5, no more than about 4.5, no more than about 4, no more than about 3.5, no more than about 3, no more than about 2.5, no more than about 2, no more than about 1.9, no more than about 1.8, no more than about 1.7, no more than about 1.6, no more than about 1.5, no more than about 1.4, no more than about 1.3, no more than about 1.2, or no more than about 1.1. Combinations of the above-referenced ratios are also possible (e.g., at least about 1 and no more than about or at least about 1.5 and no more than about 5), inclusive of all values and ranges therebetween. In some embodiments, the ratio of the thickness of the shelf 744 at its horizontal center to the thickness of the shelf 744 at its horizontal edges can be about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.5, about 3, about 3.5, about 4, about 4.5, about 5, about 5.5, about 6, about 6.5, about 7, about 7.5, about 8, about 8.5, about 9, about 9.5, or about 10.|[0075] FIG. 7D shows a top view of the shelf 744 and the cable mounting features 743. The cable mounting features 743 are designed to simplify installation and removal of the shelf 744 from the stack of shelves. As shown, the cable mounting features 743c, 743d are positioned further from the horizontal center of the shelf 744 than the cable mounting features 743a, 743b. This allows the shelf 744 to be slid into and out of the stack of shelves without releasing tension from the cables 740 or removing any other part of the contactor.|[0076] FIG. 7E shows a tray T positioned on the shelf 744. In some embodiments, the shelf 744 can be composed of acrylonitrile butadiene styrene (ABS) or any other suitable material. In some embodiments, the shelf 744 can be thermoformed. The shelf 744 can have ribs shaped and optimized for ease of manufacturing and reduction of material weight and cost. The trays can be designed to have minimal stiffness while maximizing surface area. In some embodiments, the trays can be designed to maintain uniformity of powder thickness in the tray. In some embodiments, the tray T can rest on the shelf 744 without any interlocking features between the shelf 744 and the tray. Interlocking features can potentially constrain the tray handoff between the distributor and the shelf 744. In some embodiments, the tray T can include radio frequency identification (RFID) stickers that can identify each tray. The trays can accordingly be tracked through software, and the software can store metadata about the trays. In some embodiments, the tray T can include slots machined on its lip that enable pickup and placement between the distributor and the shelf 744 for all tolerance stack-up cases.|[0077] FIG. 8 shows a design of a shelf 844, according to an embodiment. As shown, the tray 844 includes horizontal ribs 841 and cable mounting features 843. In some embodiments, the cable mounting features 843 can be the same or substantially similar to the cable mounting features 743, as described above with reference to FIG. 7A-7E. Thus, certain aspects of the cable mounting features 843 are not described in greater detail herein. As shown, the horizontal ribs 841 enable support of trays placed on the shelf 844 without a large amount of material. The void space of the shelf 844 aids in minimizing the amount of material used to produce the shelf 844. In some embodiments, the tray 844 can be composed of a composite plastic. In some embodiments, the tray 844 can be composed of glass-filled polypropylene.|[0078] FIG. 9 is a block diagram of a method 10 of operating a distributor, according to an embodiment. As shown, the method 10 includes moving the distributor in a vertical direction along a vertically oriented bar at step 11 and fixing a vertical position of the distributor along the vertically oriented bar at step 12. The method 10 optionally includes moving the actuator horizontally away from a centerline of the distributor at step 13. The method 10 further includes securing the actuator to a tray positioned on a shelf at step 14, urging the tray in a horizontal direction toward the centerline of the distributor at step 15, dispensing, via the orifice, a liquid onto the carbonation medium tray at step 16, and urging the tray in a horizontal direction onto the shelf at step 17. The method 10 optionally includes again dispensing the liquid onto the carbonation medium tray at step 18 and disengaging the actuator from the tray and moving the actuator horizontally toward the centerline of the distributor at step 19.|[0079] Step 11 includes moving the distributor in a vertical direction along the vertically oriented bar. In some embodiments, the movement of the distributor can be upward movement. In some embodiments, the movement of the distributor can be downward movement. In some embodiments, the movement of the distributor can be guided by cables attached to the distributor that move the distributor upward and downward. In some embodiments, vertical movement of the distributor can include balancing the distributor via one or more guide wheels. In some embodiments, the distributor can include one or more mounting brackets to orient the guide wheel(s) in a working position.|[0080] Step 12 includes fixing the vertical position of the distributor along the vertically oriented bar. In some embodiments, the fixed vertical position can be such that the distributor is aligned vertically with a shelf in the contactor. In some embodiments, the vertical position of the distributor can be detected by a position encoder. In some embodiments, the position actuator can reach outward from the distributor and the vertical position of the distributor relative to a shelf and/or a tray can be detected via the position actuator. In some embodiments, the vertical position of the distributor can be detected via a global positioning system (GPS) device. In some embodiments, the vertical position of the distributor can be detected via one or more fiducials. In some embodiments, the vertical position of the distributor can be detected via a pressure sensor. In some embodiments, the vertical position of the distributor can be detected via a camera or an optical sensor. In some embodiments, fixing the vertical position of the distributor can be done via a locking or a latching mechanism.|[0081] Step 13 is optional and includes moving the actuator horizontally away from the centerline of the distributor. In some embodiments, the actuator can remain in contact with a top portion of the distributor as it moves away from the centerline of this distributor. Moving the actuator horizontally away from the centerline of the distributor can aid in capturing a tray. The tray can have carbonation medium disposed therein. In some embodiments, the horizontal movement of the actuator can be in a direction toward the tray to capture the tray. In some embodiments, the movement of the actuator can be toward an outer edge of the distributor. In some embodiments, the movement of the actuator can be beyond the outer edge of the distributor. In some embodiments, step 13 can include moving a first actuator or a first portion of the actuator in a first horizontal direction away from the centerline of the distributor and moving a second actuator or a second portion of the actuator in a second direction away from the centerline of the distributor. In some embodiments, the second horizontal direction can form an angle of about 180 degrees with the first horizontal direction.|[0082] Step 14 includes securing the actuator to a tray positioned on a shelf. In some embodiments, the shelf can be suspended from a cable. In some embodiments, the actuator can engage with the tray via an arm and finger mechanism included in the actuator. In some embodiments, the finger of the actuator can engage with a hole in the tray and adjoin the actuator with the tray. In some embodiments, the finger can point downward and the finger can engage with the hole in the tray by first moving horizontally until the finger is positioned over the hole of the tray, and the finger can then be inserted into the hole by lowering the finger into the hole. In some embodiments, step 14 can include securing a first actuator or a first portion of the actuator to a first tray and securing a second actuator or a second portion of the actuator to a second tray. In some embodiments, the second tray can be positioned on an opposite side of the centerline from the first tray.|[0083] Step 15 includes urging the tray in a horizontal direction toward the centerline of the distributor. In other words, the tray is pushed and/or pulled into the body of the distributor. In some embodiments, the tray can slide along the bottom portion of the distributor toward the centerline of the distributor. In some embodiments, the movement of the tray in the horizontal direction can be perpetuated by horizontal movement of the finger relative to the centerline of the distributor. In some embodiments, the movement of the tray in the horizontal direction can be perpetuated by horizontal movement of the actuator relative to the centerline of the distributor. In some embodiments, step 15 can include urging the first tray in a first horizontal direction toward the centerline of the distributor and urging the second tray in a second horizontal direction toward the centerline of the distributor. In some embodiments, the second horizontal direction can form an angle of about 180 degrees with the first horizontal direction.|[0084] Step 16 includes dispensing via one or more orifices, a liquid onto the carbonation medium tray. Upon dispensation, the liquid interacts with carbonation medium in the tray. In some embodiments, the liquid can include water. In some embodiments, the dispensation of the liquid can be via spraying, misting, dripping, pouring, and/or any other suitable means of conveyance of the liquid. In some embodiments, the liquid can be pressurized upon being released from the orifice(s). In some embodiments, the liquid can be at atmospheric pressure upon being released from the orifice(s). In some embodiments, the liquid can be dispensed at an angle of about 5 degrees, about 10 degrees, about 15 degrees, about 20 degrees, about 25 degrees, about 30 degrees, about 35 degrees, about 40 degrees, about 45 degrees, about 50 degrees, about 55 degrees, about 60 degrees, about 65 degrees, about 70 degrees, about 75 degrees, about 80 degrees, about 85 degrees, about 90 degrees relative to a downward vertical direction, inclusive of all values and ranges therebetween. In some embodiments, the liquid can be dispensed at controlled intervals.|[0085] In some embodiments, urging the tray in the horizontal direction toward the centerline of the distributor can occur at least partially concurrent with dispensing the liquid onto the carbonation medium tray. In other words, step 16 can be at least partially concurrent with step 15. In some embodiments, step 16 can be fully concurrent with step 15.|[0086] Step 17 includes urging the tray in a horizontal direction back onto the shelf. After the liquid delivery is completed, they tray is placed back onto a shelf. In some embodiments, the tray can be placed back onto the same shelf it was retrieved from at steps 14-15. In some embodiments, the tray can be placed back onto a different shelf from the shelf it was retrieved from at steps 14-15.|[0087] Step 18 is optional and includes dispensing via the orifice, the liquid onto the carbonation medium tray. The liquid can be dispensed onto the carbonation medium after the tray is back into its original position on the shelf. In some embodiments, the dispensing can be in a horizontal or diagonal direction away from the centerline of the distributor, such that the liquid can fall into the trays and interact with the carbonation medium.|[0088] Step 19 is optional and includes disengaging the actuator from the tray and moving the actuator horizontally toward the centerline of the distributor. In some embodiments, step 19 can include placing the actuator back in its original position. In some embodiments, the actuator can remain in its original position throughout the method 10 and the arm and finger of the actuator can be retracted back toward the centerline of the distributor.|[0089] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0090] In addition, the disclosure may include other innovations not presently described. Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0091] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0092] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0093] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0094] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0095] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of” “only one of” or “exactly one of” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0096] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0097] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0098] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | Family Number|(108035748)|108035748|Advantages / Prev. Drawbacks|(US20240009617 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(WO202411170 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(AU2023303026 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(IN202517003741 A)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(JP2025522936 A)| (...) from the atmosphere, some of which include: These include acceleration of natural processes such as the uptake of CO_2 into the oceans and land biospheres (soil, forests, and minerals), bioenergy (bioenergy with carbon capture and storage, BECCS) with carbon collection and storage, and synthetic approaches using chemical substances, also known as direct air collection (direct air capture with storage, DACS) technologies with storage.|(CN120390667 A)|( . . . ) can purge current and future CO _ 2 emissions from the atmosphere , some of which include accelerating natural processes such as intake of CO _ 2 by marine and land biospheres ( soil , forests , minerals ) , bioenergy and carbon capture and storage ( BECCS ) , and synthetic methods using chemicals , also known as Direct Air Capture and Storage ( DACS ) technologies . | | Chemical engineering|Environmental technology | B01D-001/00/64|B01D-001/00/7|B01D-003/00/8|B01D-003/00/9|B01D-003/14|B01D-003/16|B01D-003/20|B01D-003/26|B01D-003/32|B01D-003/32/4|B01D-003/32/6|B01D-053/04/07|B01D-053/14|B01D-053/14/06|B01D-053/14/56|B01D-053/14/68|B01D-053/14/75|B01D-053/18|B01D-053/18/5|B01D-053/62|B01D-053/78|B01D-2251/304|B01D-2251/402|B01D-2251/404|B01D-2251/602|B01D-2251/604|B01D-2252/103|B01D-2257/504|B01D-2258/06|B01J-004/00/2|B01J-019/30|B01J-019/30/5|B01J-019/32|B01J-019/32/5 | 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WO2020239185|WO202098890|US20200187427|US11014043|US20150282437|WO2022187336|WO2020263910 | WO2020239185 91739823 WHO=Examiner SELF=N CAT=X CAT=I|WO202098890 87441322 WHO=Examiner SELF=N CAT=X CAT=I|US20200187427 89297476 WHO=Examiner SELF=N CAT=A|US11014043 78002851 WHO=Examiner SELF=N CAT=A|US20150282437 66607886 WHO=Examiner SELF=N CAT=A|WO2022187336 101683925 WHO=Applicant SELF=N|WO2020263910 92128920 WHO=Applicant SELF=N | WO202098890; WO2020239185; US11014043; US20200187427; US20150282437; WO2020263910; WO2022187336||||||| | ||(WO2024/011170)|Applicant references|||||| | PENDING | (EP4551306)|PENDING|(US20240009617)|PENDING|(WO2024/011170)|LAPSED|(JP2025522936)|PENDING|(CN120390667)|PENDING|(IN202517003741)|PENDING|(AU2023303026)|PENDING|(CA3261222)|PENDING | ALIVE | (EP4551306)|ALIVE|(US20240009617)|ALIVE|(WO2024/011170)|DEAD|(JP2025522936)|ALIVE|(CN120390667)|ALIVE|(IN202517003741)|ALIVE|(AU2023303026)|ALIVE|(CA3261222)|ALIVE | (EP4551306)|LEGAL DETAILS FOR EP4551306|Actual or 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GT, PA, PE, PG, PH, PL | (EP4551306)|EP|(US20240009617)|US|(WO2024/011170)|AU; CA; CN; EP; IN; JP|(JP2025522936)|JP|(CN120390667)|CN|(IN202517003741)|IN|(AU2023303026)|AU|(CA3261222)|CA | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=nwH/nfofj4/p0jLUtZGe16Ca4vFyxJplNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000021664783&ekey=2116&xpn=EP4551306&kind=A1 | https://register.epo.org/application?number=EP23748683 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=YLCkkSSwczjWqxLm4QBXD3fDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2024/011170)|US|(US20240009617)|US | (WO2024/011170)|NAME=HEIRLOOM CARBON TECHNOLOGIES, INC. 125 Valley Drive Brisbane, California 94005 , COUNTRY=US|(US20240009617)|NAME=Heirloom Carbon Technologies, Inc. , CITY=Brisbane , STATE=CA , COUNTRY=US | (EP4551306)|GB|(WO2024/011170)|US|||(AU2023303026)|AU|(CA3261222)|CA | (EP4551306)|NAME=Cooley (UK) LLP 22 Bishopsgate , CITY=London EC2N 4BQ , COUNTRY=GB , REG=101544956|(WO2024/011170)|NAME=HILTON, Ramsey et al. 1299 Pennsylvania Ave. NW Suite 700 Washington, District of Columbia 20004 , POSTCODE=20004 , COUNTRY=US|(JP2025522936)|NAME=AOKI ATSUSHI , REG=100099759NAME=MITSUHASHI, Shinji et al. , REG=100123582NAME=Shigeki Hirose , REG=100112357NAME=MINAMIYAMA TOMOHIRO , REG=100114018NAME=Yuichi Morimoto , REG=100153729|(CN120390667)|NAME=CENG XIANGSHENG;CCPIT PATENT AND TRADEMARK LAW OFFICE , REG=11038|(AU2023303026)|NAME=Pizzeys Patent and Trade Mark Attorneys Pty Ltd GPO Box 1374 , CITY=Brisbane , STATE=QLD , POSTCODE=4001 , COUNTRY=AU|(CA3261222)|NAME=SMART & BIGGAR LP 1100 - 150 YORK ST. , CITY=TORONTO , POSTCODE=M5H 3S5 , COUNTRY=CA , REG=9975a484-2887-4ac6-98ad-669ac5f8e9dd | (EP4551306)|US; US; US; US; US; US; US|(US20240009617)|US; US; US; US; US; US; US|(WO2024/011170)|US; US; US; US; US; US; US|||||(CA3261222)|US; US; US; US; US; US; US | (EP4551306)|NAME=DUBEL, Andrew, CITY=Moss Beach, California 94038, COUNTRY=US |NAME=KARR, Charles, CITY=San Francisco, California 94127, COUNTRY=US |NAME=KALRA, Juhi, CITY=San Francisco, California 94109, COUNTRY=US |NAME=DRENNAN, David, CITY=Springfield, New Hampshire 03284, COUNTRY=US |NAME=PAUL-GIN, Noah, CITY=San Francisco, California 94122, COUNTRY=US |NAME=GUEBLE, Isabel, CITY=Sunnyvale, California 94089, COUNTRY=US |NAME=ELAHI, Shazib, CITY=Fremont, California 94539, COUNTRY=US|(US20240009617)|NAME=DUBEL Andy, CITY=Moss Beach, STATE=CA , COUNTRY=US |NAME=KARR Charlie, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=KALRA Juhi, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=DRENNAN David, CITY=Springfield, STATE=NH , COUNTRY=US |NAME=PAUL-GIN Noah, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=GUEBLE Isabel, CITY=Sunnyvale, STATE=CA , COUNTRY=US |NAME=ELAHI Shazib, CITY=Fremont, STATE=CA , COUNTRY=US|(WO2024/011170)|NAME=DUBEL, Andy 633 Lancaster Blvd Moss Beach, California 94038, POSTCODE=94038, COUNTRY=US |NAME=KARR, Charlie 189 Marietta Dr. San Francisco, California 94127, POSTCODE=94127, COUNTRY=US |NAME=KALRA, Juhi 1100 Eddy St. Unit D San Francisco, California 94109, POSTCODE=94109, COUNTRY=US |NAME=DRENNAN, David 94 Shore Dr. Springfield, New Hampshire 03284, POSTCODE=03284, COUNTRY=US |NAME=PAUL-GIN, Noah 1458 Funston Ave. San Francisco, California 94122, POSTCODE=94122, COUNTRY=US |NAME=GUEBLE, Isabel 416 Paria Terrace Sunnyvale, California 94089, POSTCODE=94089, COUNTRY=US |NAME=ELAHI, Shazib 2265 Ocaso Camino Fremont, California 94539, POSTCODE=94539, COUNTRY=US|(JP2025522936)|NAME=Andrew Dabel|NAME=Charles Carr|NAME=Juhi Karla|NAME=David Drennan|NAME=Noah Paul Zinn|NAME=Isabelle Guebel|NAME=Shajib Elahi|(CN120390667)|NAME=DUBEL ANDREAS|NAME=KARL CHRISTIAN|NAME=KARRA JAYANT|NAME=DRENNAN DAVID|NAME=BOU-KING NICO|NAME=GABOR ISTVAN|NAME=ELAHI SHERIF|(IN202517003741)|NAME=Dubel Andrew|NAME=Karr Charles|NAME=Kalra Juhi|NAME=Drennan David|NAME=Paul-Gin Noah|NAME=Gueble Isabel|NAME=Elahi Shazib|(AU2023303026)|NAME=DUBEL, Andrew|NAME=KARR, Charles|NAME=KALRA, Juhi|NAME=DRENNAN, David|NAME=PAUL-GIN, Noah|NAME=GUEBLE, Isabel|NAME=ELAHI, Shazib|(CA3261222)|NAME=DUBEL Andrew 633 Lancaster Blvd Moss Beach, California 94038, POSTCODE=94038, COUNTRY=US |NAME=KARR Charles 189 Marietta Dr. San Francisco, California 94127, POSTCODE=94127, COUNTRY=US |NAME=KALRA Juhi 1100 Eddy St. Unit D San Francisco, California 94109, POSTCODE=94109, COUNTRY=US |NAME=DRENNAN David 94 Shore Dr. Springfield, New Hampshire 03284, POSTCODE=03284, COUNTRY=US |NAME=PAUL-GIN Noah 1458 Funston Ave. San Francisco, California 94122, POSTCODE=94122, COUNTRY=US |NAME=GUEBLE Isabel 416 Paria Terrace Sunnyvale, California 94089, POSTCODE=94089, COUNTRY=US |NAME=ELAHI Shazib 2265 Ocaso Camino Fremont, California 94539, POSTCODE=94539, COUNTRY=US | (WO2024/011170)|9|(IN202517003741)|9|(CN120390667)|9|(JP2025522936)|4||(AU2023303026)|9|(US20240009617)|9 | 3 | 8 | (EP4551306)|WO2024/011170|(JP2025522936)|WO2024/011170|(CN120390667)|WO2024/011170|(IN202517003741)|WO2024/011170|(AU2023303026)|WO2024/011170|(CA3261222)|WO2024/011170 | (US20240009617)|Number of Claims: NCL=27|Number of Drawings: NDR=19|Number of Figures: NFG=19|Independent Claim Number: ICL=1,13,20|Number of Independent Claims: NICL=3|Exemplary Claim Number: ECL=1||(WO2024/011170)|Number of Claims: NCL=27|Extended kind: EXTK=x||(JP2025522936)|Number of Claims: NCL=27|Request for examination: REQEXA=false||(CN120390667)|Number of Claims: NCL=27|Gazette date: GAZDATE=2025-07-29|Gazette number: GAZNUM=41-3101|Number of Pages: NPAGES=38||(IN202517003741)|Number of Claims: NCL=27||(AU2023303026)|Number of Claims: NCL=27| | (US20240009617)|Provisional Appl: US63/358,602 FDD=2022-07-06 [2022US-63358602]|(CA3261222)|Division of: CA3261222 FDD=2023-07-06 [2023CA-3261222] | (EP4551306)|ENGLISH (ENG) | (CN120390667)|Patent|(JP2025522936)|Patent|(EP4551306)|Patent|(IN202517003741)|Patent|(AU2023303026)|Patent|(CA3261222)|Patent|(US20240009617)|Patent|(WO202411170)|Patent | Titre: (EP4551306)|Direct air capture contactor for carbon uptake, and methods of operating the same Résumé: (EP4551306)|Embodiments described herein relate to systems, devices, and methods for uptake of CO2 from ambient air. In some aspects, a device can include a platform with a top portion and a bottom portion, an elevation mechanism configured to move the platform vertically, a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray, and an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally. In some embodiments, the bottom portion can support the tray as the tray moves laterally. In some embodiments, the elevation mechanism can include at least one of a chain or a linear actuator driven by a motor. Autre: (US20240009617)|1. A device, comprising:| a platform including a top portion and a bottom portion;| an elevation mechanism configured to move the platform vertically;| a plurality of orifices defined by the top portion of the platform, the plurality of orifices configured to dispense liquid toward a tray; and| an actuator configured to move laterally along a bottom side of the top portion of the platform, the actuator configured to urge the tray to move laterally,| wherein the bottom portion is configured to support the tray as the tray moves laterally.|2. The device of claim 1, wherein the elevation mechanism includes at least one of a chain or a linear actuator driven by a motor.|3. The device of claim 1, wherein the tray includes a carbonation medium disposed therein.|4. The device of claim 3, wherein the carbonation medium includes at least one of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide).|5. The device of claim 1, wherein the plurality of orifices include spray nozzles configured to spray the liquid onto the tray.|6. The device of claim 5, wherein the spray nozzles have variable spray angles.|7. The device of claim 1, wherein the actuator includes a pin, the pin configured to secure into a hole on the tray to engage the actuator with the tray.|8. The device of claim 7, wherein the pin is a first pin and the tray is a first tray, the actuator further including a second pin, the second pin configured to secure into a hole on a second tray to engage the actuator with the second tray and urge the second tray to move in a direction parallel to the movement of the first tray, the second tray located opposite the first tray relative to the actuator.|9. The device of claim 2, further comprising:| a counterweight configured to minimize loading requirements on the motor.|10. The device of claim 1, wherein the bottom portion of the platform includes a load cell configured to measure a weight of the tray.|11. The device of claim 1, wherein the platform includes a mechanical agitator configured to agitate contents of the tray.|12. The device of claim 11, wherein the mechanical agitator includes at least one of an irrigation implement, a stirring element, and/or a vibration element.|13. An apparatus, comprising:| a frame including a plurality of vertically oriented bars and a plurality of horizontally oriented bars;| a plurality of cables including beads, the plurality of cables coupled to and suspended from the horizontally oriented bars in tension;| a plurality of shelves coupled to the cables and supported by the beads, the plurality of shelves configured to support a plurality of trays; and| a plurality of distributors, each distributor of the plurality of distributors configured to move vertically, each distributor of the plurality of distributors configured to contact a tray from the plurality of trays and urge the tray to move horizontally into and out of the distributor.|14. The apparatus of claim 13, wherein each of the plurality of shelves includes a cable mounting feature configured to couple to the beads.|15. The apparatus of claim 13, further comprising:| a plurality of cable pucks placed upon the beads and configured to increase the surface area upon which each of the plurality of shelves rest.|16. The apparatus of claim 13, wherein each of the plurality of shelves includes an alignment feature configured to engage a tray from the plurality of trays and prevent horizontal sliding of the tray.|17. The apparatus of claim 13, further comprising:| an air conveyor configured to force air through the plurality of shelves and the plurality of trays.|18. The apparatus of claim 13, wherein each of the plurality of vertically oriented bars includes a series of fiducials configured to fix heights along the vertically oriented bars, at which the plurality of distributors are fixed while loading and unloading.|19. The apparatus of claim 13, further comprising:| at least one of a horizontal bracing element or a diagonal bracing element configured to contact at least a portion of the plurality of cables to minimize horizontal movement of the plurality of cables and the plurality of shelves.|20. A method, comprising:| moving a distributor in a vertical direction, the distributor including an actuator and an orifice;| fixing a vertical position of the distributor;| securing the actuator to a tray positioned on a shelf, the tray including a carbonation medium;| urging, via the actuator, the tray in a horizontal direction toward a centerline of the distributor; and| dispensing, via the orifice, a liquid onto the carbonation medium in the tray;|21. The method of claim 20, further comprising: urging, via the actuator, the tray in a horizontal direction onto the shelf.|22. The method of claim 20, further comprising:| disengaging the actuator from the tray and moving the actuator horizontally toward the centerline of the distributor.|23. The method of claim 20, further comprising:| before securing the actuator to the tray, moving the actuator horizontally away from the centerline of the distributor.|24. The method of claim 20, wherein urging the tray in the horizontal direction toward the centerline of the distributor occurs at least partially concurrent with the dispensing.|25. The method of claim 20, wherein the tray is a first tray, the shelf is a first shelf, and the horizontal direction is a first horizontal direction, the method further comprising:| urging, via the actuator, a second tray in a second horizontal direction toward the centerline of the distributor.|26. The method of claim 25, wherein urging the first tray and urging the second tray are at least partially concurrent.|27. The method of claim 25, wherein the second horizontal direction forms an angle of about 180 degrees with the first horizontal direction. | 18 | Abstract | gpt-4o-mini | no | The article focuses on direct air capture (DAC) of CO2 from ambient air, which does not involve biomass or energy production, and therefore does not meet the criteria for BECCS. | |||||||||||||||
| 20 | GB202201121|GB202217599 | WOGB2023/050185 | WO2023/144550 | 105974553 | WO2023/144550 A1 2023-08-03 [WO2023144550] | 2022-01-28|2022-11-24 | 2023-01-27 | 2023-08-03 | (WO2023/144550)|2025-07-28 | (WO2023/144550)|Extraction device | (WO2023/144550)|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to methods for extracting solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. The invention also relates to apparatus and methods for extracting solid and/or liquid carbon dioxide and liquid methane from gaseous mixtures, such as natural gas and biogas. | PURIFIRE LABS | (WO2023/144550)|PURIFIRE LABS LIMITED ([GB]) | PEARCE MATTHEW|MIDDLETON RAY | (WO2023/144550)|PEARCE, Matthew|MIDDLETON, Ray | (WO2023/144550)|TITMUS, Craig et al. ([GB]) | (WO2023/144550)|As such, the apparatus of the invention can advantageously be used to extract carbon dioxide from a range of sources, such as exhaust flue gases, such as from boilers, engines, and fossil fuel-fired power stations.|Sequestration of carbon dioxide from biogas plants can advantageously render the emissions from these plants net carbon negative.|The present invention solves the above-mentioned problems by providing an apparatus for extracting solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas.|Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. Post combustion carbon capture and storage with amine scrubbing technologies in coal-fired power plants is a recent technology application, but even with subsidies it is expensive, typically costing between $80/tonne of carbon dioxide for first of a kind technologies and $60/tonne of carbon dioxide for next of a kind technology.|There are various disadvantages associated with this process, including the propensity for the filters to become clogged or wet thereby requiring regular inspections for their replacement. These consumable filter components are expensive and require associated pumping, pressurisation and regulation equipment to ensure they are working correctly.| | (WO2023/144550)|1. An apparatus for extracting solid and/or liquid carbon dioxide from a gaseous mixture, the apparatus comprising: a) means for cooling and compressing the gaseous mixture, the means comprising: i) a primary heat exchanger for receiving and cooling the gaseous mixture; and ii) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger to provide a compressed cooled mixture; and b) separation means for extracting carbon dioxide from the compressed cooled mixture, the separation means comprising a separation vessel comprising: i) an inlet for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and ii) a first outlet for venting gas from the separation vessel.|26. A method for producing solid or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to a secondary heat exchanger; and c) separating liquid carbon dioxide from the gaseous phase of the mixture.|27. A method for producing gaseous methane from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture comprising liquid and/or solid carbon dioxide and gaseous methane; and c) separating liquid and/or solid carbon dioxide from gaseous methane.| | (WO2023/144550)|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to methods for extracting solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. The invention also relates to apparatus and methods for extracting solid and/or liquid carbon dioxide and liquid methane from gaseous mixtures, such as natural gas and biogas.|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to methods for extracting solid or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. The invention also relates to apparatus and methods for extracting solid and/or liquid carbon dioxide and liquid methane from gaseous mixtures, such as natural gas and biogas.|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures.| | (WO2023/144550)|CARBON DIOXIDE(100,190)|LIQUID CARBON DIOXIDE(100,65)|SOLID EXTRACTION(100,14)|GASEOUS METHANE(100,8)|SOLID PRODUCTION(100,4)|SEPARATION VESSEL(84,50)|BIOGAS(75,32)|AMINE SCRUBBING(72,1)|LIQUID METHANE(64,24)|PRIMARY COMPRESSOR(62,46)|REGULAR INSPECTION(57,1)|SECONDARY HEAT EXCHANGER(55,79)|METHANE COLLECTION VESSEL(54,10)|FLUID COMMUNICATION(53,38)|PRIMARY HEAT EXCHANGER(49,96)|CARBON DIOXIDE SEQUESTRATION(46,1)|CONSUMABLE FILTER COMPONENT(45,1)|REGULATION EQUIPMENT(45,1)|TERTIARY HEAT EXCHANGER(43,25)|LABYRINTH CHAMBER(43,12)|POST COMBUSTION CARBON CAPTURE(42,1)|PRESSURIZING(42,1)|TERTIARY COMPRESSOR(39,9)|PROPENSITY(39,1)|LIQUID SEPARATION(37,5)|GAS BYPASS(36,17)|PLANT NET CARBON NEGATIVE(36,1)|PUMPING(36,1)|SUBSIDY(36,1)|ROTOR(34,16)|VENT METHANE(34,2)|NATURAL GAS(33,24)|BIOMASS(31,1)|CARBON DIOXIDE COLLECTION VESSEL(30,22)|EXTRACTING CARBON DIOXIDE(30,3)|EXHAUST FLUE GAS(29,28)|FLUE GAS(28,90)|COLLECTING LIQUID METHANE(28,2)|CARBON NEGATIVE NET(27,1)|HYDRAULIC PRESSING(26,5)|COMPRESSION(25,8)|COOLED METHANE GAS(24,3)|REMOVING GAS(24,1)|BECCS(23,2)|DEHUMIDIFIER(22,6)|THROTTLING VALVE OUTLET(22,6)|BIOGAS PLANT(22,5)|SEPARATION VESSEL INLET(22,3)|CARBON DIOXIDE GAS REMOVAL(21,1)|SOLID CARBON DIOXIDE(20,14)|EXOGENOUS GASEOUS NITROGEN(20,5)|SEPARATED NITROGEN GAS(20,3)|SEPARATING LIQUID CARBON DIOXIDE(20,3)|COAL(20,2)|ELECTRICITY GENERATION(20,2)|FIRED POWER STATION(20,2)|LIQUID COLLECTION(20,2)|EXCESS EXHAUST FLUE GAS(19,5)|EXOGENOUS COOLANT CONDUIT(19,2)|COOLED EXHAUST FLUE GAS(18,17)|BOILER(18,8)|HEAT EXCHANGE CHILLER LABYRINTH(18,6)|UNIDIRECTIONAL FLOW(18,5)|FOSSIL FUEL(17,6)|COLD NITROGEN GAS(16,5)|THROTTLING VALVE INLET(15,4)|GASEOUS PHASE(14,3)|EXHAUST FLUE EXIT(14,2)|NONHALOGENATED HYDROCARBON(14,2)|GASEOUS CARBON DIOXIDE(13,9)|CARBON DIOXIDE EMISSION(12,8)|DOWNWARD DIRECTIONAL TUBING(12,2)|EXHAUST FLUE MODIFICATION(12,2)|DOMESTIC COOKING FUEL(12,1)|WASTEFUL DECOMMISSIONING(12,1)|HOLDING TANK(11,17)|ECONOMIC FEASIBILITY(11,2)|EXOGENOUS LIQUID(10,4)|COMPRESSED COOLED EXHAUST(10,2)|VIRGIN FOSSIL FUEL(10,2)|ABATEMENT ALTERNATIVE SCENARIO(10,1)|ANAEROBIC DIGESTION(10,1)|ATMOSPHERIC GLOBAL EMISSION(10,1)|BIOGAS PLANT FEASIBILITY(10,1)|CO2 PRECOMBUSTION(10,1)|COMPOSITIONAL MAKEUP(10,1)|ELECTRICITY MWH(10,1)|GIGA TONNE(10,1)|NONPOLLUTING RETROFITTED ALTERNATIVE(10,1)|OLD COAL FIRED ELECTRICITY(10,1)|UNMET INDUSTRIAL DEMAND(10,1)|BIO GAS SOURCE(9,4)|COAL FIRED POWER PLANT(9,2)|AMMONIA FERTILIZER(9,1)|EXPENSIVE DECOMMISSIONING(9,1)|MAJORITY CONTAMINANT(9,1)|NITROGEN GAS PUMPING(9,1)|PROPELLING EXHAUST(9,1)|STOICHIOMETRIC COMBUSTION(9,1)|SUSTAINABLE FUEL(9,1)|UREA FERTILIZER PRODUCTION(9,1)|VALUABLE COMMODITY(9,1)|CONE TUBULAR DIAMETER(8,2)|COOLANT VALVE(8,2)|GENERATION PLANT(8,2)|HYDROCHLOROFLUOROCARBON(8,2)|HYDROFLUOROCARBON(8,2)|ALUMINUM(7,3)|GASEOUS COMPONENT(7,3)|LANDFILL GAS SITE(7,3)|PARTITIONED PARALLEL EXHAUST CHAMBER(7,3)|URGENT NEED(7,3)|ADIABATIC DROP(7,1)|BIO GAS STORAGE VESSEL(7,1)|BIOGAS PLANT ECONOMIC PERFORMANCE(7,1)|COAL FUEL(7,1)|EXHAUST FLUE GAS PROPELLANT(7,1)|GLOBAL METHANE EMISSION SOURCE(7,1)|MAINTENANCE COMPRESSOR(7,1)|MEMBRANE SEPARATION(7,1)|PERTINENT MARKET(7,1)|REVERSE SUBLIMATION(7,1)|THROTTLING VALVE CONTENT(7,1)|TRANSITIONARY PASSAGE(7,1)|TUBULAR CONE EXTENSION(7,1)|TUBULAR CONE ORIENTATION(7,1)|INITIATION(6,4)|UNMET NEED(6,4)|COLD GASEOUS NITROGEN FLOW(6,3)|OUT LETTING SOLID(6,3)|CONTRIBUTION REDUCTION(6,2)|EVAPORATOR(6,2)|GAS COMPRESSOR ROTATION(6,2)|LIQUID REFRIGERANT(6,2)|PRIMARY COOLING(6,2)|UNILATERAL FLOW(6,2)|VOLUME RECIPROCATING COMPRESSOR(6,2)|VOLUMETRIC SPACE(6,2)|CARBON DIOXIDE REMEDIATION(6,1)|CARBON DIOXIDE TONNE(6,1)|EXTRACTING NITROGEN(6,1)|GREENHOUSE GAS QUARTER(6,1)|INTERCONNECTION(6,1)|INTERNAL ROTOR(6,1)|LIQUID METHANE EXTRACTION(6,1)|MANIFOLD HOUSING(6,1)|NETWORK ARRAY MATRIX(6,1)|NITROGEN GAS STORAGE VESSEL(6,1)|NITROGEN GAS TRANSFER CONDUIT(6,1)|OIL RESERVOIR DEPLETION(6,1)|PUMPING NITROGEN(6,1)|QUALITY METHANE(6,1)|RETROCONVERSION(6,1)|SIMULTANEOUS DROP(6,1)|SUDDEN DROP(6,1)|TONNAGE(6,1)|TUBULAR APERTURE(6,1)|VENTING TUBE(6,1)|AUSTENITIC STAINLESS STEEL(5,3)|AUSTENITIC STEEL(5,3)|HEAT MODIFICATION(5,3)|SULFUR DIOXIDE(5,3)|BILLION CUBIC METER(4,1)|BIOENERGY(4,1)|BIOFUEL(4,1)|BRIDGING BAR(4,1)|BURIAL(4,1)|BYPASS(4,1)|CARBON DIOXIDE PROPORTION(4,1)|CARBON DIOXIDE SNOW(4,1)|CHIMNEY DESIGN(4,1)|CIRCULATION(4,1)|CO2 GLOBAL WARMING POTENTIAL(4,1)|EXTRACTED GASEOUS NITROGEN FLOW(4,1)|FRIDGE(4,1)|GAS SEPARATION VORTEX(4,1)|GAS VELOCITY(4,1)|GASEOUS COLD CARBON DIOXIDE(4,1)|GASEOUS NITROGEN MULTIPHASE FLOW(4,1)| | (WO2023/144550)|Claims |1. An apparatus for extracting solid and/or liquid carbon dioxide from a gaseous mixture, the apparatus comprising: a) means for cooling and compressing the gaseous mixture, the means comprising: i) a primary heat exchanger for receiving and cooling the gaseous mixture; and ii) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger to provide a compressed cooled mixture; and b) separation means for extracting carbon dioxide from the compressed cooled mixture, the separation means comprising a separation vessel comprising: i) an inlet for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and ii) a first outlet for venting gas from the separation vessel.|2. The apparatus of claim 1, wherein the separation vessel further comprises: (iii) a second outlet for out letting solid and/or liquid carbon dioxide.|3. The apparatus of claim 1 or claim 2, wherein the separation vessel inlet comprises a throttling valve for receiving compressed cooled mixture from the means for cooling and compressing the gaseous mixture.|4. The apparatus of any preceding claim, wherein:|(a) the separation vessel is configured to contain solid and/or liquid carbon dioxide; and/or |(b) the apparatus further comprises a holding tank configured to receive and contain solid and/or liquid carbon dioxide from the second outlet of the separation vessel. |5. The apparatus of any preceding claim, wherein the holding tank provides a carbon dioxide collection vessel, wherein the carbon dioxide collection vessel further comprises a throttling valve in fluid communication with the second outlet of the separation vessel for receiving carbon dioxide.|6. The apparatus of any preceding claim, wherein the means for cooling and compressing the gaseous mixture further comprises one or more secondary heat exchangers for receiving and cooling the compressed cooled mixture from the primary compressor.|7. The apparatus of any preceding claim, wherein the gaseous mixture comprises nitrogen.|8. The apparatus of claim 7, wherein the first outlet of the separation vessel is for venting gaseous nitrogen, wherein the first outlet is in fluid communication with the primary heat exchanger and/or the first outlet is in fluid communication with one or more of the secondary heat exchangers.|9. The apparatus of claim 7 or claim 8, wherein the primary heat exchanger and/or one or more of the secondary heat exchangers comprise an array of conduits for receiving gaseous nitrogen from the separation vessel.|10. The apparatus of claim 9, wherein the array of conduits forms a labyrinth chamber for receiving the gaseous mixture.|11. The apparatus of any preceding claim, wherein the gaseous mixture is exhaust flue gas and wherein the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue.|12. The apparatus of claim 11 further comprising a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.|13. The apparatus of any preceding claim further comprising an impeller for propelling the gaseous mixture into the primary heat exchanger.|14. The apparatus of any preceding claim further comprising one or more impellers for propelling the compressed cooled mixture into one or more of the one or more secondary heat exchangers.|15. The apparatus of any preceding claim, wherein the means for cooling and compressing the gaseous mixture further comprises a secondary compressor for receiving and compressing compressed cooled mixture from the primary compressor.|16. The apparatus of claim 15, wherein one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor.|17. The apparatus of claim 15 or claim 16, wherein one or more secondary heat exchangers is situated between the secondary compressor and the separation means.|18. The apparatus of any of claims 15-17, wherein: (a) one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more secondary heat exchangers is situated between the secondary compressor and the separation means.|19. The apparatus of any preceding claim, wherein the apparatus comprises one or more valves for maintaining unidirectional flow of the mixture.|20. The apparatus of any preceding claim, wherein the gaseous mixture comprises methane and wherein the first outlet is configured to vent methane enriched gas from the separation vessel.|21. The apparatus of any preceding claim, wherein the gaseous mixture comprises methane and the apparatus further comprises: c) a means for cooling and compressing methane, the means comprising: i) a tertiary heat exchanger in fluid communication with the first outlet of the separation vessel for receiving and cooling methane gas; and ii) a tertiary compressor in fluid communication with the tertiary heat exchanger for receiving and compressing cooled methane gas to provide liquid methane.|22. The apparatus of claim 21 further comprising a methane collection vessel in fluid communication with the means for cooling and compressing methane, wherein the methane collection vessel is for collecting liquid methane.|23. The apparatus of claim 21 or claim 22 further comprising an impeller for propelling methane gas into the tertiary heat exchanger.|24. The apparatus of any of claims 21-23, wherein the tertiary heat exchanger comprises an array of conduits for receiving coolant and wherein the array of conduits forms a labyrinth chamber for receiving the methane gas.|25. The apparatus of any preceding claim wherein the means for cooling and compressing the gaseous mixture comprises a dehumidifier.|26. A method for producing solid or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to a secondary heat exchanger; and c) separating liquid carbon dioxide from the gaseous phase of the mixture.|27. A method for producing gaseous methane from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture;|b) compressing the cooled gaseous mixture to provide compressed cooled mixture comprising liquid and/or solid carbon dioxide and gaseous methane; and c) separating liquid and/or solid carbon dioxide from gaseous methane. |28. The method of claim U, further comprising a step of cooling and compressing the gaseous methane to provide liquid methane.|29. The method of any of claims 26-28, wherein the method comprises throttling the compressed cooled mixture through a throttling valve to provide solid and/or liquid carbon dioxide.|30. The method of any of claims 26-29, wherein the gaseous mixture comprises nitrogen and the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger.|31. The method of any of claims 26-30, wherein the cooling comprises reducing the temperature of the gas to less than -10°C.|32. The method of any of claims 26-31, wherein the compressing comprises compressing the gas to at least 1 MPa.|33. The method of any of claims 26-32, wherein the cooling comprises reducing the temperature of the gas to less than -30°C.|34. The method of any of claims 26-33, wherein the compressing comprises compressing the gas to at least 3 MPa.|35. The method of any of claims 26-34, wherein the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing.|36. The method of any of claims 26-35, wherein the gaseous mixture comprises methane and wherein the method further comprises: d) separating methane gas from solid and/or liquid carbon dioxide and delivering the methane gas to a tertiary heat exchanger to provide cooled methane gas; and e) compressing the cooled methane gas to provide liquid methane.|37. The method of claim 28-36, wherein cooling the methane gas comprises reducing the temperature of the methane gas to less than -100°C.|38. The method of any of claims 28-37, wherein compressing the methane gas comprises compressing the methane gas to at least 3 MPa. | (WO2023/144550)|[0001] EXTRACTION DEVICE | [0002] FIELD OF THE INVENTION | [0003] The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to methods for extracting solid or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. The invention also relates to apparatus and methods for extracting solid and/or liquid carbon dioxide and liquid methane from gaseous mixtures, such as natural gas and biogas. | [0004] BACKGROUND OF THE INVENTION | [0005] Global carbon dioxide emissions amount to over 10 giga tonnes per year. Simultaneously, there is a considerable requirement for carbon dioxide in a multitude of applications, such as urea fertiliser production, enhanced oil recovery processes, production of food and beverages, and other industrial processes. Approximately 250 million tonnes of carbon dioxide, corresponding to approximately 2.5% of all global emissions, are used each year for these purposes. Presently, almost all such carbon dioxide is derived from fossil fuel based sources. | [0006] In line with multiple unilateral governmental policies to reduce atmospheric global emissions of carbon dioxide, many nations are either decommissioning, scrapping or modifying existing coal-fired power stations or considering other abatement alternative scenarios. Coal-fired power stations emit approximately 80 tonnes of carbon dioxide gas per hour for every 100 MWh of electricity power generation capacity, depending on their construction and the coal fuel type being burned. This gross carbon dioxide emissions capacity exceeds comparative tonnages remediated for bioenergy with carbon capture and storage (BECCS). Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. Post combustion carbon capture and storage with amine scrubbing technologies in coal-fired power plants is a recent technology application, but even with subsidies it is expensive, typically costing between $80/tonne of carbon dioxide for first of a kind technologies and $60/tonne of carbon dioxide for next of a kind technology. | [0007] Retro-conversion of older coal-fired electricity power generation plants for carbon dioxide remediation was not considered as a future possibility when these plants were built, resulting in low availability of physical space and high costs. With many coal-fired power plants not able to beconverted into environmentally benign non-polluting retro-fitted alternatives, some are now being shut down as a result of new legislation policies. This, in turn, drives an increased demand for electricity generation from alternative sources. | [0008] According to the US Environmental Protection Agency, methane (CH4) gas has 25 times the global warming potential of CO2, whereas in compositional makeup, CO2 contributes over three-quarters of all greenhouse gases. Natural gas is a valuable commodity, yet the global gas industry flared 142 billion cubic metres ('BCM') in 2020. Due to incomplete combustion, flaring is a significant source of global methane emissions and must be reduced by 85% if the global gas industry is to meet net zero targets. | [0009] On the other hand, biogas is currently not released or flared directly into the environment. Instead, it is burned as a fuel for electricity or concentrated for domestic cooking fuel or heating. The stoichiometric combustion of one molecule of methane results in the consumption of two molecules of oxygen to produce one molecule of CO2 and two molecules of water. Consequently, all of the carbon contained within biogas plants is eventually lost into the atmosphere, either as CO2 pre-combustion or CO2 post-combustion. | [0010] There exists an urgent and unmet need for carbon capture processes that are efficient, scalable and inexpensive. To avoid expensive and wasteful decommissioning of existing coal-fired electricity power generation plants, there exists an urgent and unmet need for carbon capture processes that reduce the carbon dioxide emissions from these plants to the environment. Furthermore, there is an urgent and unmet need for carbon capture processes to further improve the environmental and economic performance of biogas plants and landfill gas sites. There is also an unmet industrial demand for carbon dioxide that is not derived directly from virgin fossil fuels e.g. for use in the ammonia fertiliser, enhanced oil recovery, medical, food and beverage industries. There is also an unmet need for biogas- derived or natural gas-derived methane which contains a lower proportion of carbon dioxide. | [0011] SUMMARY OF THE INVENTION | [0012] The present invention solves the above-mentioned problems by providing an apparatus for extracting solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. Advantageously, the apparatus of the invention can be used to extract and capture carbon dioxide that would otherwise be released into the atmosphere, thereby reducing contributions to global carbon dioxide emissions. Carbon dioxide extracted by the invention may be stored to prevent its entry into the atmosphere. Carbon dioxide extracted by the invention may also be used in industry, e.g. to reduce the reliance on carbon dioxide produced from virgin fossil fuels, thereby further reducing carbon dioxide emissions.The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures. | [0013] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from exhaust flue gas. The present invention is not limited to any particular type of exhaust flue gas. Likewise, the present invention is not limited to any particular type of flue. As such, the apparatus of the invention can advantageously be used to extract carbon dioxide from a range of sources, such as exhaust flue gases, such as from boilers, engines, and fossil fuel-fired power stations. | [0014] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from biogas. Sequestration of carbon dioxide from biogas plants can advantageously render the emissions from these plants net carbon negative. | [0015] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from natural gas. | [0016] The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. Liquid methane can advantageously be used as a low-carbon fuel, e.g. to power engines in trucks, ships and other heavy equipment such as tractors. | [0017] In some embodiments, the apparatus of the invention is for extracting liquid methane from biogas. | [0018] In some embodiments, the apparatus of the invention is for extracting liquid methane from natural gas. | [0019] The invention also relates to an apparatus for the extraction of solid and/or liquid carbon dioxide and for the extraction of liquid methane from gaseous mixtures, such as natural gas and biogas. | [0020] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and for extracting liquid methane from natural gas. The extraction of carbon dioxide and/or methane from natural gas offers an alternative to flaring that is both environmentally and economically favourable. | [0021] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and for extracting liquid methane from biogas. | [0022] The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from a gaseous mixture, the apparatus comprising: a) means for cooling and compressing the gaseous mixture, the means comprising: i) a primary heat exchanger for receiving and cooling the gaseous mixture; and ii)a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger to provide a compressed cooled mixture; and b) separation means for extracting carbon dioxide from the compressed cooled mixture, the separation means comprising a separation vessel comprising: i) an inlet for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and ii) a first outlet for venting gas from the separation vessel. | [0023] In some embodiments, the separation vessel further comprises: (iii) a second outlet for out letting solid and/or liquid carbon dioxide. | [0024] In some embodiments, the separation vessel inlet comprises a throttling valve for receiving compressed cooled mixture from the means for cooling and compressing the gaseous mixture.| [0025] In some embodiments, the separation vessel is configured to contain solid and/or liquid carbon dioxide. In some embodiments, the apparatus further comprises a holding tank configured to receive and contain solid and/or liquid carbon dioxide from the second outlet of the separation vessel.| [0026] In some embodiments, the holding tank provides a carbon dioxide collection vessel, wherein the carbon dioxide collection vessel further comprises a throttling valve in fluid communication with the second outlet of the separation vessel for receiving carbon dioxide. | [0027] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises one or more secondary heat exchangers for receiving and cooling the compressed cooled mixture from the primary compressor. | [0028] In some embodiments, the gaseous mixture comprises nitrogen. In some embodiments, the first outlet of the separation vessel is for venting gaseous nitrogen, wherein the first outlet is in fluid communication with the primary heat exchanger and/or the first outlet is in fluid communication with one or more of the secondary heat exchangers. In some embodiments, the primary heat exchanger and/or one or more of the secondary heat exchangers comprise an array of conduits for receiving gaseous nitrogen from the separation vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the gaseous mixture. | [0029] In some embodiments, the gaseous mixture is exhaust flue gas and wherein the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue. In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.In some embodiments, the apparatus further comprises an impeller for propelling the gaseous mixture into the primary heat exchanger. In some embodiments, the apparatus further comprises one or more impellers for propelling the compressed cooled mixture into one or more of the one or more secondary heat exchangers. | [0030] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises a secondary compressor for receiving and compressing compressed cooled mixture from the primary compressor. In some embodiments, one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor. In some embodiments, one or more secondary heat exchangers is situated between the secondary compressor and the separation means. | [0031] In some embodiments, (a) one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more secondary heat exchangers is situated between the secondary compressor and the separation means. | [0032] In some embodiments, the apparatus comprises one or more valves for maintaining unidirectional flow of the mixture. | [0033] In some embodiments, the gaseous mixture comprises methane and the first outlet is configured to vent methane enriched gas from the separation vessel. | [0034] In some embodiments, the gaseous mixture comprises methane and the apparatus further comprises: c) a means for cooling and compressing methane, the means comprising: i) a tertiary heat exchanger in fluid communication with the first outlet of the separation vessel for receiving and cooling methane gas; and ii) a tertiary compressor in fluid communication with the tertiary heat exchanger for receiving and compressing cooled methane gas to provide liquid methane. | [0035] In some embodiments, the apparatus further comprises a methane collection vessel in fluid communication with the means for cooling and compressing methane, wherein the methane collection vessel is for collecting liquid methane. | [0036] In some embodiments, the apparatus further comprises an impeller for propelling methane gas into the tertiary heat exchanger. | [0037] In some embodiments, the tertiary heat exchanger comprises an array of conduits for receiving coolant and wherein the array of conduits forms a labyrinth chamber for receiving the methane gas.| [0038] In some embodiments, the means for cooling and compressing the gaseous mixture comprises a dehumidifier.The invention also provides: (A) a method for producing solid or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to a secondary heat exchanger; and c) separating liquid carbon dioxide from the gaseous phase of the mixture; and (B) a method for producing gaseous methane from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture comprising liquid and/or solid carbon dioxide and gaseous methane; and c) separating liquid and/or solid carbon dioxide from gaseous methane. In some embodiments, the method further comprises a step of cooling and compressing the gaseous methane to provide liquid methane. | [0039] In some embodiments, the method comprises throttling the compressed cooled mixture through a throttling valve to provide solid and/or liquid carbon dioxide. | [0040] In some embodiments, the gaseous mixture comprises nitrogen and the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger. | [0041] In some embodiments, the cooling comprises reducing the temperature of the gas to less than -10°C.| [0042] In some embodiments, the compressing comprises compressing the gas to at least 1 MPa. | [0043] In some embodiments, the cooling comprises reducing the temperature of the gas to less than -30°C.| [0044] In some embodiments, the compressing comprises compressing the gas to at least 3 MPa. | [0045] In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing. | [0046] In some embodiments, the gaseous mixture comprises methane and the method further comprises: d) separating methane gas from solid and/or liquid carbon dioxide and delivering the methane gas to a tertiary heat exchanger to provide cooled methane gas; and e) compressing the cooled methane gas to provide liquid methane. | [0047] In some embodiments, cooling the methane gas comprises reducing the temperature of the methane gas to less than -100°C. | [0048] In some embodiments, compressing the methane gas comprises compressing the methane gas to at least 3 MPa.DETAILED DESCRIPTION OF THE INVENTION | [0049] The present invention is based on the surprising discovery that solid and/or liquid carbon dioxide can be efficiently extracted from gaseous mixtures by varying the pressure and temperature of the gaseous mixtures. The apparatus and method of the invention advantageously provide a means for reducing the carbon dioxide emissions of energy generating devices. Moreover, carbon dioxide extracted by the apparatus and method of the invention has a number of applications in industry. Carbon dioxide extracted by the apparatus and methods of the invention may also be stored, to prevent its entry to the atmosphere, thereby reducing contributions to greenhouse gases. | [0050] Advantageously, the apparatus of the invention can be used to reduce the carbon dioxide emissions from existing electricity generating power stations by extracting carbon dioxide from the exhaust flue gases generated by said power stations. Reducing the negative environmental impact of these power stations, by reducing their carbon dioxide emissions without sacrificing the efficiency of energy generation, may help avoid these power stations being decommissioned. | [0051] Liquid carbon dioxide extracted using the apparatus and methods of the invention can be stored in subterraneous storage systems. Liquid carbon dioxide at high subterraneous pressures may be maintained for a long time in liquid state due to increased pressure from burial in subterranean lakes of liquid carbon dioxide, resulting in limited surface leakage over an extended period of time. This is a desirable alternative to the current practise of allowing carbon dioxide to be released into the atmosphere. Liquid carbon dioxide extracted using the apparatus of the invention may also be used to produce pressure changes within underground water and oil reservoirs, for applications such as instigating enhanced oil recovery and/or additional extraction of oil from otherwise depleted oil reservoirs. | [0052] As used herein, a "gaseous mixture" is a gas comprising carbon dioxide. In some embodiments, the gaseous mixture comprises nitrogen. In some embodiments, the gaseous mixture comprises methane. In some embodiments, the gaseous mixture comprises carbon dioxide and nitrogen. In some embodiments, the gaseous mixture comprises carbon dioxide and methane. | [0053] In some embodiments, the gaseous mixture is exhaust flue gas. Exhaust flue gas typically comprises carbon dioxide and nitrogen. | [0054] In some embodiments, the gaseous mixture is biogas or natural gas. Biogas and natural gas typically comprise carbon dioxide and methane.In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from exhaust flue gas. Exhaust flue gas is typically generated by the combustion of a fuel, such as a fossil fuel (e.g. coal), biofuel or sustainable fuel. Exhaust flue gas may be generated by various energy generating devices, e.g. boilers, engines, generators, and power stations (e.g. fossil fuel-fired power stations). | [0055] In some embodiments, exhaust flue gas is treated by flue gas desulphurisation (FGD) methods to remove sulphur dioxide prior to delivery of the exhaust flue gas to the apparatus of the invention. In some embodiments, exhaust flue gas is post-desulphurisation exhaust flue gas. Typical post-desulphurisation exhaust flue gas comprises mainly gaseous carbon dioxide and nitrogen. | [0056] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from a gaseous mixture comprising methane to provide a gaseous mixture enriched in methane. In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and liquid methane from a gaseous mixture comprising methane. In some embodiments, the gaseous mixture comprising methane is biogas or natural gas. | [0057] In some embodiments, the gaseous mixture comprising methane is biogas. Biogas is a renewable energy source produced by anaerobic digestion of organic matter, such as food or animal waste. Biogas typically contains a mixture of approximately 60% methane (CH4) and 40% carbon dioxide (CO2). In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and liquid methane from biogas. By separating biogas into its constituent parts, the economic and environmental feasibility of biogas plants and landfill gas sites can be significantly improved. | [0058] Biogas upgrading is the process by which biogas is converted to methane enriched gas which can be supplied directly to the gas grid. The technology currently used for biogas-to-grid upgrading involves the use of membrane-based separation technologies to separate methane from carbon dioxide (which is typically released into the atmosphere). There are various disadvantages associated with this process, including the propensity for the filters to become clogged or wet thereby requiring regular inspections for their replacement. These consumable filter components are expensive and require associated pumping, pressurisation and regulation equipment to ensure they are working correctly. These factors negatively impact the economic feasibility of current biogas-to-grid upgrading technologies. Advantageously, the apparatus and methods described herein can be used to extract both carbon dioxide and high quality methane from biogas. The methane enriched gas can be injected directly into the gas grid. Alternatively, the methane can be converted into liquid methane to enable more convenient storage and transport. The carbon dioxide can be stored or used in downstreamapplications as described herein which provides important environmental benefits as opposed to simply releasing the carbon dioxide into the environment. | [0059] The apparatus of the invention comprises a means for cooling and compressing the gaseous mixture. The means for cooling and compressing the gaseous mixture comprises a primary heat exchanger for receiving and cooling the gaseous mixture. The primary heat exchanger may be any heat exchanger capable of reducing the temperature of the gaseous mixture. | [0060] In some embodiments, the primary heat exchanger comprises one or more conduits for receiving coolant. The conduit(s) act as a conductor of heat from the gaseous mixture to the coolant thereby simultaneously cooling the gaseous mixture and increasing the temperature of the coolant. In some embodiments, the primary heat exchanger comprises a plurality of conduits for receiving coolant. In some embodiments, the primary heat exchanger comprises an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the gaseous mixture. Advantageously, an array of conduits provides a large surface area for contacting the gaseous mixture in the labyrinth chamber thereby allowing even faster cooling of the gaseous mixture. | [0061] In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium. | [0062] In some embodiments, the coolant is gaseous nitrogen. In some embodiments wherein the gaseous mixture comprises nitrogen, the coolant is gaseous nitrogen extracted from the gaseous mixture. As used herein, extracted gaseous nitrogen refers to gaseous nitrogen that has been extracted from the gaseous mixture. | [0063] In some embodiments, the coolant is an exogenous coolant. | [0064] In embodiments wherein the gaseous mixture comprises nitrogen, an exogenous coolant may be employed to cool the gaseous mixture in one or more heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, the exogenous coolant is used to cool gaseous mixture until sufficient gaseous nitrogen is extracted from the gaseous mixture to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool gaseous mixture in the primary heat exchanger and/or one or more secondary heat exchangers. In some embodiments wherein the gaseous mixture comprises nitrogen, the primary heat exchangerand/or secondary heat exchangers comprise one or more conduits for receiving exogenous coolant which are separate from the one or more conduits configured to receive extracted gaseous nitrogen. | [0065] In some embodiments, the means for cooling and compressing the gaseous mixture comprises a dehumidifier. In some embodiments, the primary heat exchanger comprises a dehumidifier. The dehumidifier advantageously removes water and impurities from the gaseous mixture. In some embodiments, the dehumidifier cools the gaseous mixture to less than 5°C, optionally less than 4°C. | [0066] In some embodiments, the apparatus comprises a compressor and an evaporator in fluid communication with the one or more exogenous coolant conduits. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers, the compressor and evaporator. Circulation may be automatic or may be manually controlled. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers to increase the rate of cooling of gaseous mixture by the primary and/or secondary heat exchangers. | [0067] The exogenous coolant may be any coolant suitable to cool the gaseous mixture in the primary and/or secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. In some embodiments, the exogenous coolant is a gas or liquid refrigerant. In some embodiments, the exogenous coolant is exogenous liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous liquid and/or gaseous carbon dioxide is extracted liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous coolant comprises one or more of fluorocarbon, chlorofluorocarbon (R12), hydrochlorofluorocarbon (R22), hydrofluorocarbon (R410A, R134) freon, ammonia, sulphur dioxide, non-halogenated hydrocarbon, R404A, R407A, R407C, R407F, and R507. In some embodiments, the exogenous coolant comprises R744. | [0068] After cooling the gaseous mixture in the primary heat exchanger, coolant comprising extracted gaseous nitrogen is typically vented into the atmosphere. | [0069] In some embodiments, the primary heat exchanger comprises a control means for regulating the flow of coolant through the conduit(s). The rate of flow of the coolant determines the rate of cooling of the gaseous mixture. Increasing the flow of coolant typically increases the rate of cooling of the gaseous mixture. Reducing the flow of coolant typically reduces the rate of cooling of the gaseous mixture. The control means may comprise flow sensors. The control means may reduce the flow of coolant in response to reduced flow of gaseous mixture into the primary heat exchanger. The control means may increase the flow of coolant in response to increased flow of gaseous mixture into the primary heatexchanger. In some embodiments, the control means is configured to control the flow of extracted gaseous nitrogen through the conduit(s). In some embodiments, the control means is configured to control the flow of exogenous coolant through the one or more exogenous coolant conduits. In some embodiments, the control means comprises a coolant valve configured to control the flow of coolant through the conduit(s). In some embodiments, the coolant valve is a flow control valve. | [0070] In some embodiments, the apparatus further comprises an impeller for propelling the gaseous mixture into the primary heat exchanger. The impeller may be any rotatable component capable of propelling the gaseous mixture into the primary heat exchanger. In some embodiments, the apparatus comprises a manifold for housing the impeller. | [0071] In some embodiments wherein the gaseous mixture is exhaust flue gas, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the exhaust flue. Typically, the connection means is configured to connect to the exit point of an exhaust flue, i.e. the region of an exhaust flue that releases exhaust flue gas into the environment. In some embodiments, the connecting means is configured to direct exhaust flue gases to ground level, or a subterranean level. In some embodiments, the impeller is situated between the connection means and the primary heat exchanger. | [0072] In embodiments wherein the gaseous mixture is exhaust flue gas, the primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the exhaust flue during normal operation of the energy generating device to which the exhaust flue is connected, e.g. engine, boiler or power station. | [0073] In some embodiments wherein the gaseous mixture is exhaust flue gas, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas. Typically, the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The gas bypass system provides a regulatory control mechanism to avoid unwanted back pressure on the exhaust flue, e.g. when the flow of exhaust flue gas in the exhaust flue exceeds the maximum flow rate of the apparatus e.g. the maximum flow rate of the primary heat exchanger. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber with a gaseous flow control mechanism. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber having a modified heat and pressure take-off. Advantageously, a modified heat and pressure take-off ensures that exhaust flue modifications do not compromise the designed operations and efficiency of the energy generating device. In some embodiments, the gas bypass system comprises a unidirectional gas flow valve flap.In some embodiments wherein the gaseous mixture comprises nitrogen, the apparatus further comprises a gas separation array for extracting nitrogen from the gaseous mixture, wherein the gas separation array is positioned before the means for cooling and compressing the gaseous mixture. In some embodiments, the gas separation array comprises a gas separation membrane. In some embodiments, the gas separation array comprises a gas separation vortex. | [0074] In some embodiments wherein the gaseous mixture is biogas, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the biogas source. The biogas source may be a biogas storage vessel. The biogas source may be a biogas plant, such as an anaerobic digestor or a landfill gas plant. In embodiments wherein the gaseous mixture is biogas, the primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the biogas source during normal operation, e.g. of the anaerobic digestor or landfill gas site. | [0075] In some embodiments wherein the gaseous mixture is natural gas, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the natural gas source. The natural gas source may be a natural gas storage vessel. The natural gas source may be an oil and/or gas extraction site (e.g. an oil and/or gas well). In embodiments wherein the gaseous mixture is natural gas, the primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the natural gas source during normal operation. In some embodiments wherein the gaseous mixture is natural gas, the apparatus further comprises a gas bypass system for venting excess natural gas from the source of natural gas. | [0076] In some embodiments, the primary heat exchanger is configured to cool the gaseous mixture to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. As used herein, cooled gaseous mixture refers to gaseous mixture that has been cooled by the primary heat exchanger. | [0077] The means for cooling and compressing the gaseous mixture comprises a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger. The primary compressor compresses cooled gaseous mixture from the primary heat exchanger to provide compressed cooled mixture. | [0078] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises one or more secondary heat exchangers for cooling compressed cooled mixture from the primary compressor prior to passage of the compressed cooled mixture to the separation vessel.In some embodiments, the means for cooling and compressing the gaseous mixture further comprises one or more secondary compressors for compressing compressed cooled mixture from the primary compressor prior to passage of the compressed cooled mixture to the separation vessel. | [0079] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises: (i) a secondary compressor for receiving and compressing compressed cooled mixture from the primary compressor; and (ii) a secondary heat exchanger for receiving and cooling compressed cooled mixture from the secondary compressor. | [0080] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises: (i) a secondary heat exchanger for receiving and cooling compressed cooled mixture from the primary compressor; and (ii) a secondary compressor for receiving and compressing compressed cooled mixture from the secondary heat exchanger. | [0081] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises:| [0082] (i) a secondary heat exchanger for receiving and cooling compressed cooled mixture from the primary compressor; (ii) a secondary compressor for receiving and compressing compressed cooled mixture from the secondary heat exchanger; and (iii) a further heat exchanger for receiving and cooling compressed cooled mixture from the secondary compressor. In this embodiment, during operation the cooled mixture from the primary heat exchanger is: (i) compressed by the primary compressor;| [0083] (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the further heat exchanger, prior to passage of the compressed cooled mixture to the separation vessel. | [0084] In some embodiments, the secondary heat exchanger is configured to receive and cool compressed cooled mixture from both the primary compressor and the secondary compressor. In this embodiment, during operation the cooled gaseous mixture from the primary heat exchanger is: (i) compressed by the primary compressor; (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the secondary heat exchanger prior to passage of the compressed cooled mixture to the separation vessel. | [0085] The compressor may be any compressor capable of increasing the pressure of a gas. In some embodiments, the primary compressor and/or secondary compressor is a high volume reciprocating compressor, a rotational gas compressor, a piston compressor, a membrane compressor, or a screw compressor.As used herein, compressed cooled mixture refers to gaseous mixture that has been cooled and compressed by the means for cooling and compressing the gaseous mixture. As used herein, compressed cooled mixture includes a gaseous mixture that has been cooled in the primary heat exchanger and compressed by the primary compressor. In embodiments comprising a secondary compressor, the term compressed cooled mixture also refers to gaseous mixture that has been cooled in the primary heat exchanger and compressed by both the primary and secondary compressors. The term compressed cooled mixture also refers to gaseous mixture that has been cooled in the primary heat exchanger, compressed by at least the primary compressor, and cooled by one or more secondary heat exchangers. It will be understood that the phase of the compressed cooled mixture will be determined by the temperature and pressure of said mixture. In some embodiments, the compressed cooled mixture is a gas. In some embodiments, the compressed cooled mixture comprises both liquid and gas phases wherein the liquid phase comprises liquid carbon dioxide. | [0086] Heat exchangers for receiving and cooling compressed cooled mixture from a compressor may be any heat exchanger capable of reducing the temperature of a gas. In some embodiments, the one or more secondary heat exchangers comprise one or more conduits for receiving coolant. In some embodiments, the one or more secondary heat exchangers comprise an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled mixture from the primary compressor and/or the secondary compressor. In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium. | [0087] In some embodiments, the coolant is gaseous nitrogen. | [0088] In some embodiments wherein the gaseous mixture comprises nitrogen, the coolant is gaseous nitrogen extracted from the gaseous mixture. | [0089] In some embodiments, the coolant is an exogenous coolant. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. | [0090] In some embodiments, the one or more secondary heat exchangers comprise control means for regulating the flow of coolant through the conduit(s). In some embodiments, the control means for regulating the flow of coolant through the conduit(s) of the primary heat exchanger also controls the flow of coolant through the conduit(s) of the one or more secondary heat exchangers.In some embodiments, the conduit(s) of the primary heat exchanger are in fluid communication with the conduit(s) of the one or more secondary heat exchangers. | [0091] In some embodiments, the one or more secondary heat exchanger comprise an impeller for propelling compressed cooled mixture into the one or more secondary heat exchangers. | [0092] In some embodiments, the primary compressor is configured to compress the gaseous mixture to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, the secondary compressor is configured to compress the gaseous mixture to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In embodiments wherein the apparatus comprises a primary compressor and a secondary compressor, in some embodiments, the primary compressor is configured to compress the gaseous mixture to at least 1 MPa, and the secondary compressor is configured to compress the gaseous mixture to at least 10 MPa. | [0093] In some embodiments, the one or more secondary heat exchangers are configured to cool the gaseous mixture to a temperature of less than 0°C, less than -5°C, or less than -10°C. In some embodiments, the one or more secondary heat exchangers are configured to cool the gaseous mixture to a temperature of less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. | [0094] In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than 0°C, less than -5°C, less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. | [0095] In some embodiments, the means for cooling and compressing the gaseous mixture is configured to compress the gaseous mixture to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. | [0096] In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid. In some embodiments wherein the gaseous mixture comprises methane, the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid and at which methane forms a gas. In some embodiments wherein the gaseous mixture comprises nitrogen, the means for coolingand compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid and at which nitrogen forms a gas.| [0097] In some embodiments, such as when the gaseous mixture comprises carbon dioxide and methane, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than -30°C and to compress the gaseous mixture to at least 3 MPa. In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than -40°C and to compress the gaseous mixture to at least 2 MPa. In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than -50°C and to compress the gaseous mixture to at least 1 MPa. | [0098] The apparatus also comprises separation means for separating liquid carbon dioxide from gaseous components of the mixture. The separation means comprises a separation vessel comprising: (i) an inlet in fluid communication with the means for cooling and compressing the gaseous mixture for receiving the compressed cooled mixture; and (ii) a first outlet for venting gas. In some embodiments, the separation vessel further comprises (iii) a second outlet for out letting solid and/or liquid carbon dioxide. | [0099] The first outlet of the separation vessel allows gaseous components of the compressed cooled mixture to be removed from the separation vessel. In some embodiments, the first outlet comprises a nonreturn valve and/or a back-pressure valve. The non-return valve and/or back pressure valve may be mechanical spring operated, compressed gas operated or ball opening operated. | [0100] The second outlet of the separation vessel allows solid and/or liquid carbon dioxide to be removed from the separation vessel and separated from the gaseous components. In some embodiments, the second outlet comprises a tap and/or syphon. | [0101] The separation vessel is typically maintained at a temperature and pressure at which carbon dioxide is a liquid. Wherein the gaseous mixture comprises methane, separation vessel is typically maintained at a temperature and pressure at which carbon dioxide is a liquid and methane is a gas. Wherein the gaseous mixture comprises nitrogen, separation vessel is typically maintained at a temperature and pressure at which carbon dioxide is a liquid and nitrogen is a gas. | [0102] In some embodiments, the inlet of the separation vessel comprises a throttling valve for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture. In this embodiment, the means for cooling and compressing the gaseous mixture is typically configured tocool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a gas or liquid and the throttling valve is configured to induce phase change formation from gaseous cold or liquid carbon dioxide into either liquid or a deposition phase transition, or reverse sublimation process into solid carbon dioxide. | [0103] In some embodiments, the throttling valve is configured to receive the compressed cooled mixture from the primary compressor. In some embodiments, the throttling valve is configured to receive the compressed cooled mixture from the secondary compressor. In some embodiments, the throttling valve is configured to receive the compressed cooled mixture from the one or more secondary heat exchangers. | [0104] The throttling valve may be any valve that is capable of changing unilateral flow into turbulent flow. A throttling valve typically comprises an inlet and an outlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 10-fold, at least 20-fold, at least 30-fold, at least 40-fold, at least 50-fold, at least 60-fold, at least 70-fold, at least 80-fold, at least 90-fold, or at least 100-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the cross- sectional area of the throttling valve outlet is at least 50-fold greater than the cross-sectional area of the throttling valve inlet. | [0105] In some embodiments, the separation vessel comprises a tubular cone extending from the throttling valve outlet wherein the tubular diameter of the cone increases as it extends outwards from the throttling valve. | [0106] In some embodiments wherein the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid, the separation vessel does not comprise a throttling valve. | [0107] In some embodiments wherein the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid, the separation vessel comprises a throttling valve. In such embodiments, the throttling valve helps ensure that any remnant gaseous carbon dioxide is converted to liquid or solid carbon dioxide. | [0108] In some embodiments wherein the gaseous mixture comprises nitrogen, the first outlet is for venting gaseous nitrogen from the separation vessel. In some embodiments, the first outlet is configured to vent nitrogen to the atmosphere. In some embodiments, the first outlet for gaseous nitrogen is in fluid communication with the primary heat exchanger and/or the first outlet is in fluid communication withone or more of the secondary heat exchangers. In some embodiments, the first outlet is in fluid communication with a gaseous nitrogen storage vessel which is in fluid communication with the primary heat exchanger and/or the one or more secondary heat exchangers. As described in more detail above, the apparatus may comprise a control meansfor regulating the flow of extracted gaseous nitrogen through the primary heat exchanger and/or through the one or more secondary heat exchangers. | [0109] In some embodiments wherein the gaseous mixture comprises methane, the first outlet is for venting methane enriched gas from the separation vessel. In some embodiments, the apparatus further comprises methane enriched gas storage vessels in fluid communication with the first outlet of the separation vessel for containing methane enriched gas. | [0110] In some embodiments, the apparatus further comprises a holding tank for containing solid and/or liquid carbon dioxide from the separation vessel. | [0111] In some embodiments, the separation vessel comprises a carbon dioxide collection vessel comprising: (i) a throttling valve for receiving compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and (ii) a holding tank for containing solid and/or liquid carbon dioxide. | [0112] The holding tank is typically configured to accommodate the volumetric space required for the collection of solid and/or liquid carbon dioxide. | [0113] In some embodiments, the apparatus comprises a carbon dioxide collection vessel comprising: (i) a throttling valve in fluid communication with the second outlet of the separation vessel for receiving carbon dioxide; and (ii) a holding tank for containing solid and/or liquid carbon dioxide. The throttling valve may be any valve that is capable of changing unilateral flow into turbulent flow. A throttling valve typically comprises an inlet and an outlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 10-fold, at least 20-fold, at least 30-fold, at least 40-fold, at least 50- fold, at least 60-fold, at least 70-fold, at least 80-fold, at least 90-fold, or at least 100-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 50-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the carbon dioxide collection vessel comprises a tubular cone extending from the throttling valve outlet wherein the tubular diameter of the cone increases as it extends outwards from the throttling valve.In some embodiments wherein the gaseous mixture comprises methane, the apparatus further comprises a means for cooling and compressing methane, comprising: i) a tertiary heat exchanger in fluid communication with the first outlet of the separation vessel for receiving and cooling methane gas; and ii) a tertiary compressor in fluid communication with the tertiary heat exchanger for receiving and compressing cooled methane gas. In these embodiments, the separation vessel comprises a first outlet for methane gas and a second outlet for solid and/or liquid carbon dioxide. | [0114] In some embodiments, the gaseous mixture comprising methane is biogas or natural gas. | [0115] For ease of reference, references herein to "primary heat exchangers", "primary compressors", "secondary heat exchangers", "secondary compressors" and "further heat exchangers" refer to components of the means for cooling and compressing the gaseous mixture; and references to "tertiary heat exchangers" and "tertiary compressors" refer to components of the means for cooling and compressing methane, regardless of whetherthe apparatus comprises a secondary and/orfurther heat exchanger and/or a secondary compressor. | [0116] In some embodiments, the means for cooling and compressing methane comprises an impeller for propelling the methane gas into the tertiary heat exchanger. | [0117] In some embodiments, the tertiary heat exchanger is configured to cool the methane gas to a temperature of less than -75°C, less than -80°C, less than -90°C, less than -100°C, less than -110°C, less than -120°C, less than -130°C, less than -140°C, less than -150°C, less than -160°C, less than -170°C, or less than -180°C. | [0118] In some embodiments, the tertiary compressor is configured to compress the methane gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. | [0119] In some embodiments, the means for cooling and compressing methane is configured to cool and compress methane gas to a temperature and pressure at which methane forms a liquid. In some embodiments, the means for cooling and compressing methane is configured to cool the methane gas to a temperature of less than -100°C and to compress the methane gas to at least 3 MPa. In some embodiments, the means for cooling and compressing methane is configured to cool the methane gas to a temperature of less than -110°C and to compress the methane gas to at least 2 MPa. In some embodiments, the means for cooling and compressing methane is configured to cool the methane gas to a temperature of less than -125°C and to compress the methane gas to at least 1 MPa.Heat exchangers for receiving and cooling methane gas from the separation vessel may be any heat exchanger capable of reducing the temperature of a gas. In some embodiments, the tertiary heat exchanger comprises one or more conduits for receiving coolant. In some embodiments, the tertiary heat exchanger comprises an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the methane gas from the separation vessel. In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium. | [0120] In some embodiments, the tertiary heat exchanger comprises an exogenous coolant. The exogenous coolant may be any coolant suitable to cool the methane gas in the tertiary heat exchanger. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. In some embodiments, the exogenous gaseous nitrogen is extracted gaseous nitrogen. In some embodiments, the exogenous coolant is exogenous liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous liquid and/or gaseous carbon dioxide is extracted liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous coolant is a gas or liquid refrigerant. In some embodiments, the exogenous coolant comprises one or more of fluorocarbon, chlorofluorocarbon (R12), hydrochlorofluorocarbon (R22), hydrofluorocarbon (R410A, R134) freon, ammonia, sulphur dioxide, non-halogenated hydrocarbon, R404A, R407A, R407C, R407F, and R507. In some embodiments, the exogenous coolant comprises R744. | [0121] The tertiary compressor may be any compressor capable of increasing the pressure of a gas. In some embodiments, the tertiary compressor is a high volume reciprocating compressor, a rotational gas compressor, a piston compressor, a membrane compressor, or a screw compressor. | [0122] In some embodiments, the apparatus further comprises a methane collection vessel in fluid communication with the means for cooling and compressing methane. The methane collection vessel is for collecting and storing liquid methane. | [0123] In some embodiments, the separation vessel, carbon dioxide holding tank, and/or methane collection vessel comprises stainless steel and/or nickel-cobalt-chromium steel alloy. In some embodiments, the separation vessel, carbon dioxide holding tank, and/or methane collection vessel comprise an internal anti-corrosion coating. | [0124] In some embodiments, the apparatus is insulated to reduce heat influx from the external environment.In some embodiments, the apparatus comprises transfer conduits for delivering gaseous mixture through the apparatus from one component of the apparatus to a subsequent component of the apparatus. In some embodiments, the transfer conduits are insulated. Components of the apparatus include the primary heat exchanger, the primary compressor, and the separation vessel. Components of the apparatus may also comprise one or more secondary heat exchangers, one or more secondary compressors, one or more tertiary heat exchangers, one or more tertiary compressors, a holding tank, and/or a methane collection vessel. | [0125] In some embodiments, the apparatus further comprises one or more valves for maintaining unidirectional flow of gaseous mixture. In some embodiments, the valves are cryogenic non-return check valves. Advantageously, valves prevent thermal bridging and maintain states of matter. | [0126] In some embodiments, the apparatus further comprises additional heat exchangers and/or compressors for maintaining the temperature and pressure of the gaseous mixture and compressed cooled mixture within the apparatus. | [0127] In some embodiments, one or more of the primary, secondary and/or tertiary heat exchangers comprises a fridge or chiller. In some embodiments, one or more of the primary, secondary and/or tertiary heat exchangers comprises a heat exchanger in which recovered heat is stored and redistributed to another application, e.g. as a heating source. | [0128] The invention provides a method for producing solid and/or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to: (i) a secondary heat exchanger and/or (ii) a secondary compressor; and c) separating solid and/or liquid carbon dioxide from the gaseous phase of the mixture. | [0129] In some embodiments, the method comprises throttling the compressed cooled mixture through a throttling valve to provide solid and/or liquid carbon dioxide. | [0130] In some embodiments, the method of the invention comprises delivering gaseous mixture to the apparatus of the invention as described above. | [0131] In some embodiments wherein the gaseous mixture comprises nitrogen, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide to provide extracted gaseous nitrogen. The extracted gaseous nitrogen may be collected and stored. In someembodiments, the method comprises supplying the extracted gaseous nitrogen to the primary heat exchanger and/or secondary heat exchanger. | [0132] In some embodiments, the method comprises employing an exogenous coolant to cool the gaseous mixture in the primary heat exchanger during initiation of the carbon dioxide extraction process. In embodiments wherein the apparatus comprises one or more secondary heat exchangers, in some embodiments, the method comprises employing an exogenous coolant to cool the gaseous mixture in one or more of the secondary heat exchangers during initiation of the carbon dioxide extraction process. | [0133] In some embodiments wherein the gaseous mixture comprises nitrogen, the exogenous coolant is used to cool gaseous mixture until sufficient gaseous nitrogen is extracted from the gaseous mixture to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool the gaseous mixture in the primary heat exchanger and/or one or more secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. | [0134] In some embodiments, the method comprises regulating the flow of coolant through the primary heat exchanger and/or the secondary heat exchanger. The rate of flow of the coolant determines the rate of cooling of the gaseous mixture. Increasing the flow of coolant typically increases the rate of cooling of the gaseous mixture. Reducing the flow of coolant typically reduces the rate of cooling of the gaseous mixture. | [0135] In some embodiments, the primary heat exchanger cools the gaseous mixture to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. In some embodiments, the primary heat exchanger cools the gaseous mixture to a temperature of less than -30°C, optionally less than -40°C. | [0136] In some embodiments, the compressing comprises compressing the gaseous mixture to least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, compressing comprises compressing the gaseous mixture to at least 10 MPa. In some embodiments, the compressing comprises compressing the cooled gaseous mixture more than once. In some embodiments, the method comprises initially compressing the gaseous mixture to at least 1 MPa and then subsequently compressing the gaseous mixture to at least 10 MPa.In some embodiments, the method further comprises delivering compressed cooled gaseous mixture to a secondary heat exchanger. In some embodiments, the secondary heat exchanger cools the compressed cooled gaseous mixture to a temperature of less than 0°C, less than -5°C, or less than -10°C. | [0137] In some embodiments, the method comprises: (i) compressing the cooled gaseous mixture; (ii) cooling the compressed cooled gaseous mixture; (iii) compressing the cooled gaseous mixture; and then (iv) cooling the compressed cooled gaseous mixture. In some embodiments, the method comprises: (i) compressing the cooled gaseous mixture to less than 1 MPa; (ii) cooling the compressed cooled gaseous mixture to a temperature of less than -10°C; (iii) compressing the cooled gaseous mixture to less than 10 MPa; and then (iv) cooling the compressed cooled gaseous mixture to a temperature of less than -10°C. | [0138] In some embodiments, the method comprises cooling and compressing the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid. In some embodiments wherein the gaseous mixture comprises methane, the method comprises cooling and compressing the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid and at which methane forms a gas. | [0139] In some embodiments, such as when the gaseous mixture comprises carbon dioxide and methane, the method comprises cooling and compressing the gaseous mixture to a temperature of less than - 30°C and to a pressure of at least 3 MPa. In some embodiments, the method comprises cooling and compressing the gaseous mixture to a temperature of less than -40°C and to a pressure of at least 2 MPa. In some embodiments, the method comprises cooling and compressing the gaseous mixture to a temperature of less than -50°C and to a pressure of at least 1 MPa. | [0140] In some embodiments, the method comprises collecting solid carbon dioxide and allowing it to melt to form liquid carbon dioxide. In some embodiments, carbon dioxide is maintained at a pressure of at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, or at least 5 MPa in the holding tank. In some embodiments, carbon dioxide is maintained at a pressure of 3 MPa in the holding tank. In some embodiments, liquid carbon dioxide is stored in cryogenic pressure vessel equipment. | [0141] In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice. In some embodiments, solid carbon dioxide is converted to carbon dioxide ice by hydraulic pressing.In some embodiments, wherein the gaseous mixture comprises methane, the method further comprises: d) separating methane gas from solid and/or liquid carbon dioxide and delivering the methane gas to a tertiary heat exchanger to provide cooled methane gas; and e) compressing the cooled methane gas to provide liquid methane. | [0142] In some embodiments, cooling the methane gas comprises cooling the methane gas to a temperature of less than -75°C, less than -80°C, less than -90°C, less than -100°C, less than -110°C, less than -120°C, less than -130°C, less than -140°C, less than -150°C, less than -160°C, less than -170°C, or less than - 180°C. | [0143] In some embodiments, compressing the methane gas comprises compressing the methane gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. | [0144] In some embodiments, the method comprises cooling and compressing the methane gas to a temperature and pressure at which methane forms a liquid. In some embodiments, the method comprises cooling and compressing the methane gas to a temperature of less than -100°C and to a pressure of at least 3 MPa. In some embodiments, the method comprises cooling and compressing the methane gas to a temperature of less than -110°C and to a pressure of at least 2 MPa. In some embodiments, the method comprises cooling and compressing the methane gas to a temperature of less than -125°C and to a pressure of at least 1 MPa. | [0145] BRIEF DESCRIPTION OF THE FIGURES | [0146] Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying figures which are not drawn to scale. | [0147] Figure 1 provides a schematic representation of an exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, and carbon dioxide collection vessel. | [0148] Figure 2 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, and carbon dioxide collection vessel. | [0149] Figure 3 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary compressor, and carbon dioxide collection vessel.Figure 4 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, secondary compressor, further heat exchanger, and carbon dioxide collection vessel. | [0150] Figure 5 provides a schematic representation of another exemplary apparatus according to the invention comprising means for cooling and compressing a gaseous mixture, separation means, and means for cooling and compressing methane. | [0151] An exemplary apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas according to the invention is shown in Figure 1. The apparatus of the invention comprises a primary heat exchanger 10, a primary compressor 20, and a carbon dioxide collection vessel 30 comprising a throttling valve 32 and a holding tank 36. The apparatus may comprise means 12 for connecting to an exhaust flue. The apparatus may further comprise an impeller 14 for propelling exhaust flue gas into the primary heat exchanger 10. The carbon dioxide collection vessel 30 may comprise an outlet 34 for extracting gaseous nitrogen, and a gaseous nitrogen transfer conduit 40 in fluid communication with the primary heat exchanger 10. | [0152] The apparatus of Figure 2 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60. | [0153] The apparatus of Figure 3 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32. | [0154] The apparatus of Figure 4 comprises the features of the apparatus of Figure 1 and additionally comprises: a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20; a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger 60; and a further heat exchanger 65 for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor 25. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60 and/or further heat exchanger 65.An exemplary apparatus for extracting solid and/or liquid carbon dioxide and liquid methane from a gaseous mixture according to the invention is shown in Figure 5. The apparatus comprises: a) a means for cooling and compressing the gaseous mixture 100; b) a separation means 200; and c) a means for cooling and compressing methane 300. The means for cooling and compressing the gaseous mixture 100 comprises a primary heat exchanger 10 and a primary compressor 20. The separation means 200 comprises a separation vessel 201 having an inlet 202, a first outlet for gas 203 and a second outlet for solid and/or liquid carbon dioxide 204. The means for cooling and compressing methane 300 comprises a tertiary heat exchanger 302 for receiving methane gas from the first outlet 203 and a tertiary compressor 304 for receiving cooled methane gas from the tertiary heat exchanger 302. The apparatus may also comprise a holding tank for solid and/or liquid carbon dioxide 36 and/or a methane collection vessel 306. The apparatus may comprise an impeller 14 for propelling gaseous mixture into the primary heat exchanger 10. | [0155] Transfer conduits 50-59, 301, 303 and 305 are for transferring gaseous mixtures, cooled gaseous mixtures, compressed cooled mixtures, solid and/or liquid carbon dioxide, methane gas and/or liquid methane through the apparatus as depicted in Figures 1-5. | [0156] Specific example | [0157] The invention will now be described with reference to the following non-limiting example. | [0158] Exhaust flue gases may be redirected from the exhaust flue exit point that connects with the open-air environment, such as the above ground open air exit of a chimney into the lower atmosphere between 20 and 100 metres above ground level. The exhaust flue exit may be adapted to connect to a connection means, e.g. tubing comprising a 180° bend, to redirect exhaust flue gases towards the primary heat exchanger which may be at ground level. This downward directional tubing may connect to a manifold housing an internal impeller for propelling exhaust flue gases into the primary heat exchanger, optionally into a labyrinth chamber of the primary heat exchanger. This downward directional tubing may connect directly to the primary heat exchanger. The primary heat exchanger may comprise a labyrinth chamber comprising a network array matrix of interconnecting channels and tubing that inter-collectively contain a series of pressure vessel conduits acting as a large heat exchanger for the transport of a coolant, e.g. cold and vented gaseous nitrogen. This cold, gaseous nitrogen does not typically come into direct contact with the exhaust flue gases. The pressure vessel tubing of the conduits acts as a conductor of heat from the exhaust flue gases into the coolant, e.g. the gaseous nitrogen, thereby heating the coolant and simultaneously cooling the exhaust flue gases in the heat exchange chiller labyrinth. The exhaust flue gases may be cooled to a temperature of atleast -40°C. Gaseous nitrogen may be allowed to cool and vented to the atmosphere after flowing through the conduits of the primary heat exchanger. | [0159] Control over the temperature of the exhaust flue gases in the primary heat exchanger may be performed by control means configured to control the rate of flow of the cold gaseous nitrogen in the heat exchange chiller labyrinth. Increasing the rate of flow of cold gaseous nitrogen cools the exhaust flue gases quicker and slowing the rate of flow of cold gaseous nitrogen helps prevent the exhaust flue gases cooling down below the desired temperature, e.g. -40°C. Flow rate may be controlled by flow sensors in the cold gaseous nitrogen pumping system. The size of the heat exchange chiller labyrinth is typically designed to match the known maximum gas flow rate obtained from the exhaust flue during functional operation of the engine, boiler or coal-fired power station, so that the thermodynamic heat fluxes of the two temperature regimes are synchronised to accommodate from the known temperature of the gases upon leaving the original chimney design until exiting the heat exchange chiller labyrinth system. Typically, this may result in a temperature drop from between 50°C and 90°C to between -10°C and -40°C, ideally at least -30°C, or preferably at least -40°C. | [0160] The main function of chilling the exhaust flue gases is to prepare the gases for phase change. The heat exchange chiller labyrinth itself does not initiate the phase change - it changes the temperature of the gases but not the pressure. As such, the exhaust flue gases are typically cooled to a temperature of - 40°C and remain in gaseous state at the point of leaving the primary heat exchanger. As the cooled exhaust flue gases leave the primary heat exchanger, the external surface of the transfer conduits that deliver cooled exhaust flue gases through the apparatus are typically insulated to ensure that the gases remain at their cooled temperature throughout their transitionary passage to formation of primarily solid carbon dioxide and secondarily liquid carbon dioxide. | [0161] Upon leaving the heat exchange chiller labyrinth, the cooled exhaust flue gas is typically delivered via transfer conduit(s) to a primary compressor. The primary compressor may compress the exhaust flue gases from approximately 10 KPa to approximately 1 MPa. After primary stage compression, exhaust flue gases may be partially warmed as a result of a reduction in their volume during the compression process. Exhaust flue gases may then be chilled back to about -10°C in a secondary heat exchanger. The compressed cooled exhaust flue gas may then be compressed by a secondary compressor to compress the compressed cooled exhaust flue gas from approximately 1 MPa to 10 MPa. Compressed cooled exhaust flue gases may then be chilled back to -10°C via exposure to the same secondary heat exchanger or a further heat exchanger.Compressed cooled exhaust flue gases typically contain multiphase flow of gaseous nitrogen, as well as chilled gaseous carbon dioxide. Other majority contaminants from coal-fired power station may have previously been removed using a flue gas desulphurisation cleaning process for removal of SOx, prior to delivery of the exhaust flue gas to the primary heat exchanger, thus ensuring that most of the gases in the apparatus comprise gaseous nitrogen and carbon dioxide. This cold gas mixture may be maintained within the system by means of placement of cryogenic non-return check valves in unidirectional flow. Check valves may help to prevent thermal bridging and maintain states of matter. Optionally, adjacent and strategically placed heat exchangers and/or maintenance compressors may be present to ensure that during transit of the exhaust flue gases through the apparatus, the temperature and pressure of the gas is maintained. | [0162] The compressed cooled exhaust flue gas is delivered to a throttling valve. The throttling valve acts to change unilateral liquid flow into turbulent flow. In the throttling valve there is typically an adiabatic drop due to the pressure drop with increased gas velocity. Simultaneously, upon ejection of the compressed cooled exhaust flue gas from the throttling valve, the tubular aperture may be significantly increased, e.g. at least 50-fold, so that the cross-sectional area of the compressed cooled exhaust flue gas before the throttling valve is significantly smaller than the cross-sectional area, e.g. 1/50 of the cross-sectional area, of the venting tube after the throttling valve. Simultaneously, the exit from the throttling valve may extend in a tubular cone orientation as the output end of the contents of throttling valve of the compressed cooled exhaust flue gas extend into the larger aperture holding chamber. The tubular cone extension on the output side of the throttling valve may act to create cyclonic turbulent flow and a sudden drop in pressure, with a simultaneous drop in temperature. This typically creates the phase change formation from gaseous cold carbon dioxide into a deposition phase transition, or reverse sublimation process into solid carbon dioxide 'snow' at a temperature below -78°C and mixed with cold gaseous nitrogen. The cold gaseous nitrogen may be vented, collected and pumped for reverse passage through the primary and/or secondary heat exchangers. The holding tank is typically designed to accommodate the volumetric space required for the input of solid carbon dioxide 'snow', so that its accumulation can readily be melted from solid carbon dioxide 'snow' into liquid carbon dioxide. The entire cooled zone from the primary heat exchanger through to the carbon dioxide collection vessel may be insulated to prevent heat influx from the external environment. The liquid carbon dioxide product may be stored using conventional cryogenic pressure vessel equipment of either tank or bulk storage systems, and transported to pertinent markets worldwide. Alternatively, hydraulic pressing may be used as a functional methodology to change the form of solid crystalline carbon dioxide snow into compressed carbon dioxide ice, or dry ice.The apparatus may comprise a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The purpose of the gas bypass system is to act as a regulatory control mechanism, coupling to the exhaust flue and preceding placement of the primary heat exchanger described herein. The gas bypass system simultaneously avoids unwanted back pressure on the engine or boiler, allowing smooth, continuous and uninterrupted flow of exhaust flue gases from the engine or boiler, thereby ensuring that the regulatory control feedback mechanism for the temperature and pressure of the engine or boiler is functional. The exhaust flue gas bypass system may be constructed as a partitioned parallel exhaust chamber with a warmer than ambient temperature internal gaseous flow control mechanism. The secondary partitioned parallel exhaust chamber may have a modified heat and pressure take-off ensuring that exhaust flue modifications do not compromise or have any effects on the designed operations and efficiency of the engine or boiler by means of a unidirectional gas flow valve flap. | [0163] Statements of invention | [0164] The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising: a) a primary heat exchanger for receiving and cooling the exhaust flue gas; b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and (ii) a holding tank for containing solid and/or liquid carbon dioxide. | [0165] In some embodiments, the apparatus further comprises one or more secondary heat exchangers for receiving and cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel. | [0166] In some embodiments, the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen, wherein the outlet is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers. | [0167] In some embodiments, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue.In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue. | [0168] In some embodiments, the primary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas. | [0169] In some embodiments, the secondary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas. | [0170] In some embodiments, the apparatus further comprises an impeller for propelling the exhaust flue gas into the primary heat exchanger. | [0171] In some embodiments, the apparatus further comprises one or more impellers for propelling the compressed cooled exhaust flue gas into one or more of the one or more secondary heat exchangers.| [0172] In some embodiments, the apparatus further comprises a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor. | [0173] In some embodiments, one or more of the one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor. | [0174] In some embodiments, one or more of the one or more secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel. | [0175] In some embodiments: (a) one or more of the secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more of the secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.| [0176] In some embodiments, the apparatus comprises one or more valves for maintaining unidirectional flow of exhaust flue gas. | [0177] The invention also provides a method for producing solid or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondaryheat exchanger; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide. | [0178] In some embodiments, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger. | [0179] In some embodiments, the cooling comprises reducing the temperature of the gas to less than -10°C.| [0180] In some embodiments, the compressing comprises compressing the gas to at least 1 MPa. | [0181] In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing. | (WO2023/144550)|[0001] EXTRACTION DEVICE | [0002] FIELD OF THE INVENTION | [0003] The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to methods for extracting solid or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. The invention also relates to apparatus and methods for extracting solid and/or liquid carbon dioxide and liquid methane from gaseous mixtures, such as natural gas and biogas. | [0004] BACKGROUND OF THE INVENTION | [0005] Global carbon dioxide emissions amount to over 10 giga tonnes per year. Simultaneously, there is a considerable requirement for carbon dioxide in a multitude of applications, such as urea fertiliser production, enhanced oil recovery processes, production of food and beverages, and other industrial processes. Approximately 250 million tonnes of carbon dioxide, corresponding to approximately 2.5% of all global emissions, are used each year for these purposes. Presently, almost all such carbon dioxide is derived from fossil fuel based sources. | [0006] In line with multiple unilateral governmental policies to reduce atmospheric global emissions of carbon dioxide, many nations are either decommissioning, scrapping or modifying existing coal-fired power stations or considering other abatement alternative scenarios. Coal-fired power stations emit approximately 80 tonnes of carbon dioxide gas per hour for every 100 MWh of electricity power generation capacity, depending on their construction and the coal fuel type being burned. This gross carbon dioxide emissions capacity exceeds comparative tonnages remediated for bioenergy with carbon capture and storage (BECCS). Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. Post combustion carbon capture and storage with amine scrubbing technologies in coal-fired power plants is a recent technology application, but even with subsidies it is expensive, typically costing between $80/tonne of carbon dioxide for first of a kind technologies and $60/tonne of carbon dioxide for next of a kind technology. | [0007] Retro-conversion of older coal-fired electricity power generation plants for carbon dioxide remediation was not considered as a future possibility when these plants were built, resulting in low availability of physical space and high costs. With many coal-fired power plants not able to beconverted into environmentally benign non-polluting retro-fitted alternatives, some are now being shut down as a result of new legislation policies. This, in turn, drives an increased demand for electricity generation from alternative sources. | [0008] According to the US Environmental Protection Agency, methane (CH4) gas has 25 times the global warming potential of CO2, whereas in compositional makeup, CO2 contributes over three-quarters of all greenhouse gases. Natural gas is a valuable commodity, yet the global gas industry flared 142 billion cubic metres ('BCM') in 2020. Due to incomplete combustion, flaring is a significant source of global methane emissions and must be reduced by 85% if the global gas industry is to meet net zero targets. | [0009] On the other hand, biogas is currently not released or flared directly into the environment. Instead, it is burned as a fuel for electricity or concentrated for domestic cooking fuel or heating. The stoichiometric combustion of one molecule of methane results in the consumption of two molecules of oxygen to produce one molecule of CO2 and two molecules of water. Consequently, all of the carbon contained within biogas plants is eventually lost into the atmosphere, either as CO2 pre-combustion or CO2 post-combustion. | [0010] There exists an urgent and unmet need for carbon capture processes that are efficient, scalable and inexpensive. To avoid expensive and wasteful decommissioning of existing coal-fired electricity power generation plants, there exists an urgent and unmet need for carbon capture processes that reduce the carbon dioxide emissions from these plants to the environment. Furthermore, there is an urgent and unmet need for carbon capture processes to further improve the environmental and economic performance of biogas plants and landfill gas sites. There is also an unmet industrial demand for carbon dioxide that is not derived directly from virgin fossil fuels e.g. for use in the ammonia fertiliser, enhanced oil recovery, medical, food and beverage industries. There is also an unmet need for biogas- derived or natural gas-derived methane which contains a lower proportion of carbon dioxide. | [0011] SUMMARY OF THE INVENTION | [0012] The present invention solves the above-mentioned problems by providing an apparatus for extracting solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. Advantageously, the apparatus of the invention can be used to extract and capture carbon dioxide that would otherwise be released into the atmosphere, thereby reducing contributions to global carbon dioxide emissions. Carbon dioxide extracted by the invention may be stored to prevent its entry into the atmosphere. Carbon dioxide extracted by the invention may also be used in industry, e.g. to reduce the reliance on carbon dioxide produced from virgin fossil fuels, thereby further reducing carbon dioxide emissions.The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures. | [0013] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from exhaust flue gas. The present invention is not limited to any particular type of exhaust flue gas. Likewise, the present invention is not limited to any particular type of flue. As such, the apparatus of the invention can advantageously be used to extract carbon dioxide from a range of sources, such as exhaust flue gases, such as from boilers, engines, and fossil fuel-fired power stations. | [0014] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from biogas. Sequestration of carbon dioxide from biogas plants can advantageously render the emissions from these plants net carbon negative. | [0015] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from natural gas. | [0016] The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. Liquid methane can advantageously be used as a low-carbon fuel, e.g. to power engines in trucks, ships and other heavy equipment such as tractors. | [0017] In some embodiments, the apparatus of the invention is for extracting liquid methane from biogas. | [0018] In some embodiments, the apparatus of the invention is for extracting liquid methane from natural gas. | [0019] The invention also relates to an apparatus for the extraction of solid and/or liquid carbon dioxide and for the extraction of liquid methane from gaseous mixtures, such as natural gas and biogas. | [0020] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and for extracting liquid methane from natural gas. The extraction of carbon dioxide and/or methane from natural gas offers an alternative to flaring that is both environmentally and economically favourable. | [0021] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and for extracting liquid methane from biogas. | [0022] The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from a gaseous mixture, the apparatus comprising: a) means for cooling and compressing the gaseous mixture, the means comprising: i) a primary heat exchanger for receiving and cooling the gaseous mixture; and ii)a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger to provide a compressed cooled mixture; and b) separation means for extracting carbon dioxide from the compressed cooled mixture, the separation means comprising a separation vessel comprising: i) an inlet for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and ii) a first outlet for venting gas from the separation vessel. | [0023] In some embodiments, the separation vessel further comprises: (iii) a second outlet for out letting solid and/or liquid carbon dioxide. | [0024] In some embodiments, the separation vessel inlet comprises a throttling valve for receiving compressed cooled mixture from the means for cooling and compressing the gaseous mixture.| [0025] In some embodiments, the separation vessel is configured to contain solid and/or liquid carbon dioxide. In some embodiments, the apparatus further comprises a holding tank configured to receive and contain solid and/or liquid carbon dioxide from the second outlet of the separation vessel.| [0026] In some embodiments, the holding tank provides a carbon dioxide collection vessel, wherein the carbon dioxide collection vessel further comprises a throttling valve in fluid communication with the second outlet of the separation vessel for receiving carbon dioxide. | [0027] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises one or more secondary heat exchangers for receiving and cooling the compressed cooled mixture from the primary compressor. | [0028] In some embodiments, the gaseous mixture comprises nitrogen. In some embodiments, the first outlet of the separation vessel is for venting gaseous nitrogen, wherein the first outlet is in fluid communication with the primary heat exchanger and/or the first outlet is in fluid communication with one or more of the secondary heat exchangers. In some embodiments, the primary heat exchanger and/or one or more of the secondary heat exchangers comprise an array of conduits for receiving gaseous nitrogen from the separation vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the gaseous mixture. | [0029] In some embodiments, the gaseous mixture is exhaust flue gas and wherein the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue. In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.In some embodiments, the apparatus further comprises an impeller for propelling the gaseous mixture into the primary heat exchanger. In some embodiments, the apparatus further comprises one or more impellers for propelling the compressed cooled mixture into one or more of the one or more secondary heat exchangers. | [0030] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises a secondary compressor for receiving and compressing compressed cooled mixture from the primary compressor. In some embodiments, one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor. In some embodiments, one or more secondary heat exchangers is situated between the secondary compressor and the separation means. | [0031] In some embodiments, (a) one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more secondary heat exchangers is situated between the secondary compressor and the separation means. | [0032] In some embodiments, the apparatus comprises one or more valves for maintaining unidirectional flow of the mixture. | [0033] In some embodiments, the gaseous mixture comprises methane and the first outlet is configured to vent methane enriched gas from the separation vessel. | [0034] In some embodiments, the gaseous mixture comprises methane and the apparatus further comprises: c) a means for cooling and compressing methane, the means comprising: i) a tertiary heat exchanger in fluid communication with the first outlet of the separation vessel for receiving and cooling methane gas; and ii) a tertiary compressor in fluid communication with the tertiary heat exchanger for receiving and compressing cooled methane gas to provide liquid methane. | [0035] In some embodiments, the apparatus further comprises a methane collection vessel in fluid communication with the means for cooling and compressing methane, wherein the methane collection vessel is for collecting liquid methane. | [0036] In some embodiments, the apparatus further comprises an impeller for propelling methane gas into the tertiary heat exchanger. | [0037] In some embodiments, the tertiary heat exchanger comprises an array of conduits for receiving coolant and wherein the array of conduits forms a labyrinth chamber for receiving the methane gas.| [0038] In some embodiments, the means for cooling and compressing the gaseous mixture comprises a dehumidifier.The invention also provides: (A) a method for producing solid or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to a secondary heat exchanger; and c) separating liquid carbon dioxide from the gaseous phase of the mixture; and (B) a method for producing gaseous methane from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture comprising liquid and/or solid carbon dioxide and gaseous methane; and c) separating liquid and/or solid carbon dioxide from gaseous methane. In some embodiments, the method further comprises a step of cooling and compressing the gaseous methane to provide liquid methane. | [0039] In some embodiments, the method comprises throttling the compressed cooled mixture through a throttling valve to provide solid and/or liquid carbon dioxide. | [0040] In some embodiments, the gaseous mixture comprises nitrogen and the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger. | [0041] In some embodiments, the cooling comprises reducing the temperature of the gas to less than -10°C.| [0042] In some embodiments, the compressing comprises compressing the gas to at least 1 MPa. | [0043] In some embodiments, the cooling comprises reducing the temperature of the gas to less than -30°C.| [0044] In some embodiments, the compressing comprises compressing the gas to at least 3 MPa. | [0045] In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing. | [0046] In some embodiments, the gaseous mixture comprises methane and the method further comprises: d) separating methane gas from solid and/or liquid carbon dioxide and delivering the methane gas to a tertiary heat exchanger to provide cooled methane gas; and e) compressing the cooled methane gas to provide liquid methane. | [0047] In some embodiments, cooling the methane gas comprises reducing the temperature of the methane gas to less than -100°C. | [0048] In some embodiments, compressing the methane gas comprises compressing the methane gas to at least 3 MPa.DETAILED DESCRIPTION OF THE INVENTION | [0049] The present invention is based on the surprising discovery that solid and/or liquid carbon dioxide can be efficiently extracted from gaseous mixtures by varying the pressure and temperature of the gaseous mixtures. The apparatus and method of the invention advantageously provide a means for reducing the carbon dioxide emissions of energy generating devices. Moreover, carbon dioxide extracted by the apparatus and method of the invention has a number of applications in industry. Carbon dioxide extracted by the apparatus and methods of the invention may also be stored, to prevent its entry to the atmosphere, thereby reducing contributions to greenhouse gases. | [0050] Advantageously, the apparatus of the invention can be used to reduce the carbon dioxide emissions from existing electricity generating power stations by extracting carbon dioxide from the exhaust flue gases generated by said power stations. Reducing the negative environmental impact of these power stations, by reducing their carbon dioxide emissions without sacrificing the efficiency of energy generation, may help avoid these power stations being decommissioned. | [0051] Liquid carbon dioxide extracted using the apparatus and methods of the invention can be stored in subterraneous storage systems. Liquid carbon dioxide at high subterraneous pressures may be maintained for a long time in liquid state due to increased pressure from burial in subterranean lakes of liquid carbon dioxide, resulting in limited surface leakage over an extended period of time. This is a desirable alternative to the current practise of allowing carbon dioxide to be released into the atmosphere. Liquid carbon dioxide extracted using the apparatus of the invention may also be used to produce pressure changes within underground water and oil reservoirs, for applications such as instigating enhanced oil recovery and/or additional extraction of oil from otherwise depleted oil reservoirs. | [0052] As used herein, a "gaseous mixture" is a gas comprising carbon dioxide. In some embodiments, the gaseous mixture comprises nitrogen. In some embodiments, the gaseous mixture comprises methane. In some embodiments, the gaseous mixture comprises carbon dioxide and nitrogen. In some embodiments, the gaseous mixture comprises carbon dioxide and methane. | [0053] In some embodiments, the gaseous mixture is exhaust flue gas. Exhaust flue gas typically comprises carbon dioxide and nitrogen. | [0054] In some embodiments, the gaseous mixture is biogas or natural gas. Biogas and natural gas typically comprise carbon dioxide and methane.In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from exhaust flue gas. Exhaust flue gas is typically generated by the combustion of a fuel, such as a fossil fuel (e.g. coal), biofuel or sustainable fuel. Exhaust flue gas may be generated by various energy generating devices, e.g. boilers, engines, generators, and power stations (e.g. fossil fuel-fired power stations). | [0055] In some embodiments, exhaust flue gas is treated by flue gas desulphurisation (FGD) methods to remove sulphur dioxide prior to delivery of the exhaust flue gas to the apparatus of the invention. In some embodiments, exhaust flue gas is post-desulphurisation exhaust flue gas. Typical post-desulphurisation exhaust flue gas comprises mainly gaseous carbon dioxide and nitrogen. | [0056] In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide from a gaseous mixture comprising methane to provide a gaseous mixture enriched in methane. In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and liquid methane from a gaseous mixture comprising methane. In some embodiments, the gaseous mixture comprising methane is biogas or natural gas. | [0057] In some embodiments, the gaseous mixture comprising methane is biogas. Biogas is a renewable energy source produced by anaerobic digestion of organic matter, such as food or animal waste. Biogas typically contains a mixture of approximately 60% methane (CH4) and 40% carbon dioxide (CO2). In some embodiments, the apparatus of the invention is for extracting solid and/or liquid carbon dioxide and liquid methane from biogas. By separating biogas into its constituent parts, the economic and environmental feasibility of biogas plants and landfill gas sites can be significantly improved. | [0058] Biogas upgrading is the process by which biogas is converted to methane enriched gas which can be supplied directly to the gas grid. The technology currently used for biogas-to-grid upgrading involves the use of membrane-based separation technologies to separate methane from carbon dioxide (which is typically released into the atmosphere). There are various disadvantages associated with this process, including the propensity for the filters to become clogged or wet thereby requiring regular inspections for their replacement. These consumable filter components are expensive and require associated pumping, pressurisation and regulation equipment to ensure they are working correctly. These factors negatively impact the economic feasibility of current biogas-to-grid upgrading technologies. Advantageously, the apparatus and methods described herein can be used to extract both carbon dioxide and high quality methane from biogas. The methane enriched gas can be injected directly into the gas grid. Alternatively, the methane can be converted into liquid methane to enable more convenient storage and transport. The carbon dioxide can be stored or used in downstreamapplications as described herein which provides important environmental benefits as opposed to simply releasing the carbon dioxide into the environment. | [0059] The apparatus of the invention comprises a means for cooling and compressing the gaseous mixture. The means for cooling and compressing the gaseous mixture comprises a primary heat exchanger for receiving and cooling the gaseous mixture. The primary heat exchanger may be any heat exchanger capable of reducing the temperature of the gaseous mixture. | [0060] In some embodiments, the primary heat exchanger comprises one or more conduits for receiving coolant. The conduit(s) act as a conductor of heat from the gaseous mixture to the coolant thereby simultaneously cooling the gaseous mixture and increasing the temperature of the coolant. In some embodiments, the primary heat exchanger comprises a plurality of conduits for receiving coolant. In some embodiments, the primary heat exchanger comprises an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the gaseous mixture. Advantageously, an array of conduits provides a large surface area for contacting the gaseous mixture in the labyrinth chamber thereby allowing even faster cooling of the gaseous mixture. | [0061] In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium. | [0062] In some embodiments, the coolant is gaseous nitrogen. In some embodiments wherein the gaseous mixture comprises nitrogen, the coolant is gaseous nitrogen extracted from the gaseous mixture. As used herein, extracted gaseous nitrogen refers to gaseous nitrogen that has been extracted from the gaseous mixture. | [0063] In some embodiments, the coolant is an exogenous coolant. | [0064] In embodiments wherein the gaseous mixture comprises nitrogen, an exogenous coolant may be employed to cool the gaseous mixture in one or more heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, the exogenous coolant is used to cool gaseous mixture until sufficient gaseous nitrogen is extracted from the gaseous mixture to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool gaseous mixture in the primary heat exchanger and/or one or more secondary heat exchangers. In some embodiments wherein the gaseous mixture comprises nitrogen, the primary heat exchangerand/or secondary heat exchangers comprise one or more conduits for receiving exogenous coolant which are separate from the one or more conduits configured to receive extracted gaseous nitrogen. | [0065] In some embodiments, the means for cooling and compressing the gaseous mixture comprises a dehumidifier. In some embodiments, the primary heat exchanger comprises a dehumidifier. The dehumidifier advantageously removes water and impurities from the gaseous mixture. In some embodiments, the dehumidifier cools the gaseous mixture to less than 5°C, optionally less than 4°C. | [0066] In some embodiments, the apparatus comprises a compressor and an evaporator in fluid communication with the one or more exogenous coolant conduits. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers, the compressor and evaporator. Circulation may be automatic or may be manually controlled. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers to increase the rate of cooling of gaseous mixture by the primary and/or secondary heat exchangers. | [0067] The exogenous coolant may be any coolant suitable to cool the gaseous mixture in the primary and/or secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. In some embodiments, the exogenous coolant is a gas or liquid refrigerant. In some embodiments, the exogenous coolant is exogenous liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous liquid and/or gaseous carbon dioxide is extracted liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous coolant comprises one or more of fluorocarbon, chlorofluorocarbon (R12), hydrochlorofluorocarbon (R22), hydrofluorocarbon (R410A, R134) freon, ammonia, sulphur dioxide, non-halogenated hydrocarbon, R404A, R407A, R407C, R407F, and R507. In some embodiments, the exogenous coolant comprises R744. | [0068] After cooling the gaseous mixture in the primary heat exchanger, coolant comprising extracted gaseous nitrogen is typically vented into the atmosphere. | [0069] In some embodiments, the primary heat exchanger comprises a control means for regulating the flow of coolant through the conduit(s). The rate of flow of the coolant determines the rate of cooling of the gaseous mixture. Increasing the flow of coolant typically increases the rate of cooling of the gaseous mixture. Reducing the flow of coolant typically reduces the rate of cooling of the gaseous mixture. The control means may comprise flow sensors. The control means may reduce the flow of coolant in response to reduced flow of gaseous mixture into the primary heat exchanger. The control means may increase the flow of coolant in response to increased flow of gaseous mixture into the primary heatexchanger. In some embodiments, the control means is configured to control the flow of extracted gaseous nitrogen through the conduit(s). In some embodiments, the control means is configured to control the flow of exogenous coolant through the one or more exogenous coolant conduits. In some embodiments, the control means comprises a coolant valve configured to control the flow of coolant through the conduit(s). In some embodiments, the coolant valve is a flow control valve. | [0070] In some embodiments, the apparatus further comprises an impeller for propelling the gaseous mixture into the primary heat exchanger. The impeller may be any rotatable component capable of propelling the gaseous mixture into the primary heat exchanger. In some embodiments, the apparatus comprises a manifold for housing the impeller. | [0071] In some embodiments wherein the gaseous mixture is exhaust flue gas, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the exhaust flue. Typically, the connection means is configured to connect to the exit point of an exhaust flue, i.e. the region of an exhaust flue that releases exhaust flue gas into the environment. In some embodiments, the connecting means is configured to direct exhaust flue gases to ground level, or a subterranean level. In some embodiments, the impeller is situated between the connection means and the primary heat exchanger. | [0072] In embodiments wherein the gaseous mixture is exhaust flue gas, the primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the exhaust flue during normal operation of the energy generating device to which the exhaust flue is connected, e.g. engine, boiler or power station. | [0073] In some embodiments wherein the gaseous mixture is exhaust flue gas, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas. Typically, the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The gas bypass system provides a regulatory control mechanism to avoid unwanted back pressure on the exhaust flue, e.g. when the flow of exhaust flue gas in the exhaust flue exceeds the maximum flow rate of the apparatus e.g. the maximum flow rate of the primary heat exchanger. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber with a gaseous flow control mechanism. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber having a modified heat and pressure take-off. Advantageously, a modified heat and pressure take-off ensures that exhaust flue modifications do not compromise the designed operations and efficiency of the energy generating device. In some embodiments, the gas bypass system comprises a unidirectional gas flow valve flap.In some embodiments wherein the gaseous mixture comprises nitrogen, the apparatus further comprises a gas separation array for extracting nitrogen from the gaseous mixture, wherein the gas separation array is positioned before the means for cooling and compressing the gaseous mixture. In some embodiments, the gas separation array comprises a gas separation membrane. In some embodiments, the gas separation array comprises a gas separation vortex. | [0074] In some embodiments wherein the gaseous mixture is biogas, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the biogas source. The biogas source may be a biogas storage vessel. The biogas source may be a biogas plant, such as an anaerobic digestor or a landfill gas plant. In embodiments wherein the gaseous mixture is biogas, the primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the biogas source during normal operation, e.g. of the anaerobic digestor or landfill gas site. | [0075] In some embodiments wherein the gaseous mixture is natural gas, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the natural gas source. The natural gas source may be a natural gas storage vessel. The natural gas source may be an oil and/or gas extraction site (e.g. an oil and/or gas well). In embodiments wherein the gaseous mixture is natural gas, the primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the natural gas source during normal operation. In some embodiments wherein the gaseous mixture is natural gas, the apparatus further comprises a gas bypass system for venting excess natural gas from the source of natural gas. | [0076] In some embodiments, the primary heat exchanger is configured to cool the gaseous mixture to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. As used herein, cooled gaseous mixture refers to gaseous mixture that has been cooled by the primary heat exchanger. | [0077] The means for cooling and compressing the gaseous mixture comprises a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger. The primary compressor compresses cooled gaseous mixture from the primary heat exchanger to provide compressed cooled mixture. | [0078] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises one or more secondary heat exchangers for cooling compressed cooled mixture from the primary compressor prior to passage of the compressed cooled mixture to the separation vessel.In some embodiments, the means for cooling and compressing the gaseous mixture further comprises one or more secondary compressors for compressing compressed cooled mixture from the primary compressor prior to passage of the compressed cooled mixture to the separation vessel. | [0079] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises: (i) a secondary compressor for receiving and compressing compressed cooled mixture from the primary compressor; and (ii) a secondary heat exchanger for receiving and cooling compressed cooled mixture from the secondary compressor. | [0080] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises: (i) a secondary heat exchanger for receiving and cooling compressed cooled mixture from the primary compressor; and (ii) a secondary compressor for receiving and compressing compressed cooled mixture from the secondary heat exchanger. | [0081] In some embodiments, the means for cooling and compressing the gaseous mixture further comprises:| [0082] (i) a secondary heat exchanger for receiving and cooling compressed cooled mixture from the primary compressor; (ii) a secondary compressor for receiving and compressing compressed cooled mixture from the secondary heat exchanger; and (iii) a further heat exchanger for receiving and cooling compressed cooled mixture from the secondary compressor. In this embodiment, during operation the cooled mixture from the primary heat exchanger is: (i) compressed by the primary compressor;| [0083] (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the further heat exchanger, prior to passage of the compressed cooled mixture to the separation vessel. | [0084] In some embodiments, the secondary heat exchanger is configured to receive and cool compressed cooled mixture from both the primary compressor and the secondary compressor. In this embodiment, during operation the cooled gaseous mixture from the primary heat exchanger is: (i) compressed by the primary compressor; (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the secondary heat exchanger prior to passage of the compressed cooled mixture to the separation vessel. | [0085] The compressor may be any compressor capable of increasing the pressure of a gas. In some embodiments, the primary compressor and/or secondary compressor is a high volume reciprocating compressor, a rotational gas compressor, a piston compressor, a membrane compressor, or a screw compressor.As used herein, compressed cooled mixture refers to gaseous mixture that has been cooled and compressed by the means for cooling and compressing the gaseous mixture. As used herein, compressed cooled mixture includes a gaseous mixture that has been cooled in the primary heat exchanger and compressed by the primary compressor. In embodiments comprising a secondary compressor, the term compressed cooled mixture also refers to gaseous mixture that has been cooled in the primary heat exchanger and compressed by both the primary and secondary compressors. The term compressed cooled mixture also refers to gaseous mixture that has been cooled in the primary heat exchanger, compressed by at least the primary compressor, and cooled by one or more secondary heat exchangers. It will be understood that the phase of the compressed cooled mixture will be determined by the temperature and pressure of said mixture. In some embodiments, the compressed cooled mixture is a gas. In some embodiments, the compressed cooled mixture comprises both liquid and gas phases wherein the liquid phase comprises liquid carbon dioxide. | [0086] Heat exchangers for receiving and cooling compressed cooled mixture from a compressor may be any heat exchanger capable of reducing the temperature of a gas. In some embodiments, the one or more secondary heat exchangers comprise one or more conduits for receiving coolant. In some embodiments, the one or more secondary heat exchangers comprise an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled mixture from the primary compressor and/or the secondary compressor. In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium. | [0087] In some embodiments, the coolant is gaseous nitrogen. | [0088] In some embodiments wherein the gaseous mixture comprises nitrogen, the coolant is gaseous nitrogen extracted from the gaseous mixture. | [0089] In some embodiments, the coolant is an exogenous coolant. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. | [0090] In some embodiments, the one or more secondary heat exchangers comprise control means for regulating the flow of coolant through the conduit(s). In some embodiments, the control means for regulating the flow of coolant through the conduit(s) of the primary heat exchanger also controls the flow of coolant through the conduit(s) of the one or more secondary heat exchangers.In some embodiments, the conduit(s) of the primary heat exchanger are in fluid communication with the conduit(s) of the one or more secondary heat exchangers. | [0091] In some embodiments, the one or more secondary heat exchanger comprise an impeller for propelling compressed cooled mixture into the one or more secondary heat exchangers. | [0092] In some embodiments, the primary compressor is configured to compress the gaseous mixture to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, the secondary compressor is configured to compress the gaseous mixture to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In embodiments wherein the apparatus comprises a primary compressor and a secondary compressor, in some embodiments, the primary compressor is configured to compress the gaseous mixture to at least 1 MPa, and the secondary compressor is configured to compress the gaseous mixture to at least 10 MPa. | [0093] In some embodiments, the one or more secondary heat exchangers are configured to cool the gaseous mixture to a temperature of less than 0°C, less than -5°C, or less than -10°C. In some embodiments, the one or more secondary heat exchangers are configured to cool the gaseous mixture to a temperature of less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. | [0094] In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than 0°C, less than -5°C, less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. | [0095] In some embodiments, the means for cooling and compressing the gaseous mixture is configured to compress the gaseous mixture to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. | [0096] In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid. In some embodiments wherein the gaseous mixture comprises methane, the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid and at which methane forms a gas. In some embodiments wherein the gaseous mixture comprises nitrogen, the means for coolingand compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid and at which nitrogen forms a gas.| [0097] In some embodiments, such as when the gaseous mixture comprises carbon dioxide and methane, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than -30°C and to compress the gaseous mixture to at least 3 MPa. In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than -40°C and to compress the gaseous mixture to at least 2 MPa. In some embodiments, the means for cooling and compressing the gaseous mixture is configured to cool the gaseous mixture to a temperature of less than -50°C and to compress the gaseous mixture to at least 1 MPa. | [0098] The apparatus also comprises separation means for separating liquid carbon dioxide from gaseous components of the mixture. The separation means comprises a separation vessel comprising: (i) an inlet in fluid communication with the means for cooling and compressing the gaseous mixture for receiving the compressed cooled mixture; and (ii) a first outlet for venting gas. In some embodiments, the separation vessel further comprises (iii) a second outlet for out letting solid and/or liquid carbon dioxide. | [0099] The first outlet of the separation vessel allows gaseous components of the compressed cooled mixture to be removed from the separation vessel. In some embodiments, the first outlet comprises a nonreturn valve and/or a back-pressure valve. The non-return valve and/or back pressure valve may be mechanical spring operated, compressed gas operated or ball opening operated. | [0100] The second outlet of the separation vessel allows solid and/or liquid carbon dioxide to be removed from the separation vessel and separated from the gaseous components. In some embodiments, the second outlet comprises a tap and/or syphon. | [0101] The separation vessel is typically maintained at a temperature and pressure at which carbon dioxide is a liquid. Wherein the gaseous mixture comprises methane, separation vessel is typically maintained at a temperature and pressure at which carbon dioxide is a liquid and methane is a gas. Wherein the gaseous mixture comprises nitrogen, separation vessel is typically maintained at a temperature and pressure at which carbon dioxide is a liquid and nitrogen is a gas. | [0102] In some embodiments, the inlet of the separation vessel comprises a throttling valve for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture. In this embodiment, the means for cooling and compressing the gaseous mixture is typically configured tocool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a gas or liquid and the throttling valve is configured to induce phase change formation from gaseous cold or liquid carbon dioxide into either liquid or a deposition phase transition, or reverse sublimation process into solid carbon dioxide. | [0103] In some embodiments, the throttling valve is configured to receive the compressed cooled mixture from the primary compressor. In some embodiments, the throttling valve is configured to receive the compressed cooled mixture from the secondary compressor. In some embodiments, the throttling valve is configured to receive the compressed cooled mixture from the one or more secondary heat exchangers. | [0104] The throttling valve may be any valve that is capable of changing unilateral flow into turbulent flow. A throttling valve typically comprises an inlet and an outlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 10-fold, at least 20-fold, at least 30-fold, at least 40-fold, at least 50-fold, at least 60-fold, at least 70-fold, at least 80-fold, at least 90-fold, or at least 100-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the cross- sectional area of the throttling valve outlet is at least 50-fold greater than the cross-sectional area of the throttling valve inlet. | [0105] In some embodiments, the separation vessel comprises a tubular cone extending from the throttling valve outlet wherein the tubular diameter of the cone increases as it extends outwards from the throttling valve. | [0106] In some embodiments wherein the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid, the separation vessel does not comprise a throttling valve. | [0107] In some embodiments wherein the means for cooling and compressing the gaseous mixture is configured to cool and compress the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid, the separation vessel comprises a throttling valve. In such embodiments, the throttling valve helps ensure that any remnant gaseous carbon dioxide is converted to liquid or solid carbon dioxide. | [0108] In some embodiments wherein the gaseous mixture comprises nitrogen, the first outlet is for venting gaseous nitrogen from the separation vessel. In some embodiments, the first outlet is configured to vent nitrogen to the atmosphere. In some embodiments, the first outlet for gaseous nitrogen is in fluid communication with the primary heat exchanger and/or the first outlet is in fluid communication withone or more of the secondary heat exchangers. In some embodiments, the first outlet is in fluid communication with a gaseous nitrogen storage vessel which is in fluid communication with the primary heat exchanger and/or the one or more secondary heat exchangers. As described in more detail above, the apparatus may comprise a control meansfor regulating the flow of extracted gaseous nitrogen through the primary heat exchanger and/or through the one or more secondary heat exchangers. | [0109] In some embodiments wherein the gaseous mixture comprises methane, the first outlet is for venting methane enriched gas from the separation vessel. In some embodiments, the apparatus further comprises methane enriched gas storage vessels in fluid communication with the first outlet of the separation vessel for containing methane enriched gas. | [0110] In some embodiments, the apparatus further comprises a holding tank for containing solid and/or liquid carbon dioxide from the separation vessel. | [0111] In some embodiments, the separation vessel comprises a carbon dioxide collection vessel comprising: (i) a throttling valve for receiving compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and (ii) a holding tank for containing solid and/or liquid carbon dioxide. | [0112] The holding tank is typically configured to accommodate the volumetric space required for the collection of solid and/or liquid carbon dioxide. | [0113] In some embodiments, the apparatus comprises a carbon dioxide collection vessel comprising: (i) a throttling valve in fluid communication with the second outlet of the separation vessel for receiving carbon dioxide; and (ii) a holding tank for containing solid and/or liquid carbon dioxide. The throttling valve may be any valve that is capable of changing unilateral flow into turbulent flow. A throttling valve typically comprises an inlet and an outlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 10-fold, at least 20-fold, at least 30-fold, at least 40-fold, at least 50- fold, at least 60-fold, at least 70-fold, at least 80-fold, at least 90-fold, or at least 100-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 50-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the carbon dioxide collection vessel comprises a tubular cone extending from the throttling valve outlet wherein the tubular diameter of the cone increases as it extends outwards from the throttling valve.In some embodiments wherein the gaseous mixture comprises methane, the apparatus further comprises a means for cooling and compressing methane, comprising: i) a tertiary heat exchanger in fluid communication with the first outlet of the separation vessel for receiving and cooling methane gas; and ii) a tertiary compressor in fluid communication with the tertiary heat exchanger for receiving and compressing cooled methane gas. In these embodiments, the separation vessel comprises a first outlet for methane gas and a second outlet for solid and/or liquid carbon dioxide. | [0114] In some embodiments, the gaseous mixture comprising methane is biogas or natural gas. | [0115] For ease of reference, references herein to "primary heat exchangers", "primary compressors", "secondary heat exchangers", "secondary compressors" and "further heat exchangers" refer to components of the means for cooling and compressing the gaseous mixture; and references to "tertiary heat exchangers" and "tertiary compressors" refer to components of the means for cooling and compressing methane, regardless of whetherthe apparatus comprises a secondary and/orfurther heat exchanger and/or a secondary compressor. | [0116] In some embodiments, the means for cooling and compressing methane comprises an impeller for propelling the methane gas into the tertiary heat exchanger. | [0117] In some embodiments, the tertiary heat exchanger is configured to cool the methane gas to a temperature of less than -75°C, less than -80°C, less than -90°C, less than -100°C, less than -110°C, less than -120°C, less than -130°C, less than -140°C, less than -150°C, less than -160°C, less than -170°C, or less than -180°C. | [0118] In some embodiments, the tertiary compressor is configured to compress the methane gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. | [0119] In some embodiments, the means for cooling and compressing methane is configured to cool and compress methane gas to a temperature and pressure at which methane forms a liquid. In some embodiments, the means for cooling and compressing methane is configured to cool the methane gas to a temperature of less than -100°C and to compress the methane gas to at least 3 MPa. In some embodiments, the means for cooling and compressing methane is configured to cool the methane gas to a temperature of less than -110°C and to compress the methane gas to at least 2 MPa. In some embodiments, the means for cooling and compressing methane is configured to cool the methane gas to a temperature of less than -125°C and to compress the methane gas to at least 1 MPa.Heat exchangers for receiving and cooling methane gas from the separation vessel may be any heat exchanger capable of reducing the temperature of a gas. In some embodiments, the tertiary heat exchanger comprises one or more conduits for receiving coolant. In some embodiments, the tertiary heat exchanger comprises an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the methane gas from the separation vessel. In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium. | [0120] In some embodiments, the tertiary heat exchanger comprises an exogenous coolant. The exogenous coolant may be any coolant suitable to cool the methane gas in the tertiary heat exchanger. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. In some embodiments, the exogenous gaseous nitrogen is extracted gaseous nitrogen. In some embodiments, the exogenous coolant is exogenous liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous liquid and/or gaseous carbon dioxide is extracted liquid and/or gaseous carbon dioxide. In some embodiments, the exogenous coolant is a gas or liquid refrigerant. In some embodiments, the exogenous coolant comprises one or more of fluorocarbon, chlorofluorocarbon (R12), hydrochlorofluorocarbon (R22), hydrofluorocarbon (R410A, R134) freon, ammonia, sulphur dioxide, non-halogenated hydrocarbon, R404A, R407A, R407C, R407F, and R507. In some embodiments, the exogenous coolant comprises R744. | [0121] The tertiary compressor may be any compressor capable of increasing the pressure of a gas. In some embodiments, the tertiary compressor is a high volume reciprocating compressor, a rotational gas compressor, a piston compressor, a membrane compressor, or a screw compressor. | [0122] In some embodiments, the apparatus further comprises a methane collection vessel in fluid communication with the means for cooling and compressing methane. The methane collection vessel is for collecting and storing liquid methane. | [0123] In some embodiments, the separation vessel, carbon dioxide holding tank, and/or methane collection vessel comprises stainless steel and/or nickel-cobalt-chromium steel alloy. In some embodiments, the separation vessel, carbon dioxide holding tank, and/or methane collection vessel comprise an internal anti-corrosion coating. | [0124] In some embodiments, the apparatus is insulated to reduce heat influx from the external environment.In some embodiments, the apparatus comprises transfer conduits for delivering gaseous mixture through the apparatus from one component of the apparatus to a subsequent component of the apparatus. In some embodiments, the transfer conduits are insulated. Components of the apparatus include the primary heat exchanger, the primary compressor, and the separation vessel. Components of the apparatus may also comprise one or more secondary heat exchangers, one or more secondary compressors, one or more tertiary heat exchangers, one or more tertiary compressors, a holding tank, and/or a methane collection vessel. | [0125] In some embodiments, the apparatus further comprises one or more valves for maintaining unidirectional flow of gaseous mixture. In some embodiments, the valves are cryogenic non-return check valves. Advantageously, valves prevent thermal bridging and maintain states of matter. | [0126] In some embodiments, the apparatus further comprises additional heat exchangers and/or compressors for maintaining the temperature and pressure of the gaseous mixture and compressed cooled mixture within the apparatus. | [0127] In some embodiments, one or more of the primary, secondary and/or tertiary heat exchangers comprises a fridge or chiller. In some embodiments, one or more of the primary, secondary and/or tertiary heat exchangers comprises a heat exchanger in which recovered heat is stored and redistributed to another application, e.g. as a heating source. | [0128] The invention provides a method for producing solid and/or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to: (i) a secondary heat exchanger and/or (ii) a secondary compressor; and c) separating solid and/or liquid carbon dioxide from the gaseous phase of the mixture. | [0129] In some embodiments, the method comprises throttling the compressed cooled mixture through a throttling valve to provide solid and/or liquid carbon dioxide. | [0130] In some embodiments, the method of the invention comprises delivering gaseous mixture to the apparatus of the invention as described above. | [0131] In some embodiments wherein the gaseous mixture comprises nitrogen, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide to provide extracted gaseous nitrogen. The extracted gaseous nitrogen may be collected and stored. In someembodiments, the method comprises supplying the extracted gaseous nitrogen to the primary heat exchanger and/or secondary heat exchanger. | [0132] In some embodiments, the method comprises employing an exogenous coolant to cool the gaseous mixture in the primary heat exchanger during initiation of the carbon dioxide extraction process. In embodiments wherein the apparatus comprises one or more secondary heat exchangers, in some embodiments, the method comprises employing an exogenous coolant to cool the gaseous mixture in one or more of the secondary heat exchangers during initiation of the carbon dioxide extraction process. | [0133] In some embodiments wherein the gaseous mixture comprises nitrogen, the exogenous coolant is used to cool gaseous mixture until sufficient gaseous nitrogen is extracted from the gaseous mixture to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool the gaseous mixture in the primary heat exchanger and/or one or more secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. | [0134] In some embodiments, the method comprises regulating the flow of coolant through the primary heat exchanger and/or the secondary heat exchanger. The rate of flow of the coolant determines the rate of cooling of the gaseous mixture. Increasing the flow of coolant typically increases the rate of cooling of the gaseous mixture. Reducing the flow of coolant typically reduces the rate of cooling of the gaseous mixture. | [0135] In some embodiments, the primary heat exchanger cools the gaseous mixture to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. In some embodiments, the primary heat exchanger cools the gaseous mixture to a temperature of less than -30°C, optionally less than -40°C. | [0136] In some embodiments, the compressing comprises compressing the gaseous mixture to least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, compressing comprises compressing the gaseous mixture to at least 10 MPa. In some embodiments, the compressing comprises compressing the cooled gaseous mixture more than once. In some embodiments, the method comprises initially compressing the gaseous mixture to at least 1 MPa and then subsequently compressing the gaseous mixture to at least 10 MPa.In some embodiments, the method further comprises delivering compressed cooled gaseous mixture to a secondary heat exchanger. In some embodiments, the secondary heat exchanger cools the compressed cooled gaseous mixture to a temperature of less than 0°C, less than -5°C, or less than -10°C. | [0137] In some embodiments, the method comprises: (i) compressing the cooled gaseous mixture; (ii) cooling the compressed cooled gaseous mixture; (iii) compressing the cooled gaseous mixture; and then (iv) cooling the compressed cooled gaseous mixture. In some embodiments, the method comprises: (i) compressing the cooled gaseous mixture to less than 1 MPa; (ii) cooling the compressed cooled gaseous mixture to a temperature of less than -10°C; (iii) compressing the cooled gaseous mixture to less than 10 MPa; and then (iv) cooling the compressed cooled gaseous mixture to a temperature of less than -10°C. | [0138] In some embodiments, the method comprises cooling and compressing the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid. In some embodiments wherein the gaseous mixture comprises methane, the method comprises cooling and compressing the gaseous mixture to a temperature and pressure at which carbon dioxide forms a liquid and at which methane forms a gas. | [0139] In some embodiments, such as when the gaseous mixture comprises carbon dioxide and methane, the method comprises cooling and compressing the gaseous mixture to a temperature of less than - 30°C and to a pressure of at least 3 MPa. In some embodiments, the method comprises cooling and compressing the gaseous mixture to a temperature of less than -40°C and to a pressure of at least 2 MPa. In some embodiments, the method comprises cooling and compressing the gaseous mixture to a temperature of less than -50°C and to a pressure of at least 1 MPa. | [0140] In some embodiments, the method comprises collecting solid carbon dioxide and allowing it to melt to form liquid carbon dioxide. In some embodiments, carbon dioxide is maintained at a pressure of at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, or at least 5 MPa in the holding tank. In some embodiments, carbon dioxide is maintained at a pressure of 3 MPa in the holding tank. In some embodiments, liquid carbon dioxide is stored in cryogenic pressure vessel equipment. | [0141] In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice. In some embodiments, solid carbon dioxide is converted to carbon dioxide ice by hydraulic pressing.In some embodiments, wherein the gaseous mixture comprises methane, the method further comprises: d) separating methane gas from solid and/or liquid carbon dioxide and delivering the methane gas to a tertiary heat exchanger to provide cooled methane gas; and e) compressing the cooled methane gas to provide liquid methane. | [0142] In some embodiments, cooling the methane gas comprises cooling the methane gas to a temperature of less than -75°C, less than -80°C, less than -90°C, less than -100°C, less than -110°C, less than -120°C, less than -130°C, less than -140°C, less than -150°C, less than -160°C, less than -170°C, or less than - 180°C. | [0143] In some embodiments, compressing the methane gas comprises compressing the methane gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. | [0144] In some embodiments, the method comprises cooling and compressing the methane gas to a temperature and pressure at which methane forms a liquid. In some embodiments, the method comprises cooling and compressing the methane gas to a temperature of less than -100°C and to a pressure of at least 3 MPa. In some embodiments, the method comprises cooling and compressing the methane gas to a temperature of less than -110°C and to a pressure of at least 2 MPa. In some embodiments, the method comprises cooling and compressing the methane gas to a temperature of less than -125°C and to a pressure of at least 1 MPa. | [0145] BRIEF DESCRIPTION OF THE FIGURES | [0146] Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying figures which are not drawn to scale. | [0147] Figure 1 provides a schematic representation of an exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, and carbon dioxide collection vessel. | [0148] Figure 2 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, and carbon dioxide collection vessel. | [0149] Figure 3 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary compressor, and carbon dioxide collection vessel.Figure 4 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, secondary compressor, further heat exchanger, and carbon dioxide collection vessel. | [0150] Figure 5 provides a schematic representation of another exemplary apparatus according to the invention comprising means for cooling and compressing a gaseous mixture, separation means, and means for cooling and compressing methane. | [0151] An exemplary apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas according to the invention is shown in Figure 1. The apparatus of the invention comprises a primary heat exchanger 10, a primary compressor 20, and a carbon dioxide collection vessel 30 comprising a throttling valve 32 and a holding tank 36. The apparatus may comprise means 12 for connecting to an exhaust flue. The apparatus may further comprise an impeller 14 for propelling exhaust flue gas into the primary heat exchanger 10. The carbon dioxide collection vessel 30 may comprise an outlet 34 for extracting gaseous nitrogen, and a gaseous nitrogen transfer conduit 40 in fluid communication with the primary heat exchanger 10. | [0152] The apparatus of Figure 2 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60. | [0153] The apparatus of Figure 3 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32. | [0154] The apparatus of Figure 4 comprises the features of the apparatus of Figure 1 and additionally comprises: a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20; a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger 60; and a further heat exchanger 65 for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor 25. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60 and/or further heat exchanger 65.An exemplary apparatus for extracting solid and/or liquid carbon dioxide and liquid methane from a gaseous mixture according to the invention is shown in Figure 5. The apparatus comprises: a) a means for cooling and compressing the gaseous mixture 100; b) a separation means 200; and c) a means for cooling and compressing methane 300. The means for cooling and compressing the gaseous mixture 100 comprises a primary heat exchanger 10 and a primary compressor 20. The separation means 200 comprises a separation vessel 201 having an inlet 202, a first outlet for gas 203 and a second outlet for solid and/or liquid carbon dioxide 204. The means for cooling and compressing methane 300 comprises a tertiary heat exchanger 302 for receiving methane gas from the first outlet 203 and a tertiary compressor 304 for receiving cooled methane gas from the tertiary heat exchanger 302. The apparatus may also comprise a holding tank for solid and/or liquid carbon dioxide 36 and/or a methane collection vessel 306. The apparatus may comprise an impeller 14 for propelling gaseous mixture into the primary heat exchanger 10. | [0155] Transfer conduits 50-59, 301, 303 and 305 are for transferring gaseous mixtures, cooled gaseous mixtures, compressed cooled mixtures, solid and/or liquid carbon dioxide, methane gas and/or liquid methane through the apparatus as depicted in Figures 1-5. | [0156] Specific example | [0157] The invention will now be described with reference to the following non-limiting example. | [0158] Exhaust flue gases may be redirected from the exhaust flue exit point that connects with the open-air environment, such as the above ground open air exit of a chimney into the lower atmosphere between 20 and 100 metres above ground level. The exhaust flue exit may be adapted to connect to a connection means, e.g. tubing comprising a 180° bend, to redirect exhaust flue gases towards the primary heat exchanger which may be at ground level. This downward directional tubing may connect to a manifold housing an internal impeller for propelling exhaust flue gases into the primary heat exchanger, optionally into a labyrinth chamber of the primary heat exchanger. This downward directional tubing may connect directly to the primary heat exchanger. The primary heat exchanger may comprise a labyrinth chamber comprising a network array matrix of interconnecting channels and tubing that inter-collectively contain a series of pressure vessel conduits acting as a large heat exchanger for the transport of a coolant, e.g. cold and vented gaseous nitrogen. This cold, gaseous nitrogen does not typically come into direct contact with the exhaust flue gases. The pressure vessel tubing of the conduits acts as a conductor of heat from the exhaust flue gases into the coolant, e.g. the gaseous nitrogen, thereby heating the coolant and simultaneously cooling the exhaust flue gases in the heat exchange chiller labyrinth. The exhaust flue gases may be cooled to a temperature of atleast -40°C. Gaseous nitrogen may be allowed to cool and vented to the atmosphere after flowing through the conduits of the primary heat exchanger. | [0159] Control over the temperature of the exhaust flue gases in the primary heat exchanger may be performed by control means configured to control the rate of flow of the cold gaseous nitrogen in the heat exchange chiller labyrinth. Increasing the rate of flow of cold gaseous nitrogen cools the exhaust flue gases quicker and slowing the rate of flow of cold gaseous nitrogen helps prevent the exhaust flue gases cooling down below the desired temperature, e.g. -40°C. Flow rate may be controlled by flow sensors in the cold gaseous nitrogen pumping system. The size of the heat exchange chiller labyrinth is typically designed to match the known maximum gas flow rate obtained from the exhaust flue during functional operation of the engine, boiler or coal-fired power station, so that the thermodynamic heat fluxes of the two temperature regimes are synchronised to accommodate from the known temperature of the gases upon leaving the original chimney design until exiting the heat exchange chiller labyrinth system. Typically, this may result in a temperature drop from between 50°C and 90°C to between -10°C and -40°C, ideally at least -30°C, or preferably at least -40°C. | [0160] The main function of chilling the exhaust flue gases is to prepare the gases for phase change. The heat exchange chiller labyrinth itself does not initiate the phase change - it changes the temperature of the gases but not the pressure. As such, the exhaust flue gases are typically cooled to a temperature of - 40°C and remain in gaseous state at the point of leaving the primary heat exchanger. As the cooled exhaust flue gases leave the primary heat exchanger, the external surface of the transfer conduits that deliver cooled exhaust flue gases through the apparatus are typically insulated to ensure that the gases remain at their cooled temperature throughout their transitionary passage to formation of primarily solid carbon dioxide and secondarily liquid carbon dioxide. | [0161] Upon leaving the heat exchange chiller labyrinth, the cooled exhaust flue gas is typically delivered via transfer conduit(s) to a primary compressor. The primary compressor may compress the exhaust flue gases from approximately 10 KPa to approximately 1 MPa. After primary stage compression, exhaust flue gases may be partially warmed as a result of a reduction in their volume during the compression process. Exhaust flue gases may then be chilled back to about -10°C in a secondary heat exchanger. The compressed cooled exhaust flue gas may then be compressed by a secondary compressor to compress the compressed cooled exhaust flue gas from approximately 1 MPa to 10 MPa. Compressed cooled exhaust flue gases may then be chilled back to -10°C via exposure to the same secondary heat exchanger or a further heat exchanger.Compressed cooled exhaust flue gases typically contain multiphase flow of gaseous nitrogen, as well as chilled gaseous carbon dioxide. Other majority contaminants from coal-fired power station may have previously been removed using a flue gas desulphurisation cleaning process for removal of SOx, prior to delivery of the exhaust flue gas to the primary heat exchanger, thus ensuring that most of the gases in the apparatus comprise gaseous nitrogen and carbon dioxide. This cold gas mixture may be maintained within the system by means of placement of cryogenic non-return check valves in unidirectional flow. Check valves may help to prevent thermal bridging and maintain states of matter. Optionally, adjacent and strategically placed heat exchangers and/or maintenance compressors may be present to ensure that during transit of the exhaust flue gases through the apparatus, the temperature and pressure of the gas is maintained. | [0162] The compressed cooled exhaust flue gas is delivered to a throttling valve. The throttling valve acts to change unilateral liquid flow into turbulent flow. In the throttling valve there is typically an adiabatic drop due to the pressure drop with increased gas velocity. Simultaneously, upon ejection of the compressed cooled exhaust flue gas from the throttling valve, the tubular aperture may be significantly increased, e.g. at least 50-fold, so that the cross-sectional area of the compressed cooled exhaust flue gas before the throttling valve is significantly smaller than the cross-sectional area, e.g. 1/50 of the cross-sectional area, of the venting tube after the throttling valve. Simultaneously, the exit from the throttling valve may extend in a tubular cone orientation as the output end of the contents of throttling valve of the compressed cooled exhaust flue gas extend into the larger aperture holding chamber. The tubular cone extension on the output side of the throttling valve may act to create cyclonic turbulent flow and a sudden drop in pressure, with a simultaneous drop in temperature. This typically creates the phase change formation from gaseous cold carbon dioxide into a deposition phase transition, or reverse sublimation process into solid carbon dioxide 'snow' at a temperature below -78°C and mixed with cold gaseous nitrogen. The cold gaseous nitrogen may be vented, collected and pumped for reverse passage through the primary and/or secondary heat exchangers. The holding tank is typically designed to accommodate the volumetric space required for the input of solid carbon dioxide 'snow', so that its accumulation can readily be melted from solid carbon dioxide 'snow' into liquid carbon dioxide. The entire cooled zone from the primary heat exchanger through to the carbon dioxide collection vessel may be insulated to prevent heat influx from the external environment. The liquid carbon dioxide product may be stored using conventional cryogenic pressure vessel equipment of either tank or bulk storage systems, and transported to pertinent markets worldwide. Alternatively, hydraulic pressing may be used as a functional methodology to change the form of solid crystalline carbon dioxide snow into compressed carbon dioxide ice, or dry ice.The apparatus may comprise a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The purpose of the gas bypass system is to act as a regulatory control mechanism, coupling to the exhaust flue and preceding placement of the primary heat exchanger described herein. The gas bypass system simultaneously avoids unwanted back pressure on the engine or boiler, allowing smooth, continuous and uninterrupted flow of exhaust flue gases from the engine or boiler, thereby ensuring that the regulatory control feedback mechanism for the temperature and pressure of the engine or boiler is functional. The exhaust flue gas bypass system may be constructed as a partitioned parallel exhaust chamber with a warmer than ambient temperature internal gaseous flow control mechanism. The secondary partitioned parallel exhaust chamber may have a modified heat and pressure take-off ensuring that exhaust flue modifications do not compromise or have any effects on the designed operations and efficiency of the engine or boiler by means of a unidirectional gas flow valve flap. | [0163] Statements of invention | [0164] The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising: a) a primary heat exchanger for receiving and cooling the exhaust flue gas; b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and (ii) a holding tank for containing solid and/or liquid carbon dioxide. | [0165] In some embodiments, the apparatus further comprises one or more secondary heat exchangers for receiving and cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel. | [0166] In some embodiments, the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen, wherein the outlet is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers. | [0167] In some embodiments, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue.In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue. | [0168] In some embodiments, the primary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas. | [0169] In some embodiments, the secondary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas. | [0170] In some embodiments, the apparatus further comprises an impeller for propelling the exhaust flue gas into the primary heat exchanger. | [0171] In some embodiments, the apparatus further comprises one or more impellers for propelling the compressed cooled exhaust flue gas into one or more of the one or more secondary heat exchangers.| [0172] In some embodiments, the apparatus further comprises a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor. | [0173] In some embodiments, one or more of the one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor. | [0174] In some embodiments, one or more of the one or more secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel. | [0175] In some embodiments: (a) one or more of the secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more of the secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.| [0176] In some embodiments, the apparatus comprises one or more valves for maintaining unidirectional flow of exhaust flue gas. | [0177] The invention also provides a method for producing solid or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondaryheat exchanger; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide. | [0178] In some embodiments, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger. | [0179] In some embodiments, the cooling comprises reducing the temperature of the gas to less than -10°C.| [0180] In some embodiments, the compressing comprises compressing the gas to at least 1 MPa. | [0181] In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing. | Family Number|(105974553)|105974553|Advantages / Prev. Drawbacks|(WO2023144550 A1)|Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. | | Chemical engineering|Environmental technology | B01D-053/00/2|B01D-2256/245|B01D-2257/504|B01D-2258/01|B01D-2258/0283|B01D-2258/05|F25J-003/06/1|F25J-003/06/35|F25J-003/06/6|F25J-003/06/7|F25J-2205/20|F25J-2210/66|F25J-2210/70|F25J-2215/04|F25J-2220/66|F25J-2220/82|F25J-2230/04|F25J-2230/08|F25J-2230/30|Y02C-020/40 | B01D-053/00/2|B01D-2256/245|B01D-2257/504|B01D-2258/01|B01D-2258/0283|B01D-2258/05|F25J-003/06/1|F25J-003/06/35|F25J-003/06/6|F25J-003/06/7|F25J-2205/20|F25J-2210/66|F25J-2210/70|F25J-2215/04|F25J-2220/66|F25J-2220/82|F25J-2230/04|F25J-2230/08|F25J-2230/30|Y02C-020/40 | B01D-053/00|F25J-001/00|F25J-003/06 | B01D-053/00|F25J-001/00|F25J-003/06 | WO202641856 | WO202641856 117906052 WHO=Examiner SELF=N CAT=I CAT=Y | WO2011127552|GB2416389|EP2574392|WO9707329|US20200309451|WO2020225794|US5642630|US20110167866|US5233837 | WO2011127552 52020605 WHO=Examiner SELF=N CAT=Y|GB2416389 1781894 WHO=Examiner SELF=N CAT=Y|EP2574392 44799486 WHO=Examiner SELF=N CAT=X CAT=Y CAT=I|WO9707329 1367728 WHO=Examiner SELF=N CAT=X CAT=I|US20200309451 90836177 WHO=Examiner SELF=N CAT=X|WO2020225794 91435083 WHO=Examiner SELF=N CAT=I|US5642630 42950131 WHO=Examiner SELF=N CAT=I|US20110167866 44341766 WHO=Examiner SELF=N CAT=A|US5233837 59958923 WHO=Examiner SELF=N CAT=A | EP2574392; WO9707329; US20200309451; US5642630; WO2020225794; WO2011127552; GB2416389; US20110167866; US5233837 | LAPSED | (WO2023/144550)|LAPSED | DEAD | (WO2023/144550)|DEAD | (WO2023/144550)|LEGAL DETAILS FOR WO2023/144550|Actual or expected expiration date=2025-07-28|Legal state=DEAD|Status=LAPSED|Event publication date=2023-01-27|Event code=WO/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=WO WOGB2023/050185|Application date=2023-01-27|Standardized application number=2023WO-GB50185|Event publication date=2023-08-03|Event code=WO/A1|Event group=Examination events|Published application with search report|Publication country=WO|Publication number=WO2023/144550|Publication stage code=A1|Publication date=2023-08-03|Standardized publication number=WO2023144550|Event publication date=2025-07-28|Event code=WO/EETL|Event group=Event indicating Not In Force|PCT Application validity period expired.|MEMBER STATE LEGAL DETAILS FOR DE|Actual or expected expiration date=2024-08-29|Legal state=DEAD|Status=LAPSED|Corresponding cc:|Designated or member state=DE|Event publication date=2024-08-29|Event code=WO/NENP|Event group=Event indicating Not In Force|Non-entry into the national phase|Corresponding cc:|Designated or member state=DE|MEMBER STATE LEGAL DETAILS FOR EP|Actual or expected expiration date=2025-01-22|Legal state=DEAD|Status=LAPSED|Corresponding cc:|Designated or member state=EP Corresponding appl: EP23703845|Event publication date=2023-09-13|Event code=WO/121|Event group=Designated states|EP: The EPO has been informed by wipo that ep was designated in this application|Corresponding cc:|Designated or member state=EP|Event publication date=2025-01-22|Event code=WO/122|Event indicator=Neg|Event group=Event indicating Not In Force|EP: PCT app. not ent. europ. phase|EP: PCT anmeldung nicht in europaeische phase eingetreten|Corresponding cc:|Designated or member state=EP | (WO2023/144550)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2023/144550)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2023/144550)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, ME, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2023/144550)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2023/144550)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IQ, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, JM, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, CV, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=icjTorqguCBRkYir6ykuFd0P/F2Pwh1EkaV0SMUACwOllNWWvacaWhEyjmCehg6RdJNcKluWvdhS0llBJ/BQPQ==&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=WO0000000006268826&ekey=2366&xpn=WO2023144550&kind=A1 | http://www.wipo.int/patentscope/search/en/detail.jsf?docId=WO2023144550&redirectedID=true | https://permalink.orbit.com/RenderStaticFirstPage?XPN=8aV6LWb0vZuU4Wc2r2RSWbmsLuw%252FR4oY%252BQgpgFzVRnM%3D%26n%3D1&id=0&base=FAMPAT | GB | (WO2023/144550)|GB | (WO2023/144550)|NAME=PURIFIRE LABS LIMITED Salisbury House Station Road Cambridge Cambridgeshire CB1 2LA , COUNTRY=GB | (WO2023/144550)|GB | (WO2023/144550)|NAME=TITMUS, Craig et al. Mathys & Squire The Shard 32 London Bridge Street London SE1 9SG , POSTCODE=SE1 9SG , COUNTRY=GB | (WO2023/144550)|GB; GB | (WO2023/144550)|NAME=PEARCE, Matthew Salisbury House Station Road Cambridge Cambridgeshire CB1 2LA, POSTCODE=CB1 2LA, COUNTRY=GB |NAME=MIDDLETON, Ray Salisbury House Station Road Cambridge Cambridgeshire CB1 2LA, POSTCODE=CB1 2LA, COUNTRY=GB | (WO2023/144550)|5 | 2 | 1 | (WO2023/144550)|Number of Claims: NCL=38|Extended kind: EXTK=x| | (WO2023/144550)|ENGLISH (ENG) | (WO2023144550)|Patent | Titre: (WO2023/144550)|Extraction device Résumé: (WO2023/144550)|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to methods for extracting solid and/or liquid carbon dioxide from gaseous mixtures, such as exhaust flue gas, natural gas and biogas. The invention also relates to apparatus and methods for extracting liquid methane from gaseous mixtures, such as natural gas and biogas. The invention also relates to apparatus and methods for extracting solid and/or liquid carbon dioxide and liquid methane from gaseous mixtures, such as natural gas and biogas. Autre: (WO2023/144550)|Claims |1. An apparatus for extracting solid and/or liquid carbon dioxide from a gaseous mixture, the apparatus comprising: a) means for cooling and compressing the gaseous mixture, the means comprising: i) a primary heat exchanger for receiving and cooling the gaseous mixture; and ii) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled gaseous mixture from the primary heat exchanger to provide a compressed cooled mixture; and b) separation means for extracting carbon dioxide from the compressed cooled mixture, the separation means comprising a separation vessel comprising: i) an inlet for receiving the compressed cooled mixture from the means for cooling and compressing the gaseous mixture; and ii) a first outlet for venting gas from the separation vessel.|2. The apparatus of claim 1, wherein the separation vessel further comprises: (iii) a second outlet for out letting solid and/or liquid carbon dioxide.|3. The apparatus of claim 1 or claim 2, wherein the separation vessel inlet comprises a throttling valve for receiving compressed cooled mixture from the means for cooling and compressing the gaseous mixture.|4. The apparatus of any preceding claim, wherein:|(a) the separation vessel is configured to contain solid and/or liquid carbon dioxide; and/or |(b) the apparatus further comprises a holding tank configured to receive and contain solid and/or liquid carbon dioxide from the second outlet of the separation vessel. |5. The apparatus of any preceding claim, wherein the holding tank provides a carbon dioxide collection vessel, wherein the carbon dioxide collection vessel further comprises a throttling valve in fluid communication with the second outlet of the separation vessel for receiving carbon dioxide.|6. The apparatus of any preceding claim, wherein the means for cooling and compressing the gaseous mixture further comprises one or more secondary heat exchangers for receiving and cooling the compressed cooled mixture from the primary compressor.|7. The apparatus of any preceding claim, wherein the gaseous mixture comprises nitrogen.|8. The apparatus of claim 7, wherein the first outlet of the separation vessel is for venting gaseous nitrogen, wherein the first outlet is in fluid communication with the primary heat exchanger and/or the first outlet is in fluid communication with one or more of the secondary heat exchangers.|9. The apparatus of claim 7 or claim 8, wherein the primary heat exchanger and/or one or more of the secondary heat exchangers comprise an array of conduits for receiving gaseous nitrogen from the separation vessel.|10. The apparatus of claim 9, wherein the array of conduits forms a labyrinth chamber for receiving the gaseous mixture.|11. The apparatus of any preceding claim, wherein the gaseous mixture is exhaust flue gas and wherein the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue.|12. The apparatus of claim 11 further comprising a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.|13. The apparatus of any preceding claim further comprising an impeller for propelling the gaseous mixture into the primary heat exchanger.|14. The apparatus of any preceding claim further comprising one or more impellers for propelling the compressed cooled mixture into one or more of the one or more secondary heat exchangers.|15. The apparatus of any preceding claim, wherein the means for cooling and compressing the gaseous mixture further comprises a secondary compressor for receiving and compressing compressed cooled mixture from the primary compressor.|16. The apparatus of claim 15, wherein one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor.|17. The apparatus of claim 15 or claim 16, wherein one or more secondary heat exchangers is situated between the secondary compressor and the separation means.|18. The apparatus of any of claims 15-17, wherein: (a) one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more secondary heat exchangers is situated between the secondary compressor and the separation means.|19. The apparatus of any preceding claim, wherein the apparatus comprises one or more valves for maintaining unidirectional flow of the mixture.|20. The apparatus of any preceding claim, wherein the gaseous mixture comprises methane and wherein the first outlet is configured to vent methane enriched gas from the separation vessel.|21. The apparatus of any preceding claim, wherein the gaseous mixture comprises methane and the apparatus further comprises: c) a means for cooling and compressing methane, the means comprising: i) a tertiary heat exchanger in fluid communication with the first outlet of the separation vessel for receiving and cooling methane gas; and ii) a tertiary compressor in fluid communication with the tertiary heat exchanger for receiving and compressing cooled methane gas to provide liquid methane.|22. The apparatus of claim 21 further comprising a methane collection vessel in fluid communication with the means for cooling and compressing methane, wherein the methane collection vessel is for collecting liquid methane.|23. The apparatus of claim 21 or claim 22 further comprising an impeller for propelling methane gas into the tertiary heat exchanger.|24. The apparatus of any of claims 21-23, wherein the tertiary heat exchanger comprises an array of conduits for receiving coolant and wherein the array of conduits forms a labyrinth chamber for receiving the methane gas.|25. The apparatus of any preceding claim wherein the means for cooling and compressing the gaseous mixture comprises a dehumidifier.|26. A method for producing solid or liquid carbon dioxide from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture; b) compressing the cooled gaseous mixture to provide compressed cooled mixture, and optionally delivering the compressed cooled mixture to a secondary heat exchanger; and c) separating liquid carbon dioxide from the gaseous phase of the mixture.|27. A method for producing gaseous methane from a gaseous mixture, the method comprising: a) delivering the gaseous mixture to a primary heat exchanger to provide cooled gaseous mixture;|b) compressing the cooled gaseous mixture to provide compressed cooled mixture comprising liquid and/or solid carbon dioxide and gaseous methane; and c) separating liquid and/or solid carbon dioxide from gaseous methane. |28. The method of claim U, further comprising a step of cooling and compressing the gaseous methane to provide liquid methane.|29. The method of any of claims 26-28, wherein the method comprises throttling the compressed cooled mixture through a throttling valve to provide solid and/or liquid carbon dioxide.|30. The method of any of claims 26-29, wherein the gaseous mixture comprises nitrogen and the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger.|31. The method of any of claims 26-30, wherein the cooling comprises reducing the temperature of the gas to less than -10°C.|32. The method of any of claims 26-31, wherein the compressing comprises compressing the gas to at least 1 MPa.|33. The method of any of claims 26-32, wherein the cooling comprises reducing the temperature of the gas to less than -30°C.|34. The method of any of claims 26-33, wherein the compressing comprises compressing the gas to at least 3 MPa.|35. The method of any of claims 26-34, wherein the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing.|36. The method of any of claims 26-35, wherein the gaseous mixture comprises methane and wherein the method further comprises: d) separating methane gas from solid and/or liquid carbon dioxide and delivering the methane gas to a tertiary heat exchanger to provide cooled methane gas; and e) compressing the cooled methane gas to provide liquid methane.|37. The method of claim 28-36, wherein cooling the methane gas comprises reducing the temperature of the methane gas to less than -100°C.|38. The method of any of claims 28-37, wherein compressing the methane gas comprises compressing the methane gas to at least 3 MPa. | 20 | Abstract | gpt-4o-mini | no | The article focuses on the extraction of CO₂ and methane from gaseous mixtures, without discussing biomass energy production or carbon capture and storage systems. | |||||||||||||||||||
| 21 | US63/402,211P|US18/239,201|WOUS2023/073092 | WOUS2023/073092|EP23776539|CA3266193|US18/239,201 | EP4580786|CA3266193|WO2024/050365|US20240069580 | 108609889 | WO2024/050365 A1 2024-03-07 [WO202450365]|EP4580786 A1 2025-07-09 [EP4580786]|CA3266193 A1 2024-03-07 [CA3266193]|US20240069580 A1 2024-02-29 [US20240069580] | 2022-08-30|2023-08-29 | 2023-08-29|2023-08-29|2023-08-29|2023-08-29 | 2025-07-09|2024-03-07|2024-03-07|2024-02-29 | (EP4580786)|2043-08-29|(US20240069580)|2043-08-29|(WO2024/050365)|2026-02-28|(CA3266193)|2043-08-29 | (EP4580786)|Controls architecture for predicting and maintaining co2 uptake rates in direct air capture contactors, and methods of operating the same | (EP4580786)|In some aspects, a method of carbonation control can include monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium, monitoring, via a second sensor, an environmental condition at a location outside of the contactor unit, predicting, based on the measured environmental condition in the contactor unit and the measured environmental condition at the location outside of the contactor unit, a local humidity in a carbonation vessel from the plurality of carbonation vessels, a water content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period, and executing an action on the plurality of carbonation vessels based on the predicted water content and predicted carbonation extent. | HEIRLOOM CARBON TECHNOLOGY | (EP4580786)|Heirloom Carbon Technologies, Inc. ([US])|(US20240069580)|Heirloom Carbon Technologies, Inc. ([US])|(WO2024/050365)|HEIRLOOM CARBON TECHNOLOGIES, INC. ([US])|(CA3266193)|HEIRLOOM CARBON TECHNOLOGIES, INC. ([US]) | DUBEL ANDY|NEWMAN AARON|DUNCAN ROBERT|MILLS JENNIFER|OLSON SCOTT|GUEBLE ISABEL|LIU RUOFEI|MCQUEEN NOAH | (EP4580786)|DUBEL, Andy|NEWMAN, Aaron|DUNCAN, Robert|MILLS, Jennifer|OLSON, Scott|GUEBLE, Isabel|LIU, Ruofei|MCQUEEN, Noah | (EP4580786)|Cooley (UK) LLP ([GB])|Reg. Nb: 101544956|(WO2024/050365)|WESTON, Scott B. et al. ([US])|(CA3266193)|Borden Ladner Gervais LLP ([CA])|Reg. Nb: 1eb8433e-b5c5-4bfa-97b3-55392a3251aa | (US20240069580)|Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | (US20240069580)|1 . A method, comprising: monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium; monitoring, via a second sensor, an environmental condition at a location outside of the contactor unit; predicting, based on the environmental condition in the contactor unit and the environmental condition at the location outside of the contactor unit, each of a local humidity in a carbonation vessel from the plurality of carbonation vessels, a moisture content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period; and executing an action on the plurality of carbonation vessels based on the predicted moisture content and predicted carbonation extent.|19 . A system for managing moisture content of a carbonation medium, the system comprising: a contactor unit including a plurality of carbonation vessels with carbonation medium disposed therein; a first sensor in the contactor unit, the first sensor configured to measure an environmental condition at a location in the contactor unit; a second sensor outside the contactor unit, the second sensor configured to measure an environmental condition at a location outside the contactor unit, the measured environmental conditions including relative humidity; a communication device configured to collect weather forecast data and current weather information from a weather service provider; and a processor configured to receive data from the first sensor, the second sensor, and the communication device, the processor further configured to develop model predictions for the carbonation extent and moisture content of the carbonation medium in a carbonation vessel from the plurality of carbonation vessels and communicate instructions with components of the contactor unit based on the model predictions.|24 . A non-transitory, processor-readable medium storing processor-executable instructions to cause a processor to: receive, via a first sensor, environmental condition data in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium; receive, via a second sensor, environmental condition data at a location outside of the contactor unit; predict, based on the environmental condition in the contactor unit and the environmental condition outside of the contactor unit, a water content and a carbonation extent of the carbonation medium for a carbonation forecasting period; and cause, via an instrument, the execution of an action on the plurality of carbonation vessels based on the predicted water content and predicted carbonation extent.| | (US20240069580)|In some aspects, a method of carbonation control can include monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium, monitoring, via a second sensor, an environmental condition at a location outside of the contactor unit, predicting, based on the measured environmental condition in the contactor unit and the measured environmental condition at the location outside of the contactor unit, a local humidity in a carbonation vessel from the plurality of carbonation vessels, a water content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period, and executing an action on the plurality of carbonation vessels based on the predicted water content and predicted carbonation extent.| | (EP4580786)|CO2 UPTAKE(100,1)|CONTROL ARCHITECTURE(100,1)|DIRECT AIR CAPTURE(100,1)|DIRECT AIR CAPTURE CONTACTOR(100,1)||(US20240069580)|CARBONATION VESSEL(100,104)|CONTACTOR(100,100)|CARBONATION MEDIUM(100,60)|PROCESSOR(100,17)|CO2 UPTAKE(100,4)|CONTROL ARCHITECTURE(100,3)|DIRECT AIR CAPTURE(100,3)|DIRECT AIR CAPTURE CONTACTOR(100,2)|ENVIRONMENTAL CONDITION DATA(100,2)|MOISTURE CONTENT MANAGEMENT(100,1)|PROCESSOR EXECUTABLE INSTRUCTION(100,1)|CARBONATION FORECASTING(38,9)|PREDICTED CARBONATION EXTENT(35,7)|CARBONATION EXTENT(30,24)|CARBONATION MEDIUM CARBONATION EXTENT(28,9)|CARBONATION MOISTURE CONTENT(28,3)|FORECAST PROVIDER(25,6)|OCEAN CO2 UPTAKE(25,1)|PREDICTION MODEL(24,2)|TERRESTRIAL BIOSPHERE(23,1)|WEATHER SERVICE PROVIDER(21,8)|CARBONATION(18,30)|SOLAR IRRADIANCE(18,3)|FUTURE CO2 EMISSION(18,1)|GLOBAL RELIANCE(16,1)|WEATHER FORECAST DATA(15,11)|UPDATE INTERVAL(15,10)|CONTACTOR OUTSIDE BORDER(15,3)|ENVIRONMENTAL CONDITION(14,23)|PREDICTED MOISTURE CONTENT(14,8)|MOISTURE CONTENT(13,20)|FORECASTED CARBONATION EXTENT(13,2)|NATURAL ACCELERATION(13,1)|WEATHER INFORMATION(13,1)|ENTERPRISE USER(11,1)|MEASURING ENVIRONMENTAL CONDITION(10,4)|PREDICTED WATER CONTENT(10,2)|CARBONATION WATER CONTENT(10,1)|CUSTOMIZATION(10,1)|DESIRE(10,1)|PORTFOLIO(10,1)|HUMIDITY(9,9)|GUST SPEED(9,5)|CAPILLARY MAT(9,4)|BIOENERGY(9,1)|DATABASE CONFIGURATION(9,1)|CARBONATION SUBSYSTEM(8,7)|FOREST(8,1)|FRAMEWORK(8,1)|MEASURED CARBONATION EXTENT(8,1)|CONDUCTOR GATEWAY(7,10)|DISTRIBUTOR(7,10)|SPRAYING(7,8)|CARBONATION CONTROL(7,2)|SPRAY SPEED(7,2)|BECCS(7,1)|FOSSIL FUEL(7,1)|WATER CONTENT(6,6)|WATER DELIVERY(6,5)|CARBONATION VESSEL BOUND(6,4)|CARBONATION PERCENTAGE FORECAST(6,3)|FORECASTING PERIOD(6,3)|DATA TRANSMISSION(6,1)|MINERAL(6,1)|RELATIONAL MODEL(6,1)|SPRAY MASS(6,1)|SPRAYER(6,1)|SYNTAX STRUCTURE(6,1)|FORECAST WEATHER DATA(5,7)|PROCESS READABLE MEDIUM(5,5)|CARBONATION PLOT(5,4)|ANALYTICS DASHBOARD(5,3)|CADDY(5,2)|ENVIRONMENTAL CONDITION FORECAST(5,2)|CARBON CAPTURE(5,1)|CO2 MITIGATION DIVERSE PORTFOLIO(5,1)|FORECASTED WATER CONTENT(5,1)|FOURIER TRANSFORM INFRARED SPECTROSCOPY(5,1)|MEASURED MASS(5,1)|BAROMETRIC PRESSURE(4,15)|RELATIVE HUMIDITY(4,15)|PLANNER(4,14)|COMPUTING CLUSTER(4,13)|CARBONATION REGENERATION SUBSYSTEM(4,1)|OVERWEIGHT CARBONATION VESSEL(4,1)|WATER CONTENT PREDICTION(4,1)|WIND SPEED(3,14)|SOLAR RADIATION(3,10)|ENVIRONMENTAL DATA LOCALIZER(3,9)|WIND DIRECTION(3,9)|ANALYTICS SERVICE(3,3)|COMMUNICATIVE COUPLING(3,3)|CONDUCTOR DATABASE(3,3)|OPERATOR DASHBOARD(3,3)|CARBONATION EXTENT PREDICTION(3,2)|CONVEYANCE SUBSYSTEM(3,2)|FORECASTED MOISTURE CONTENT(3,2)|MOISTURE CONTENT PERCENTAGE FORECAST(3,2)|MOVEMENT PLAN(3,2)|VERSIONED WEATHER FORECAST(3,2)|AERATE CARBONATION MEDIUM(3,1)|CARBONATION MODELING(3,1)|CARBONATION VESSEL IR SPECTRUM(3,1)|CARBONATION VESSEL SCHEDULE(3,1)|MODELER SUPERVISOR(3,1)|SHARED MACHINERY AVAILABILITY(3,1)|PROCESS CELL MANAGEMENT(2,10)|CAPILLARY ACTION(2,9)|BACKPRESSURE DATA(2,3)|CONTRACTOR(2,3)|REPORTING(2,3)|SUBCLUSTER(2,3)|CARBONATION EQUIPMENT(2,2)|CARBONATION MEDIUM MOISTURE CONTENT(2,2)|COMPUTATIONAL HARDWARE(2,2)|METRIC 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TRANSFER(1,1)|CENTRALIZED LOCATION(1,1)|CO2 CONCENTRATION SENSOR(1,1)|CO2 UPTAKE RATE MAINTENANCE(1,1)|COLLECTION TRAY(1,1)|CONDUCTOR INSTANCE(1,1)|CONTACTOR BAR(1,1)|DACS(1,1)|DOTTED CONNECTOR(1,1)|ED API(1,1)|ESTIMATED MOISTURE CONTENT(1,1)|EXCLUSION LIMIT(1,1)|EXCLUSIVITY TERM(1,1)|FEED RECIPE(1,1)|FILESYSTEM(1,1)|FIREWALL INTERFACE(1,1)|GEOMETRIC RELATIONSHIP(1,1)|HYDROXIDE MINERAL(1,1)|INTERACTION BENEFIT(1,1)|IRRADIANCE SENSOR(1,1)|IRREGULAR INTERVAL(1,1)|LATE ESTIMATE(1,1)|LOCAL SERVICE PROVIDER(1,1)|LOCALIZATION(1,1)|MOISTURE CALCULATION CONTENT(1,1)|POST COMMAND(1,1)|PRECIPITATION SENSOR(1,1)|RESISTIVE HUMIDITY SENSOR(1,1)|RESPONSIBLE CONDUCTOR(1,1)|SATURATED CARBONATION MEDIUM(1,1)|SENSING CAPABILITY(1,1)|SINGULAR FEATURE(1,1)|STIRRING TIMING(1,1)|TARGET CARBONATION VALUE(1,1)|TERM ORDINARY MEANING(1,1)|TRAY BLENDING(1,1)|TRAY FILLING(1,1)|UPDATED ESTIMATE(1,1)|WEATHER FORECAST SERVICE(1,1)|YELLOW HEADING(1,1)||(WO2024/050365)|CARBONATION VESSEL(100,104)|CONTACTOR(100,100)|CARBONATION MEDIUM(100,60)|PROCESSOR(100,17)|CO2 UPTAKE(100,5)|CONTROL ARCHITECTURE(100,5)|DIRECT AIR CAPTURE(100,5)|DIRECT AIR CAPTURE CONTACTOR(100,4)|ENVIRONMENTAL CONDITION DATA(100,2)|MOISTURE CONTENT MANAGEMENT(100,1)|PROCESSOR EXECUTABLE INSTRUCTION(100,1)|CARBONATION FORECASTING(38,9)|PREDICTED CARBONATION EXTENT(35,7)|CARBONATION EXTENT(30,24)|CARBONATION MEDIUM CARBONATION EXTENT(28,9)|CARBONATION MOISTURE CONTENT(28,3)|FORECAST PROVIDER(25,6)|OCEAN CO2 UPTAKE(25,1)|PREDICTION MODEL(24,2)|TERRESTRIAL BIOSPHERE(23,1)|WEATHER SERVICE PROVIDER(21,8)|CARBONATION(18,30)|SOLAR IRRADIANCE(18,3)|FUTURE CO2 EMISSION(18,1)|GLOBAL RELIANCE(16,1)|WEATHER FORECAST DATA(15,11)|UPDATE INTERVAL(15,10)|CONTACTOR OUTSIDE BORDER(15,3)|ENVIRONMENTAL CONDITION(14,23)|PREDICTED MOISTURE CONTENT(14,8)|MOISTURE CONTENT(13,20)|FORECASTED CARBONATION EXTENT(13,2)|NATURAL ACCELERATION(13,1)|WEATHER INFORMATION(13,1)|ENTERPRISE USER(11,1)|MEASURING ENVIRONMENTAL CONDITION(10,4)|PREDICTED WATER CONTENT(10,2)|CARBONATION WATER CONTENT(10,1)|CUSTOMIZATION(10,1)|DESIRE(10,1)|PORTFOLIO(10,1)|HUMIDITY(9,9)|GUST SPEED(9,5)|CAPILLARY MAT(9,4)|BIOENERGY(9,1)|DATABASE CONFIGURATION(9,1)|CARBONATION SUBSYSTEM(8,7)|FOREST(8,1)|FRAMEWORK(8,1)|MEASURED CARBONATION EXTENT(8,1)|CONDUCTOR GATEWAY(7,10)|DISTRIBUTOR(7,10)|SPRAYING(7,8)|CARBONATION CONTROL(7,2)|SPRAY SPEED(7,2)|BECCS(7,1)|FOSSIL FUEL(7,1)|WATER CONTENT(6,6)|WATER DELIVERY(6,5)|CARBONATION VESSEL BOUND(6,4)|CARBONATION PERCENTAGE FORECAST(6,3)|FORECASTING PERIOD(6,3)|DATA TRANSMISSION(6,1)|MINERAL(6,1)|RELATIONAL MODEL(6,1)|SPRAY MASS(6,1)|SPRAYER(6,1)|SYNTAX STRUCTURE(6,1)|FORECAST WEATHER DATA(5,7)|PROCESS READABLE MEDIUM(5,5)|CARBONATION PLOT(5,4)|ANALYTICS DASHBOARD(5,3)|CADDY(5,2)|ENVIRONMENTAL CONDITION FORECAST(5,2)|CARBON CAPTURE(5,1)|CO2 MITIGATION DIVERSE PORTFOLIO(5,1)|FORECASTED WATER CONTENT(5,1)|FOURIER TRANSFORM INFRARED SPECTROSCOPY(5,1)|MEASURED MASS(5,1)|BAROMETRIC PRESSURE(4,15)|RELATIVE HUMIDITY(4,15)|PLANNER(4,14)|COMPUTING CLUSTER(4,13)|CARBONATION REGENERATION SUBSYSTEM(4,1)|OVERWEIGHT CARBONATION VESSEL(4,1)|WATER CONTENT PREDICTION(4,1)|WIND SPEED(3,14)|SOLAR RADIATION(3,10)|ENVIRONMENTAL DATA LOCALIZER(3,9)|WIND DIRECTION(3,9)|ANALYTICS SERVICE(3,3)|COMMUNICATIVE COUPLING(3,3)|CONDUCTOR DATABASE(3,3)|OPERATOR DASHBOARD(3,3)|CARBONATION EXTENT PREDICTION(3,2)|CONVEYANCE SUBSYSTEM(3,2)|FORECASTED MOISTURE CONTENT(3,2)|MOISTURE CONTENT PERCENTAGE FORECAST(3,2)|MOVEMENT PLAN(3,2)|VERSIONED WEATHER FORECAST(3,2)|AERATE CARBONATION MEDIUM(3,1)|CARBONATION MODELING(3,1)|CARBONATION VESSEL IR SPECTRUM(3,1)|CARBONATION VESSEL SCHEDULE(3,1)|MODELER SUPERVISOR(3,1)|SHARED MACHINERY AVAILABILITY(3,1)|PROCESS CELL MANAGEMENT(2,10)|CAPILLARY ACTION(2,9)|BACKPRESSURE DATA(2,3)|CONTRACTOR(2,3)|REPORTING(2,3)|SUBCLUSTER(2,3)|CARBONATION EQUIPMENT(2,2)|CARBONATION MEDIUM MOISTURE CONTENT(2,2)|COMPUTATIONAL HARDWARE(2,2)|METRIC COLLECTION(2,2)|NONLINEARITY(2,2)|PREDICTED EVAPORATION RATE(2,2)|CARBONATION FORECASTING MODEL(2,1)|CARBONATION VESSEL MASS MEASUREMENT(2,1)|CONTACTOR CONTROLLER(2,1)|DUMPING CARBONATION MEDIUM(2,1)|ESTIMATED CARBONATION EXTENT(2,1)|FORECASTED RAIN(2,1)|FUTURE CARBONATION EXTENT(2,1)|HTTP POST REQUEST(2,1)|INFRARED INSTRUMENTATION(2,1)|INFRARED SPECTRAL SENSOR(2,1)|LOGGING SUBSYSTEM(2,1)|NONCONTIGUOUS PLOT(2,1)|OXIDE PASSIVE CARBONATION(2,1)|PLURAL REFERENT(2,1)|PREDICTED FUTURE MOISTURE CONTENT(2,1)|SPENT CARBONATION MEDIUM(2,1)|TRAY CARBONATION EXTENT(2,1)|TRAY COHORT(2,1)|UNLISTED ITEM(2,1)|WATER CONTENT MEASUREMENT(2,1)|WEATHER FORECAST PROVIDER(2,1)|PROCESS CELL SUBSYSTEM(1,5)|RAW ENVIRONMENTAL DATA(1,5)|ENVIRONMENTAL SENSOR DATA COLLECTOR(1,4)|WEATHER STATION(1,4)|ENVIRONMENTAL DATA SERVICE(1,3)|CALCINATION(1,2)|CARBONATION RATE(1,2)|CO2 REMOVAL(1,2)|PROCESSING TRAY(1,2)|SHELF(1,2)|TARGET COMPOUND(1,2)|TRAY PROCESSING INSTRUCTION(1,2)|ANEMOMETER(1,1)|CAPACITIVE HUMIDITY SENSOR(1,1)|CARBON UPTAKE(1,1)|CARBONATION TRANSFER(1,1)|CENTRALIZED LOCATION(1,1)|CO2 CONCENTRATION SENSOR(1,1)|CO2 UPTAKE RATE MAINTENANCE(1,1)|COLLECTION TRAY(1,1)|CONDUCTOR INSTANCE(1,1)|CONTACTOR BAR(1,1)|DACS(1,1)|DOTTED CONNECTOR(1,1)|ED API(1,1)|ESTIMATED MOISTURE CONTENT(1,1)|EXCLUSION LIMIT(1,1)|EXCLUSIVITY TERM(1,1)|FEED RECIPE(1,1)|FILESYSTEM(1,1)|FIREWALL INTERFACE(1,1)|GEOMETRIC RELATIONSHIP(1,1)|HYDROXIDE MINERAL(1,1)|INTERACTION BENEFIT(1,1)|IRRADIANCE SENSOR(1,1)|IRREGULAR INTERVAL(1,1)|LATE ESTIMATE(1,1)|LOCAL SERVICE PROVIDER(1,1)|LOCALIZATION(1,1)|MOISTURE CALCULATION CONTENT(1,1)|POST COMMAND(1,1)|PRECIPITATION SENSOR(1,1)|RESISTIVE HUMIDITY SENSOR(1,1)|RESPONSIBLE CONDUCTOR(1,1)|SATURATED CARBONATION MEDIUM(1,1)|SENSING CAPABILITY(1,1)|SINGULAR FEATURE(1,1)|STIRRING TIMING(1,1)|TARGET CARBONATION VALUE(1,1)|TERM ORDINARY MEANING(1,1)|TRAY BLENDING(1,1)|TRAY FILLING(1,1)|UPDATED ESTIMATE(1,1)|WEATHER FORECAST SERVICE(1,1)|YELLOW HEADING(1,1)| | (US20240069580)|1. A method, comprising:| monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium;| monitoring, via a second sensor, an environmental condition at a location outside of the contactor unit;| predicting, based on the environmental condition in the contactor unit and the environmental condition at the location outside of the contactor unit, each of a local humidity in a carbonation vessel from the plurality of carbonation vessels, a moisture content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period; and| executing an action on the plurality of carbonation vessels based on the predicted moisture content and predicted carbonation extent.|2. The method of claim 1, further comprising:| receiving, at a processor, current weather data from a weather service provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the current weather data.|3. The method of claim 2, further comprising:| receiving, at the processor, weather forecast data from a forecast provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the weather forecast data.|4. The method of claim 1, wherein the action includes at least one of spraying water into the carbonation vessel, humidifying the carbonation vessel, taking a measurement of the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, stirring the carbonation medium in the carbonation vessel, dumping the carbonation medium from the carbonation vessel, or filling the carbonation vessel with carbonation medium.|5. The method of claim 1, wherein the forecasting period is between about 1 hour and about 48 hours.|6. The method of claim 3, wherein the weather service provider and the forecast provider are the same provider.|7. The method of claim 1, wherein the location outside of the contactor unit is within about 50 m of an outside border of the contactor unit.|8. The method of claim 3, wherein the weather forecast data is for a period of about 1 hour to about 96 hours.|9. The method of claim 1, further comprising:| updating the prediction of the water content and the carbonation extent of the carbonation medium at an update interval.|10. The method of claim 9, wherein the update interval is between about 5 minutes and about 12 hours.|11. The method of claim 1, wherein the current weather data includes at least one of temperature, relative humidity, wind speed, wind direction, gust speed, solar radiation and irradiance, barometric pressure, CO2 concentration, and precipitation.|12. The method of claim 1, further comprising:| measuring, via the first sensor, at least one of carbonation vessel mass, Fourier transform infrared spectroscopy (FTIR) data from carbonation medium, temperature in the contactor unit, CO2 concentration in the contactor unit, barometric pressure in the contactor unit, wind speed in the contactor unit, or wind direction in the contactor unit.|13. The method of claim 1, further comprising:| measuring, via the second sensor, at least one of temperature, relative humidity, or CO2 concentration at the location outside the contactor unit.|14. The method of claim 1, further comprising:| generating a schedule for application of water to the plurality of carbonation vessels based on the predicting.|15. The method of claim 14, wherein the schedule includes a movement plan for a distributor in the contactor unit.|16. The method of claim 1, further comprising:| measuring a mass of the carbonation vessel;| providing the measured mass of the carbonation vessel, the predicted moisture content of the carbonation vessel, and the predicted carbonation extent of the carbonation medium in the carbonation vessel to a modeler; and either:| (1) transporting the carbonation vessel to a caddy for collection;| (2) translating a spray mass returned by the modeler into a spray speed and requesting the carbonation vessel be sprayed at the spray speed; or| (3) taking no action.|17. The method of claim 1, wherein the carbonation vessels include trays.|18. The method of claim 1, wherein the action includes spraying water into the carbonation vessel, and an amount of water sprayed is determined by at least one of the environmental condition at the location outside of the contactor unit, a forecasted environmental condition, a measured water content in the carbonation vessel, a forecasted water content in the carbonation vessel, a measured carbonation extent in the carbonation vessel, or a forecasted carbonation extent in the carbonation vessel.|19. A system for managing moisture content of a carbonation medium, the system comprising:| a contactor unit including a plurality of carbonation vessels with carbonation medium disposed therein;| a first sensor in the contactor unit, the first sensor configured to measure an environmental condition at a location in the contactor unit;| a second sensor outside the contactor unit, the second sensor configured to measure an environmental condition at a location outside the contactor unit, the measured environmental conditions including relative humidity;| a communication device configured to collect weather forecast data and current weather information from a weather service provider; and| a processor configured to receive data from the first sensor, the second sensor, and the communication device, the processor further configured to develop model predictions for the carbonation extent and moisture content of the carbonation medium in a carbonation vessel from the plurality of carbonation vessels and communicate instructions with components of the contactor unit based on the model predictions.|20. The system of claim 19, wherein the components of the contactor unit include at least one of a water delivery device or a distributor.|21. The system of claim 20, wherein the water delivery device includes a sprayer configured to spray water into the carbonation vessel.|22. The system of claim 19, further comprising:| a third sensor incorporated into a carbonation vessel from the plurality of carbonation vessels.|23. The system of claim 19, wherein the carbonation vessels include trays.|24. A non-transitory, processor-readable medium storing processor-executable instructions to cause a processor to:| receive, via a first sensor, environmental condition data in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium;| receive, via a second sensor, environmental condition data at a location outside of the contactor unit;| predict, based on the environmental condition in the contactor unit and the environmental condition outside of the contactor unit, a water content and a carbonation extent of the carbonation medium for a carbonation forecasting period; and| cause, via an instrument, the execution of an action on the plurality of carbonation vessels based on the predicted water content and predicted carbonation extent.|25. The non-transitory, processor-readable medium of claim 24, wherein the environmental condition in the contactor unit includes at least one of relative humidity, temperature, CO2 concentration, solar irradiance, barometric pressure, wind speed, gust speed, or wind direction.|26. The non-transitory, processor-readable medium of claim 24, wherein the environmental condition at the location outside of the contactor unit includes at least one of relative humidity, temperature, CO2 concentration, solar irradiance, barometric pressure, wind speed, gust speed, or wind direction.|27. The non-transitory, processor-readable medium of claim 24, further storing instructions to cause the processor to receive current weather data from a weather service provider, wherein predicting the water content and the carbonation extent of the carbonation medium is based on the current weather data.|28. The non-transitory, processor-readable medium of claim 25, further storing instructions to cause the processor to receive weather forecast data from a forecast provider wherein predicting the water content and the carbonation extent of the carbonation medium is based on the weather forecast data.|29. The non-transitory, processor-readable medium of claim 24, further storing instructions to cause the processor to update predicted water content and carbonation extent at an update interval.|30. The non-transitory, process-readable medium of claim 29, wherein the update interval is between about 5 minutes and about 12 hours.|31. The non-transitory, process-readable medium of claim 24, wherein the action includes at least one of spraying water onto the carbonation vessel, stirring the carbonation medium in the carbonation vessel, dumping the carbonation medium from the carbonation vessel, or filling the carbonation vessel with carbonation medium.|32. The non-transitory, process-readable medium of claim 24, wherein the weather service provider and the forecast provider are the same provider.|33. The non-transitory, process-readable medium of claim 23, wherein the location outside of the contactor unit is within about 1 m of an outside border of the contactor unit.|34. The non-transitory, process-readable medium of claim 23, wherein the carbonation vessels include trays. | (US20240069580)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to U.S. Provisional Application No. 63/402,211, filed Aug. 30, 2022, and titled “Controls Architecture for Predicting and Maintaining CO2 Uptake Rates in Direct Air Capture Contactors, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety.|(US20240069580)|TECHNICAL FIELD|[0002] Embodiments described herein relate to control systems and methods for predicting and maintaining CO2 uptake rates in an automated system.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's average surface temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. For DACS technologies based on the passive carbonation of oxide and hydroxide minerals, inclusion of moisture in the air capture medium can improve the uptake of CO2. Efficiency of water delivery to the carbonation medium affects the overall efficiency of a system employing a carbonation medium. A system can be implemented to control the delivery of water to the carbonation medium and improve its efficiency.|SUMMARY|[0004] Embodiments described herein relate to control systems for controlling the moisture content of a carbonation medium, and methods of predicting and maintaining CO2 uptake rates in an automated system. In some aspects, a method can include monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium, monitoring, via a second sensor, environmental conditions at a location outside of the contactor unit, predicting, based on the environmental condition in the contactor unit and the environmental condition at the location outside of the contactor unit, a local relative humidity in a carbonation vessel from the plurality of carbonation vessels, a moisture content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period, and executing an action on the plurality of carbonation vessels based on the predicted moisture content and/or predicted carbonation extent.|[0005] In some embodiments, the method can further include receiving, at a processor, current weather data from a weather service provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the current weather data. In some embodiments, the method can further include receiving, at the processor, weather forecast data from a forecast provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the weather forecast data. In some embodiments, the action can include at least one of spraying water into the carbonation vessel, increasing humidity in the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, stirring the carbonation medium in the carbonation vessel, dumping the carbonation medium from the carbonation vessel, or filling the carbonation vessel with carbonation medium. In some embodiments, the forecasting period can be between about 1 hour and about 48 hours. In some embodiments, the weather service provider and the forecast provider can be the same provider. In some embodiments, the location outside of the contactor unit can be within about 50 m of an outside border of the contactor unit. In some embodiments, the weather forecast data can be for a period of about 1 hour to about 96 hours.|(US20240069580)|BRIEF DESCRIPTION OF THE DRAWINGS|[0006] FIG. 1 is a flow diagram of a method of controlling water delivery to a carbonation medium, according to an embodiment.|[0007] FIG. 2 is a block diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|[0008] FIG. 3 is a block diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|[0009] FIG. 4 is a block diagram of a computing cluster for controlling water delivery to a carbonation medium, according to an embodiment.|[0010] FIG. 5 is a block diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|[0011] FIG. 6 is an entity relationship diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|(US20240069580)|DETAILED DESCRIPTION|[0012] Embodiments described herein relate to controls architecture for water delivery to a carbonation medium and maintenance of CO2 uptake rates in an automated fashion. The controls architecture can be used to control carbonation vessel (e.g., tray) processing inside of a contactor system. In some embodiments, trays and contactor units described herein can be the same or substantially similar to those described in U.S. patent application Ser. No. 18/348,112 (“the '112 application”), filed Jul. 6, 2023, and titled, “Direct Air Capture Contactor for Carbon Uptake, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety.|[0013] Carbonation vessels described herein can be processed using a distributor (i.e., a processing unit). A controls system can take in environmental data from sensors integrated into a contactor, sensors that are distributed throughout a process cell, as well as predictive data from weather forecasts to anticipate when and how a tray should be processed. In some embodiments, this prediction is then prioritized and used to create a schedule for processing trays. In some embodiments, a tray processing instruction can be generated when a distributor approaches a tray. For example, a central processing unit (CPU) can send a tray processing instruction to the distributor when the distributor is in close proximity to the tray. Processing can include spraying, increasing local humidity in the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, taking measurements using a distributor (or other similar hardware), stirring, or other actions or combinations thereof.|[0014] Embodiments described herein provide a basis for tray processing, carbonation, and moisture control, as well as predicting carbonation extent and moisture content. An array of sensors can be provided both outside and inside the contactors that are continuously collecting environmental data that is fed into an environmental data localizer. The environmental data localizer determines environmental conditions of specific trays and groups of trays using algorithms described herein. The information from the environmental data localizer is sent to the modeler. The modeler can also receive information from weather forecast services (among other external data sources) as well as information on latest estimates for the state of a tray (i.e., predicted carbonation extent and moisture content). Using this information, the modeler can determine a current calculated moisture content and a predicted future moisture content for the carbonation medium for a given carbonation vessel.|[0015] In some embodiments, the carbonation medium can include at least one of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation rate can be a function of moisture content in the carbonation medium as well as other environmental factors and material properties. This information can be used to determine when the moisture content will be sufficiently low to hamper carbonation rate, and when the carbonation extent of the tray will approach a specified threshold at which the carbonation medium is deemed ready to be emptied form the carbonation vessel. In some embodiments, the carbonation extent threshold value can range from about 50% to about 100% carbonation.|[0016] The prediction from the modeler can be used to inform the system's next action via a planner. The planner can receive updated estimates from the modeler for a tray and translates the estimate into a schedule of tray operations in the form of a list of conditions. Tray operations can include commands, such as spray, deliver water via capillary action, humidify, dump, fill, measure, stir, or any combination thereof. Prior to outputting a carbonation vessel schedule, the schedule is constrained by the availability of shared machinery for each contactor. After developing a schedule, the planner can send the schedule to a conductor gateway via a request (e.g., an HTTP POST request). The conductor gateway is a routing layer that maintains a mapping between a carbonation vessel and a contactor, using mapping to dispatch schedules received for a tray to the responsible conductor via a request (e.g., an HTTP POST request).|[0017] In an example embodiment, a distributor can visit each tray in the contactor sequentially and execute the following for each tray: (1) execute load cell measurement of tray mass; (2) provide the load cell measurement to a modeler via an HTTP POST request along with data (e.g., weather forecasting data, state-of-tray data, as described above), which the modeler uses to calculate carbonation extent (%) and the mass or water to add to the tray; (3) if the carbonation extent is sufficiently high, the conductor can (3a) move the tray to a caddy to be picked up for collection; otherwise the conductor can (3b) request that the tray is operated upon using one of the aforementioned methods (i.e., spray, deliver water via capillary action, humidify, dump, fill, measure, stir, or any combination thereof). The conductor can also choose to take no action.|[0018] Embodiments described herein enable high CO2 uptake rates in carbonation medium irrespective of environmental conditions (i.e., effective control of carbonation rates). Embodiments described herein also enable tracking and prediction of carbonation extent (i.e., CO2 uptake via carbonation medium) and moisture content in order to precisely time the transfer of carbonation medium to a carbonation regeneration subsystem.|[0019] Embodiments described herein can also enable control of water use and subsequently minimize water use in the carbonation system. The level of precision and control of water delivery enables greater efficiency and allows for more optimization than modern irrigation systems. Additionally, all-in-one weather stations can calculate predicted evaporation rates, but do not include a feedback loop to process a material or give a command to a piece of physical infrastructure. Predicted evaporation rates can be calculated based on specific characteristics of the carbonation medium. In other words, a range of different carbonation media can be accounted for in the development of the modeling of the carbonation system. They additionally do not include an environmental data localizer.|[0020] In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2020/263910 (“the '910 publication”), filed Jun. 24, 2020, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Application No. US2022/018484 (“the '484 application”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. Benefits of interactions between water and carbonation medium are described in greater detail in the '910 publication and the '484 application.|[0021] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions. In some embodiments, carbonation plots can include a composition that sequesters a target compound.|[0022] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0023] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0024] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0025] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0026] As used herein, the term “about” and “approximately” generally means plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0027] FIG. 1 is a flow diagram of a method 10 of controlling water delivery to a carbonation medium, according to an embodiment. As shown, the method 10 includes monitoring an atmospheric condition in a contactor unit at step 11. The method 10 optionally includes measuring carbonation vessel mass, Fourier Transform Infrared (FTIR) spectroscopy from the carbonation medium, temperature, CO2 concentration, barometric pressure, solar radiation and irradiance, wind speed, gust speed, and/or wind direction in the contractor unit at step 12. The method 10 further includes monitoring an atmospheric condition at a location outside of the contactor unit at step 13. The method 10 optionally includes receiving current weather data at step 14 and receiving forecasted weather data at step 15. The method 10 further includes predicting the moisture content and the carbonation extent of the carbonation medium for a carbonation forecasting period at step 16 and executing an action based on the predicted moisture content and carbonation extent at step 17. The method 10 optionally includes updating the predicted moisture content and carbonation extent at an update interval at step 18.|[0028] Step 11 includes monitoring an environmental condition in the contactor unit. In some embodiments, the environmental condition can include relative humidity. In some embodiments, the environmental condition can include temperature in the contactor unit, CO2 concentration in the contactor unit, barometric pressure in contractor unit, solar radiation and irradiance, wind speed, and/or wind direction in the contactor unit. In some embodiments, the monitoring can include measurement of the relative humidity via a sensor. In some embodiments, the contactor unit can be exposed to the surrounding or outside environment. In some embodiments, the contactor unit can be contained or isolated from the surrounding environment. In some embodiments, “in the contactor unit” can refer to locations within the bounds created by bars of the contactor unit. For example, the region in the contactor unit can be between minimum and maximum x, y, and z values occupied by bars that form the contactor unit. In some embodiments, “in the contactor unit” can refer to a location within a specified distance of a center of gravity of the carbonation vessels. In some embodiments, the specified distance can be about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, or about 10 m, inclusive of all values and ranges therebetween.|[0029] In some embodiments, “in the contactor unit” can refer to a location within a specified distance of outer edges of the carbonation vessels. In some embodiments, the specified distance can be about 5 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, or about 5 m, inclusive of all values and ranges therebetween. In some embodiments, the relative humidity in the contactor unit can be monitored via a capacitive humidity sensor, a resistive humidity sensor, and/or a thermal humidity sensor. In some embodiments, a single sensor or measurement system can be used to monitor a plurality of contactors. For example, a sensor can be placed within a specified distance (e.g., about 5 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, or about 5 m, inclusive of all values and ranges therebetween) of the outer edge of multiple carbonation vessels, and can make predictions about each of the carbonation vessels.|[0030] Step 12 is optional and includes measuring the carbonation vessel mass, FTIR from the carbonation medium, temperature in the contactor unit, CO2 concentration in the contactor unit, barometric pressure in contractor unit, solar radiation and irradiance, wind speed, and/or wind direction in the contactor unit. In some embodiments, the measurement can be from a sensor or instrumentation, different from the sensor used to measure relative humidity. In some embodiments, multiple sensors (i.e., with different sensing capabilities such as CO2 concentration and relative humidity) can be housed in one location or one housing. In some embodiments, mass can be measured via a scale placed below each carbonation vessel. In some embodiments, mass can be measured via a moving scale that can be placed under one carbonation vessel at a time. In some embodiments, the scale can be placed at a central location (e.g., inside of a distributor).|[0031] In some embodiments, the measurements of a single tray can be used to make predictions about a cohort of trays (e.g., about 2 trays, about 3 trays, about 4 trays, about 5 trays, about 6 trays, about 7 trays, about 8 trays, about 9 trays, about 10 trays, about 20 trays, about 30 trays, about 40 trays, about 50 trays, about 60 trays, about 70 trays, about 80 trays, about 90 trays, or about 100 trays, inclusive of all values and ranges therebetween). In other words, a single tray can be measured (e.g., weighed) at a centralized location and used as a proxy for multiple trays.|[0032] In some embodiments, infrared instrumentation (e.g., FTIR) can be used to determine the chemical makeup and various concentrations of compounds in the carbonation medium. In some embodiments, an infrared spectral sensor can be used to determine the composition of the carbonation medium. In some embodiments, temperature can be measured in a carbonation vessel and/or the contactor unit via a thermocouple. In some embodiments, temperature can be measured in a carbonation vessel and/or the contactor unit via a thermometer. In some embodiments, CO2 concentration can be measured in a carbonation vessel and/or the contactor unit via an ambient gas sensor. In some embodiments, barometric pressure can be measured in a carbonation vessel and/or the contactor unit via a barometer. In some embodiments, the wind speed can be measured via an anemometer.|[0033] At step 13, the method 10 includes monitoring an atmospheric condition at a location outside of the contactor unit. In some embodiments, the atmospheric condition can include relative humidity. In some embodiments, the relative humidity can be monitored via a sensor, different from the sensor used to monitor relative humidity inside the contactor unit. In some embodiments, the location outside of the contactor unit can be measured from a boundary between the inside of the contactor unit and the outside of the contactor unit, as described above with reference to step 11, where “in the contactor unit” refers to physical boundaries created by imaginary lines extending from bars of the contactor unit. In some embodiments, the location outside of the contactor unit can be measured from the center of gravity of a carbonation vessel. In some embodiments, the location outside of the contactor unit can be measured from the external bounds of a carbonation vessel. In some embodiments, the atmospheric condition monitored at step 13 can include temperature, CO2 concentration, solar irradiance, barometric pressure, wind speed, gust speed, wind direction, or any combination thereof.|[0034] In some embodiments, the location outside of the contactor unit can be at least about 1 m, at least about 2 m, at least about 3 m, at least about 4 m, at least about 5 m, at least about 6 m, at least about 7 m, at least about 8 m, at least about 9 m, at least about 10 m, at least about 20 m, at least about 30 m, at least about 40 m, at least about 50 m, at least about 60 m, at least about 70 m, at least about 80 m, or at least about 90 m from the boundary, the center of gravity of the carbonation vessel, or the external bounds of the carbonation vessel. In some embodiments, the location outside of the contactor unit can be no more than about 100 m, no more than about 90 m, no more than about 80 m, no more than about 70 m, no more than about 60 m, no more than about 50 m, no more than about 40 m, no more than about 30 m, no more than about 20 m, no more than about 10 m, no more than about 9 m, no more than about 8 m, no more than about 7 m, no more than about 6 m, no more than about 5 m, no more than about 4 m, no more than about 3 m, or no more than about 2 m from the boundary, the center of gravity of the carbonation vessel, or the external bounds of the carbonation vessel.|[0035] Combinations of the above-referenced distances are also possible (e.g., at least about 1 m and no more than about 100 m or at least about 5 m and no more than about 60 m), inclusive of all values and ranges therebetween. In some embodiments, the location outside of the contactor unit can be about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, about 10 m, about 20 m, about 30 m, about 40 m, about 50 m, about 60 m, about 70 m, about 80 m, about 90 m, or about 100 m from the boundary, the center of gravity of the carbonation vessel, or the external bounds of the carbonation vessel.|[0036] Step 14 is optional and includes receiving current weather data. The current weather data includes data from the geographic region where the contactor unit resides. In some embodiments, the current weather data can be from a local weather service provider. In some embodiments, the current weather data can be from a professional or commercial provider. In some embodiments, the current weather data can be collected independently (e.g., from instrumentation). In some embodiments, the current weather data can include temperature, humidity, precipitation, barometric pressure, solar radiation and irradiance, dewpoint, wind speed, and/or wind direction data.|[0037] In some embodiments, the current weather data can be received at regular intervals. In some embodiments, the current weather data can be received at irregular intervals. In some embodiments, the current weather data can be received at intervals of at least about 1 second, at least about 2 seconds, at least about 3 seconds, at least about 4 seconds, at least about 5 seconds, at least about 10 seconds, at least about 15 seconds, at least about 20 seconds, at least about 30 seconds, at least about 40 seconds, at least about 50 seconds, at least about 1 minute, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, or at least about 18 hours. In some embodiments, the current weather data can be received at intervals of no more than about 24 hours, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, no more than about 5 minutes, no more than about 4 minutes, no more than about 3 minutes, no more than about 2 minutes, no more than about 1 minute, no more than about 50 seconds, no more than about 40 seconds, no more than about 30 seconds, no more than about 20 seconds, no more than about 15 seconds, no more than about 10 seconds, no more than about 5 seconds, no more than about 4 seconds, no more than about 3 seconds, or no more than about 2 seconds.|[0038] In some embodiments, the current weather data can be received at intervals of about 1 second, about 2 seconds, about 3 seconds, about 4 seconds, about 5 seconds, about 10 seconds, about 15 seconds, about 20 seconds, about 30 seconds, about 40 seconds, about 50 seconds, about 1 minute, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, or about 24 hours.|[0039] Step 15 is optional and includes receiving forecast weather data. In some embodiments, the forecast weather data can be from a local service provider. In some embodiments, the forecast weather data can be from a professional or commercial service provider. In some embodiments, the forecast weather data can be collected independently (e.g., from instrumentation provided). In some embodiments, the forecast weather data can be received from the same provider as the current weather data. In some embodiments, the forecast weather data can include temperature, relative humidity, precipitation, barometric pressure, solar radiation and irradiance, CO2 concentration, dewpoint, wind speed, and/or wind direction forecast data. In some embodiments, the forecast weather data can forecast into the future by about 1 hour, about 4 hours, about 12 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 7 days, about 8 days, about 9 days, about 10 days, about 11 days, about 12 days, about 13 days, about 14 days, or about 15 days, inclusive of all values and ranges therebetween.|[0040] In some embodiments, forecast weather data can be retrieved or refreshed at intervals of at least about 1 minute, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, at least about 18 hours, at least about 1 day, at least about 2 days, at least about 3 days, at least about 4 days, at least about 5 days, or at least about 6 days. In some embodiments, the forecast weather data can be retrieved or refreshed at intervals of no more than about 7 days, no more than about 6 days, no more than about 5 days, no more than about 4 days, no more than about 3 days, no more than about 2 days, no more than about 1 day, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, no more than about 5 minutes, no more than about 4 minutes, no more than about 3 minutes, or no more than about 2 minutes.|[0041] Combinations of the above-referenced intervals are also possible (e.g., at least about 1 minute and no more than about 7 days or at least about 12 hours and no more than about 1 day), inclusive of all values and ranges therebetween. In some embodiments, forecast weather data can be retrieved or refreshed at intervals of about 1 minute, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, or about 7 days.|[0042] Step 16 includes predicting a moisture content and a carbonation extent of the carbonation medium for a carbonation forecasting period. Moisture content can be a function of predicted temperatures, humidity, solar radiation and irradiance, wind speed, barometric pressures, and CO2 concentration, as well as current temperatures, humidity, solar radiation and irradiance, wind speed, barometric pressure, and CO2 concentration. Moisture content may also be a function of material properties (such as surface area and particle size) as well as the material's carbonation and hydration state. In some embodiments, the predicting can be via a modeler software. Carbonation rate is a function of moisture content, as described in the '910 publication and the '484 application. A carbonation forecasting model predicts the future carbonation extent of the carbonation medium for a carbonation forecasting period. In some embodiments, the method 10 can include generating a schedule for application of water to one or more carbonation vessels based on the predicted moisture content and carbonation extent at step 16. In some embodiments, the schedule can include a movement plan for a distributor in the contactor unit.|[0043] In some embodiments, the carbonation forecasting period can be at least about 1 minute, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, at least about 18 hours, at least about 1 day, at least about 2 days, at least about 3 days, at least about 4 days, at least about 5 days, at least about 6 days, at least about 7 days, at least about 10 days, at least about 15 days, at least about 20 days, or at least about 25 days. In some embodiments, the forecasting period can be no more than about 30 days, no more than about 25 days, no more than about 20 days, no more than about 15 days, no more than about 10 days, no more than about 7 days, no more than about 6 days, no more than about 5 days, no more than about 4 days, no more than about 3 days, no more than about 2 days, no more than about 1 day, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, or no more than about 5 minutes.|[0044] Combinations of the above-referenced carbonation forecasting periods are also possible (e.g., at least about 1 minute and no more than about 30 days or at least about 3 hours and no more than about 6 days), inclusive of all values and ranges therebetween. In some embodiments, the carbonation forecasting period can be about 1 minute, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 7 days, about 10 days, about 15 days, about 20 days, about 25 days, or about 30 days.|[0045] Step 17 includes executing an action based on a predicted moisture content and a predicted carbonation extent. In some embodiments, the action can include spraying a carbonation vessel, humidifying the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, dumping carbonation medium from a carbonation vessel, filling a carbonation vessel with carbonation medium, measuring a mass of a carbonation vessel, taking an IR spectrum of the carbonation vessel, and/or stirring the carbonation medium in the carbonation vessel. In some embodiments, either of these actions can be scheduled at prescribed intervals in the future.|[0046] In some embodiments, spraying can include spraying of water into the carbonation vessel at prescribed times and/or with prescribed amounts in the future when the moisture content of the carbonation medium is predicted to fall below a threshold value. In some embodiments, the threshold value can be about 100 wt % water, about 95 wt % water, about 90 wt % water, about 85 wt % water, about 80 wt % water, about 75 wt % water, about 70 wt % water, about 65 wt % water, about 60 wt % water, about 55 wt % water, about 50 wt % water, about 45 wt % water, about 40 wt % water, about 35 wt % water, about 30 wt % water, about 25 wt % water, about 20 wt % water, about 15 wt % water, about 10 wt % water, about 9 wt % water, about 8 wt % water, about 7 wt % water, about 6 wt % water, about 5 wt % water, about 4 wt % water, about 3 wt % water, about 2 wt % water, about 1 wt % water, about 0.9 wt % water, about 0.8 wt % water, about 0.7 wt % water, about 0.6 wt % water, about 0.5 wt % water, about 0.4 wt % water, about 0.3 wt % water, about 0.2 wt % water, or about 0.1 wt % water, inclusive of all values and ranges therebetween. In some embodiments, the amount and/or frequency of water sprayed can be determined by a measured environmental condition, a forecasted environmental condition, a measured moisture content in the carbonation vessel, and/or a forecasted moisture content in the carbonation vessel.|[0047] In some embodiments, dumping the carbonation medium can be in response to the carbonation medium being spent (i.e., the carbonation medium is no longer taking up CO2 and is mostly carbonate), such that the spent carbonation medium can be calcined. Dumping can also be in response to detecting that the carbonation vessel is over a desired weight. In some embodiments, stirring the carbonation medium can be in response to a predicted moisture content that is higher than a threshold value (due to forecasted rain or humidity) to aerate the carbonation medium. In some embodiments, the threshold value can be about 10 wt %, about 11 wt %, about 12 wt %, about 13 wt %, about 14 wt %, about 15 wt %, about 16 wt %, about 17 wt %, about 18 wt %, about 19 wt %, about 20 wt %, about 21 wt %, about 22 wt %, about 23 wt %, about 24 wt %, about 25 wt %, about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, about 50%, about 55 wt %, or about 60 wt %, inclusive of all values and ranges therebetween. Stirring can also be in response to an overweight carbonation vessel in order to aerate the carbonation medium. Filling the carbonation vessel with carbonation medium can be in response to detecting that the carbonation vessel is less than a desired weight or to restart a cycle by depositing fresh sorbent material. In some embodiments, collected trays can be selected based on their carbonation extent. Trays with varying levels of carbonation extent can be collected. This “tray blending” can yield an aggregate material that meets or exceeds a target carbonation value (e.g., about 50% carbonation, about 55% carbonation, about 60% carbonation, about 65% carbonation, about 70% carbonation, about 75% carbonation, about 80% carbonation, about 85% carbonation, or about 90% carbonation, inclusive of all values and ranges therebetween) by blending over-carbonated and under-carbonated material.|[0048] Step 18 is optional and includes updating a current estimated moisture content, current estimated carbonation extent, forecasted moisture content, and forecasted carbonation extent at an update interval. In some embodiments, the update can be based on present environmental data. In some embodiments, the update can be based on forecast data. In some embodiments, the update interval can be at least about 1 minute, at least about 2 minutes, at least about 3 minutes, at least about 4 minutes, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, or at least about 18 hours. In some embodiments, the update interval can be no more than about 24 hours, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, no more than about 5 minutes, no more than about 4 minutes, no more than about 3 minutes, or no more than about 2 minutes.|[0049] Combinations of the above-referenced update intervals are also possible (e.g., at least about 1 minute and no more than about 24 hours or at least about 5 minutes and no more than about 12 hours), inclusive of all values and ranges therebetween. In some embodiments, the update interval can be about 1 minute, about 2 minutes, about 3 minutes, about 4 minutes, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, or about 24 hours.|[0050] FIG. 2 is a block diagram of a system 100 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the system 100 includes a site 101 with carbonation equipment and a computing cluster 102 with computational hardware.|[0051] As shown, the site 101 includes a contactor unit 110 and sensors 120, while the computing cluster 102 includes a communication device 130, a memory 132, an Input/Output (I/O) device 134, and a processor 140. In some embodiments, the contactor unit 110 can have the same or substantially similar properties to those described in the '112 application. In some embodiments, the sensors 120 can include humidity sensors, temperature sensors, solar radiation and irradiance sensors, wind speed sensors, wind direction sensors, precipitation sensors, barometric pressure sensors, and/or CO2 concentration sensors, as described above with reference to FIG. 1. In some embodiments, one or more of the sensors 120 can be coupled to the contactor unit 110. In some embodiments, one or more of the sensors 120 can be positioned outside of the contactor unit 110 and/or uncoupled from the contactor unit 110.|[0052] As shown, dotted connectors indicate a communicative coupling and solid connectors indicate solid coupling. In some embodiments, the communicative coupling can be via a Wi-Fi connection, a wired connection, a wireless connection, a 3G connection, a 4G connection, a 5G connection, or any other suitable communicative coupling or combinations thereof. In some embodiments, the computing cluster 102 can be physically located at the site 101 or in close proximity to the site 101. In some embodiments, the computing cluster 102 can be located at a separate location from the site.|[0053] As shown, the communication device 130 receives data from the contactor unit 110 and the sensors 120. In some embodiments, the data can include any of the environmental conditions described above with reference to FIG. 1 (e.g., temperature, humidity, barometric pressure, CO2 concentration, solar radiation and irradiance, wind speed, wind direction, etc.). The communication device 130 communicates with the processor 140. The processor 140 then communicates instructions to the contactor unit 110 to execute operations (e.g., spray, humidify, deliver water via capillary action, dump, fill, measure, stir).|[0054] In some embodiments, the memory 132, can include a random-access memory (RAM), a memory buffer, a hard drive, a database, an erasable programmable read-only memory (EPROM), an electrically erasable read-only memory (EEPROM), a read-only memory (ROM), or any combination thereof. In some embodiments, memory 122 stores instructions that cause processor 140 to execute modules, processes, and/or functions associated with operating one or more components of the contactor unit 110. Such instructions can be designed to integrate specialized functions into a controller of the contactor unit 110, such that one or actions can be performed.|[0055] The I/O device 134 includes one or more components for receiving information and/or sending information to other components of computing cluster 102 and/or site 101. In some embodiments, the I/O device 134 can optionally include or be operatively coupled to a display, audio device, or other output device for presenting information to a user. In some embodiments, the I/O device 134 can include a communication interface that can enable communication between the communication device 130, the sensors 120, a power source, and/or the contactor unit 110. In some embodiments, the I/O device 134 can include a network interface that can enable communication between the computing cluster 102 and one or more external devices, including, for example, an external user device (e.g., a mobile phone, a tablet, a laptop) and/or other compute device (e.g., a local or remote compute, a server, etc.). The network interface can be configured to provide a wired connection with the external device, (e.g., via a port or firewall interface, can be configured to communicate with the external device via a wireless network).|[0056] The processor 140 can be any suitable processing device configured to run and/or execute functions associated with the contactor unit 110. For example, processor 140 can be configured to process and/or analyze sensor data (e.g., received from sensor(s) 120 coupled to and/or integrated into the contactor unit 110), to change the timing of stirring, spraying, humidifying, measuring, delivering water via capillary action, filling, dumping, to adjust one or more other parameters or aspects of contactor unit operation, etc. The processor 140 can be a general-purpose processor, a Field Programmable Gate Array (FPGA), an Application Specific Integrated Circuit (ASIC), a Digital Signal Processor (DSP), and/or the like.|[0057] FIG. 3 shows a system 200 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the system 200 includes a site 201 with carbonation equipment and a computing cluster 202 with computational hardware. As shown, the site 201 includes environmental sensors 220, an environmental data service 222, and conductors 224. As shown, the computing cluster 202 includes an environmental data localizer 231, a modeler 233, a planner 235, a process cell manager 237, and a conductor gateway 239.|[0058] In some embodiments, the environmental sensors 220 can be the same or substantially similar to the sensors 120, as described above with reference to FIG. 2. As shown, the environmental sensors 220 transport raw environmental data to the environmental data service 222 (e.g., via a GET function). The raw environmental data is buffered via a filesystem (FS). The environmental data localizer 231 retrieves the raw environmental data via the environmental data service 222.|[0059] The environmental data localizer 231 shares raw environmental data, versioned weather forecasts, and localized environmental data with a time series database (TS DB), as well as retrieving raw environmental data, versioned weather forecasts, and localized environmental data from the TS DB. The environmental data localizer 231 retrieves weather forecasts from external weather forecasts (e.g., via a GET function). In some embodiments, the environmental weather forecasts can be from professional or commercial weather forecast providers. The environmental data localizer 231 feeds localized environmental data (i.e., present environmental data and forecasted weather data) to the modeler 233. The modeler 233 shares carbonation percentage forecasts, moisture content percentage forecasts, and material state (e.g., saturated carbonation medium, fresh carbonation medium) forecasts with a TS DB. In some embodiments, the material state data can include a ‘ready to empty’ flag. In addition, the modeler 233 receives carbonation percentage forecasts, moisture content percentage forecasts, and material state forecasts from the TS DB.|[0060] The modeler 233 feeds carbonation percentage forecasts and moisture content forecasts to the planner 235. The process cell manager 237 also feeds offline period data and backpressure data to the planner 235. The backpressure data is information conveyed by the process cell manager 237 to signal to the carbonation subsystem that the carbonation subsystem should reduce its output rate of carbonation medium. In other words, the backpressure data keeps the carbonation subsystem and the regeneration subsystem in balance. The process cell manager 237 is responsible for coordinating the operation of a carbonation subsystem with the operation of material handling and regeneration subsystems. For example, if the regeneration subsystem is unable to receive additional carbonated material, the process cell manager 237 notifies the planner 235 of the carbonation subsystem and the material handling subsystems to reduce output.|[0061] The planner 235 makes decisions about whether a quantity of carbonation medium should be retired (i.e., dumped and recycled for calcining). The planner 235 feeds recipes (i.e., sequences of steps enacted on the contactor unit) to the conductor gateway 239 via a POST command. The conductor gateway 239 communicates with a TS DB to develop versioned (i.e., tracked for possible evaluation later) recipes. The conductor gateway 239 feeds the recipes to the conductors 224 and receives event and data from the conductors 224 as well as from the environmental sensors. The conductors 224 are software programs that initiate actions to be performed on the trays (e.g., moving, dumping, measuring, filling, spraying, humidifying, deliver water via capillary action). The conductors 224 receive current contactor state information, as well as buffered event.|[0062] The conductor gateway 239 provides an abstraction layer between the conductor instances, which map 1-1 with PLC's, and other software programs that operate at the site 201. For example, the planner 235 can request information from any tray from the conductor gateway 239, regardless of which of the conductors 224 is responsible for the tray. When the conductor gateway 239 receives a request, it selects the conductor 224 that manages the requested information and forward the request to that particular conductor 224 instance. Once the response is received, the conductor gateway 239 returns the response to the planner 235.|[0063] FIG. 4 shows a computing cluster 302 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the computing cluster 302 includes subclusters for area management and reporting 303, process cell subsystems 304, and monitoring and logging 305. The area management and reporting 303 subcluster includes an area user interface 350 with an operator dashboard 352 and an analytics dashboard 354. The management and reporting 303 subcluster further includes an analytics service 356 and a process cells manager 358. The process cell subsystems 304 include a regeneration subsystem 362, a carbonation subsystem 364, and a conveyance subsystem. The monitoring and logging 305 subsystem can include a monitoring and metrics collection service 361 and a data visualization and analytics service 363.|[0064] A user or operator can make system management decisions via the operator dashboard 352. The operator dashboard 352 can receive data from the process cells manager 358. The process cells manager 358 receives information from a relational database (DB). The analytics dashboard 354 can allow the user or operator to read data that is either raw or has been subject to processing by the analytics service 356. In some embodiments, the analytics dashboard can receive analyzed data from the analytics service 356. In some embodiments, the analytics service 356 can receive data from a TS DB. The TS DB can receive data from a data ingestion site 355, which receives data from the process cell subsystems 303.|[0065] In the process cell subsystems 303, the regeneration subsystem 362 makes decisions regarding whether to replace and/or replenish carbonation medium in a particular carbonation vessel (e.g., tray). The carbonation subsystem 364 produces data about carbonation and uptake. The conveyance subsystem 366 produces data about movement of carbonation vessels.|[0066] In the monitoring and logging subsystem, the monitoring and metrics collection service 361 looks up data and receives performance data from the regeneration subsystem 362. The data visualization and analytics service 363 receives a process cell subsystem log in a search engine section.|[0067] FIG. 5 is a block diagram of a system 400 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the system includes a site 401 and a computing cluster 402. In some embodiments, the site 401 and the cluster 402 can be the same or substantially similar to the site 101 and the cluster 102, as described above with reference to FIG. 2. As shown, the site 401 includes environmental sensors 420, a local environmental sensor data collector 421, and a local weather station 472. The computing cluster 402 includes an environmental data service 422.|[0068] In some embodiments, the environmental sensors 420 can be the same or substantially similar to the environmental sensors 120, as described above with reference to FIG. 2. The environmental sensors 420 communicate with the local environmental sensor data collector 421, which communicates with an local environmental sensor DB, which provides local sensor data to the environmental data service 422. The local environmental sensor data collector 421 is a supervisory control and data acquisition (SCADA) software control system used to generate a human machine interface (HMI). The local environmental sensor data collector 421 is both in the SCADA system and the HMI provider. The local weather station 472 communicates weather data. As shown by example, local weather station 472 communicates ambient weather data with a Cloud DB via Wi-Fi. The local and ambient weather data are then fed to a local weather data collector, which feeds local weather data to a local weather DB. The local weather DB fees the local weather data to the environmental data service 422.|[0069] The environmental data service 422 receives weather forecasts by location from various weather apps as forecasts queried at forecasting intervals. The environmental data service 422 communicates site specific forecasts with the forecast DB and receives local weather data from the forecast DB. The environmental data service 422 includes an environmental data service application programming interface (EDS API) for interaction with the user. FIG. 6 is an entity relationship diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment. Blocks with yellow headings are controlled by the conductors. The block in purple is controlled by the planner. Blocks in green are controlled by the modeler supervisor. The block in blue is controlled by the process cell manager. The modeler includes localization algorithms, evaporation algorithms, and carbonation algorithms in communication with the planner and the conductor. The modeler also includes assignments in communication with the algorithms and the trays. The planner is also in communication with the trays. The conductor database events are in communication with a tray filling system, contactors, shelves, and trays. The conductor database events are also in communication with material batches of the process cell manager. The contactors in the conductor database are also in communication with the hopper and the shelves.|[0070] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0071] In addition, the disclosure may include other innovations not presently described. Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0072] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0073] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0074] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0075] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0076] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0077] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0078] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0079] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | (US20240069580)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to U.S. Provisional Application No. 63/402,211, filed Aug. 30, 2022, and titled “Controls Architecture for Predicting and Maintaining CO2 Uptake Rates in Direct Air Capture Contactors, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety.|(US20240069580)|TECHNICAL FIELD|[0002] Embodiments described herein relate to control systems and methods for predicting and maintaining CO2 uptake rates in an automated system.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's average surface temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. For DACS technologies based on the passive carbonation of oxide and hydroxide minerals, inclusion of moisture in the air capture medium can improve the uptake of CO2. Efficiency of water delivery to the carbonation medium affects the overall efficiency of a system employing a carbonation medium. A system can be implemented to control the delivery of water to the carbonation medium and improve its efficiency.|SUMMARY|[0004] Embodiments described herein relate to control systems for controlling the moisture content of a carbonation medium, and methods of predicting and maintaining CO2 uptake rates in an automated system. In some aspects, a method can include monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium, monitoring, via a second sensor, environmental conditions at a location outside of the contactor unit, predicting, based on the environmental condition in the contactor unit and the environmental condition at the location outside of the contactor unit, a local relative humidity in a carbonation vessel from the plurality of carbonation vessels, a moisture content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period, and executing an action on the plurality of carbonation vessels based on the predicted moisture content and/or predicted carbonation extent.|[0005] In some embodiments, the method can further include receiving, at a processor, current weather data from a weather service provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the current weather data. In some embodiments, the method can further include receiving, at the processor, weather forecast data from a forecast provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the weather forecast data. In some embodiments, the action can include at least one of spraying water into the carbonation vessel, increasing humidity in the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, stirring the carbonation medium in the carbonation vessel, dumping the carbonation medium from the carbonation vessel, or filling the carbonation vessel with carbonation medium. In some embodiments, the forecasting period can be between about 1 hour and about 48 hours. In some embodiments, the weather service provider and the forecast provider can be the same provider. In some embodiments, the location outside of the contactor unit can be within about 50 m of an outside border of the contactor unit. In some embodiments, the weather forecast data can be for a period of about 1 hour to about 96 hours.|(US20240069580)|BRIEF DESCRIPTION OF THE DRAWINGS|[0006] FIG. 1 is a flow diagram of a method of controlling water delivery to a carbonation medium, according to an embodiment.|[0007] FIG. 2 is a block diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|[0008] FIG. 3 is a block diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|[0009] FIG. 4 is a block diagram of a computing cluster for controlling water delivery to a carbonation medium, according to an embodiment.|[0010] FIG. 5 is a block diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|[0011] FIG. 6 is an entity relationship diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment.|(US20240069580)|DETAILED DESCRIPTION|[0012] Embodiments described herein relate to controls architecture for water delivery to a carbonation medium and maintenance of CO2 uptake rates in an automated fashion. The controls architecture can be used to control carbonation vessel (e.g., tray) processing inside of a contactor system. In some embodiments, trays and contactor units described herein can be the same or substantially similar to those described in U.S. patent application Ser. No. 18/348,112 (“the '112 application”), filed Jul. 6, 2023, and titled, “Direct Air Capture Contactor for Carbon Uptake, and Methods of Operating the Same,” the disclosure of which is hereby incorporated by reference in its entirety.|[0013] Carbonation vessels described herein can be processed using a distributor (i.e., a processing unit). A controls system can take in environmental data from sensors integrated into a contactor, sensors that are distributed throughout a process cell, as well as predictive data from weather forecasts to anticipate when and how a tray should be processed. In some embodiments, this prediction is then prioritized and used to create a schedule for processing trays. In some embodiments, a tray processing instruction can be generated when a distributor approaches a tray. For example, a central processing unit (CPU) can send a tray processing instruction to the distributor when the distributor is in close proximity to the tray. Processing can include spraying, increasing local humidity in the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, taking measurements using a distributor (or other similar hardware), stirring, or other actions or combinations thereof.|[0014] Embodiments described herein provide a basis for tray processing, carbonation, and moisture control, as well as predicting carbonation extent and moisture content. An array of sensors can be provided both outside and inside the contactors that are continuously collecting environmental data that is fed into an environmental data localizer. The environmental data localizer determines environmental conditions of specific trays and groups of trays using algorithms described herein. The information from the environmental data localizer is sent to the modeler. The modeler can also receive information from weather forecast services (among other external data sources) as well as information on latest estimates for the state of a tray (i.e., predicted carbonation extent and moisture content). Using this information, the modeler can determine a current calculated moisture content and a predicted future moisture content for the carbonation medium for a given carbonation vessel.|[0015] In some embodiments, the carbonation medium can include at least one of calcium oxide, calcium hydroxide, magnesium oxide, magnesium hydroxide, sodium oxide, sodium hydroxide, or dolomitic lime (calcium-magnesium oxide or hydroxide). Carbonation rate can be a function of moisture content in the carbonation medium as well as other environmental factors and material properties. This information can be used to determine when the moisture content will be sufficiently low to hamper carbonation rate, and when the carbonation extent of the tray will approach a specified threshold at which the carbonation medium is deemed ready to be emptied form the carbonation vessel. In some embodiments, the carbonation extent threshold value can range from about 50% to about 100% carbonation.|[0016] The prediction from the modeler can be used to inform the system's next action via a planner. The planner can receive updated estimates from the modeler for a tray and translates the estimate into a schedule of tray operations in the form of a list of conditions. Tray operations can include commands, such as spray, deliver water via capillary action, humidify, dump, fill, measure, stir, or any combination thereof. Prior to outputting a carbonation vessel schedule, the schedule is constrained by the availability of shared machinery for each contactor. After developing a schedule, the planner can send the schedule to a conductor gateway via a request (e.g., an HTTP POST request). The conductor gateway is a routing layer that maintains a mapping between a carbonation vessel and a contactor, using mapping to dispatch schedules received for a tray to the responsible conductor via a request (e.g., an HTTP POST request).|[0017] In an example embodiment, a distributor can visit each tray in the contactor sequentially and execute the following for each tray: (1) execute load cell measurement of tray mass; (2) provide the load cell measurement to a modeler via an HTTP POST request along with data (e.g., weather forecasting data, state-of-tray data, as described above), which the modeler uses to calculate carbonation extent (%) and the mass or water to add to the tray; (3) if the carbonation extent is sufficiently high, the conductor can (3a) move the tray to a caddy to be picked up for collection; otherwise the conductor can (3b) request that the tray is operated upon using one of the aforementioned methods (i.e., spray, deliver water via capillary action, humidify, dump, fill, measure, stir, or any combination thereof). The conductor can also choose to take no action.|[0018] Embodiments described herein enable high CO2 uptake rates in carbonation medium irrespective of environmental conditions (i.e., effective control of carbonation rates). Embodiments described herein also enable tracking and prediction of carbonation extent (i.e., CO2 uptake via carbonation medium) and moisture content in order to precisely time the transfer of carbonation medium to a carbonation regeneration subsystem.|[0019] Embodiments described herein can also enable control of water use and subsequently minimize water use in the carbonation system. The level of precision and control of water delivery enables greater efficiency and allows for more optimization than modern irrigation systems. Additionally, all-in-one weather stations can calculate predicted evaporation rates, but do not include a feedback loop to process a material or give a command to a piece of physical infrastructure. Predicted evaporation rates can be calculated based on specific characteristics of the carbonation medium. In other words, a range of different carbonation media can be accounted for in the development of the modeling of the carbonation system. They additionally do not include an environmental data localizer.|[0020] In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Publication No. 2020/263910 (“the '910 publication”), filed Jun. 24, 2020, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. In some embodiments, the carbonation medium and/or the contactors described herein can have any of the properties described in International Patent Application No. US2022/018484 (“the '484 application”), filed Mar. 2, 2022, and titled, “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. Benefits of interactions between water and carbonation medium are described in greater detail in the '910 publication and the '484 application.|[0021] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions. In some embodiments, carbonation plots can include a composition that sequesters a target compound.|[0022] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0023] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0024] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0025] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0026] As used herein, the term “about” and “approximately” generally means plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0027] FIG. 1 is a flow diagram of a method 10 of controlling water delivery to a carbonation medium, according to an embodiment. As shown, the method 10 includes monitoring an atmospheric condition in a contactor unit at step 11. The method 10 optionally includes measuring carbonation vessel mass, Fourier Transform Infrared (FTIR) spectroscopy from the carbonation medium, temperature, CO2 concentration, barometric pressure, solar radiation and irradiance, wind speed, gust speed, and/or wind direction in the contractor unit at step 12. The method 10 further includes monitoring an atmospheric condition at a location outside of the contactor unit at step 13. The method 10 optionally includes receiving current weather data at step 14 and receiving forecasted weather data at step 15. The method 10 further includes predicting the moisture content and the carbonation extent of the carbonation medium for a carbonation forecasting period at step 16 and executing an action based on the predicted moisture content and carbonation extent at step 17. The method 10 optionally includes updating the predicted moisture content and carbonation extent at an update interval at step 18.|[0028] Step 11 includes monitoring an environmental condition in the contactor unit. In some embodiments, the environmental condition can include relative humidity. In some embodiments, the environmental condition can include temperature in the contactor unit, CO2 concentration in the contactor unit, barometric pressure in contractor unit, solar radiation and irradiance, wind speed, and/or wind direction in the contactor unit. In some embodiments, the monitoring can include measurement of the relative humidity via a sensor. In some embodiments, the contactor unit can be exposed to the surrounding or outside environment. In some embodiments, the contactor unit can be contained or isolated from the surrounding environment. In some embodiments, “in the contactor unit” can refer to locations within the bounds created by bars of the contactor unit. For example, the region in the contactor unit can be between minimum and maximum x, y, and z values occupied by bars that form the contactor unit. In some embodiments, “in the contactor unit” can refer to a location within a specified distance of a center of gravity of the carbonation vessels. In some embodiments, the specified distance can be about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, or about 10 m, inclusive of all values and ranges therebetween.|[0029] In some embodiments, “in the contactor unit” can refer to a location within a specified distance of outer edges of the carbonation vessels. In some embodiments, the specified distance can be about 5 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, or about 5 m, inclusive of all values and ranges therebetween. In some embodiments, the relative humidity in the contactor unit can be monitored via a capacitive humidity sensor, a resistive humidity sensor, and/or a thermal humidity sensor. In some embodiments, a single sensor or measurement system can be used to monitor a plurality of contactors. For example, a sensor can be placed within a specified distance (e.g., about 5 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 2 m, about 3 m, about 4 m, or about 5 m, inclusive of all values and ranges therebetween) of the outer edge of multiple carbonation vessels, and can make predictions about each of the carbonation vessels.|[0030] Step 12 is optional and includes measuring the carbonation vessel mass, FTIR from the carbonation medium, temperature in the contactor unit, CO2 concentration in the contactor unit, barometric pressure in contractor unit, solar radiation and irradiance, wind speed, and/or wind direction in the contactor unit. In some embodiments, the measurement can be from a sensor or instrumentation, different from the sensor used to measure relative humidity. In some embodiments, multiple sensors (i.e., with different sensing capabilities such as CO2 concentration and relative humidity) can be housed in one location or one housing. In some embodiments, mass can be measured via a scale placed below each carbonation vessel. In some embodiments, mass can be measured via a moving scale that can be placed under one carbonation vessel at a time. In some embodiments, the scale can be placed at a central location (e.g., inside of a distributor).|[0031] In some embodiments, the measurements of a single tray can be used to make predictions about a cohort of trays (e.g., about 2 trays, about 3 trays, about 4 trays, about 5 trays, about 6 trays, about 7 trays, about 8 trays, about 9 trays, about 10 trays, about 20 trays, about 30 trays, about 40 trays, about 50 trays, about 60 trays, about 70 trays, about 80 trays, about 90 trays, or about 100 trays, inclusive of all values and ranges therebetween). In other words, a single tray can be measured (e.g., weighed) at a centralized location and used as a proxy for multiple trays.|[0032] In some embodiments, infrared instrumentation (e.g., FTIR) can be used to determine the chemical makeup and various concentrations of compounds in the carbonation medium. In some embodiments, an infrared spectral sensor can be used to determine the composition of the carbonation medium. In some embodiments, temperature can be measured in a carbonation vessel and/or the contactor unit via a thermocouple. In some embodiments, temperature can be measured in a carbonation vessel and/or the contactor unit via a thermometer. In some embodiments, CO2 concentration can be measured in a carbonation vessel and/or the contactor unit via an ambient gas sensor. In some embodiments, barometric pressure can be measured in a carbonation vessel and/or the contactor unit via a barometer. In some embodiments, the wind speed can be measured via an anemometer.|[0033] At step 13, the method 10 includes monitoring an atmospheric condition at a location outside of the contactor unit. In some embodiments, the atmospheric condition can include relative humidity. In some embodiments, the relative humidity can be monitored via a sensor, different from the sensor used to monitor relative humidity inside the contactor unit. In some embodiments, the location outside of the contactor unit can be measured from a boundary between the inside of the contactor unit and the outside of the contactor unit, as described above with reference to step 11, where “in the contactor unit” refers to physical boundaries created by imaginary lines extending from bars of the contactor unit. In some embodiments, the location outside of the contactor unit can be measured from the center of gravity of a carbonation vessel. In some embodiments, the location outside of the contactor unit can be measured from the external bounds of a carbonation vessel. In some embodiments, the atmospheric condition monitored at step 13 can include temperature, CO2 concentration, solar irradiance, barometric pressure, wind speed, gust speed, wind direction, or any combination thereof.|[0034] In some embodiments, the location outside of the contactor unit can be at least about 1 m, at least about 2 m, at least about 3 m, at least about 4 m, at least about 5 m, at least about 6 m, at least about 7 m, at least about 8 m, at least about 9 m, at least about 10 m, at least about 20 m, at least about 30 m, at least about 40 m, at least about 50 m, at least about 60 m, at least about 70 m, at least about 80 m, or at least about 90 m from the boundary, the center of gravity of the carbonation vessel, or the external bounds of the carbonation vessel. In some embodiments, the location outside of the contactor unit can be no more than about 100 m, no more than about 90 m, no more than about 80 m, no more than about 70 m, no more than about 60 m, no more than about 50 m, no more than about 40 m, no more than about 30 m, no more than about 20 m, no more than about 10 m, no more than about 9 m, no more than about 8 m, no more than about 7 m, no more than about 6 m, no more than about 5 m, no more than about 4 m, no more than about 3 m, or no more than about 2 m from the boundary, the center of gravity of the carbonation vessel, or the external bounds of the carbonation vessel.|[0035] Combinations of the above-referenced distances are also possible (e.g., at least about 1 m and no more than about 100 m or at least about 5 m and no more than about 60 m), inclusive of all values and ranges therebetween. In some embodiments, the location outside of the contactor unit can be about 1 m, about 2 m, about 3 m, about 4 m, about 5 m, about 6 m, about 7 m, about 8 m, about 9 m, about 10 m, about 20 m, about 30 m, about 40 m, about 50 m, about 60 m, about 70 m, about 80 m, about 90 m, or about 100 m from the boundary, the center of gravity of the carbonation vessel, or the external bounds of the carbonation vessel.|[0036] Step 14 is optional and includes receiving current weather data. The current weather data includes data from the geographic region where the contactor unit resides. In some embodiments, the current weather data can be from a local weather service provider. In some embodiments, the current weather data can be from a professional or commercial provider. In some embodiments, the current weather data can be collected independently (e.g., from instrumentation). In some embodiments, the current weather data can include temperature, humidity, precipitation, barometric pressure, solar radiation and irradiance, dewpoint, wind speed, and/or wind direction data.|[0037] In some embodiments, the current weather data can be received at regular intervals. In some embodiments, the current weather data can be received at irregular intervals. In some embodiments, the current weather data can be received at intervals of at least about 1 second, at least about 2 seconds, at least about 3 seconds, at least about 4 seconds, at least about 5 seconds, at least about 10 seconds, at least about 15 seconds, at least about 20 seconds, at least about 30 seconds, at least about 40 seconds, at least about 50 seconds, at least about 1 minute, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, or at least about 18 hours. In some embodiments, the current weather data can be received at intervals of no more than about 24 hours, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, no more than about 5 minutes, no more than about 4 minutes, no more than about 3 minutes, no more than about 2 minutes, no more than about 1 minute, no more than about 50 seconds, no more than about 40 seconds, no more than about 30 seconds, no more than about 20 seconds, no more than about 15 seconds, no more than about 10 seconds, no more than about 5 seconds, no more than about 4 seconds, no more than about 3 seconds, or no more than about 2 seconds.|[0038] In some embodiments, the current weather data can be received at intervals of about 1 second, about 2 seconds, about 3 seconds, about 4 seconds, about 5 seconds, about 10 seconds, about 15 seconds, about 20 seconds, about 30 seconds, about 40 seconds, about 50 seconds, about 1 minute, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, or about 24 hours.|[0039] Step 15 is optional and includes receiving forecast weather data. In some embodiments, the forecast weather data can be from a local service provider. In some embodiments, the forecast weather data can be from a professional or commercial service provider. In some embodiments, the forecast weather data can be collected independently (e.g., from instrumentation provided). In some embodiments, the forecast weather data can be received from the same provider as the current weather data. In some embodiments, the forecast weather data can include temperature, relative humidity, precipitation, barometric pressure, solar radiation and irradiance, CO2 concentration, dewpoint, wind speed, and/or wind direction forecast data. In some embodiments, the forecast weather data can forecast into the future by about 1 hour, about 4 hours, about 12 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 7 days, about 8 days, about 9 days, about 10 days, about 11 days, about 12 days, about 13 days, about 14 days, or about 15 days, inclusive of all values and ranges therebetween.|[0040] In some embodiments, forecast weather data can be retrieved or refreshed at intervals of at least about 1 minute, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, at least about 18 hours, at least about 1 day, at least about 2 days, at least about 3 days, at least about 4 days, at least about 5 days, or at least about 6 days. In some embodiments, the forecast weather data can be retrieved or refreshed at intervals of no more than about 7 days, no more than about 6 days, no more than about 5 days, no more than about 4 days, no more than about 3 days, no more than about 2 days, no more than about 1 day, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, no more than about 5 minutes, no more than about 4 minutes, no more than about 3 minutes, or no more than about 2 minutes.|[0041] Combinations of the above-referenced intervals are also possible (e.g., at least about 1 minute and no more than about 7 days or at least about 12 hours and no more than about 1 day), inclusive of all values and ranges therebetween. In some embodiments, forecast weather data can be retrieved or refreshed at intervals of about 1 minute, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, or about 7 days.|[0042] Step 16 includes predicting a moisture content and a carbonation extent of the carbonation medium for a carbonation forecasting period. Moisture content can be a function of predicted temperatures, humidity, solar radiation and irradiance, wind speed, barometric pressures, and CO2 concentration, as well as current temperatures, humidity, solar radiation and irradiance, wind speed, barometric pressure, and CO2 concentration. Moisture content may also be a function of material properties (such as surface area and particle size) as well as the material's carbonation and hydration state. In some embodiments, the predicting can be via a modeler software. Carbonation rate is a function of moisture content, as described in the '910 publication and the '484 application. A carbonation forecasting model predicts the future carbonation extent of the carbonation medium for a carbonation forecasting period. In some embodiments, the method 10 can include generating a schedule for application of water to one or more carbonation vessels based on the predicted moisture content and carbonation extent at step 16. In some embodiments, the schedule can include a movement plan for a distributor in the contactor unit.|[0043] In some embodiments, the carbonation forecasting period can be at least about 1 minute, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, at least about 18 hours, at least about 1 day, at least about 2 days, at least about 3 days, at least about 4 days, at least about 5 days, at least about 6 days, at least about 7 days, at least about 10 days, at least about 15 days, at least about 20 days, or at least about 25 days. In some embodiments, the forecasting period can be no more than about 30 days, no more than about 25 days, no more than about 20 days, no more than about 15 days, no more than about 10 days, no more than about 7 days, no more than about 6 days, no more than about 5 days, no more than about 4 days, no more than about 3 days, no more than about 2 days, no more than about 1 day, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, or no more than about 5 minutes.|[0044] Combinations of the above-referenced carbonation forecasting periods are also possible (e.g., at least about 1 minute and no more than about 30 days or at least about 3 hours and no more than about 6 days), inclusive of all values and ranges therebetween. In some embodiments, the carbonation forecasting period can be about 1 minute, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 7 days, about 10 days, about 15 days, about 20 days, about 25 days, or about 30 days.|[0045] Step 17 includes executing an action based on a predicted moisture content and a predicted carbonation extent. In some embodiments, the action can include spraying a carbonation vessel, humidifying the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, dumping carbonation medium from a carbonation vessel, filling a carbonation vessel with carbonation medium, measuring a mass of a carbonation vessel, taking an IR spectrum of the carbonation vessel, and/or stirring the carbonation medium in the carbonation vessel. In some embodiments, either of these actions can be scheduled at prescribed intervals in the future.|[0046] In some embodiments, spraying can include spraying of water into the carbonation vessel at prescribed times and/or with prescribed amounts in the future when the moisture content of the carbonation medium is predicted to fall below a threshold value. In some embodiments, the threshold value can be about 100 wt % water, about 95 wt % water, about 90 wt % water, about 85 wt % water, about 80 wt % water, about 75 wt % water, about 70 wt % water, about 65 wt % water, about 60 wt % water, about 55 wt % water, about 50 wt % water, about 45 wt % water, about 40 wt % water, about 35 wt % water, about 30 wt % water, about 25 wt % water, about 20 wt % water, about 15 wt % water, about 10 wt % water, about 9 wt % water, about 8 wt % water, about 7 wt % water, about 6 wt % water, about 5 wt % water, about 4 wt % water, about 3 wt % water, about 2 wt % water, about 1 wt % water, about 0.9 wt % water, about 0.8 wt % water, about 0.7 wt % water, about 0.6 wt % water, about 0.5 wt % water, about 0.4 wt % water, about 0.3 wt % water, about 0.2 wt % water, or about 0.1 wt % water, inclusive of all values and ranges therebetween. In some embodiments, the amount and/or frequency of water sprayed can be determined by a measured environmental condition, a forecasted environmental condition, a measured moisture content in the carbonation vessel, and/or a forecasted moisture content in the carbonation vessel.|[0047] In some embodiments, dumping the carbonation medium can be in response to the carbonation medium being spent (i.e., the carbonation medium is no longer taking up CO2 and is mostly carbonate), such that the spent carbonation medium can be calcined. Dumping can also be in response to detecting that the carbonation vessel is over a desired weight. In some embodiments, stirring the carbonation medium can be in response to a predicted moisture content that is higher than a threshold value (due to forecasted rain or humidity) to aerate the carbonation medium. In some embodiments, the threshold value can be about 10 wt %, about 11 wt %, about 12 wt %, about 13 wt %, about 14 wt %, about 15 wt %, about 16 wt %, about 17 wt %, about 18 wt %, about 19 wt %, about 20 wt %, about 21 wt %, about 22 wt %, about 23 wt %, about 24 wt %, about 25 wt %, about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, about 50%, about 55 wt %, or about 60 wt %, inclusive of all values and ranges therebetween. Stirring can also be in response to an overweight carbonation vessel in order to aerate the carbonation medium. Filling the carbonation vessel with carbonation medium can be in response to detecting that the carbonation vessel is less than a desired weight or to restart a cycle by depositing fresh sorbent material. In some embodiments, collected trays can be selected based on their carbonation extent. Trays with varying levels of carbonation extent can be collected. This “tray blending” can yield an aggregate material that meets or exceeds a target carbonation value (e.g., about 50% carbonation, about 55% carbonation, about 60% carbonation, about 65% carbonation, about 70% carbonation, about 75% carbonation, about 80% carbonation, about 85% carbonation, or about 90% carbonation, inclusive of all values and ranges therebetween) by blending over-carbonated and under-carbonated material.|[0048] Step 18 is optional and includes updating a current estimated moisture content, current estimated carbonation extent, forecasted moisture content, and forecasted carbonation extent at an update interval. In some embodiments, the update can be based on present environmental data. In some embodiments, the update can be based on forecast data. In some embodiments, the update interval can be at least about 1 minute, at least about 2 minutes, at least about 3 minutes, at least about 4 minutes, at least about 5 minutes, at least about 10 minutes, at least about 15 minutes, at least about 20 minutes, at least about 30 minutes, at least about 40 minutes, at least about 50 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 10 hours, at least about 12 hours, or at least about 18 hours. In some embodiments, the update interval can be no more than about 24 hours, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, no more than about 1 hour, no more than about 50 minutes, no more than about 40 minutes, no more than about 30 minutes, no more than about 20 minutes, no more than about 15 minutes, no more than about 10 minutes, no more than about 5 minutes, no more than about 4 minutes, no more than about 3 minutes, or no more than about 2 minutes.|[0049] Combinations of the above-referenced update intervals are also possible (e.g., at least about 1 minute and no more than about 24 hours or at least about 5 minutes and no more than about 12 hours), inclusive of all values and ranges therebetween. In some embodiments, the update interval can be about 1 minute, about 2 minutes, about 3 minutes, about 4 minutes, about 5 minutes, about 10 minutes, about 15 minutes, about 20 minutes, about 30 minutes, about 40 minutes, about 50 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 10 hours, about 12 hours, about 18 hours, or about 24 hours.|[0050] FIG. 2 is a block diagram of a system 100 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the system 100 includes a site 101 with carbonation equipment and a computing cluster 102 with computational hardware.|[0051] As shown, the site 101 includes a contactor unit 110 and sensors 120, while the computing cluster 102 includes a communication device 130, a memory 132, an Input/Output (I/O) device 134, and a processor 140. In some embodiments, the contactor unit 110 can have the same or substantially similar properties to those described in the '112 application. In some embodiments, the sensors 120 can include humidity sensors, temperature sensors, solar radiation and irradiance sensors, wind speed sensors, wind direction sensors, precipitation sensors, barometric pressure sensors, and/or CO2 concentration sensors, as described above with reference to FIG. 1. In some embodiments, one or more of the sensors 120 can be coupled to the contactor unit 110. In some embodiments, one or more of the sensors 120 can be positioned outside of the contactor unit 110 and/or uncoupled from the contactor unit 110.|[0052] As shown, dotted connectors indicate a communicative coupling and solid connectors indicate solid coupling. In some embodiments, the communicative coupling can be via a Wi-Fi connection, a wired connection, a wireless connection, a 3G connection, a 4G connection, a 5G connection, or any other suitable communicative coupling or combinations thereof. In some embodiments, the computing cluster 102 can be physically located at the site 101 or in close proximity to the site 101. In some embodiments, the computing cluster 102 can be located at a separate location from the site.|[0053] As shown, the communication device 130 receives data from the contactor unit 110 and the sensors 120. In some embodiments, the data can include any of the environmental conditions described above with reference to FIG. 1 (e.g., temperature, humidity, barometric pressure, CO2 concentration, solar radiation and irradiance, wind speed, wind direction, etc.). The communication device 130 communicates with the processor 140. The processor 140 then communicates instructions to the contactor unit 110 to execute operations (e.g., spray, humidify, deliver water via capillary action, dump, fill, measure, stir).|[0054] In some embodiments, the memory 132, can include a random-access memory (RAM), a memory buffer, a hard drive, a database, an erasable programmable read-only memory (EPROM), an electrically erasable read-only memory (EEPROM), a read-only memory (ROM), or any combination thereof. In some embodiments, memory 122 stores instructions that cause processor 140 to execute modules, processes, and/or functions associated with operating one or more components of the contactor unit 110. Such instructions can be designed to integrate specialized functions into a controller of the contactor unit 110, such that one or actions can be performed.|[0055] The I/O device 134 includes one or more components for receiving information and/or sending information to other components of computing cluster 102 and/or site 101. In some embodiments, the I/O device 134 can optionally include or be operatively coupled to a display, audio device, or other output device for presenting information to a user. In some embodiments, the I/O device 134 can include a communication interface that can enable communication between the communication device 130, the sensors 120, a power source, and/or the contactor unit 110. In some embodiments, the I/O device 134 can include a network interface that can enable communication between the computing cluster 102 and one or more external devices, including, for example, an external user device (e.g., a mobile phone, a tablet, a laptop) and/or other compute device (e.g., a local or remote compute, a server, etc.). The network interface can be configured to provide a wired connection with the external device, (e.g., via a port or firewall interface, can be configured to communicate with the external device via a wireless network).|[0056] The processor 140 can be any suitable processing device configured to run and/or execute functions associated with the contactor unit 110. For example, processor 140 can be configured to process and/or analyze sensor data (e.g., received from sensor(s) 120 coupled to and/or integrated into the contactor unit 110), to change the timing of stirring, spraying, humidifying, measuring, delivering water via capillary action, filling, dumping, to adjust one or more other parameters or aspects of contactor unit operation, etc. The processor 140 can be a general-purpose processor, a Field Programmable Gate Array (FPGA), an Application Specific Integrated Circuit (ASIC), a Digital Signal Processor (DSP), and/or the like.|[0057] FIG. 3 shows a system 200 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the system 200 includes a site 201 with carbonation equipment and a computing cluster 202 with computational hardware. As shown, the site 201 includes environmental sensors 220, an environmental data service 222, and conductors 224. As shown, the computing cluster 202 includes an environmental data localizer 231, a modeler 233, a planner 235, a process cell manager 237, and a conductor gateway 239.|[0058] In some embodiments, the environmental sensors 220 can be the same or substantially similar to the sensors 120, as described above with reference to FIG. 2. As shown, the environmental sensors 220 transport raw environmental data to the environmental data service 222 (e.g., via a GET function). The raw environmental data is buffered via a filesystem (FS). The environmental data localizer 231 retrieves the raw environmental data via the environmental data service 222.|[0059] The environmental data localizer 231 shares raw environmental data, versioned weather forecasts, and localized environmental data with a time series database (TS DB), as well as retrieving raw environmental data, versioned weather forecasts, and localized environmental data from the TS DB. The environmental data localizer 231 retrieves weather forecasts from external weather forecasts (e.g., via a GET function). In some embodiments, the environmental weather forecasts can be from professional or commercial weather forecast providers. The environmental data localizer 231 feeds localized environmental data (i.e., present environmental data and forecasted weather data) to the modeler 233. The modeler 233 shares carbonation percentage forecasts, moisture content percentage forecasts, and material state (e.g., saturated carbonation medium, fresh carbonation medium) forecasts with a TS DB. In some embodiments, the material state data can include a ‘ready to empty’ flag. In addition, the modeler 233 receives carbonation percentage forecasts, moisture content percentage forecasts, and material state forecasts from the TS DB.|[0060] The modeler 233 feeds carbonation percentage forecasts and moisture content forecasts to the planner 235. The process cell manager 237 also feeds offline period data and backpressure data to the planner 235. The backpressure data is information conveyed by the process cell manager 237 to signal to the carbonation subsystem that the carbonation subsystem should reduce its output rate of carbonation medium. In other words, the backpressure data keeps the carbonation subsystem and the regeneration subsystem in balance. The process cell manager 237 is responsible for coordinating the operation of a carbonation subsystem with the operation of material handling and regeneration subsystems. For example, if the regeneration subsystem is unable to receive additional carbonated material, the process cell manager 237 notifies the planner 235 of the carbonation subsystem and the material handling subsystems to reduce output.|[0061] The planner 235 makes decisions about whether a quantity of carbonation medium should be retired (i.e., dumped and recycled for calcining). The planner 235 feeds recipes (i.e., sequences of steps enacted on the contactor unit) to the conductor gateway 239 via a POST command. The conductor gateway 239 communicates with a TS DB to develop versioned (i.e., tracked for possible evaluation later) recipes. The conductor gateway 239 feeds the recipes to the conductors 224 and receives event and data from the conductors 224 as well as from the environmental sensors. The conductors 224 are software programs that initiate actions to be performed on the trays (e.g., moving, dumping, measuring, filling, spraying, humidifying, deliver water via capillary action). The conductors 224 receive current contactor state information, as well as buffered event.|[0062] The conductor gateway 239 provides an abstraction layer between the conductor instances, which map 1-1 with PLC's, and other software programs that operate at the site 201. For example, the planner 235 can request information from any tray from the conductor gateway 239, regardless of which of the conductors 224 is responsible for the tray. When the conductor gateway 239 receives a request, it selects the conductor 224 that manages the requested information and forward the request to that particular conductor 224 instance. Once the response is received, the conductor gateway 239 returns the response to the planner 235.|[0063] FIG. 4 shows a computing cluster 302 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the computing cluster 302 includes subclusters for area management and reporting 303, process cell subsystems 304, and monitoring and logging 305. The area management and reporting 303 subcluster includes an area user interface 350 with an operator dashboard 352 and an analytics dashboard 354. The management and reporting 303 subcluster further includes an analytics service 356 and a process cells manager 358. The process cell subsystems 304 include a regeneration subsystem 362, a carbonation subsystem 364, and a conveyance subsystem. The monitoring and logging 305 subsystem can include a monitoring and metrics collection service 361 and a data visualization and analytics service 363.|[0064] A user or operator can make system management decisions via the operator dashboard 352. The operator dashboard 352 can receive data from the process cells manager 358. The process cells manager 358 receives information from a relational database (DB). The analytics dashboard 354 can allow the user or operator to read data that is either raw or has been subject to processing by the analytics service 356. In some embodiments, the analytics dashboard can receive analyzed data from the analytics service 356. In some embodiments, the analytics service 356 can receive data from a TS DB. The TS DB can receive data from a data ingestion site 355, which receives data from the process cell subsystems 303.|[0065] In the process cell subsystems 303, the regeneration subsystem 362 makes decisions regarding whether to replace and/or replenish carbonation medium in a particular carbonation vessel (e.g., tray). The carbonation subsystem 364 produces data about carbonation and uptake. The conveyance subsystem 366 produces data about movement of carbonation vessels.|[0066] In the monitoring and logging subsystem, the monitoring and metrics collection service 361 looks up data and receives performance data from the regeneration subsystem 362. The data visualization and analytics service 363 receives a process cell subsystem log in a search engine section.|[0067] FIG. 5 is a block diagram of a system 400 for controlling water delivery to a carbonation medium, according to an embodiment. As shown, the system includes a site 401 and a computing cluster 402. In some embodiments, the site 401 and the cluster 402 can be the same or substantially similar to the site 101 and the cluster 102, as described above with reference to FIG. 2. As shown, the site 401 includes environmental sensors 420, a local environmental sensor data collector 421, and a local weather station 472. The computing cluster 402 includes an environmental data service 422.|[0068] In some embodiments, the environmental sensors 420 can be the same or substantially similar to the environmental sensors 120, as described above with reference to FIG. 2. The environmental sensors 420 communicate with the local environmental sensor data collector 421, which communicates with an local environmental sensor DB, which provides local sensor data to the environmental data service 422. The local environmental sensor data collector 421 is a supervisory control and data acquisition (SCADA) software control system used to generate a human machine interface (HMI). The local environmental sensor data collector 421 is both in the SCADA system and the HMI provider. The local weather station 472 communicates weather data. As shown by example, local weather station 472 communicates ambient weather data with a Cloud DB via Wi-Fi. The local and ambient weather data are then fed to a local weather data collector, which feeds local weather data to a local weather DB. The local weather DB fees the local weather data to the environmental data service 422.|[0069] The environmental data service 422 receives weather forecasts by location from various weather apps as forecasts queried at forecasting intervals. The environmental data service 422 communicates site specific forecasts with the forecast DB and receives local weather data from the forecast DB. The environmental data service 422 includes an environmental data service application programming interface (EDS API) for interaction with the user. FIG. 6 is an entity relationship diagram of a system for controlling water delivery to a carbonation medium, according to an embodiment. Blocks with yellow headings are controlled by the conductors. The block in purple is controlled by the planner. Blocks in green are controlled by the modeler supervisor. The block in blue is controlled by the process cell manager. The modeler includes localization algorithms, evaporation algorithms, and carbonation algorithms in communication with the planner and the conductor. The modeler also includes assignments in communication with the algorithms and the trays. The planner is also in communication with the trays. The conductor database events are in communication with a tray filling system, contactors, shelves, and trays. The conductor database events are also in communication with material batches of the process cell manager. The contactors in the conductor database are also in communication with the hopper and the shelves.|[0070] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0071] In addition, the disclosure may include other innovations not presently described. Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0072] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0073] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0074] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0075] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0076] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0077] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0078] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0079] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | Family Number|(108609889)|108609889|Advantages / Prev. Drawbacks|(US20240069580 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(WO202450365 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | Control|Environmental technology|Measurement | B01D-053/62|B01D-053/82|B01D-2251/304|B01D-2251/402|B01D-2251/404|B01D-2251/602|B01D-2251/604|B01D-2257/504|B01D-2258/06|G01W-001/10|G05D-022/02 | 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STAA|Event publication date=2024-03-08|Event code=EP/STAAPCT|Event group=Examination events Entry into national phase|The international publication has been made|Original code: STAA|Event publication date=2025-06-06|Event code=EP/PUAI|Event group=Administrative notifications|PUBLIC REFERENCE MADE UNDER ARTICLE 153(3) EPC TO A PUBLISHED INTERNATIONAL APPLICATION THAT HAS ENTERED THE EUROPEAN PHASE|Publication in section i.1 EP bulletin|Original code: 0009012|Event publication date=2025-06-06|Event code=EP/STAARQ|Event indicator=Pos|Event group=Examination events|Request for examination was made|Original code: STAA|Event publication date=2025-07-09|Event code=EP/A1|Event group=Examination events|Application published with search report|Publication country=EP|Publication number=EP4580786|Publication stage code=A1|Publication date=2025-07-09|Standardized publication number=EP4580786|Event publication date=2025-07-09|Event code=EP/17P|Event indicator=Pos|Event group=Examination 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events|Application published|Publication country=US|Publication number=US20240069580|Publication stage code=A1|Publication date=2024-02-29|Standardized publication number=US20240069580|Event publication date=2024-03-01|Event code=US/PGPUBN|Event indicator=Pos|Event group=Examination events OAO|PG-Pub Issue Notification|Event publication date=2025-05-27|Event code=US/IDS|Event group=Examination events OAI|Information Disclosure Statement Filed|Event publication date=2025-09-29|Event code=US/DOCK|Event indicator=Pos|Event group=Examination events|Case Docketed to Examiner|Event publication date=2026-03-13|Event code=US/CTNF|Event group=Examination events OA OAO|Non-Final Rejection|Event publication date=2026-03-17|Event code=US/101ALCNF|Event indicator=Neg|Event group=Examination events|Non-final rejection reason 101 - subject matter not patentable under Alice (abstract ideas)|RJD=2026-03-17|R4R=101ALC|RJST=non-final|Rejected claims 19-23|Event publication date=2026-03-17|Event code=US/112NF|Event indicator=Neg|Event group=Examination events|Non-final rejection reason 112 - subject matter in claims not properly defined|RJD=2026-03-17|R4R=112b|RJST=non-final|Rejected claims 11|Event publication date=2026-03-17|Event code=US/103NF|Event indicator=Neg|Event group=Examination events|Non-final rejection reason 103 - obvious subject matter in claims|RJD=2026-03-17|R4R=103|RJST=non-final|Rejected claims 1-4, 6-7, 9, 12-13, 17-29 and 31-34; 5, 8, 10 and 30; 11; 14|RJCT=US20240024815|RJCT=WO202245021|RJCT=CN114859998|RJCT=US20230177330|RJCT=CN110347127|RJCT=US20230330590|(WO2024/050365)|LEGAL DETAILS FOR WO2024/050365|Actual or expected expiration date=2026-02-28|Legal state=DEAD|Status=LAPSED|Event publication date=2023-08-29|Event code=WO/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=WO WOUS2023/073092|Application date=2023-08-29|Standardized application number=2023WO-US73092|Event publication date=2024-03-07|Event 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LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, MG, EC, MK, US, EE, MN, EG, UZ, MU, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4580786)|EP|(US20240069580)|US|(WO2024/050365)|CA; EP|(CA3266193)|CA | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=nwH/nfofj4+0GKaOH5q2kKCa4vFyxJplNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000021776160&ekey=1996&xpn=EP4580786&kind=A1 | https://register.epo.org/application?number=EP23776539 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=KoWgjm0P0XrWqxLm4QBXD3fDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2024/050365)|US|(US20240069580)|US | (WO2024/050365)|NAME=HEIRLOOM CARBON TECHNOLOGIES, INC. 125 Valley Drive Brisbane, California 94005 , COUNTRY=US|(US20240069580)|NAME=Heirloom Carbon Technologies, Inc. , CITY=Brisbane , STATE=CA , COUNTRY=US | (EP4580786)|GB|(WO2024/050365)|US|(CA3266193)|CA | (EP4580786)|NAME=Cooley (UK) LLP 22 Bishopsgate , CITY=London EC2N 4BQ , COUNTRY=GB , REG=101544956|(WO2024/050365)|NAME=WESTON, Scott B. et al. Cooley LLP 1299 Pennsylvania Ave. Suite 700 Washington, District of Columbia 20004 , POSTCODE=20004 , COUNTRY=US|(CA3266193)|NAME=Borden Ladner Gervais LLP WORLD EXCHANGE PLAZA, 100 QUEEN STREET, SUITE 1300 , CITY=OTTAWA , POSTCODE=K1P 1J9 , COUNTRY=CA , REG=1eb8433e-b5c5-4bfa-97b3-55392a3251aa | (EP4580786)|US; US; US; US; US; US; US; US|(US20240069580)|US; US; US; US; US; US; US; US|(WO2024/050365)|US; US; US; US; US; US; US; US|(CA3266193)|US; US; US; US; US; US; US; US | (EP4580786)|NAME=DUBEL, Andy, CITY=Moss Beach, California 94038, COUNTRY=US |NAME=NEWMAN, Aaron, CITY=San Francisco, California 94131, COUNTRY=US |NAME=DUNCAN, Robert, CITY=San Francisco, California 94110, COUNTRY=US |NAME=MILLS, Jennifer, CITY=San Leandro, California 94577, COUNTRY=US |NAME=OLSON, Scott, CITY=San Francisco, California 94107, COUNTRY=US |NAME=GUEBLE, Isabel, CITY=Sunnyvale, California 94089, COUNTRY=US |NAME=LIU, Ruofei, CITY=San Jose, California 95133, COUNTRY=US |NAME=MCQUEEN, Noah, CITY=San Francisco, California 94107, COUNTRY=US|(US20240069580)|NAME=DUBEL Andy, CITY=Moss Beach, STATE=CA , COUNTRY=US |NAME=NEWMAN Aaron, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=DUNCAN Robert, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=MILLS Jennifer, CITY=San Leandro, STATE=CA , COUNTRY=US |NAME=OLSON Scott, CITY=San Francisco, STATE=CA , COUNTRY=US |NAME=GUEBLE Isabel, CITY=Sunnyvale, STATE=CA , COUNTRY=US |NAME=LIU Ruofei, CITY=San Jose, STATE=CA , COUNTRY=US |NAME=MCQUEEN Noah, CITY=San Francisco, STATE=CA , COUNTRY=US|(WO2024/050365)|NAME=DUBEL, Andy 633 Lancaster Blvd Moss Beach, California 94038, POSTCODE=94038, COUNTRY=US |NAME=NEWMAN, Aaron 436 30th Street San Francisco, California 94131, POSTCODE=94131, COUNTRY=US |NAME=DUNCAN, Robert 319 Banks Street San Francisco, California 94110, POSTCODE=94110, COUNTRY=US |NAME=MILLS, Jennifer 270 Oakes Blvd San Leandro, California 94577, POSTCODE=94577, COUNTRY=US |NAME=OLSON, Scott 451 Kansas Street, Unit 550 San Francisco, California 94107, POSTCODE=94107, COUNTRY=US |NAME=GUEBLE, Isabel 416 Paria Terrace Sunnyvale, California 94089, POSTCODE=94089, COUNTRY=US |NAME=LIU, Ruofei 1056 Vanilla Walkway San Jose, California 95133, POSTCODE=95133, COUNTRY=US |NAME=MCQUEEN, Noah 2660 3rd Street, Unit 426 San Francisco, California 94107, POSTCODE=94107, COUNTRY=US|(CA3266193)|NAME=DUBEL Andy 633 Lancaster Blvd Moss Beach, California 94038, POSTCODE=94038, COUNTRY=US |NAME=NEWMAN Aaron 436 30th Street San Francisco, California 94131, POSTCODE=94131, COUNTRY=US |NAME=DUNCAN Robert 319 Banks Street San Francisco, California 94110, POSTCODE=94110, COUNTRY=US |NAME=MILLS Jennifer 270 Oakes Blvd San Leandro, California 94577, POSTCODE=94577, COUNTRY=US |NAME=OLSON Scott 451 Kansas Street, Unit 550 San Francisco, California 94107, POSTCODE=94107, COUNTRY=US |NAME=GUEBLE Isabel 416 Paria Terrace Sunnyvale, California 94089, POSTCODE=94089, COUNTRY=US |NAME=LIU Ruofei 1056 Vanilla Walkway San Jose, California 95133, POSTCODE=95133, COUNTRY=US |NAME=MCQUEEN Noah 2660 3rd Street, Unit 426 San Francisco, California 94107, POSTCODE=94107, COUNTRY=US | (WO2024/050365)|6||(US20240069580)|6 | 3 | 4 | (EP4580786)|WO2024/050365|(CA3266193)|WO2024/050365 | (US20240069580)|Number of Claims: NCL=34|Number of Drawings: NDR=6|Number of Figures: NFG=6|Independent Claim Number: ICL=1,19,24|Number of Independent Claims: NICL=3|Exemplary Claim Number: ECL=1||(WO2024/050365)|Number of Claims: NCL=34|Extended kind: EXTK=x| | (US20240069580)|Provisional Appl: US63/402,211 FDD=2022-08-30 [2022US-63402211]|(CA3266193)|Division of: CA3266193 FDD=2023-08-29 [2023CA-3266193] | (EP4580786)|ENGLISH (ENG) | (EP4580786)|Patent|(CA3266193)|Patent|(WO202450365)|Patent|(US20240069580)|Patent | Titre: (EP4580786)|Controls architecture for predicting and maintaining co2 uptake rates in direct air capture contactors, and methods of operating the same Résumé: (EP4580786)|In some aspects, a method of carbonation control can include monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium, monitoring, via a second sensor, an environmental condition at a location outside of the contactor unit, predicting, based on the measured environmental condition in the contactor unit and the measured environmental condition at the location outside of the contactor unit, a local humidity in a carbonation vessel from the plurality of carbonation vessels, a water content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period, and executing an action on the plurality of carbonation vessels based on the predicted water content and predicted carbonation extent. Autre: (US20240069580)|1. A method, comprising:| monitoring, via a first sensor, an environmental condition in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium;| monitoring, via a second sensor, an environmental condition at a location outside of the contactor unit;| predicting, based on the environmental condition in the contactor unit and the environmental condition at the location outside of the contactor unit, each of a local humidity in a carbonation vessel from the plurality of carbonation vessels, a moisture content of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels, and a carbonation extent of the carbonation medium in the carbonation vessel from the plurality of carbonation vessels for a carbonation forecasting period; and| executing an action on the plurality of carbonation vessels based on the predicted moisture content and predicted carbonation extent.|2. The method of claim 1, further comprising:| receiving, at a processor, current weather data from a weather service provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the current weather data.|3. The method of claim 2, further comprising:| receiving, at the processor, weather forecast data from a forecast provider, wherein predicting the moisture content and carbonation extent of the carbonation medium is based on the weather forecast data.|4. The method of claim 1, wherein the action includes at least one of spraying water into the carbonation vessel, humidifying the carbonation vessel, taking a measurement of the carbonation vessel, delivering water to the carbonation vessel via capillary action and/or capillary mats, stirring the carbonation medium in the carbonation vessel, dumping the carbonation medium from the carbonation vessel, or filling the carbonation vessel with carbonation medium.|5. The method of claim 1, wherein the forecasting period is between about 1 hour and about 48 hours.|6. The method of claim 3, wherein the weather service provider and the forecast provider are the same provider.|7. The method of claim 1, wherein the location outside of the contactor unit is within about 50 m of an outside border of the contactor unit.|8. The method of claim 3, wherein the weather forecast data is for a period of about 1 hour to about 96 hours.|9. The method of claim 1, further comprising:| updating the prediction of the water content and the carbonation extent of the carbonation medium at an update interval.|10. The method of claim 9, wherein the update interval is between about 5 minutes and about 12 hours.|11. The method of claim 1, wherein the current weather data includes at least one of temperature, relative humidity, wind speed, wind direction, gust speed, solar radiation and irradiance, barometric pressure, CO2 concentration, and precipitation.|12. The method of claim 1, further comprising:| measuring, via the first sensor, at least one of carbonation vessel mass, Fourier transform infrared spectroscopy (FTIR) data from carbonation medium, temperature in the contactor unit, CO2 concentration in the contactor unit, barometric pressure in the contactor unit, wind speed in the contactor unit, or wind direction in the contactor unit.|13. The method of claim 1, further comprising:| measuring, via the second sensor, at least one of temperature, relative humidity, or CO2 concentration at the location outside the contactor unit.|14. The method of claim 1, further comprising:| generating a schedule for application of water to the plurality of carbonation vessels based on the predicting.|15. The method of claim 14, wherein the schedule includes a movement plan for a distributor in the contactor unit.|16. The method of claim 1, further comprising:| measuring a mass of the carbonation vessel;| providing the measured mass of the carbonation vessel, the predicted moisture content of the carbonation vessel, and the predicted carbonation extent of the carbonation medium in the carbonation vessel to a modeler; and either:| (1) transporting the carbonation vessel to a caddy for collection;| (2) translating a spray mass returned by the modeler into a spray speed and requesting the carbonation vessel be sprayed at the spray speed; or| (3) taking no action.|17. The method of claim 1, wherein the carbonation vessels include trays.|18. The method of claim 1, wherein the action includes spraying water into the carbonation vessel, and an amount of water sprayed is determined by at least one of the environmental condition at the location outside of the contactor unit, a forecasted environmental condition, a measured water content in the carbonation vessel, a forecasted water content in the carbonation vessel, a measured carbonation extent in the carbonation vessel, or a forecasted carbonation extent in the carbonation vessel.|19. A system for managing moisture content of a carbonation medium, the system comprising:| a contactor unit including a plurality of carbonation vessels with carbonation medium disposed therein;| a first sensor in the contactor unit, the first sensor configured to measure an environmental condition at a location in the contactor unit;| a second sensor outside the contactor unit, the second sensor configured to measure an environmental condition at a location outside the contactor unit, the measured environmental conditions including relative humidity;| a communication device configured to collect weather forecast data and current weather information from a weather service provider; and| a processor configured to receive data from the first sensor, the second sensor, and the communication device, the processor further configured to develop model predictions for the carbonation extent and moisture content of the carbonation medium in a carbonation vessel from the plurality of carbonation vessels and communicate instructions with components of the contactor unit based on the model predictions.|20. The system of claim 19, wherein the components of the contactor unit include at least one of a water delivery device or a distributor.|21. The system of claim 20, wherein the water delivery device includes a sprayer configured to spray water into the carbonation vessel.|22. The system of claim 19, further comprising:| a third sensor incorporated into a carbonation vessel from the plurality of carbonation vessels.|23. The system of claim 19, wherein the carbonation vessels include trays.|24. A non-transitory, processor-readable medium storing processor-executable instructions to cause a processor to:| receive, via a first sensor, environmental condition data in a contactor unit, the contactor unit including a plurality of carbonation vessels including carbonation medium;| receive, via a second sensor, environmental condition data at a location outside of the contactor unit;| predict, based on the environmental condition in the contactor unit and the environmental condition outside of the contactor unit, a water content and a carbonation extent of the carbonation medium for a carbonation forecasting period; and| cause, via an instrument, the execution of an action on the plurality of carbonation vessels based on the predicted water content and predicted carbonation extent.|25. The non-transitory, processor-readable medium of claim 24, wherein the environmental condition in the contactor unit includes at least one of relative humidity, temperature, CO2 concentration, solar irradiance, barometric pressure, wind speed, gust speed, or wind direction.|26. The non-transitory, processor-readable medium of claim 24, wherein the environmental condition at the location outside of the contactor unit includes at least one of relative humidity, temperature, CO2 concentration, solar irradiance, barometric pressure, wind speed, gust speed, or wind direction.|27. The non-transitory, processor-readable medium of claim 24, further storing instructions to cause the processor to receive current weather data from a weather service provider, wherein predicting the water content and the carbonation extent of the carbonation medium is based on the current weather data.|28. The non-transitory, processor-readable medium of claim 25, further storing instructions to cause the processor to receive weather forecast data from a forecast provider wherein predicting the water content and the carbonation extent of the carbonation medium is based on the weather forecast data.|29. The non-transitory, processor-readable medium of claim 24, further storing instructions to cause the processor to update predicted water content and carbonation extent at an update interval.|30. The non-transitory, process-readable medium of claim 29, wherein the update interval is between about 5 minutes and about 12 hours.|31. The non-transitory, process-readable medium of claim 24, wherein the action includes at least one of spraying water onto the carbonation vessel, stirring the carbonation medium in the carbonation vessel, dumping the carbonation medium from the carbonation vessel, or filling the carbonation vessel with carbonation medium.|32. The non-transitory, process-readable medium of claim 24, wherein the weather service provider and the forecast provider are the same provider.|33. The non-transitory, process-readable medium of claim 23, wherein the location outside of the contactor unit is within about 1 m of an outside border of the contactor unit.|34. The non-transitory, process-readable medium of claim 23, wherein the carbonation vessels include trays. | 17 | Abstract | gpt-4o-mini | no | The article focuses on direct air capture (DAC) technology, which captures CO₂ from the ambient air, not from biomass or integrated systems involving biomass energy production. | ||||||||||||||||
| 22 | US63/201,168P|EP22787208|US18/069,041|WOCA2022/050586|US18/360,236 | WOCA2022/050586|US18/360,236|EP22787208|DE22787208T|US18/069,041|CA3214940 | EP4323308|DE22787208|EP4323308|US20240025739|US11760630|US20230183064|CA3214940|WO2022/217365 | 102196477 | WO2022/217365 A1 2022-10-20 [WO2022217365]|US20240025739 A1 2024-01-25 [US20240025739]|EP4323308 A4 2025-04-23 [EP4323308]|EP4323308 A1 2024-02-21 [EP4323308]|DE22787208 T1 2024-03-21 [DE22787208T]|US11760630 B2 2023-09-19 [US11760630]|US20230183064 A1 2023-06-15 [US20230183064]|CA3214940 A1 2022-10-20 [CA3214940] | 2021-04-15|2022-04-14|2022-12-20|2023-07-27 | 2022-04-14|2023-07-27|2022-04-14|2022-04-14|2022-04-14|2022-04-14 | 2025-04-23|2024-03-21|2024-02-21|2024-01-25|2023-09-19|2023-06-15|2022-10-20|2022-10-20 | |(US11760630)|2023-09-19|||| | (EP4323308)|2042-04-14|(US11760630)|2042-04-14|(US20240025739)|2042-04-14|(WO2022/217365)|2024-10-15|(DE22787208)|2042-04-14|(CA3214940)|2042-04-14 | (EP4323308)|Process and system for producing low carbon intensity renewable hydrogen | (EP4323308)|A process and/or system for producing fuel that includes providing biogas, removing at least 50% of the carbon dioxide from the biogas, transporting the upgraded biogas to a hydrogen plant; providing the transported upgraded biogas as feedstock for hydrogen production. The carbon intensity of the fuel is less than 0 gCO2-eq/MJ, at least in part because carbon dioxide removed from the biogas and carbon dioxide from hydrogen production is captured and stored. | IOGEN|LOGEN | (EP4323308)|Iogen Corporation|(EP4323308)|Iogen Corporation ([CA])|(US11760630)|Iogen Corporation ([CA])|(US20230183064)|Iogen Coproration ([CA])|(US20240025739)|Iogen Coproration ([CA])|(WO2022/217365)|IOGEN CORPORATION ([CA])|(DE22787208)|logen Corporation ([CA])|(CA3214940)|IOGEN CORPORATION ([CA]) | FOODY PATRICK J | (EP4323308)|FOODY, Patrick J.|(EP4323308)|FOODY, Patrick J. | (EP4323308)|Keltie LLP ([GB])|Reg. Nb: 101927740|(US11760630)|Knobbe Martens Olson & Bear LLP|(WO2022/217365)|LAMSON, Wendy ([CA])|(DE22787208)|KUHNEN & WACKER Patent- und Rechtsanwaltsbüro PartG mbB ([DE])|(CA3214940)|LAMSON, WENDY ([CA]) | (US11760630)|Further advantageously, providing multiple CO2 capture steps, each at a different stage of the process, can result in the renewable hydrogen having not only a negative CI, but a CI that is not higher than −10 gCO2e/MJ, −20 gCO2e/MJ, −30 gCO2e/MJ, −40 gCO2e/MJ, −50 gCO2e/MJ, −60 gCO2e/MJ, or −70 gCO2/MJ of H2.|It can be particularly advantageous to produce upgraded biogas having a CH4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system.|Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).|As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings.|Unfortunately, biogas production from manure can be more costly and/or may be associated with a limited supply (e.g., relative to landfill gas).|Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations.| | (US11760630)|1. A method of producing low carbon intensity hydrogen, the method comprising: providing transported upgraded biogas for a hydrogen production process, the transported upgraded biogas produced from a biogas upgrading process comprising: a) subjecting biogas comprising methane and carbon dioxide to biogas upgrading, thereby producing the upgraded biogas, b) capturing a first quantity of carbon dioxide and providing the first quantity of carbon dioxide for storage, the first quantity of carbon dioxide captured (i) as part of the biogas upgrading, (ii) from a stream produced from the biogas upgrading, or (iii) a combination of (i) and (ii), and c) transporting the upgraded biogas; generating hydrogen from the hydrogen production process using fossil-based natural gas and the transported upgraded biogas, the hydrogen production process comprising methane reforming and hydrogen purification, the methane reforming producing syngas comprising carbon dioxide and hydrogen, the hydrogen purification comprising purifying at least one of the syngas or a stream derived from the syngas to produce the low carbon intensity hydrogen; and capturing a second quantity of carbon dioxide from the hydrogen production process, and providing the second quantity of carbon dioxide for storage, wherein the low carbon intensity hydrogen has a carbon intensity that is dependent, at least in part, on storage of the first and second quantities of carbon dioxide.|22. A method of producing low carbon intensity hydrogen, the method comprising: providing transported upgraded biogas for a hydrogen production process, the transported upgraded biogas produced from a process comprising: a) subjecting biogas comprising methane and carbon dioxide to biogas upgrading, thereby producing the upgraded biogas, and b) transporting the upgraded biogas; and generating hydrogen from the hydrogen production process using fossil-based natural gas and the transported upgraded biogas, the hydrogen production process comprising methane reforming and hydrogen purification, the methane reforming producing syngas comprising carbon dioxide and hydrogen, the hydrogen purification comprising purifying at least one of the syngas or a stream derived from the syngas to produce the low carbon intensity hydrogen, wherein a first quantity of carbon dioxide is captured and provided for storage, transport, or a combination thereof, the first quantity of carbon dioxide captured (i) as part of the biogas upgrading, (ii) from a stream produced from the biogas upgrading, or (iii) a combination of (i) and (ii), wherein a second quantity of carbon dioxide is captured and provided for storage, transport, or a combination thereof, the second quantity of carbon dioxide captured from the hydrogen production process, and wherein the low carbon intensity hydrogen has a carbon intensity that is less than 11 gCO2eq/MJ.| | (US11760630)|The present disclosure relates to a process and/or system for producing renewable hydrogen, and in particular, to a process and/or system where carbon dioxide from the process is captured and stored.|The present disclosure relates to at least one process/system wherein the CI of renewable hydrogen is low as a result of capturing and storing CO2 not only from the hydrogen production (e.g., from the feedstock and/or fuel) but also from the biogas upgrading.|The present disclosure relates to producing renewable hydrogen having a negative CI from biogas, which can be used as fuel, as industrial feedstock (e.g., to produce fuel, fuel intermediates, or chemical products), or in fuel cells (e.g., to generate heat and/or electricity).| | (US11760630)|RENEWABLE HYDROGEN(100,79)|METHANE REFORMING(100,30)|LOW CARBON INTENSITY HYDROGEN(100,12)|LOW CARBON INTENSITY(100,4)|PRODUCING LOW CARBON INTENSITY(100,1)|UPGRADED BIOGAS(88,45)|STEAM METHANE REFORMING(76,7)|BIOGAS(62,229)|RENEWABLE FEEDSTOCK COPROCESSING(59,3)|STEAM METHANE REFORMER(47,2)|SYNGA(35,68)|FOSSIL NATURAL GAS(33,12)|CARBON DIOXIDE(32,73)|RENEWABLE FEEDSTOCK(32,9)|NONRENEWABLE FEEDSTOCK(30,6)|GCO2E MEGAJOULE(28,43)|FEEDSTOCK(27,63)|GCO2EQ MEGAJOULE(27,3)|GEOLOGICAL SEQUESTRATION(27,2)|SWINE MANURE(26,1)|DAIRY MANURE(25,1)|COMBUSTION ZONE(21,3)|CO2 CAPTURE(20,16)|FUNGIBLE BATCH(19,9)|CO2(18,132)|HYDROGEN PURIFICATION(18,24)|BATCH SEGREGATION(18,3)|HYDROGEN PRODUCTION(17,110)|HYDROGEN PLANT(16,19)|PRODUCING RENEWABLE HYDROGEN(16,9)|HYDROGENIZING CRUDE OIL(16,1)|FEEDSTOCK ANAEROBIC DIGESTION(15,3)|COGENERATION(15,2)|HYDROGEN GENERATION(14,2)|METHANE(13,23)|CO2 DISTRIBUTION(13,19)|AUTOTHERMAL REFORMING(12,64)|GCO(12,5)|BIOGENIC CARBON DIOXIDE(12,2)|NATURAL GAS(11,40)|NATURAL GAS DISTRIBUTION(11,21)|ELECTRICITY(11,11)|CRYOGENIC SEPARATION(11,9)|RAW BIOGAS(11,9)|AMMONIA PRODUCTION(11,2)|HEAT PRODUCTION(11,1)|MANURE(10,5)|CENTRALIZED BIOGAS UPGRADING FACILITY(10,1)|HYDROGEN PRODUCTION(9,9)|LANDFILL GAS(9,5)|CARBON INTENSITY(8,69)|RENEWABLE BIOFUEL(8,2)|TRADABLE CURRENCY(8,2)|BIOMASS FEEDSTOCK DRY TONNE(8,1)|CENTRALIZED ANAEROBIC DIGESTER(8,1)|MANURE ANAEROBIC DIGESTION(8,1)|FLUE GAS(7,24)|BIOGAS PRODUCTION(7,7)|CO2 SEPARATION(7,7)|APPLICABLE REGULATION(7,6)|CAPTURING CO2(7,4)|CO2 PIPELINE(7,4)|BIO GAS CLEANING(7,3)|CENTRALIZED BIOGAS PLANT(7,3)|ANAEROBIC MICROORGANISM(7,2)|BIOMASS TRANSPORTATION(7,2)|FEEDSTOCK RENEWABLE FRACTION(7,1)|CO2 REMOVAL(6,8)|LIFECYCLE(6,8)|CAPTURE CO2(6,3)|MANAGING(6,2)|REFORMING CATALYST(6,2)|SALINE AQUIFER(6,2)|BIOGAS ATTRIBUTE(6,1)|GASOLINE BASELINE EMISSION(6,1)|LIMITED SUPPLY(6,1)|BIO GAS SOURCE(5,7)|ADSORPTION(5,6)|FUEL CELL(5,4)|HYDROPROCESSING(5,4)|RAW(5,4)|GRAY HYDROGEN(5,3)|REMOTE LOCATION(5,3)|ANAEROBIC OXYGEN(5,2)|APPLICABLE REGULATORY AGENCY(5,2)|ENRICHED HYDROGEN STREAM(5,2)|FACILITY OWNER(5,2)|FOSSIL CO2(5,2)|NET CREDIT(5,2)|BECCS DEPLOYMENT(5,1)|BIO GAS PIPELINE(5,1)|BIOGENIC CO2 RELEASE(5,1)|BIOGENIC SYNGA(5,1)|BIOMASS DIESEL(5,1)|BOILER FEEDWATER(5,1)|CO2 DISAGGREGATION(5,1)|COPROCESSED FEEDSTOCK(5,1)|CRYOGENIC BIOGAS(5,1)|CRYOGENIC CO2 CAPTURE(5,1)|ENDOTHERMIC REFORMING REACTION(5,1)|EXTRACTING BIOENERGY(5,1)|FEEDSTOCK PREPROCESSING(5,1)|FIRED BURNER(5,1)|FOSSIL FERTILIZER(5,1)|FOSSIL METHANE(5,1)|GOVERNMENT AUTHORITY(5,1)|GOVERNMENT INITIATIVE(5,1)|GOVERNMENTAL AUTHORITY(5,1)|INCENTIVIZE RENEWABLE FUEL(5,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(5,1)|LIVESTOCK FARM(5,1)|NONGOVERNMENTAL AGENCY(5,1)|NONRENEWABLE GASOLINE(5,1)|NONRENEWABLE METHANE(5,1)|OXIDATIVE REFORMING(5,1)|PRODUCER CREDIT(5,1)|RENEWABLE CONTENT QUANTIFICATION(5,1)|SUGARCANE BAGASSE(5,1)|VALUABLE FUEL CREDIT(5,1)|GREENHOUSE GAS(4,35)|GEOLOGICAL FORMATION(4,9)|PSIG(4,8)|BLUE HYDROGEN(4,5)|MONOETHANOLAMINE(4,5)|CERTIFICATE(4,4)|CO2 PRODUCT(4,4)|IMPURITY(4,4)|ORGANIC WASTE(4,4)|PURGE GAS(4,4)|RFS(4,4)|CO2 COLLECTION(4,2)|COLLECTION RADIUS(4,2)|GEOLOGICAL STORAGE(4,2)|NEGATIVE EMISSION(4,2)|SYNGA GAS(4,2)|AVERAGE GASOLINE BASELINE(4,1)|BARLEY STRAW(4,1)|BAUXITE RESIDUE CARBONATION(4,1)|BIOTRICKLING FILTER(4,1)|CENTRALIZED FACILITY(4,1)|CHALLENGE LISTED WORK(4,1)|CO2 COMPRESSED STREAM(4,1)|CO2 EQUIVALENT EMISSION GRAM(4,1)|CO2 SELECTIVE MEMBRANE(4,1)|COMPLIANCE PATHWAY(4,1)|ELECTRICALLY HEATED METHANE REFORMER(4,1)|ENERGY INTENSIVE BIOMASS(4,1)|EQ CATALYTIC REFORMING(4,1)|ESTABLISHED BIOENERGY(4,1)|FEEDSTOCK EMANATION(4,1)|FEEDSTOCK EMISSION CREDIT(4,1)|FEEDSTOCK TRANSPORTATION(4,1)|FUEL CREDIT GENERATION(4,1)|FUEL RENEWABLE CONTENT(4,1)|LACK INFRASTRUCTURE(4,1)|NET NEGATIVE CO2 EMISSION(4,1)|OPERATIVE COMPLICATION(4,1)|PREVAILING REGULATION(4,1)|PRIVATE CONTRACT(4,1)|QUANTIFIABLE BENEFIT(4,1)|RENEWABLE FAT(4,1)|SYNERGETIC BENEFIT(4,1)|TRANSPORTATION SECTOR(4,1)|WHEAT STRAW(4,1)|CHEMICAL PRODUCT(3,6)|H2O(3,6)|JET FUEL(3,6)|MEMBRANE SEPARATION(3,6)|CO2 CAPTURE(3,5)|DEHYDRATION(3,3)|FUEL PRODUCTION FACILITY(3,3)|HYDROCRACKING(3,3)|ORGANIC FRACTION(3,3)|RAILCAR(3,3)|ALLOWANCE(3,2)|BIODEGRADATION(3,2)|CARBONIZING ATMOSPHERE(3,2)|CO2 SEPARATED(3,2)|CONTAMINANT(3,2)|CORN STOVER(3,2)|DETERRENT(3,2)|FEEDSTOCK COST(3,2)|GREEN HYDROGEN(3,2)|HYDROGEN CONTENT(3,2)|HYDROPOWER(3,2)|NUTRIENT(3,2)|PHOTOSYNTHESIS(3,2)|PIPELINE STANDARD(3,2)|REACTOR TUBE(3,2)|RENEWABLE ELECTRICITY(3,2)|RENEWABLE HYDROGEN YIELD(3,2)|SUBSTITUTE(3,2)|WITHDRAWN GAS(3,2)|ADSORBENT BED(3,1)|APPLICABLE REGULATORY AUTHORITY(3,1)|BECCS PROJECT(3,1)|CAPTURED CO2 STORAGE(3,1)|CENTRALIZED PROCESSING FACILITY(3,1)|CO2 BIOGAS(3,1)|CO2 GRAM(3,1)|CO2 PURITY(3,1)|CO2 RICH TAIL GAS(3,1)|CORN GRAIN(3,1)|COVERED LAGOON(3,1)|FARM WASTE(3,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(3,1)|HYDROGEN TONNE(3,1)|METHANATION REACTION(3,1)|NET POSITIVE EMISSION(3,1)|ONSHORE SETTING(3,1)|POOLED INJECTION(3,1)|RENEWABLE ENERGY DIRECTIVE(3,1)|RENEWABLE HYDROGEN EMISSION(3,1)|STEAM METHANE(3,1)|STORAGE PERMANENCE(3,1)|UPSTREAM EMISSION(3,1)|VOLUNTARY CARBON(3,1)|GAS MIXTURE(2,9)|RENEWABLE H2(2,5)|DERIVED LIQUID HYDROCARBON(2,4)|AGRICULTURAL RESIDUE(2,3)|CCSH(2,3)|AVIATION FUEL(2,2)|LIQUID CO2(2,2)|ABSORPTION AMINE(2,1)|ABSORPTION COLUMN(2,1)|ACETOGENESIS(2,1)|ACIDOGENESIS(2,1)|ACTIVE ALUMINA(2,1)|ADVANCED BIOFUEL(2,1)|AGRICULTURAL CROP(2,1)|APPLICABLE QUALITY(2,1)|AUTHORIZATION(2,1)|AVOIDANCE(2,1)|BASELINE LEVEL(2,1)|BECCS COST(2,1)|BIO DEGRADATION PREVENTION(2,1)|BIODIESEL(2,1)|BIOFILTER(2,1)|BIOMASS PRODUCTION(2,1)|BIOMASS SOURCE(2,1)|BUSINESS(2,1)|BYPRODUCT(2,1)|CAPITAL EXPENDITURE(2,1)|CARBOHYDRATE(2,1)|CARBON INTENSITY CALCULATION(2,1)|CARBON STORAGE(2,1)|CELLULOSE ACETATE(2,1)|CELLULOSIC BIOFUEL(2,1)|CO2 CONTENT(2,1)|CO2 TRANSFER(2,1)|CO2E MEGAJOULE(2,1)|COLLECTION ZONE(2,1)|COMPONENT UPSTREAM REMOVAL(2,1)|CORN ETHANOL(2,1)|DAIRY(2,1)|DEHUMIDIFIER(2,1)|DIGESTION LEVEL(2,1)|DISTRIBUTED CARBON CAPTURE(2,1)|DISTRIBUTED NATURE(2,1)|ELECTRICITY GRID(2,1)|ELECTROLYSIS(2,1)|EMISSION REDUCTION REGISTRY(2,1)|EMISSION THRESHOLD(2,1)|EMISSIONS REDUCTION COMPARISON(2,1)|EVIDENCE PRODUCTION(2,1)|EVOLUTION(2,1)|FEEDSTOCK CARBON INPUT(2,1)|FEEDSTOCK STORAGE(2,1)|FOSSIL CARBON DIOXIDE(2,1)|FOSSIL CARBONACEOUS MATERIAL(2,1)|FOSSIL FUEL CONSUMPTION(2,1)|FOSSIL FUEL PRODUCTION(2,1)|FOSSIL SOURCE(2,1)|FUEL ENERGY(2,1)|FUEL MEETING LIFE CYCLE(2,1)|FUEL STREAM(2,1)|FUNDING(2,1)|GAS CONTENT(2,1)|GASOLINE ENERGY EQUIVALENT(2,1)|GCO2E MMBTU(2,1)|HYDROGEN REFUELING STATION GRID(2,1)|HYDROTHERMAL LIQUEFACTION(2,1)|IRON SPONGE(2,1)|LIQUID TRANSPORTATION FUEL(2,1)|MANDATED VOLUME(2,1)|MESOPHILIC TEMPERATURE(2,1)|NAOH WASHING(2,1)|OFFSHORE SETTING(2,1)|ORGANIC PHYSICAL SCRUBBING(2,1)|PDX REACTION(2,1)|POLYDIMETHYLSILOXANE(2,1)|PURGE STREAM(2,1)|REFORMER TUBE(2,1)|REFRIGERATION(2,1)|RELEASING CO2(2,1)|STANDARD BIOGAS(2,1)|STEAM GENERATION(2,1)|STREAM COMPRESSION(2,1)|SUBSURFACE FORMATION(2,1)|SULFONA(2,1)|SUPPLY REGION(2,1)|TEMPORARY STORAGE(2,1)|TERM BIOGAS(2,1)|TRANSPORT CO2(2,1)|UNREFINED(2,1)|UPGRADED PRODUCTION(2,1)|VIABLE SCALE(2,1)|VOLUNTARY EMISSION REDUCTION(2,1)|WITHDRAWN FEED(2,1)||(US20230183064)|RENEWABLE HYDROGEN(100,81)|METHANE REFORMING(100,30)|LOW CARBON INTENSITY HYDROGEN(100,12)|LOW CARBON INTENSITY(100,4)|PRODUCING LOW CARBON INTENSITY(100,1)|UPGRADED BIOGAS(88,46)|STEAM METHANE REFORMING(76,7)|BIOGAS(62,234)|RENEWABLE FEEDSTOCK COPROCESSING(59,3)|STEAM METHANE REFORMER(42,3)|SYNGA(35,69)|FOSSIL NATURAL GAS(33,12)|CARBON DIOXIDE(32,73)|RENEWABLE FEEDSTOCK(32,9)|NONRENEWABLE FEEDSTOCK(30,6)|GCO2E MEGAJOULE(28,44)|FEEDSTOCK(27,63)|GCO2EQ MEGAJOULE(27,3)|GEOLOGICAL SEQUESTRATION(27,2)|SWINE MANURE(26,1)|DAIRY MANURE(25,1)|COMBUSTION ZONE(21,3)|CO2 CAPTURE(20,16)|FUNGIBLE BATCH(19,9)|CO2(18,134)|HYDROGEN PURIFICATION(18,24)|BATCH SEGREGATION(18,3)|HYDROGEN PRODUCTION(17,115)|HYDROGEN PLANT(16,20)|PRODUCING RENEWABLE HYDROGEN(16,9)|HYDROGENIZING CRUDE OIL(16,1)|FEEDSTOCK ANAEROBIC DIGESTION(15,3)|COGENERATION(15,2)|HYDROGEN GENERATION(14,2)|METHANE(13,24)|CO2 DISTRIBUTION(13,21)|AUTOTHERMAL REFORMING(12,65)|GCO(12,5)|BIOGENIC CARBON DIOXIDE(12,2)|NATURAL GAS(11,41)|NATURAL GAS DISTRIBUTION(11,21)|ELECTRICITY(11,11)|CRYOGENIC SEPARATION(11,9)|RAW BIOGAS(11,9)|AMMONIA PRODUCTION(11,2)|HEAT PRODUCTION(11,1)|MANURE(10,5)|CENTRALIZED BIOGAS UPGRADING FACILITY(10,1)|HYDROGEN PRODUCTION(9,9)|LANDFILL GAS(9,5)|CARBON INTENSITY(8,74)|RENEWABLE BIOFUEL(8,2)|TRADABLE CURRENCY(8,2)|BIOMASS FEEDSTOCK DRY TONNE(8,1)|CENTRALIZED ANAEROBIC DIGESTER(8,1)|MANURE ANAEROBIC DIGESTION(8,1)|FLUE GAS(7,24)|BIOGAS PRODUCTION(7,7)|CO2 SEPARATION(7,7)|APPLICABLE REGULATION(7,6)|CAPTURING CO2(7,4)|CO2 PIPELINE(7,4)|BIO GAS CLEANING(7,3)|CENTRALIZED BIOGAS PLANT(7,3)|FOSSIL CO2(7,3)|ANAEROBIC MICROORGANISM(7,2)|BIOMASS TRANSPORTATION(7,2)|FEEDSTOCK RENEWABLE FRACTION(7,1)|CO2 REMOVAL(6,8)|APPLICABLE REGULATORY AUTHORITY(6,3)|CAPTURE CO2(6,3)|MANAGING(6,2)|REFORMING CATALYST(6,2)|SALINE AQUIFER(6,2)|BIOGAS ATTRIBUTE(6,1)|GASOLINE BASELINE EMISSION(6,1)|LIMITED SUPPLY(6,1)|BIO GAS SOURCE(5,7)|ADSORPTION(5,6)|BLUE HYDROGEN(5,6)|FUEL CELL(5,4)|HYDROPROCESSING(5,4)|RAW(5,4)|GRAY HYDROGEN(5,3)|REMOTE LOCATION(5,3)|ANAEROBIC OXYGEN(5,2)|APPLICABLE REGULATORY AGENCY(5,2)|ENRICHED HYDROGEN STREAM(5,2)|FACILITY OWNER(5,2)|NET CREDIT(5,2)|BECCS DEPLOYMENT(5,1)|BIO GAS PIPELINE(5,1)|BIOGENIC CO2 RELEASE(5,1)|BIOGENIC SYNGA(5,1)|BIOMASS DIESEL(5,1)|BOILER FEEDWATER(5,1)|CO2 CAP PURITY(5,1)|CO2 DISAGGREGATION(5,1)|COPROCESSED FEEDSTOCK(5,1)|CRYOGENIC BIOGAS(5,1)|CRYOGENIC CO2 CAPTURE(5,1)|ENDOTHERMIC REFORMING REACTION(5,1)|EXTRACTING BIOENERGY(5,1)|FEEDSTOCK CAPTURE COMBUSTION(5,1)|FEEDSTOCK HYDROGEN CO2(5,1)|FEEDSTOCK PLANT CO2(5,1)|FEEDSTOCK PREPROCESSING(5,1)|FIRED BURNER(5,1)|FOSSIL FERTILIZER(5,1)|FOSSIL METHANE(5,1)|GOVERNMENT AUTHORITY(5,1)|GOVERNMENT INITIATIVE(5,1)|GOVERNMENTAL AUTHORITY(5,1)|INCENTIVIZE RENEWABLE FUEL(5,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(5,1)|LIVESTOCK FARM(5,1)|NONGOVERNMENTAL AGENCY(5,1)|NONRENEWABLE GASOLINE(5,1)|NONRENEWABLE METHANE(5,1)|OXIDATIVE REFORMING(5,1)|PRODUCER CREDIT(5,1)|RENEWABLE CONTENT QUANTIFICATION(5,1)|SUGARCANE BAGASSE(5,1)|VALUABLE FUEL CREDIT(5,1)|GREENHOUSE GAS(4,38)|GEOLOGICAL FORMATION(4,9)|PSIG(4,8)|MONOETHANOLAMINE(4,5)|CERTIFICATE(4,4)|CO2 PRODUCT(4,4)|IMPURITY(4,4)|ORGANIC WASTE(4,4)|PURGE GAS(4,4)|RFS(4,4)|CO2 COLLECTION(4,2)|COLLECTION RADIUS(4,2)|GEOLOGICAL STORAGE(4,2)|NEGATIVE EMISSION(4,2)|SYNGA GAS(4,2)|AVERAGE GASOLINE BASELINE(4,1)|BARLEY STRAW(4,1)|BAUXITE RESIDUE CARBONATION(4,1)|BIOTRICKLING FILTER(4,1)|CENTRALIZED FACILITY(4,1)|CO2 COMPRESSED STREAM(4,1)|CO2 EQUIVALENT EMISSION GRAM(4,1)|CO2 SELECTIVE MEMBRANE(4,1)|COMPLIANCE PATHWAY(4,1)|ELECTRICALLY HEATED METHANE REFORMER(4,1)|ENERGY INTENSIVE BIOMASS(4,1)|EQ CATALYTIC REFORMING(4,1)|ESTABLISHED BIOENERGY(4,1)|FEEDSTOCK EMANATION(4,1)|FEEDSTOCK EMISSION CREDIT(4,1)|FEEDSTOCK TRANSPORTATION(4,1)|FUEL CREDIT GENERATION(4,1)|FUEL RENEWABLE CONTENT(4,1)|LACK INFRASTRUCTURE(4,1)|NET NEGATIVE CO2 EMISSION(4,1)|OPERATIVE COMPLICATION(4,1)|PREVAILING REGULATION(4,1)|PRIVATE CONTRACT(4,1)|QUANTIFIABLE BENEFIT(4,1)|RENEWABLE FAT(4,1)|SYNERGETIC BENEFIT(4,1)|TRANSPORTATION SECTOR(4,1)|WHEAT STRAW(4,1)|JET FUEL(3,7)|CHEMICAL PRODUCT(3,6)|MEMBRANE SEPARATION(3,6)|CCSBG(3,5)|CCSH(3,5)|CO2 CAPTURE(3,5)|H2O(3,4)|DEHYDRATION(3,3)|FUEL PRODUCTION FACILITY(3,3)|HEAT CAP(3,3)|HYDROCRACKING(3,3)|NUTRIENT(3,3)|ORGANIC FRACTION(3,3)|RAILCAR(3,3)|ALLOWANCE(3,2)|BIODEGRADATION(3,2)|CARBONIZING ATMOSPHERE(3,2)|CO2 SEPARATED(3,2)|CONTAMINANT(3,2)|CORN STOVER(3,2)|DETERRENT(3,2)|FEEDSTOCK COST(3,2)|GREEN HYDROGEN(3,2)|HYDROGEN CONTENT(3,2)|HYDROPOWER(3,2)|PHOTOSYNTHESIS(3,2)|PIPELINE STANDARD(3,2)|REACTOR TUBE(3,2)|RENEWABLE ELECTRICITY(3,2)|RENEWABLE HYDROGEN YIELD(3,2)|SUBSTITUTE(3,2)|WITHDRAWN GAS(3,2)|ADSORBENT BED(3,1)|BECCS PROJECT(3,1)|CAPTURED CO2 STORAGE(3,1)|CENTRALIZED PROCESSING FACILITY(3,1)|CO2 BIOGAS(3,1)|CO2 GRAM(3,1)|CO2 RICH TAIL GAS(3,1)|CONVERSION ELECTRICITY(3,1)|CORN GRAIN(3,1)|COVERED LAGOON(3,1)|FARM WASTE(3,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(3,1)|METHANATION REACTION(3,1)|NET POSITIVE EMISSION(3,1)|ONSHORE SETTING(3,1)|POOLED INJECTION(3,1)|POSITIVE CO2 EMISSION(3,1)|RENEWABLE ENERGY DIRECTIVE(3,1)|RENEWABLE HYDROGEN EMISSION(3,1)|STEAM METHANE(3,1)|STORAGE PERMANENCE(3,1)|UPSTREAM EMISSION(3,1)|VOLUNTARY CARBON(3,1)|GAS MIXTURE(2,9)|RENEWABLE H2(2,9)|DERIVED LIQUID HYDROCARBON(2,4)|AGRICULTURAL RESIDUE(2,3)|EMISSION VALUE(2,3)|AVIATION FUEL(2,2)|LIQUID CO2(2,2)|ABSORPTION AMINE(2,1)|ABSORPTION COLUMN(2,1)|ACETOGENESIS(2,1)|ACIDOGENESIS(2,1)|ACTIVE ALUMINA(2,1)|ADVANCED BIOFUEL(2,1)|AGRICULTURAL CROP(2,1)|APPLICABLE QUALITY(2,1)|AUTHORIZATION(2,1)|AVOIDANCE(2,1)|BASELINE LEVEL(2,1)|BECCS COST(2,1)|BIO DEGRADATION PREVENTION(2,1)|BIODIESEL(2,1)|BIOFILTER(2,1)|BIOMASS PRODUCTION(2,1)|BIOMASS SOURCE(2,1)|BUSINESS(2,1)|BYPRODUCT(2,1)|CAPITAL EXPENDITURE(2,1)|CARBOHYDRATE(2,1)|CARBON INTENSITY CALCULATION(2,1)|CARBON STORAGE(2,1)|CELLULOSE ACETATE(2,1)|CELLULOSIC BIOFUEL(2,1)|CH4CONTENT(2,1)|CO2 CONTENT(2,1)|CO2 TRANSFER(2,1)|CO2E MEGAJOULE(2,1)|COLLECTION ZONE(2,1)|COMPONENT UPSTREAM REMOVAL(2,1)|CORN ETHANOL(2,1)|DAIRY(2,1)|DEHUMIDIFIER(2,1)|DIGESTION CAP LEVEL(2,1)|DISTRIBUTED CARBON CAPTURE(2,1)|DISTRIBUTED NATURE(2,1)|ELECTRICITY GRID(2,1)|ELECTROLYSIS(2,1)|EMISSION REDUCTION REGISTRY(2,1)|EMISSION THRESHOLD(2,1)|EMISSIONS REDUCTION COMPARISON(2,1)|EVIDENCE PRODUCTION(2,1)|EVOLUTION(2,1)|FEEDSTOCK CARBON INPUT(2,1)|FEEDSTOCK STORAGE(2,1)|FOSSIL BASED CO2 EMISSION(2,1)|FOSSIL CARBON DIOXIDE(2,1)|FOSSIL CARBONACEOUS MATERIAL(2,1)|FOSSIL FUEL CONSUMPTION(2,1)|FOSSIL FUEL PRODUCTION(2,1)|FOSSIL SOURCE(2,1)|FUEL ENERGY(2,1)|FUEL MEETING LIFE CYCLE(2,1)|FUEL STREAM(2,1)|FUNDING(2,1)|GAS CONTENT(2,1)|HYDROGEN REFUELING STATION GRID(2,1)|HYDROTHERMAL LIQUEFACTION(2,1)|IRON SPONGE(2,1)|LIQUID TRANSPORTATION FUEL(2,1)|MANDATED VOLUME(2,1)|MESOPHILIC TEMPERATURE(2,1)|NAOH WASHING(2,1)|OFFSHORE SETTING(2,1)|ORGANIC PHYSICAL SCRUBBING(2,1)|PDX REACTION(2,1)|POLYDIMETHYLSILOXANE(2,1)|PURGE STREAM(2,1)|REFORMER TUBE(2,1)|REFRIGERATION(2,1)|RELEASING CO2(2,1)|RENEWAL CONTENT(2,1)|STANDARD BIOGAS(2,1)|STEAM GENERATION(2,1)|STREAM COMPRESSION(2,1)|SUBSURFACE FORMATION(2,1)|SUPPLY REGION(2,1)|TEMPORARY STORAGE(2,1)|TERM BIOGAS(2,1)|TRANSPORT CO2(2,1)|UNREFINED(2,1)|UPGRADED PRODUCTION(2,1)|VIABLE SCALE(2,1)|VOLUNTARY EMISSION REDUCTION(2,1)|WITHDRAWN FEED(2,1)||(US20240025739)|CRYOGENIC CO2 CAPTURE(100,1)|BIOGAS(99,7)|CNG TANKER(87,1)|FEEDSTOCK(64,3)|CRYOGENIC SEPARATION(62,1)|RENEWABLE HYDROGEN(55,5)|APPLICABLE REGULATION(50,1)|GREY HYDROGEN(50,1)|HYDROGEN PLANT(50,1)|RENEWABLE CONTENT(50,1)|RNG(44,2)|ADSORPTION(37,1)|BIOFUEL(37,1)||(WO2022/217365)|RENEWABLE HYDROGEN(100,101)|FUEL(100,60)|PRODUCING RENEWABLE HYDROGEN(100,13)|FUEL PRODUCTION(100,8)|LOW CARBON INTENSITY(100,7)|PRODUCING LOW CARBON INTENSITY(100,1)|UPGRADED BIOGAS(99,52)|BIOGAS(78,260)|SYNGA(71,84)|METHANE REFORMING(61,22)|CARBON DIOXIDE(53,97)|FEEDSTOCK(41,71)|METHANE(33,30)|ANAEROBIC DIGESTION(31,32)|BIOMASS SUBJECTION(28,1)|HYDROGEN PRODUCTION(26,124)|ESTABLISHED BIOENERGY(23,1)|HYDROGEN PLANT(20,23)|CARBON INTENSITY(20,16)|CARBON INTENSITY DEPENDENT(20,4)|BATCH SEGREGATION(19,4)|HYDROGEN PRODUCT GAS(19,4)|GEOLOGICAL SEQUESTRATION(18,2)|SWINE MANURE(18,1)|GCCK EQ MEGAJOULE(17,3)|DAIRY MANURE(17,1)|GCCK(16,2)|RENEWABLE HYDROGEN CARBON INTENSITY(15,2)|BECCS COST(15,1)|BIOMASS(14,25)|FUNGIBLE BATCH(13,9)|RENEWABLE FAT(13,2)|CO2(12,130)|BIOGAS PRODUCTION(12,4)|RENEWABLE FEEDSTOCK COPROCESSING(12,3)|GEOGRAPHICAL LOCATION(12,2)|RENEWABLE OIL(12,1)|CARBON CAPTURE(11,10)|CRYOGENIC SEPARATION(11,10)|DISTRIBUTED NATURE(11,1)|HYDROGEN PRODUCTION(10,9)|NONRENEWABLE FEEDSTOCK(10,6)|STORAGE(10,4)|FEEDSTOCK ANAEROBIC DIGESTION(10,3)|COGENERATION(10,2)|CO2 DISTRIBUTION(9,23)|BECCS(9,8)|BIOGAS PRODUCTION(8,9)|FB GCCBE MEGAJOULE(8,6)|GASIFICATION(8,6)|NEGATIVE CARBON INTENSITY(8,1)|BIOGAS PLANT(7,9)|RAW BIOGAS(7,9)|CENTRALIZED BIOGAS UPGRADING FACILITY(7,1)|GCO(7,1)|HEAT PRODUCTION(7,1)|SEPARATING CARBON DIOXIDE(7,1)|GCCKE MEGAJOULE(6,17)|CENTRALIZED ANAEROBIC DIGESTER(6,1)|MANURE ANAEROBIC DIGESTION(6,1)|NATURAL GAS DISTRIBUTION(5,22)|CO2 SEPARATION(5,7)|RENEWABLE HYDROGEN CL(5,7)|CAPTURING CO2(5,4)|CO2 PIPELINE(5,4)|BIO GAS CLEANING(5,3)|CENTRALIZED BIOGAS PLANT(5,3)|ANAEROBIC MICROORGANISM(5,2)|RENEWABLE BIOFUEL(5,2)|TRADABLE CURRENCY(5,2)|BIOMASS FEEDSTOCK DRY TONNE(5,1)|CARBON DIOXIDE REMOVAL(5,1)|FEEDSTOCK RENEWABLE FRACTION(5,1)|HYDROGEN PURIFICATION(4,20)|CO2 REMOVAL(4,7)|APPLICABLE REGULATION(4,6)|DERIVED LIQUID HYDROCARBON(4,5)|LANDFILL GAS(4,5)|NONMETHANE COMPONENT(4,5)|HYDROPROCESSING(4,4)|RAW(4,4)|APPLICABLE REGULATORY AUTHORITY(4,3)|CAPTURE CO2(4,3)|FOSSIL CO2(4,3)|AUTOTHERMAL REFORMING HYDROGEN PLANT(4,2)|BIOMASS TRANSPORTATION(4,2)|COM STOVER(4,2)|MANAGING(4,2)|REFORMING CATALYST(4,2)|SALINE AQUIFER(4,2)|BIOGAS ATTRIBUTE(4,1)|BIOGENIC SYNGA(4,1)|COM GRAIN FERMENTATION(4,1)|COPROCESSED FEEDSTOCK(4,1)|CRYOGENIC CO2 CAPTURE(4,1)|FEEDSTOCK PREPROCESSING(4,1)|FOSSIL FERTILIZER(4,1)|GASOLINE BASELINE EMISSION(4,1)|INTEGRATING FH PURIFICATION(4,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(4,1)|NONGOVERNMENTAL AGENCY(4,1)|PRODUCER CREDIT(4,1)|RENEWABLE CONTENT QUANTIFICATION(4,1)|STEAM METHANE REFORMER(4,1)|STEAM METHANE REFORMING(4,1)|SUGARCANE BAGASSE(4,1)|VALUABLE FUEL CREDIT(4,1)|GREENHOUSE GAS(3,37)|NATURAL GAS(3,33)|FLUE GAS(3,21)|GEOLOGICAL FORMATION(3,9)|BIO GAS SOURCE(3,7)|GC02E MEGAJOULE(3,6)|GCCEE MEGAJOULE(3,6)|CERTIFICATE(3,4)|CO2 PRODUCT(3,4)|GCCLE MEGAJOULE(3,4)|IMPURITY(3,4)|ORGANIC WASTE(3,4)|PURGE GAS(3,4)|REMOTE LOCATION(3,3)|ANAEROBIC OXYGEN(3,2)|APPLICABLE REGULATORY AGENCY(3,2)|BLUE HYDROGEN CL(3,2)|ENRICHED HYDROGEN STREAM(3,2)|FACILITY OWNER(3,2)|NET CREDIT(3,2)|AVERAGE GASOLINE BASELINE(3,1)|BARLEY STRAW(3,1)|BAUXITE RESIDUE CARBONATION(3,1)|BECCS DEPLOYMENT(3,1)|BIO GAS PIPELINE(3,1)|BIOGENIC CO2 RELEASE(3,1)|BIOMASS DIESEL(3,1)|BIOTRICKLING FILTER(3,1)|BOILER FEEDWATER(3,1)|CENTRALIZED FACILITY(3,1)|CFH PURIFICATION(3,1)|CO2 COMPRESSED STREAM(3,1)|CO2 DISAGGREGATION(3,1)|CO2 EQUIVALENT EMISSION GRAM(3,1)|CO2 SELECTIVE MEMBRANE(3,1)|COMPLIANCE PATHWAY(3,1)|CRYOGENIC BIOGAS(3,1)|ELECTRICALLY HEATED METHANE REFORMER(3,1)|EMISSION FB(3,1)|ENDOTHERMIC REFORMING REACTION(3,1)|ENERGY INTENSIVE BIOMASS(3,1)|EQ CATALYTIC REFORMING(3,1)|EXTRACTING BIOENERGY(3,1)|FEEDSTOCK EMANATION(3,1)|FEEDSTOCK EMISSION CREDIT(3,1)|FEEDSTOCK TRANSPORTATION(3,1)|FIRED BURNER(3,1)|FOSSIL METHANE(3,1)|FUEL CREDIT GENERATION(3,1)|FUEL RENEWABLE CONTENT(3,1)|GOVERNMENT AUTHORITY(3,1)|GOVERNMENT INITIATIVE(3,1)|GOVERNMENTAL AUTHORITY(3,1)|GRAY HYDROGEN CL(3,1)|INCENTIVIZE RENEWABLE FUEL(3,1)|LACK INFRASTRUCTURE(3,1)|LIVESTOCK FARM(3,1)|NET NEGATIVE CO2 EMISSION(3,1)|NONRENEWABLE METHANE(3,1)|OPERATIVE COMPLICATION(3,1)|OXIDATIVE REFORMING(3,1)|PREVAILING REGULATION(3,1)|PRIVATE CONTRACT(3,1)|QUANTIFIABLE BENEFIT(3,1)|SYNERGETIC BENEFIT(3,1)|TOTAL AMOUNT CO2(3,1)|TRANSPORTATION SECTOR(3,1)|WHEAT STRAW(3,1)|CRUDE OIL(2,8)|PSIG(2,8)|JET FUEL(2,7)|LOW CARBON ELECTRICITY(2,6)|MEMBRANE SEPARATION(2,6)|CO2 CAPTURE(2,5)|MONOETHANOLAMINE(2,5)|RFS(2,4)|DEHYDRATION(2,3)|FUEL PRODUCTION FACILITY(2,3)|H2O(2,3)|HYDROCRACKING(2,3)|NUTRIENT(2,3)|ORGANIC FRACTION(2,3)|RAILCAR(2,3)|ALLOWANCE(2,2)|BIODEGRADATION(2,2)|CARBONIZING ATMOSPHERE(2,2)|CEE CONTENT(2,2)|CO2 SEPARATED(2,2)|COLLECTION RADIUS(2,2)|CONTAMINANT(2,2)|DETERRENT(2,2)|FEEDSTOCK COST(2,2)|GEOLOGICAL STORAGE(2,2)|GREEN HYDROGEN(2,2)|HYDROGEN CONTENT(2,2)|HYDROPOWER(2,2)|NEGATIVE EMISSION(2,2)|PHOTOSYNTHESIS(2,2)|PIPELINE STANDARD(2,2)|REACTOR TUBE(2,2)|RENEWABLE ELECTRICITY(2,2)|RENEWABLE HYDROGEN YIELD(2,2)|SUBSTITUTE(2,2)|SYNGA GAS(2,2)|WITHDRAWN GAS(2,2)|ABSORPTION AMINE(2,1)|ABSORPTION COLUMN(2,1)|ADSORBENT BED(2,1)|BECCS PROJECT(2,1)|BIOGENIC CARBON DIOXIDE(2,1)|BIOMASS PRODUCTION(2,1)|CAPTURED CO2 STORAGE(2,1)|CENTRALIZED PROCESSING FACILITY(2,1)|CFH CONTENT(2,1)|CL SCORE(2,1)|CO2 BIOGAS(2,1)|CO2 COLLECTION(2,1)|CO2 CONTENT(2,1)|CO2 GRAM(2,1)|CO2 PURITY(2,1)|CO2 RICH TAIL GAS(2,1)|COLLECTION ZONE(2,1)|COM COB(2,1)|COMBUSTION ZONE(2,1)|CORN ETHANOL(2,1)|COVERED LAGOON(2,1)|EEO CO2(2,1)|EH YIELD(2,1)|EMISSION THRESHOLD(2,1)|EVIDENCE PRODUCTION(2,1)|EVOLUTION(2,1)|FARM WASTE(2,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(2,1)|FEEDSTOCK STORAGE(2,1)|FH PRODUCTION(2,1)|FOSSIL BASED CO2 EMISSION(2,1)|FOSSIL CARBON DIOXIDE(2,1)|FOSSIL FUEL CONSUMPTION(2,1)|FOSSIL NATURAL GAS CL(2,1)|FUEL CL(2,1)|FUEL MEETING LIFE CYCLE(2,1)|HYDROGEN REFUELING STATION GRID(2,1)|HYDROTHERMAL LIQUEFACTION(2,1)|IRON SPONGE(2,1)|LIQUID TRANSPORTATION FUEL(2,1)|MANDATED VOLUME(2,1)|MESOPHILIC TEMPERATURE(2,1)|METHANATION REACTION(2,1)|NAOH WASHING(2,1)|NEGATIVE CL HYDROGEN(2,1)|NET POSITIVE EMISSION(2,1)|NON RENEWABLE GASOLINE(2,1)|OFFSHORE SETTING(2,1)|ONSHORE SETTING(2,1)|ORGANIC PHYSICAL SCRUBBING(2,1)|POLYDIMETHYLSILOXANE(2,1)|POOLED INJECTION(2,1)|POSITIVE CO2 EMISSION(2,1)|PURGE STREAM(2,1)|REFORMER TUBE(2,1)|REFRIGERATION(2,1)|RELEASING CO2(2,1)|RENEWABLE ENERGY DIRECTIVE(2,1)|RENEWABLE HYDROGEN EMISSION(2,1)|RENEWAL CONTENT(2,1)|STANDARD BIOGAS(2,1)|STEAM GENERATION(2,1)|STORAGE PERMANENCE(2,1)|STREAM COMPRESSION(2,1)|SUBSURFACE FORMATION(2,1)|SUPPLY REGION(2,1)|TEMPORARY STORAGE(2,1)|TERM BIOGAS(2,1)|TRANSPORT CO2(2,1)|UNREFINED(2,1)|UPGRADED PRODUCTION(2,1)|UPSTREAM EMISSION(2,1)|VIABLE SCALE(2,1)|VOLUNTARY CARBON(2,1)|VOLUNTARY EMISSION REDUCTION(2,1)|WITHDRAWN FEED(2,1)|GAS MIXTURE(1,9)|AGRICULTURAL RESIDUE(1,3)|AVIATION FUEL(1,2)|LIQUID CO2(1,2)|ACETOGENESIS(1,1)|ACIDOGENESIS(1,1)|ACTIVE ALUMINA(1,1)|ADVANCED BIOFUEL(1,1)|AGRICULTURAL CROP(1,1)|AMMONIA PRODUCTION(1,1)|APPLICABLE QUALITY(1,1)|AUTHORIZATION(1,1)|AVOIDANCE(1,1)|BASELINE LEVEL(1,1)|BIO DEGRADATION PREVENTION(1,1)|BIODIESEL(1,1)|BIOFILTER(1,1)|BIOMASS SOURCE(1,1)|BUSINESS(1,1)|BYPRODUCT(1,1)|CAPITAL EXPENDITURE(1,1)|CARBOHYDRATE(1,1)|CARBON INTENSITY CALCULATION(1,1)|CARBON STORAGE(1,1)|CCKFROM(1,1)|CELLULOSIC BIOFUEL(1,1)|CFB RICH GAS(1,1)|CO2 TRANSFER(1,1)|COMPONENT UPSTREAM REMOVAL(1,1)|DAIRY(1,1)|DEHUMIDIFIER(1,1)|DIGESTION LEVEL(1,1)|DISTRIBUTED CARBON CAPTURE(1,1)|ELECTRICITY GRID(1,1)|ELECTROLYSIS(1,1)|EMISSION REDUCTION REGISTRY(1,1)|EMISSIONS REDUCTION COMPARISON(1,1)|FEEDSTOCK CARBON INPUT(1,1)|FK PRODUCT(1,1)|FOSSIL CARBONACEOUS MATERIAL(1,1)|FOSSIL FUEL PRODUCTION(1,1)|FOSSIL SOURCE(1,1)|FUEL ENERGY(1,1)|FUEL STREAM(1,1)||(CA3214940)|RENEWABLE HYDROGEN(100,95)|FUEL(100,59)|UPGRADED BIOGAS(100,50)|PRODUCING RENEWABLE HYDROGEN(100,13)|FUEL PRODUCTION(100,8)|LOW CARBON INTENSITY(100,6)|BIOGAS(78,250)|SYNGA(72,84)|METHANE REFORMING(62,22)|CARBON DIOXIDE(53,94)|FEEDSTOCK(41,68)|METHANE(34,29)|ANAEROBIC DIGESTION(31,31)|BIOMASS SUBJECTION(28,1)|HYDROGEN PRODUCTION(26,116)|ESTABLISHED BIOENERGY(23,1)|CARBON INTENSITY DEPENDENT(20,4)|BATCH SEGREGATION(19,4)|HYDROGEN PRODUCT GAS(19,4)|HYDROGEN PLANT(18,21)|GEOLOGICAL SEQUESTRATION(18,2)|SWINE MANURE(18,1)|DAIRY MANURE(17,1)|GCO(16,6)|RENEWABLE HYDROGEN CARBON INTENSITY(16,2)|BECCS COST(15,1)|BIOMASS(14,25)|FUNGIBLE BATCH(13,9)|RENEWABLE FEEDSTOCK COPROCESSING(13,3)|RENEWABLE FAT(13,2)|PROCESS CORN PRI(13,1)|CO2(12,134)|BIOGAS PRODUCTION(12,4)|GEOGRAPHICAL LOCATION(12,2)|RENEWABLE OIL(12,1)|CARBON INTENSITY(11,57)|CARBON CAPTURE(11,10)|CRYOGENIC SEPARATION(11,10)|DISTRIBUTED NATURE(11,1)|HYDROGEN PRODUCTION(10,9)|NONRENEWABLE FEEDSTOCK(10,6)|STORAGE(10,4)|FEEDSTOCK ANAEROBIC DIGESTION(10,3)|COGENERATION(10,2)|GCO2E MEGAJOULE(9,40)|CO2 DISTRIBUTION(9,21)|BECCS(9,8)|BIOGAS PRODUCTION(8,9)|GASIFICATION(8,6)|BIOGAS PLANT(7,9)|RAW BIOGAS(7,9)|CENTRALIZED BIOGAS UPGRADING FACILITY(7,1)|HEAT PRODUCTION(7,1)|SEPARATING CARBON DIOXIDE(7,1)|CENTRALIZED ANAEROBIC DIGESTER(6,1)|NATURAL GAS DISTRIBUTION(5,21)|CO2 SEPARATION(5,7)|CAPTURING CO2(5,4)|CO2 PIPELINE(5,4)|BIO GAS CLEANING(5,3)|CENTRALIZED BIOGAS PLANT(5,3)|ANAEROBIC MICROORGANISM(5,2)|BIOMASS TRANSPORTATION(5,2)|RENEWABLE BIOFUEL(5,2)|TRADABLE CURRENCY(5,2)|BIOMASS FEEDSTOCK DRY TONNE(5,1)|CARBON DIOXIDE REMOVAL(5,1)|FEEDSTOCK RENEWABLE FRACTION(5,1)|HYDROGEN PURIFICATION(4,20)|CO2 REMOVAL(4,8)|APPLICABLE REGULATION(4,6)|DERIVED LIQUID HYDROCARBON(4,5)|LANDFILL GAS(4,5)|HYDROPROCESSING(4,4)|RAW(4,4)|CAPTURE CO2(4,3)|AUTOTHERMAL REFORMING HYDROGEN PLANT(4,2)|CCSBG RNG(4,2)|MANAGING(4,2)|REFORMING CATALYST(4,2)|SALINE AQUIFER(4,2)|BIOGAS ATTRIBUTE(4,1)|BIOGENIC SYNGA(4,1)|COPROCESSED FEEDSTOCK(4,1)|CRYOGENIC CO2 CAPTURE(4,1)|FEEDSTOCK PREPROCESSING(4,1)|FOSSIL FERTILIZER(4,1)|GASOLINE BASELINE EMISSION(4,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(4,1)|LANDFILL RNG(4,1)|NONGOVERNMENTAL AGENCY(4,1)|PRODUCER CREDIT(4,1)|RENEWABLE CONTENT QUANTIFICATION(4,1)|STEAM METHANE REFORMING(4,1)|SUGARCANE BAGASSE(4,1)|VALUABLE FUEL CREDIT(4,1)|GREENHOUSE GAS(3,36)|NATURAL GAS(3,34)|GEOLOGICAL FORMATION(3,9)|BIO GAS SOURCE(3,7)|FOSSIL NATURAL GAS(3,6)|BLUE HYDROGEN(3,5)|MANURE(3,5)|CERTIFICATE(3,4)|CO2 PRODUCT(3,4)|IMPURITY(3,4)|ORGANIC WASTE(3,4)|PURGE GAS(3,4)|GRAY HYDROGEN(3,3)|REMOTE LOCATION(3,3)|ANAEROBIC OXYGEN(3,2)|APPLICABLE REGULATORY AGENCY(3,2)|ENRICHED HYDROGEN STREAM(3,2)|FACILITY OWNER(3,2)|FOSSIL CO2(3,2)|NET CREDIT(3,2)|AVERAGE GASOLINE BASELINE(3,1)|BARLEY STRAW(3,1)|BAUXITE RESIDUE CARBONATION(3,1)|BECCS DEPLOYMENT(3,1)|BIO GAS PIPELINE(3,1)|BIOGENIC CO2 RELEASE(3,1)|BIOMASS DIESEL(3,1)|BIOTRICKLING FILTER(3,1)|BOILER FEEDWATER(3,1)|CENTRALIZED FACILITY(3,1)|CO2 COMPRESSED STREAM(3,1)|CO2 DISAGGREGATION(3,1)|CO2 EQUIVALENT EMISSION GRAM(3,1)|CO2 SELECTIVE MEMBRANE(3,1)|COMPLIANCE PATHWAY(3,1)|CRYOGENIC BIOGAS(3,1)|ELECTRICALLY HEATED METHANE REFORMER(3,1)|ENDOTHERMIC REFORMING REACTION(3,1)|ENERGY INTENSIVE BIOMASS(3,1)|EQ CATALYTIC REFORMING(3,1)|EXTRACTING BIOENERGY(3,1)|FEEDSTOCK EMANATION(3,1)|FEEDSTOCK EMISSION CREDIT(3,1)|FEEDSTOCK TRANSPORTATION(3,1)|FIRED BURNER(3,1)|FOSSIL METHANE(3,1)|FUEL CREDIT GENERATION(3,1)|FUEL RENEWABLE CONTENT(3,1)|GOVERNMENT AUTHORITY(3,1)|GOVERNMENT INITIATIVE(3,1)|GOVERNMENTAL AUTHORITY(3,1)|INCENTIVIZE RENEWABLE FUEL(3,1)|LACK INFRASTRUCTURE(3,1)|LIQUEFIED RNG(3,1)|LIVESTOCK FARM(3,1)|NET NEGATIVE CO2 EMISSION(3,1)|NONRENEWABLE GASOLINE(3,1)|NONRENEWABLE METHANE(3,1)|OPERATIVE COMPLICATION(3,1)|OXIDATIVE REFORMING(3,1)|PREVAILING REGULATION(3,1)|PRIVATE CONTRACT(3,1)|QUANTIFIABLE BENEFIT(3,1)|RNG CL(3,1)|SIVIR BURNER(3,1)|SYNERGETIC BENEFIT(3,1)|TOTAL AMOUNT CO2(3,1)|TRANSPORTATION SECTOR(3,1)|WHEAT STRAW(3,1)|FLUE GAS(2,18)|CRUDE OIL(2,8)|PSIG(2,8)|JET FUEL(2,6)|MEMBRANE SEPARATION(2,6)|CO2 CAPTURE(2,5)|LOW CARBON ELECTRICITY(2,5)|MONOETHANOLAMINE(2,5)|H2O(2,4)|CCSH(2,3)|DEHYDRATION(2,3)|FUEL PRODUCTION FACILITY(2,3)|HYDROCRACKING(2,3)|ORGANIC FRACTION(2,3)|RAILCAR(2,3)|RFS(2,3)|ALLOWANCE(2,2)|BIODEGRADATION(2,2)|CARBONIZING ATMOSPHERE(2,2)|CO2 COLLECTION(2,2)|CO2 SEPARATED(2,2)|COLLECTION RADIUS(2,2)|CONTAMINANT(2,2)|CORN STOVER(2,2)|DETERRENT(2,2)|FEEDSTOCK COST(2,2)|FOSSIL GAS(2,2)|GEOLOGICAL STORAGE(2,2)|GREEN HYDROGEN(2,2)|HYDROGEN CONTENT(2,2)|HYDROPOWER(2,2)|NEGATIVE CL(2,2)|NEGATIVE EMISSION(2,2)|NUTRIENT(2,2)|PHOTOSYNTHESIS(2,2)|PIPELINE STANDARD(2,2)|REACTOR TUBE(2,2)|RENEWABLE ELECTRICITY(2,2)|RENEWABLE HYDROGEN YIELD(2,2)|SUBSTITUTE(2,2)|SYNGA GAS(2,2)|WITHDRAWN GAS(2,2)|ABSORPTION AMINE(2,1)|ABSORPTION COLUMN(2,1)|ADSORBENT BED(2,1)|APPLICABLE REGULATORY AUTHORITY(2,1)|BECCS PROJECT(2,1)|BIOGENIC CARBON DIOXIDE(2,1)|BIOMASS PRODUCTION(2,1)|CAPTURED CO2 STORAGE(2,1)|CC SBG(2,1)|CELLULOSE ACETATE(2,1)|CENTRALIZED PROCESSING FACILITY(2,1)|CO2 BIOGAS(2,1)|CO2 CONTENT(2,1)|CO2 PURITY(2,1)|CO2 RICH TAIL GAS(2,1)|COLLECTION ZONE(2,1)|COMBUSTION ZONE(2,1)|COMPRESSED RNG(2,1)|CORN ETHANOL(2,1)|CORN GRAIN(2,1)|COVERED LAGOON(2,1)|DOCUMENT LCFSLIFECYCLEANALYSISMODELSANDDOCUMENTATION(2,1)|ELECTRICITY GENERATION(2,1)|EMISSION THRESHOLD(2,1)|EVIDENCE PRODUCTION(2,1)|EVOLUTION(2,1)|FARM WASTE(2,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(2,1)|FEEDSTOCK CO2(2,1)|FEEDSTOCK STORAGE(2,1)|FOSSIL BASED CO2 EMISSION(2,1)|FOSSIL CARBON DIOXIDE(2,1)|FOSSIL FUEL CONSUMPTION(2,1)|FUEL MEETING LIFE CYCLE(2,1)|HYDROGEN CL(2,1)|HYDROGEN REFUELING STATION GRID(2,1)|HYDROGEN TONNE(2,1)|HYDROTHERMAL LIQUEFACTION(2,1)|IRON SPONGE(2,1)|LIQUID TRANSPORTATION FUEL(2,1)|MANDATED VOLUME(2,1)|MESOPHILIC TEMPERATURE(2,1)|METHANATION REACTION(2,1)|NAOH WASHING(2,1)|NET POSITIVE EMISSION(2,1)|OFFSHORE SETTING(2,1)|ONSHORE SETTING(2,1)|ORGANIC PHYSICAL SCRUBBING(2,1)|PDX REACTION(2,1)|POLYDIMETHYLSILOXANE(2,1)|POOLED INJECTION(2,1)|POSITIVE CO2 EMISSION(2,1)|PRODUCING RNG(2,1)|PURGE STREAM(2,1)|REFORMER TUBE(2,1)|REFRIGERATION(2,1)|RELEASING CO2(2,1)|RENEWABLE ENERGY DIRECTIVE(2,1)|RENEWABLE HYDROGEN EMISSION(2,1)|STANDARD BIOGAS(2,1)|STEAM GENERATION(2,1)|STORAGE PERMANENCE(2,1)|STREAM COMPRESSION(2,1)|SUBSURFACE FORMATION(2,1)|SUPPLY REGION(2,1)|TEMPORARY STORAGE(2,1)|TERM BIOGAS(2,1)|TERM RNG(2,1)|TRANSPORT CO2(2,1)|UNREFINED(2,1)|UPGRADED PRODUCTION(2,1)|UPSTREAM EMISSION(2,1)|VIABLE SCALE(2,1)|VOLUNTARY CARBON(2,1)|VOLUNTARY EMISSION REDUCTION(2,1)|WITHDRAWN FEED(2,1)|GAS MIXTURE(1,9)|RENEWABLE H2(1,5)|AGRICULTURAL RESIDUE(1,3)|AVIATION FUEL(1,2)|LIQUID CO2(1,2)|ACETOGENESIS(1,1)|ACIDOGENESIS(1,1)|ACTIVE ALUMINA(1,1)|ADVANCED BIOFUEL(1,1)|AGRICULTURAL CROP(1,1)|AMMONIA PRODUCTION(1,1)|APPLICABLE QUALITY(1,1)|AUTHORIZATION(1,1)|AVOIDANCE(1,1)|BASELINE LEVEL(1,1)|BIO DEGRADATION PREVENTION(1,1)|BIODIESEL(1,1)|BIOFILTER(1,1)|BIOMASS SOURCE(1,1)|BUSINESS(1,1)|BYPRODUCT(1,1)|CAPITAL EXPENDITURE(1,1)|CARBOHYDRATE(1,1)|CARBON INTENSITY CALCULATION(1,1)|CARBON STORAGE(1,1)|CELLULOSIC BIOFUEL(1,1)|CO2 TRANSFER(1,1)|COMPONENT UPSTREAM REMOVAL(1,1)|DAIRY(1,1)|DEHUMIDIFIER(1,1)|DIGESTION LEVEL(1,1)|DISTRIBUTED CARBON CAPTURE(1,1)|ELECTRICITY GRID(1,1)|ELECTROLYSIS(1,1)|EMISSION REDUCTION REGISTRY(1,1)|EMISSIONS REDUCTION COMPARISON(1,1)|FEEDSTOCK CARBON INPUT(1,1)|FOSSIL CARBONACEOUS MATERIAL(1,1)|FOSSIL FUEL PRODUCTION(1,1)|FOSSIL SOURCE(1,1)| | (US11760630)|The invention claimed is:|1. A method of producing low carbon intensity hydrogen, the method comprising:| providing transported upgraded biogas for a hydrogen production process, the transported upgraded biogas produced from a biogas upgrading process comprising:| a) subjecting biogas comprising methane and carbon dioxide to biogas upgrading, thereby producing the upgraded biogas,| b) capturing a first quantity of carbon dioxide and providing the first quantity of carbon dioxide for storage, the first quantity of carbon dioxide captured (i) as part of the biogas upgrading, (ii) from a stream produced from the biogas upgrading, or (iii) a combination of (i) and (ii), and| c) transporting the upgraded biogas;| generating hydrogen from the hydrogen production process using fossil-based natural gas and the transported upgraded biogas, the hydrogen production process comprising methane reforming and hydrogen purification, the methane reforming producing syngas comprising carbon dioxide and hydrogen, the hydrogen purification comprising purifying at least one of the syngas or a stream derived from the syngas to produce the low carbon intensity hydrogen; and| capturing a second quantity of carbon dioxide from the hydrogen production process, and providing the second quantity of carbon dioxide for storage,| wherein the low carbon intensity hydrogen has a carbon intensity that is dependent, at least in part, on storage of the first and second quantities of carbon dioxide.|2. The method according to claim 1, wherein the second quantity of carbon dioxide comprises biogenic carbon dioxide generated from the transported upgraded biogas and fossil based carbon dioxide generated from the fossil-based natural gas.|3. The method according to claim 1, wherein at least some of the carbon dioxide in the second quantity is removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas.|4. The method according to claim 3, wherein the methane reforming comprises steam methane reforming, the steam methane reforming producing flue gas, and wherein at least some of the carbon dioxide in the second quantity is removed from the flue gas.|5. The method according to claim 1, wherein all of the carbon dioxide in the second quantity is removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas.|6. The method according to claim 1, wherein the methane reforming comprises steam methane reforming, the steam methane reforming producing flue gas, and wherein all of the carbon dioxide in the second quantity is removed from the flue gas.|7. The method according to claim 1, wherein storage of the first and second quantities of carbon dioxide comprises geological sequestration.|8. The method according to claim 1, wherein at least a portion of the transported upgraded biogas is used as feedstock for the methane reforming.|9. The method according to claim 8, wherein at least a portion of the fossil-based natural gas is used as feedstock for the methane reforming.|10. The method according to claim 8, wherein the methane reforming comprises steam methane reforming, and wherein at least a portion of the transported upgraded biogas is fed to a combustion zone of the steam methane reformer.|11. The method according to claim 1, wherein at least a portion of the fossil-based natural gas is used as feedstock for methane reforming.|12. The method according to claim 1, wherein the methane reforming comprises steam methane reforming, and wherein at least a portion of the transported upgraded biogas is fed to a combustion zone of the steam methane reformer.|13. The method according to claim 1, wherein transporting the upgraded biogas comprises transporting at least a portion of the upgraded biogas to the hydrogen plant as a fungible batch.|14. The method according to claim 1, wherein transporting the upgraded biogas comprises transporting at least a portion of the upgraded biogas to the hydrogen plant as a segregated batch.|15. The method according to claim 1, wherein the second quantity of carbon dioxide contains not more than 75% of a total amount of carbon dioxide produced from hydrogen production.|16. The method according to claim 1, wherein the biogas is landfill gas.|17. The method according to claim 16, wherein the biogas is produced from anaerobic digestion of organic waste, swine manure, dairy manure, or any combination thereof.|18. The method according to claim 1, further comprising providing the low carbon intensity hydrogen for use in ammonia production.|19. The method according to claim 1, further comprising providing the low carbon intensity hydrogen for use in producing a fuel.|20. The method according to claim 19, wherein the fuel is produced in a fuel production process comprising hydrogenating crude oil derived liquid hydrocarbon with the low carbon intensity hydrogen.|21. The method according to claim 1, wherein the low carbon intensity hydrogen has a carbon intensity that is less than 11 gCO2eq/MJ.|22. A method of producing low carbon intensity hydrogen, the method comprising:| providing transported upgraded biogas for a hydrogen production process, the transported upgraded biogas produced from a process comprising:| a) subjecting biogas comprising methane and carbon dioxide to biogas upgrading, thereby producing the upgraded biogas, and| b) transporting the upgraded biogas; and| generating hydrogen from the hydrogen production process using fossil-based natural gas and the transported upgraded biogas, the hydrogen production process comprising methane reforming and hydrogen purification, the methane reforming producing syngas comprising carbon dioxide and hydrogen, the hydrogen purification comprising purifying at least one of the syngas or a stream derived from the syngas to produce the low carbon intensity hydrogen,| wherein a first quantity of carbon dioxide is captured and provided for storage, transport, or a combination thereof, the first quantity of carbon dioxide captured (i) as part of the biogas upgrading, (ii) from a stream produced from the biogas upgrading, or (iii) a combination of (i) and (ii),| wherein a second quantity of carbon dioxide is captured and provided for storage, transport, or a combination thereof, the second quantity of carbon dioxide captured from the hydrogen production process, and| wherein the low carbon intensity hydrogen has a carbon intensity that is less than 11 gCO2eq/MJ.|23. The method of producing low carbon intensity hydrogen according to claim 22, wherein the low carbon intensity hydrogen has a carbon intensity that is less than 0 gCO2eq/MJ. | (US11760630)|TECHNICAL FIELD|[0001] The present disclosure relates to a process and/or system for producing renewable hydrogen, and in particular, to a process and/or system where carbon dioxide from the process is captured and stored.|BACKGROUND|[0002] Hydrogen is largely produced from the processing of fossil fuels. For example, hydrogen is often produced from the steam methane reforming (SMR) of natural gas or the gasification of coal. Unfortunately, the production of hydrogen from fossil fuels is associated with significant greenhouse gas (GHG) emissions, and in particular, with significant carbon dioxide (CO2) emissions.|[0003] One approach to reduce the GHG emissions associated with hydrogen production is to use carbon capture and storage (CCS). CCS may, for example, involve capturing CO2 emissions and storing them underground in suitable geological formations, which is also referred to as carbon sequestration. In integrating CCS with hydrogen production from fossil fuels, the fossil based CO2 produced during the hydrogen production is captured and stored in order to prevent it from being released to the atmosphere, thereby reducing GHG emissions of the process (e.g., a reduction of about 80-90%).|[0004] Another approach to reduce the GHG emissions associated with hydrogen production is to use biomass rather than fossil fuels as feedstock. Such hydrogen, may for example, be produced from the gasification or pyrolysis of biomass, or by reforming biogas produced by the anaerobic digestion of biomass. Any CO2 derived from biomass and produced during such processing is biogenic. As the release of biogenic CO2 to the atmosphere simply returns to the atmosphere carbon that was recently fixed by photosynthesis, biogenic CO2 is generally considered to be carbon neutral (e.g., its release does not result in an increase in net GHG emissions). Accordingly, in integrating CCS with hydrogen production from biomass, where biogenic CO2 produced during the hydrogen production is captured and stored, there is the potential for so-called “negative emissions.”|[0005] Negative emissions can be the basis for BECCS, which stands for bioenergy with carbon capture and storage. For example, in some cases, BECCS, which is a group of technologies that combine extracting bioenergy from biomass with CCS, can be viewed as a process where biomass (e.g., plants) is used to extract CO2 from the atmosphere, the biomass is processed to produce bioenergy (e.g., heat, electricity, fuels) while releasing CO2, and the CO2 produced during the processing is captured and stored such that there is there is a transfer of CO2 from the atmosphere to storage.|[0006] While BECCS is increasing discussed as a means to decrease CO2 emissions and/or CO2 concentrations in the atmosphere, some potential challenges that may hinder its success include 1) energy intensive biomass supply chains, 2) low energy conversion efficiencies, and/or 3) high costs (e.g., incentives and/or funding may be required). With regard to the first two points, it is generally preferable that the process provide a net energy gain (e.g., as opposed to a net energy loss, where the bioenergy provided from the process is lower than the energy put into the process) and/or that the process actually deliver net negative CO2 emissions (e.g., as opposed to net positive emissions, where the CO2 emissions from the bioenergy production process and CCS processes exceed the quantity of CO2 captured and stored). CO2 emissions from the bioenergy production process may arise from any point in the process (e.g., biomass production, transport, conversion, and/or utilization), and may for example, be attributed to non-renewable energy use within the process, waste management, and/or land use changes. With regard to the third point, for established bioenergy technologies, the cost of BECCS may be largely limited by the cost of CCS. Since the cost of CCS is typically scale sensitive, and since the capture of CO2 is often considered to be one of most expensive parts of CCS, BECCS has been generally considered for applications where the CO2 emissions are relatively pure and/or can be captured from a large point source.|[0007] Some potential applications of BECCS have been identified as power stations wherein biomass is combusted (e.g., where biogenic CO2 generated from the combustion process is captured and stored), biogas upgrading processes (e.g., where CO2 separated from the biogas captured and stored), and ethanol production processes (e.g., where CO2 produced by fermentation of corn grain is captured and stored). Unfortunately, at least in part due to one or more of the challenges listed above, BECCS deployment has been slow.|[0008] In terms of hydrogen production, BECCS has been discussed for the generation of hydrogen from the gasification of biomass. Gasification is a process that converts organic or fossil-based carbonaceous materials at high temperatures (>700° C.), without combustion, with a controlled amount of oxygen and/or steam into syngas (i.e., a gas mixture primarily composed of carbon monoxide (CO) and H2 and sometimes CO2). The gasification of biomass, including waste, is an evolving technology for producing hydrogen. In terms of BECCS it has the advantage that it is relatively simple, can be conducted on relatively large scale, and is generally configured such that all of the CO2 produced during the gasification is collected from one point source. Unfortunately, it may require some preprocessing of the feedstock (e.g., drying, grinding, etc.), may require treatment of the syngas to remove contaminants and/or reduce particulate matter emissions, and/or may require a large land footprint (e.g., for on-site storage of feedstock).|[0009] The reforming of biogas for hydrogen production has some advantages over the gasification of biomass, however, in terms of BECCS it is generally more complicated. First, raw biogas is generally regarded as low-quality fuel, which can require upgrading prior to hydrogen production. While biogas upgrading is a proven technology, it can be energy intensive and/or the cost can be a significant deterrent (e.g., in many countries, only a small share of overall biogas output is upgraded, with the remainder used in power generation, co-generation, and/or heat for buildings). Second, biogas plants (i.e., where biogas is upgraded) are often small and located close the source of biogas (e.g., remote locations). The small scale and/or distributed nature typical of biogas plants can make hydrogen production and/or CCS more challenging (e.g., both can be scale sensitive and/or energy intensive). In addition, such processes involve at least two conversions, namely, biomass to upgraded biogas and upgraded biogas to hydrogen, and thus the process is more complicated than the direct gasification of biomass. As a result, the resulting hydrogen may have net positive CO2 emissions.|SUMMARY|[0010] The present disclosure relates to a novel approach to produce renewable hydrogen from biogas, wherein the renewable hydrogen has a negative carbon intensity (CI). In particular, the present disclosure relates to a process(es)/system(s) wherein biogas is upgraded, the upgraded biogas is transported to at least one hydrogen plant, and carbon dioxide from both the biogas upgrading and the hydrogen production is captured and stored. The renewable hydrogen of the present invention can be used for many applications that are known in the art, e.g., for producing fuel, chemical product, fuel or chemical intermediates, or any combination thereof using the renewable hydrogen. For example, in certain embodiments, processes of the instant disclosure produce fuel (e.g., one or more fuels such as hydrogen, gasoline, diesel, jet fuel, methanol, ethanol, etc.), chemical product (e.g., methanol, ammonia, fertilizer, etc.), or intermediates (e.g., methanol, hydrogen, ammonia, ethanol, etc.), and include one or more steps wherein biogas is upgraded, the upgraded biogas is transported to fuel/product production, and carbon dioxide from both the biogas upgrading and the hydrogen production is captured and stored.|[0011] Advantageously, in capturing CO2 at multiple stages in the process, the CO2 capture process at each stage can be optimized for that stage in the process (e.g., bioenergy process), and/or a greater quantity of CO2 can be stored (e.g., relative to capturing CO2 from only one stage). Further advantageously, since the biogas is transported after it is upgraded, the distance between the biogas plant and the hydrogen plant can be increased (e.g., which can increase the number of potential biogas plants that can provide upgraded biogas for the hydrogen production). Accordingly, the present disclosure defies one or more common assumptions for BECCS projects (i.e., that the distance between the biomass source and the bioenergy production should be limited and/or that it is preferable to capture CO2 derived from the biomass from a single, relatively large, point source), while still yielding renewable hydrogen having a negative CI.|[0012] In accordance with one aspect of the instant invention there is provided a process for producing fuel, the fuel selected from renewable hydrogen and fuel produced from renewable hydrogen, the process comprising: providing biogas, the biogas comprising methane and carbon dioxide; removing at least 50% of the carbon dioxide from the biogas, thereby producing upgraded biogas; transporting the upgraded biogas to a hydrogen plant; processing the upgraded biogas at the hydrogen plant to produce syngas, the processing comprising providing the transported upgraded biogas as feedstock for methane reforming, the syngas comprising carbon dioxide and hydrogen; and purifying at least one of the syngas or a stream derived from the syngas to produce a hydrogen product comprising renewable hydrogen, and providing a quantity of the renewable hydrogen for at least one of (i) use as a fuel or (ii) producing a fuel, wherein the process further comprises: capturing and storing a first quantity of carbon dioxide, the carbon dioxide in the first quantity removed from the biogas; and capturing and storing a second quantity of carbon dioxide, the carbon dioxide in the second quantity removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, wherein the quantity of renewable hydrogen has a carbon intensity less than 0 gCO2-eq/MJ, and wherein the carbon intensity is dependent on steps a) and b).|[0013] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen, the process comprising: providing biogas, the biogas comprising methane and carbon dioxide; removing at least 50% of the carbon dioxide from the biogas, thereby producing upgraded biogas; providing the upgraded biogas for transport; providing the transported upgraded biogas as feedstock for methane reforming, thereby producing syngas, the processing comprising the syngas comprising carbon dioxide and hydrogen; and purifying a stream selected from the syngas and a stream derived from the syngas to produce a hydrogen product gas comprising renewable hydrogen, and providing a quantity of the renewable hydrogen, wherein the process further comprises: capturing and storing a first quantity of carbon dioxide, the carbon dioxide in the first quantity removed from the biogas; and capturing and storing a second quantity of carbon dioxide, the carbon dioxide in the second quantity removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, wherein the second quantity of carbon dioxide comprises at least 50% of the carbon dioxide produced from the feedstock from the methane reforming, and wherein the quantity of renewable hydrogen has a carbon intensity less than 0 gCO2-eq/MJ, and wherein the carbon intensity is dependent on steps a) and b).|[0014] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen having low carbon intensity, the process comprising: providing biogas, the biogas comprising methane and carbon dioxide; processing the biogas in a biogas upgrading process to produce upgraded biogas, the biogas upgrading process removing at least 50% of the carbon dioxide from the biogas; providing the upgraded biogas for transport; producing hydrogen from a hydrogen production process, a feedstock for the hydrogen production process comprising the upgraded biogas, the hydrogen production process comprising subjecting the feedstock to methane reforming to produce syngas comprising carbon dioxide and hydrogen, and purifying a stream selected from the syngas and a stream derived from the syngas to produce a hydrogen product gas comprising renewable hydrogen, wherein the process further comprises: capturing and storing a first quantity of carbon dioxide, the carbon dioxide in the first quantity removed from the biogas; and capturing and storing a second quantity of carbon dioxide, the carbon dioxide in the second quantity removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, and wherein the renewable hydrogen has a carbon intensity dependent on steps a) and b).|[0015] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen having low carbon intensity, the process comprising: providing biogas produced from a biogas production process, the biogas comprising methane and carbon dioxide, the biogas production process producing digestate; processing the biogas in a biogas upgrading process to produce upgraded biogas, the biogas upgrading process removing at least 50% of the carbon dioxide from the biogas; producing hydrogen from a hydrogen production process, a feedstock for the hydrogen production process comprising the upgraded biogas, the biogas upgrading process and the hydrogen production process conducted at different geographical locations, the hydrogen production process comprising subjecting the feedstock to methane reforming to produce syngas comprising carbon dioxide and hydrogen, and purifying a stream selected from the syngas and a stream derived from the syngas to produce hydrogen comprising renewable hydrogen, wherein the process further comprises: capturing and storing a first quantity of carbon from the biogas production process, the biogas upgrading process, or a combination thereof; capturing and storing a second quantity of carbon from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, the second quantity of carbon comprising carbon dioxide, and wherein the renewable hydrogen has a carbon intensity dependent on steps a) and b).|[0016] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen having low carbon intensity, the process comprising: producing hydrogen from a hydrogen production process, a feedstock for the hydrogen production process comprising upgraded biogas, the upgraded biogas produced in a process comprising subjecting biomass to an anaerobic digestion, thereby producing biogas and digestate, the biogas comprising methane and carbon dioxide, subjecting the biogas to biogas upgrading, thereby removing at least 50% of carbon dioxide from the biogas and producing upgraded biogas, transporting the upgraded biogas, and providing carbon containing material derived from the biomass for storage as part of a first carbon capture and storage process, the carbon containing material comprising carbon dioxide from the biogas, carbon containing material obtained or derived from the digestate, or a combination thereof, the hydrogen production process comprising subjecting the feedstock to methane reforming to produce syngas comprising carbon dioxide and hydrogen, purifying a stream selected from the syngas and a stream derived from the syngas to produce hydrogen comprising renewable hydrogen, and providing carbon dioxide produced from hydrogen production for storage as part of a second carbon capture and storage process, wherein a carbon intensity of the renewable hydrogen is reduced as a result of steps (iv) and (c).|(US11760630)|BRIEF DESCRIPTION OF THE DRAWINGS|[0017] FIG. 1 is a simplified process flow diagram of one embodiment of an SMR based hydrogen plant;|[0018] FIG. 2 is a simplified process flow diagram illustrating an embodiment wherein biogas is upgraded, the upgraded biogas is converted to hydrogen, and CO2 from both the biogas upgrading and hydrogen production is captured and stored;|[0019] FIG. 3 is a simplified process flow diagram of another embodiment of an SMR based hydrogen plant; and|[0020] FIG. 4 is a schematic diagram illustrating how the CO2 captured from the biogas upgrading and hydrogen production can be stored by injection into the same injection point of a CO2 distribution system or using different injection points of the same or different CO2 distribution systems.|(US11760630)|DETAILED DESCRIPTION|[0021] Certain exemplary embodiments of the invention now will be described in more detail, with reference to the drawings, in which like features are identified by like reference numerals. The invention may, however, be embodied in many different forms and should not be construed as limited to the embodiments set forth herein.|[0022] The terminology used herein is for the purpose of describing certain embodiments only and is not intended to be limiting of the invention. For example, as used herein, the singular forms “a,” “an,” and “the” may include plural references unless the context clearly dictates otherwise. The terms “comprises”, “comprising”, “including”, and/or “includes”, as used herein, are intended to mean “including but not limited to.” The term “and/or”, as used herein, is intended to refer to either or both of the elements so conjoined. The phrase “at least one” in reference to a list of one or more elements, is intended to refer to at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements. Thus, as a non-limiting example, the phrase “at least one of A and B” may refer to at least one A with no B present, at least one B with no A present, or at least one A and at least one B in combination. In the context of describing the combining of components by the “addition” or “adding” of one component to another, or the separating of components by the “removal” or “removing” of one component from another, those skilled in the art will understand that the order of addition/removal is not critical (unless stated otherwise). The terms “remove”, “removing”, and “removal”, with reference to one or more impurities, contaminants, and/or constituents of biogas, includes partial removal. The terms “cause” or “causing”, as used herein, may include arranging or bringing about a specific result (e.g., a withdrawal of a gas), either directly or indirectly, or to play a role in a series of activities through commercial arrangements such as a written agreement, verbal agreement, or contract. The term “associated with”, as used herein with reference to two elements (e.g., a fuel credit associated with the transportation fuel), is intended to refer to the two elements being connected with each other, linked to each other, related in some way, dependent upon each other in some way, and/or in some relationship with each other. The terms “first”, “second”, etc., may be used to distinguish one element from another, and these elements should not be limited by these terms. The term “plurality”, as used herein, refers to two or more. The term “providing” as used herein with respect to an element, refers to directly or indirectly obtaining the element and/or making the element available for use. The terms “upstream” and “downstream”, as used herein, refer to the disposition of a step/stage in the process with respect to the disposition of other steps/stages of the process. For example, the term upstream can be used to describe to a step/stage that occurs at an earlier point of the process, whereas the term downstream can be used to describe a step/stage that occurs later in the process. Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art.|[0023] The term “biomass”, as used herein, refers to organic material originating from plants, animals, or micro-organisms (e.g., including plants, agricultural crops or residues, municipal wastes, and algae). Biomass is a renewable resource, which can be naturally replenished on a human timescale, and which can be used to produce bioenergy and/or biofuels (e.g., biogas).|[0024] The term “biogas”, as used herein, refers to a gas mixture that contains methane produced from biomass. While biogas is predominately produced from the anaerobic digestion (AD) of biomass, it is also possible to produce biogas from the gasification of biomass. For example, the gasification of biomass may produce syngas, which may be cleaned up, and methanated. When produced from the anaerobic digestion of biomass, raw biogas typically includes methane (CH4), carbon dioxide (CO2), and can contain water (H2O), nitrogen (N2), hydrogen sulfide (H2S), ammonia (NH3), oxygen (O2), volatile organic compounds (VOCs), and/or siloxanes, depending up its source. The term biogas, as used herein, can refer to raw biogas, cleaned biogas, or upgraded biogas.|[0025] The term “raw biogas”, as used herein, refers to biogas as obtained from its source (e.g., anaerobic digester or landfill) before it is treated to remove any chemical components (e.g., CO2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates). Raw biogas can be subjected to biogas cleaning to produce cleaned biogas or subjected to biogas upgrading to produce upgraded biogas.|[0026] The term “biogas cleaning”, as used herein refers to a process where biogas (e.g., raw biogas) is treated to remove one or more components (e.g., H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), but does not remove a significant amount of CO2 and/or N2 (e.g., the calorific value of the biogas may not change significantly as a result of biogas cleaning).|[0027] The term “biogas upgrading”, as used herein, refers to a process where biogas (e.g., raw or cleaned biogas) is treated to remove one or more components (e.g., CO2, N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), wherein the treatment increases the calorific value of the biogas. For example, biogas upgrading typically includes removing CO2 and/or N2. Biogas upgrading, which can include biogas cleaning, produces upgraded biogas. The term “upgraded biogas”, as used herein, can refer to a partially purified biogas (i.e., requires further treatment in order to meet applicable specifications) or renewable natural gas (RNG).|[0028] The term “renewable natural gas” or “RNG”, as used herein, refers to biogas that has been upgraded to meet or exceed applicable natural gas pipeline specifications, meet or exceed applicable quality specifications for vehicle use (e.g., CNG specifications), and/or natural gas withdrawn from a natural gas distribution system that is associated with the environmental attributes of biogas injected into the natural gas distribution system (e.g., a gas that qualifies as RNG under applicable regulations). For example, the term RNG can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of RNG, upgraded from biogas, that was injected into the natural gas distribution system. Pipeline specifications include specifications required for biogas for injection into a natural gas distribution system. Pipeline quality standards or specifications may vary by region and/or country in terms of value and units. For example, pipelines standards may require the RNG to have a CH4 level that is at least 95% or have a heating value of at least 950 BTU/scf. The percentages used to quantify gas composition and/or a specific gas content, as used herein, are expressed as mol%, unless otherwise specified. More specifically, they are expressed by mole fraction at standard temperature and pressure (STP), which is equivalent to volume fraction.|[0029] The term “natural gas” or “NG”, as used herein, refers a gas mixture rich in hydrocarbons, where the primary component is CH4. The term “gas” or “gas mixture”, as used herein, refers to a fluid that is gaseous at standard temperatures and pressures, unless indicated otherwise.|[0030] The term “environmental attributes”, as used herein with regard to a specific material (e.g., biogas), refers to any and all attributes related to the material, including all rights, credits, benefits, or payments associated with the renewable nature of the material and/or the reduction in or avoidance of fossil fuel consumption or reduction in lifecycle GHG gas emissions associated with the use of the material. Some non-limiting examples of environmental attributes include verified emission reductions, voluntary emission reductions, offsets, allowances, credits, avoided compliance costs, emission rights and authorizations, certificates, voluntary carbon units, under any law or regulation, or any emission reduction registry, trading system, or reporting or reduction program for GHG gas emissions that is established, certified, maintained, or recognized by any international, governmental, or nongovernmental agency.|[0031] The terms “capturing and storing”, as used herein with reference to CO2, refers to capturing the CO2 and storing the captured CO2 to prevent the captured CO2, or an equal quantity of CO2 displaced physically by the captured CO2, from being released to the atmosphere. Capturing the CO2 can include removing CO2 from a gas mixture (e.g., biogas, syngas) using any suitable separation technology, or if the CO2 is relatively pure, capturing the CO2 can simply refer to collecting the CO2 (e.g., in a pipe). Storing the captured CO2 can include sequestering it underground (e.g., trapping it in geological formations, such as saline aquifers, or using it for enhanced oil recovery (EOR)), or can include storing the captured CO2 in one or more products (e.g., using the captured CO2 as a resource to create valuable products such plastics, concrete, etc.). For example, “capturing and storing CO2” can be part of one or more processes commonly referred to as “carbon capture and sequestration”, “carbon capture and utilization” or CCU, or “carbon capture, utilization and storage” or CCUS. In most cases, capturing and storing CO2 also includes compressing the captured CO2 (e.g., to produce liquid CO2 or for injection into a CO2 distribution system) and transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). As will be understood by those skilled in the art, it can be advantageous to store the captured CO2 using a method recognized by the applicable regulatory authority for reducing GHG emissions and/or mitigating climate change.|[0032] The term “carbon intensity” or “CI” refers to the quantity of lifecycle GHG emissions, per unit of fuel energy, and is often expressed in grams of CO2 equivalent emissions per unit of fuel (e.g., gCO2e/MJ or gCO2e/MMBTU). As will be understood by those skilled in the art, CI is often determined using Lifecycle Analysis (LCA), which identifies and estimates all GHG emissions in producing a fuel/product (e.g., renewable hydrogen), from the growing or extraction of raw materials, to the production of the fuel/product, through to the end use of the fuel/product (e.g., well-to-wheel). Those skilled in the art will understand that CI values for a given fuel/product can be dependent on the LCA methodology used (e.g., as required by the applicable regulatory authority). Methodologies for calculating carbon intensities and/or lifecycle GHG emissions according to various regulatory bodies are well known in the art and can be readily calculated by those of ordinary skill in the art. The CI values recited herein are determined using the CA-GREET 3.0 model (e.g., see, https://ww2.arb.ca.gov/resources/documents/lcfs-life-cycle-analysis-models-and-documentation), unless otherwise specified.|[0033] The present disclosure relates to producing renewable hydrogen having a negative CI from biogas, which can be used as fuel, as industrial feedstock (e.g., to produce fuel, fuel intermediates, or chemical products), or in fuel cells (e.g., to generate heat and/or electricity). For example, hydrogen is commonly used in oil refining, ammonia production, methanol production, and steel production.|[0034] Raw biogas produced from the anaerobic digestion of biomass can have a significant CO2 content (e.g., about 35%), which reduces the calorific value of the biogas (i.e., relative to pure methane). As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings. Alternatively, raw or cleaned biogas can be upgraded (e.g., to RNG) and used as a substitute for fossil based natural gas (e.g., used as a transportation fuel in the form of compressed RNG (bio-CNG) or liquefied RNG (bio-LNG)).|[0035] As a substitute for fossil based natural gas, upgraded biogas (e.g., RNG) may be used to produce renewable hydrogen using any technology suitable for converting natural gas to hydrogen (e.g., methane reforming). Renewable hydrogen, which can be used as a fuel in gas or liquid form, is very versatile as it can be used as a fuel, converted into electricity, and/or converted to one or more fuels. For example, renewable hydrogen can power fuel cell electric vehicles (FCEVs), which emit no tailpipe emissions other than water, or can be run through a fuel cell to power the electricity grid. Alternatively, renewable hydrogen can be used to produce liquid fuels (e.g., gasoline, diesel, jet fuel) that are renewable and/or have renewable content.|[0036] Converting upgraded biogas (e.g., RNG) to renewable hydrogen by SMR is advantageous in that it exploits technology that is well established for natural gas. Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations. While the relatively small scale and/or remote locations may be advantageous when the goal is to produce a grid of hydrogen refueling stations for FCEVs (e.g., where multiple geographically spaced small scale hydrogen plants can avoid transport and storage problems with hydrogen), such distributed hydrogen production cannot take advantage of economies of scale (e.g., SMR based hydrogen production is more economical when operated at a large scale), and thus is more expensive. Given the low value of raw biogas, the relatively small scale of many biogas plants, the cost of biogas upgrading, and/or the cost of SMR, it may be challenging to find facility owners willing to collect biogas and convert it to hydrogen, particularly since other uses of biogas are more economical.|[0037] It may be particularly challenging to find facility owners further willing to integrate CCS with such processes. Distributed carbon capture may be considered unfavorable compared to centralized large-scale carbon capture. For example, the cost of CCS is typically scale sensitive, and since distributed hydrogen production is generally small scale, the cost of CCS for distributed hydrogen production may be prohibitive. In addition, a lack infrastructure (e.g., CO2 pipelines) and/or space-consuming CO2 purification and capture equipment may be a deterrent for distributed CCS.|[0038] While large-scale CCS has been demonstrated for SMR plants that process fossil based natural gas, it is not cheap, and is not necessarily simple. For example, consider the hydrogen plant illustrated in FIG. 1. A stream of preheated natural gas 1 is desulfurized (not shown) and fed, along with steam 2, into the reactor tubes for the SMR 10, which contain the reforming catalyst. Streams of natural gas 3 and combustion air 4 are fed into the SMR burners, which provide the heat required for the endothermic reforming reaction. The syngas 15 produced from the SMR is fed to water gas shift (WGS) 20 to produce more hydrogen. The resulting syngas 25, which may also be referred to as shifted gas, is cooled (not shown) and purified using pressure swing adsorption (PSA) 30, which produces a stream enriched in hydrogen 32 and a purge stream 34. The purge stream 34, which may contain unconverted CH4, H2, CO2, and/or CO, is fed back to SMR 10, where it is used to provide process heat for the SMR (e.g., fuel the SMR burners). More specifically, the purge stream 34 is combusted together with the stream of natural gas 3.|[0039] In the hydrogen production process illustrated in FIG. 1, there are two sources of CO2, namely, CO2 produced from the feedstock 1 for the SMR (e.g., CO2 in the syngas 25), which can make up about 60% of the total CO2 produced, and CO2 produced from the fuel 3 for SMR (e.g., CO2 in the flue gas 12), which can make up about 40% of the total CO2 produced, depending upon the configuration of the hydrogen plant. In terms of capturing CO2, there are various options of how and where the CO2 may be captured, each with different energy requirements and/or yields. FIG. 1 identifies three possible options.|[0040] The first option, which is labelled A, captures CO2 from the flue gas 12, and thus captures both CO2 from the feedstock and CO2 from the fuel (e.g., may capture up to about 90% of the total CO2 produced). The second option, which is labelled B, captures CO2 from the syngas 25, and thus captures only the CO2 from the feedstock (e.g., about 60% of the CO2). The third option, which is labelled C, captures CO2 from the purge gas 34, and thus also captures only the CO2 from the feedstock. While the first option theoretically can capture more CO2 from the hydrogen production, capturing carbon dioxide from the syngas 25 (e.g., using vacuum pressure swing adsorption (VPSA) or an absorption amine unit) or from the purge gas 34 (e.g., using an activated amine process) may be more technically and/or economically feasible. For example, relative to the syngas 25, the flue gas may have a relatively low CO2 concentration (e.g., relatively low partial pressure) and/or may be at a lower pressure (e.g., atmospheric). In addition, the flue gas may contain N2 (N2-CH4 separations may be more challenging than CO2-CH4 separations).|[0041] In general, the SMR of fossil based natural gas to produce hydrogen can produce significant GHG emissions. While cooling of the syngas can allow heat recovery back into the process (e.g., steam generation and boiler feed water pre-heating), thereby preventing GHG emissions that would be associated with the heat, the resulting hydrogen can still have a high CI. For example, hydrogen produced from the SMR of fossil based natural gas, which is often referred to as “grey hydrogen,” may have a CI of about 100 gCO2e/MJ. When CCS is integrated with the SMR of fossil based natural gas, the resulting hydrogen it is often referred to as “blue hydrogen.” As will be understood by those skilled in the art, the CI of blue hydrogen is dependent on both the hydrogen production and how much of the fossil based CO2 is captured and stored. For example, in the case where only the CO2 from the feedstock is captured and stored (i.e., not the flue gas), blue hydrogen may have a CI of about 45 gCO2e/MJ.|[0042] As discussed herein, another approach to reduce the CI of hydrogen is to use a renewable feedstock (e.g., use RNG instead of fossil based natural gas), thereby producing renewable hydrogen. The CI of renewable hydrogen produced by the SMR of RNG can be dependent on the CI of the RNG, which can be dependent upon its source. For example, compared to the CI of fossil based natural gas, which can be about 80 gCO2e/MJ, RNG produced from a landfill may have a CI of about 46 gCO2e/MJ, whereas RNG produced from manure may have a CI of about −271 gCO2e/MJ of CH4 (e.g., as a result of avoided GHG emissions). Assuming that fossil based natural gas is used to fuel the SMR (e.g., fuel stream 3 is fossil based natural gas), the CI of renewable hydrogen produced by the SMR of landfill based RNG may be about 65 gCO2e/MJ (e.g., higher than blue hydrogen). If this process is integrated with CCS, wherein only the CO2 from the feedstock is captured and stored, the renewable hydrogen may have a CI of about 11 gCO2e/MJ. Such calculations are discussed in further detail with regard to Table 1. For comparative purposes, the CI of compressed H2 from electrolysis run with green electricity, which can be referred to as “green hydrogen”, may be less than 10 gCO2e/MJ.|[0043] While a CI of about 10 gCO2e/MJ is generally preferable to 100 gCO2e/MJ, it would be advantageous to provide renewable hydrogen having a lower CI, and in particular, a negative CI. In theory, the CI of renewable hydrogen produced by the SMR of RNG produced from a landfill may be able to be reach below 10 gCO2e/MJ if the CO2 from the flue gas is also, or alternatively, captured. However, capturing CO2 from the flue gas can be costly. Additionally, or alternatively, the CI of the renewable hydrogen produced by the SMR of RNG may reach below 10 gCO2e/MJ if the feedstock for producing the RNG is manure (e.g., CH4 having a CI of about −271 gCO2e/MJ). Unfortunately, biogas production from manure can be more costly and/or may be associated with a limited supply (e.g., relative to landfill gas).|[0044] The present disclosure relates to at least one process/system wherein the CI of renewable hydrogen is low as a result of capturing and storing CO2 not only from the hydrogen production (e.g., from the feedstock and/or fuel) but also from the biogas upgrading. Accordingly, the renewable hydrogen can have a negative CI regardless of whether the biogas is generated from a landfill or from manure and/or whether the CO2 is collected from the flue gas of the SMR. For example, consider the schematic diagram illustrated in FIG. 2.|[0045] Referring to FIG. 2, biomass is converted to biogas at biogas production 50. Biogas production 50 provides biogas from at least one biogas source 50, (e.g., a landfill or anaerobic digester). The biogas (e.g., raw or cleaned) is subjected to biogas upgrading 100. The biogas upgrading 100 can be conducted at or near at the biogas source 50, (e.g., at a biogas plant at the landfill or farm) or can be conducted at a centralized biogas upgrading facility that also processes biogas from other biogas sources (e.g., 50ii). The upgraded biogas (e.g., RNG) 125 is transported to hydrogen production 200 (e.g., to a commercial hydrogen plant or a hydrogen plant at a fuel production facility). Hydrogen production 200 converts at least a portion of the upgraded biogas (e.g., RNG) to renewable hydrogen (e.g., via SMR). The renewable hydrogen in the H2 product 275 can be used as a transportation fuel (e.g., direct combustion or in a fuel cell), used for generating electricity (e.g., in a fuel cell), and/or used as an industrial feedstock (e.g., to produce a fuel such as a transportation fuel).|[0046] At least a portion of the CO2 from the biogas (e.g., generated during anaerobic digestion) 150, and at least a portion of the CO2 produced from hydrogen production 250, is captured and provided for storage 300. In general, the upgraded biogas 125 may be transported to hydrogen production 200 and the CO2 150, 250 may be transported to storage 300 (if required) using any suitable mode of transportation, including transport by pipeline and/or vehicle (e.g., ship, rail car, truck). For example, in one particularly advantageous embodiment, the upgraded biogas 125 is injected into a natural gas distribution system near the biogas upgrading 100 and is withdrawn from the same natural gas distribution system for hydrogen production 200 (e.g., is transported as a fungible batch to the hydrogen plant and/or fuel production facility). In general, the CO2 captured from the biogas upgrading 150 and from the hydrogen production 250 can be stored together or separately. For example, the CO2 captured from the biogas upgrading 150 may be used for CCSU, while the CO2 captured from the hydrogen production 250 may be used for CCS. In some embodiments, the CO2 captured from the biogas upgrading 150 and from the hydrogen production 250 are transported to storage, at least in part, using one or more CO2 distribution systems. For example, in one particularly advantageous embodiment, the captured CO2 (e.g., 150 and/or 250) is injected into a CO2 distribution system for transport and is withdrawn from the same CO2 distribution system for storage (e.g., is transported as a fungible batch(es) to storage). CO2 distributions systems, which typically transfer large quantities of CO2 by pipeline, are increasingly used to facilitate enhanced oil recovery (EOR).|[0047] Although this process relies on at least two CO2 capture steps, which are often considered to be energy-consuming steps, there are various advantages and/or synergetic benefits of using this process for producing renewable hydrogen.|[0048] For example, compare the process discussed with reference to FIG. 2 to the gasification of biomass. Biomass gasification may offer large scale centralized hydrogen production, facilitates collecting the biogenic carbon dioxide from one point source, and avoids some intermediate steps (e.g., the conversion of biomass to biogas and biogas upgrading). Nevertheless, there are challenges to hydrogen production via biomass gasification, many of which relate to the costs associated with capital equipment and biomass feedstocks. A facility producing 100 tonnes of hydrogen per day may be very large (e.g., require 1,350 dry tonnes of biomass feedstock per day), and thus may not be feasible based on regional supplies. Smaller facilities may be more feasible from a feedstock availability perspective but may drive up the capital expenditures. The cost of the biomass feedstocks can be dependent on costs for storage and transportation of the biomass, the latter of which may be dependent on the collection radius. Feedstock costs may be modest where agricultural residues can be collected and transported over short distances, but can be high when significant transport distances are involved, at least in part due to the low energy density of biomass.|[0049] Alternatively, compare the process discussed with reference to FIG. 2 to the SMR of biogas, wherein biomass is transported to a centralized processing facility that conducts the anaerobic digestion, biogas upgrading, and hydrogen production (i.e., upgraded biogas is not transported). As with the gasification of biomass, the feedstock costs for such a process can be largely dependent on the storage and transportation of the biomass. When the feedstock has a large moisture content (e.g., manure or food waste) the transportation cost may be even higher.|[0050] In contrast, in the process illustrated in FIG. 2, the upgraded biogas is transported for hydrogen production (i.e., biogas upgrading 100 and hydrogen production 200 are conducted at different locations). Transporting upgraded biogas over extended distances can be more cost efficient than transporting feedstock for anaerobic digestion and/or gasification. In particular, upgraded biogas such as RNG may be transported using any method suitable for transporting natural gas (e.g., a truck designed for transporting liquified natural gas (LNG) or compressed natural gas (CNG), the latter of which is often transported at pressures above about 3600 psig (24.8 MPa)). Transporting the upgraded biogas as bio-LNG or bio-CNG allows more MJ to be delivered per truck (e.g., relative to biomass for gasification or anaerobic digestion) and/or can increase the collection radius for the renewable feedstock. Alternatively, or additionally, the upgraded biogas can be transported by pipeline (e.g., in a natural gas distribution system such as the US natural gas grid), where it is transported as a fungible batch.|[0051] Transporting the upgraded biogas via a natural gas distribution system is particularly advantageous. In particular, it is a cost effective method that uses existing infrastructure, and depending upon the applicable regulatory agency, may have only a small penalty (cost and/or GHG emissions) for transporting the upgraded biogas over extended distances. Accordingly, the collection zone for the renewable feedstock is not limited to the area around a centralized facility conducting anaerobic digestion, biogas upgrading, and hydrogen production, but rather can include any area that provides feedstock for biogas production, where the biogas production is near the natural gas distribution system or can be economically transported to an injection point of the natural gas distribution system. This can increase the area from which the feedstock is collected, thereby making more feedstock available for the process and increasing the feasible scale of the renewable hydrogen production and/or CCS. Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).|[0052] Co-processing renewable and non-renewable feedstock can increase the possible scale of hydrogen production and/or CCS (e.g., biogenic and fossil CO2 can be captured and stored together), can facilitate using existing hydrogen plant(s) configured to process natural gas, and/or can reduce operational complications associated with intermittent renewable feedstock supply (e.g., cold start-up times may be between about 15 and 24 hours). Accordingly, the costs of hydrogen production and/or CCS can be reduced. In addition to the economies of scale, the costs of CCS may be reduced when the hydrogen plant is in close proximity to a CO2 pipeline.|[0053] Advantageously, providing multiple CO2 capture steps (e.g., the disaggregation of CO2 capture processes) for CO2 storage allows each capture process to be optimized for that stage of the process (e.g., bioenergy process). For example, since biogas upgrading typically includes separating CO2 from CH4, many biogas upgrading technologies can include CO2 capture, can be readily modified to include CO2 capture, or may facilitate CO2 capture, thereby reducing costs of at least one CO2 capture step.|[0054] Further advantageously, providing multiple CO2 capture steps, each at a different stage of the process, can result in the renewable hydrogen having not only a negative CI, but a CI that is not higher than −10 gCO2e/MJ, −20 gCO2e/MJ, −30 gCO2e/MJ, −40 gCO2e/MJ, −50 gCO2e/MJ, −60 gCO2e/MJ, or −70 gCO2/MJ of H2. For example, consider the example where biogas having a CH4 content of about 60% and a CO2 content of about 40% is upgraded and subjected to SMR to produce hydrogen. Even if 100% of the CO2 generated from the hydrogen production is captured and stored (i.e., from feedstock and fuel), without capturing the CO2 from the biogas upgrading, a lot of the carbon from the biogas will be released to the atmosphere as CO2 (e.g., 40% of the biogas on a volume basis, or about 65% of the biogas on a mass basis). While providing a zero carbon hydrogen is generally advantageous, it may be particularly advantageous if the CI is as low as possible when the hydrogen is used as a fuel or to produce a fuel, for fuel credit purposes.|[0055] Further details about the biogas production 50, the biogas upgrading 100, hydrogen production 200, capture and/or storage 300, and optional fuel production and/or fuel credits, are discussed below.|Biogas Production|[0056] In general, the biogas can be produced from any suitable biomass. For example, the biogas can be produced from the anaerobic digestion of any suitable feedstock. Anaerobic digestion, which refers to the biological breakdown of organic matter by anaerobic microorganisms, is typically conducted in anaerobic or low oxygen conditions, and may involve a series of microorganism types and processes (e.g., hydrolysis, acidogenesis, acetogenesis, and methanogenesis).|[0057] In one embodiment, the biogas is produced from the anaerobic digestion of any suitable feedstock, where the feedstock is and/or comprises: (i) an energy crop (e.g., switchgrass, sorghum, etc.); (ii) residues, byproducts, or waste from the processing of plant material in a facility, or feedstock derived therefrom (e.g., sugarcane bagasse, sugarcane tops/leaves, corn stover, etc.); (iii) agricultural residues (e.g., wheat straw, corn cobs, barley straw, corn stover, etc.); (iv) forestry material; (v) pulp and paper residues; and/or (vi) municipal waste or components removed or derived from municipal waste. In one embodiment, the feedstock for the anaerobic digestion is or includes cellulosic and/or lignocellulosic material(s).|[0058] In one embodiment, the biogas is produced from the anaerobic digestion of “organic waste.” Using organic waste as the feedstock for anaerobic digestion is particularly advantageous. Organic waste, may for example, include the organic fraction of municipal solid waste (MSW), sludge from a wastewater treatment plant (WWTP), manure from a livestock farm (e.g., a dairy or swine farm), or food or yard waste collected from households, restaurants, supermarkets, food-processing companies, schools, businesses, etc. In one embodiment, the feedstock for the anaerobic digestion is manure (e.g., swine or dairy) or other farm waste, the organic fraction of MSW, or agricultural residues (e.g., straw, stover, etc.).|[0059] The composition of biogas produced from anaerobic digestion can be dependent upon the feedstock. For example, although biogas produced from anaerobic digestion generally has a CH4 content between about 35% and 75% (e.g., about 60%) and a CO2 content between about 15% and 65% (e.g., about 35%), the CH4 content can tend towards the high end of this range when the feedstock is agricultural waste (e.g., between about 50% and 75%) and towards the low end of this range when the feedstock is the organic fraction of municipal solid waste (e.g., between about 25% and 65%). In addition to CH4 and CO2 biogas produced from anaerobic digestion may also include N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates, in dependence upon its source. For example, biogas produced from a landfill often has a higher N2 content than biogas produced in anaerobic digester. In one embodiment, the raw biogas has a CH4 content between about 25% and 75% and a CO2 content between about 15% and 65%, and the CO2 and CH4 make up at least 75% of the biogas by volume.|[0060] The anaerobic digestion of the feedstocks (e.g., solid or liquid) can be conducted in any suitable environment, including a natural environment (e.g., a landfill) or a controlled environment (e.g., an anaerobic digester). An anaerobic digester can be a holding tank, or another contained volume, such as a covered lagoon or sealed structure, configured to facilitate the breakdown of organic material by microorganisms under anaerobic or low oxygen conditions. Anaerobic digestion may be carried out in one or multiple anaerobic digesters connected in series and/or parallel, where each digester may be a single-stage or multi-stage digestion system, and/or may be designed and/or operated in a number of configurations including batch or continuous, mesophilic or thermophilic temperature ranges, and low, medium, or high rates. The term “anaerobic digester”, as used herein, can refer to plurality of fluidly connected anaerobic digesters. The operation of an anaerobic digester may be dependent on nature of the organic matter fed to the anaerobic digester and/or the level of digestion required. The appropriate selection of operating parameters, including but not limited to residence time, temperature, pH, and/or the nutrients supplied, will be known to those skilled in the art.|[0061] When conducted in one or more anaerobic digesters, the anaerobic digestion of biomass also produces a potentially usable digestate. Digestate refers to the material remaining after one or more stages of the anaerobic digestion (e.g., may refer to acidogenic digestate, methanogenic digestate, or a combination thereof). Digestate can include organic material not digested by the anaerobic microorganisms, by-products of the anaerobic digestion released by the microorganisms, and/or the microorganisms themselves. For example, the digestate can include carbohydrates, nutrients (such as nitrogen compounds and phosphates), other organics, and/or wild yeasts. The composition of digestate can vary depending on the biomass from which it is derived. Digestate often has both a solid and liquid component. A common use of digestate is as a soil conditioner, where it can provide nutrients for plant growth and/or displace the use of fossil-based fertilizers. In one embodiment, the digestate is processed to provide carbon-containing material that is stored as part of CCS.|[0062] In general, the biogas can be produced from one or more sources (e.g., one or more landfills and/or anaerobic digesters). In one embodiment, the biogas is produced from a single biogas source. In one embodiment, the biogas is produced from multiple biogas sources.|Biogas Upgrading|[0063] In general, the biogas produced from the feedstock(s) is upgraded in one or more stages to provide upgraded biogas (i.e., prior to transport to hydrogen production). Biogas upgrading, which increases the calorific value of the biogas, typically provides a CH4-rich gas having a CH4 content of at least 90%. In one embodiment, the upgraded biogas has a CH4 content of at least 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95%, at least 96%, at least 97%, or at least at least 98%. It can be particularly advantageous to produce upgraded biogas having a CH4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system. In one embodiment, the biogas upgrading produces RNG. In one embodiment, the biogas upgrading produces biogas having a CH4 content of at least 95%. In one embodiment, the biogas upgrading produces biogas having a heating value of at least 950 BTU/ft3.|[0064] Biogas upgrading can be conducted using any suitable technology or combination of technologies that can separate CH4 from one or more non-methane components in the biogas (e.g., CO2, N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates). For example, biogas upgrading technologies are often based on absorption, adsorption, membrane separation, and/or cryogenic separation. As will be understood by those skilled in the art, the technology used for the biogas upgrading can be dependent up the composition of the biogas and the desired purity of the upgraded biogas.|[0065] As biogas typically has a significant CO2 content, biogas plants often include at least one system for separating CH4 from CO2. Some examples of technologies that can remove CO2 from biogas include, but are not limited to, absorption (e.g., water scrubbing, organic physical scrubbing, chemical scrubbing), adsorption (e.g., pressure swing adsorption (PSA)), membrane separation (e.g., CO2 selective membranes based on polyimide, polysulfone, cellulose acetate, polydimethylsiloxane), and cryogenic separation.|[0066] While some CO2 removal systems may remove one or more other non-methane components in addition to CO2 (e.g., N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates), biogas plants often include one or more other systems (e.g., dehydration units, H2S removal units, N2 rejection units, etc.). For example, some CO2 removal systems require that the biogas be cleaned upstream of CO2 removal (e.g., remove impurities that can negatively affect the CO2 removal unit. Alternatively, or additionally, the biogas can be cleaned and/or upgraded downstream of CO2 removal. In general, the non-methane components can be removed by any combination of chemical and/or physical technologies, in one or more stages. For example. H2O may be removed using a standard biogas dehumidifier, whereas H2S may be removed using a commercial H2S removal unit (e.g., based on activated carbon, molecular sieve, iron sponge, water scrubbing, NaOH washing, and/or biofilter or biotrickling filter technologies). In some cases, one stage may remove more than one non-methane component. For example. in some cases, some H2S may also be removed during the water removal step.|[0067] In general, the biogas upgrading can be conducted close to the biogas source (e.g., at a biogas plant at the landfill site or near the anaerobic digester) or at a centralized biogas plant (e.g., which receives raw, cleaned, or partially purified biogas from multiple sources). For example, a centralized biogas plant may be connected to one or more anaerobic digesters (e.g., each at a separate farm) via a biogas pipeline and/or grid. Alternatively, or additionally, the centralized biogas plant may receive biogas from one or more biogas sources by vehicle (e.g., see U.S. Pat. No. 10,760,024). In one embodiment, the biogas source is a centralized anaerobic digester, wherein the feedstock for anaerobic digestion is transported from multiple locations (e.g., multiple farms).|[0068] The upgraded biogas is transported to hydrogen production (e.g., to a stand-alone hydrogen plant or to a production facility having at least one hydrogen plant). As the upgraded biogas may be relatively pure (e.g., have a CH4 content greater than about 92%), it may be transported using methods used to transport natural gas. For example, if the biogas is upgraded to RNG it can be transported in a CNG tanker (e.g., at a pressure of about 3600 psig) and/or transported by pipeline (e.g., a natural gas distribution system such as the US natural gas grid). In some cases, upgraded biogas that does not meet pipeline standards can be mixed with another gas (e.g., propane or fossil based natural gas) in order to facilitate injection into the natural gas distribution system.|[0069] In general, when upgraded biogas is transported by pipeline, it is transferred as a fluid (e.g., in gaseous or liquid form), and may be provided as a segregated batch or a fungible batch. The term “batch”, as used herein, refers to a certain amount of the gas (e.g., energy delivered) and does not imply or exclude an interruption in the production and/or delivery.|[0070] When upgraded biogas is transported as a fungible batch in a natural gas distribution system, a quantity of the upgraded biogas (e.g., in MJ) is injected into the natural gas distribution system (optionally after being blended with another gas having a relatively high calorific value), where it can comingle with non-renewable natural gas, and an equivalent quantity of gas (e.g., in MJ) is withdrawn at another location (i.e., as long as there is a physical link between the injection point and the withdrawal point). Since the transfer or allocation of the environmental attributes of the upgraded biogas injected into the natural gas distribution system to gas withdrawn at a different location is typically recognized, the withdrawn gas is recognized as the upgraded biogas and/or qualifies as RNG under applicable regulations (e.g., even though the withdrawn gas may not contain actual molecules from the original biomass and/or contains methane from fossil sources). Such transfer may be carried out on a displacement basis, where transactions within the natural gas distribution system involve a matching and balancing of inputs and outputs. Typically, the direction of the physical flow of gas is not considered. Establishing that a gas is recognized as and/or qualifies as RNG (e.g., originates from renewable sources) under applicable regulations can depend on whether the gas is transported by truck or by pipeline and the practices and requirements of the applicable regulatory agency, where such practices may include, for example, the use of chain of custody accounting methods such as identity preservation, book-and-claim, and/or mass balance.|[0071] Transporting the upgraded biogas via a natural gas grid is particularly advantageous as it facilitates transporting the renewable feedstock anywhere where the grid delivers without significant additional cost (e.g., financially and/or GHG emissions). In one embodiment, the upgraded biogas is transported to hydrogen production, at least in part, via a natural gas distribution system. In one embodiment, the upgraded production is transported to hydrogen production, at least in part, by vehicle.|Hydrogen Production|[0072] In general, the renewable hydrogen may be produced at one or more hydrogen plants. The term “hydrogen plant”, as used herein, refers to a system or combination of systems primarily used for hydrogen production. The term “renewable hydrogen”, as used herein, refers to hydrogen produced using biogas (e.g., upgraded biogas and/or RNG). For example, the term “renewable hydrogen” can refer to hydrogen produced by methane reforming a feed withdrawn from a natural gas distribution system, when at least a portion of the withdrawn feed is recognized as and/or qualifies as RNG under applicable regulations.|[0073] In general, the hydrogen production may use any suitable technology known in the art that can convert upgraded biogas and/or natural gas to hydrogen. Examples of technologies that may be suitable include, but are not limited to, steam methane reforming (SMR), autothermal reforming (ATR), partial oxidation (PDX), and dry methane reforming (DMR). SMR, ATR, and DMR, which are types of catalytic reforming, may operate by exposing natural gas to a catalyst at high temperature and pressure to produce syngas. PDX reactions, which include thermal partial oxidation reactions (TPDX) and catalytic partial oxidation reactions (CPDX), may occur when a sub-stoichiometric fuel-oxygen mixture is partially combusted in a reformer. PDX also may be referred to as oxidative reforming. For purposes herein, the term “methane reforming” may refer to SMR, ATR, DMR, or PDX.|[0074] Of the various types of methane reforming, SMR is the most common. In SMR, which is an endothermic process, methane is reacted with steam under pressure in the presence of a catalyst to produce carbon monoxide (CO) and H2 according to the following reaction:|CH4+H2O+heat→CO+3H2 (1)|[0075] Referring to the hydrogen plant in FIG. 1, this reaction may occur in the SMR reactor tubes, which contain the reforming catalyst. Without being limiting, the catalyst may be nickel-based, the operating pressure may be between 200 psig (1.38 MPa) and 600 psig (4.14 MPa), and the operating temperature may be between about 450 to 1000° C. The heat required for the catalytic reforming of Eq. 1 can be provided by the combustion in the SMR burners (e.g., the combustion chamber may surround the reformer tubes in which the reaction is conducted).|[0076] The syngas produced from Eq. (1) may be further reacted in the WGS 20. The WGS is based on the water gas shift reaction, wherein carbon monoxide is converted to carbon dioxide and hydrogen:|CO+H2O→CO2+H2+small amount of heat (2)|[0077] Providing WGS downstream of SMR increases the yield of H2, and thus is commonly included in hydrogen production. For example, in addition to H2, the syngas produced from the SMR may have a CO2 content between about 7-10%, a CO content between about 12-19%, and a CH4 content between about 2-6%, whereas the syngas produced from the WGS may have a CO2 content between about 15-16%, a CO content between about 4-5%, and a CH4 content between about 3-4%.|[0078] The gas produced from methane reforming (e.g., the syngas 25) is subjected to a hydrogen purification, wherein H2 is separated from CO, CO2, and/or CH4 in one or more stages to produce a hydrogen product (e.g., containing at least 80% hydrogen). For example, in one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 90, 92, 94, 96, 98, 99, or 99.5%. In one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 99.9%. Without being limiting, some examples of suitable hydrogen purification technologies include, but are not limited to: a) absorption, b) adsorption, c) membrane separation, d) cryogenic separation, and e) methanation. Some examples of absorption systems that may be suitable include, but are not limited to, a monoethanolamine (MEA) unit or a methyl-diethanolamine (MDEA) unit. A MEA unit may include one or more absorption columns containing an aqueous solution of MEA at about 30 wt%. The outlet liquid stream of solvent may be treated to regenerate the MEA and separate CO2. Some examples of adsorption systems that may be suitable include, but are not limited to, systems that use adsorbent bed (e.g., molecular sieves, activated carbon, active alumina, or silica gel) to remove impurities such as CH4, CO2, CO, N2, and/or water from the syngas gas. For example, hydrogen purification systems that are based on PSA are commonly used for hydrogen plants, as such systems produces a purge gas that can be recycled to fuel the SMR burners, thereby improving energy efficiency (e.g., see FIG. 1). In one embodiment, hydrogen purification uses vacuum PSA system (VPSA). Some examples of membranes systems that may be suitable include, but are not limited to, H2 selective membranes. A hydrogen purification unit that is based on cryogenic separation may cool the syngas gas down to temperatures where the impurities condense or sublimate and can be separated as a liquid or a solid fraction, while the hydrogen accumulates in the gas phase. For example, cryogenic separations may use temperatures below −10° C. or below −50° C. Methanation is a catalytic process that can be conducted to convert the residual carbon monoxide and/or carbon dioxide in the syngas to methane. For example, see equation 3.|CO+3H→CH4+H2O (3)|Since the methanation reaction consumes hydrogen, a hydrogen purification unit that includes a methanation may include CO2 removal prior to methanation.|[0079] In general, hydrogen production is well known and those skilled in the art will understand that the hydrogen plant(s) may use any suitable technology and/or have any suitable configuration. For example, the hydrogen production may be based on any suitable methane reforming technology combined with any suitable hydrogen purification. With specific regard to FIG. 1, those skilled in the art will understand that each of the SMR unit 10 and WGS unit 20 may include a single reactor or multiple reactors (e.g., the WGS unit 20 may include a high temperature WGS reactor (e.g., 350° C.) followed by a low temperature WGS reactor (e.g., 200° C.)), that the SMR reactor(s) may be top-fired reformers, side-fired reformers, bottom-fired reformers, etc., that the SMR reformer may be downstream of a purification unit to remove sulfur, chloride, olefin, and/or other compounds that may be detrimental to the SMR reforming catalysts, or that the SMR reformer may be downstream a pre-reforming unit, which allows a higher inlet feed temperature with minimal risk of carbon deposition. Those skilled in the art will also understand that although a steam methane reformer may be referred to as a “methane reformer,” typically they can convert any of the hydrocarbons present in the natural gas to syngas (i.e., not just the methane).|[0080] In the above-described embodiments, the feedstock for the hydrogen production process contains the upgraded biogas (e.g., RNG), which can be transported to the hydrogen plant(s) by vehicle and/or as a fungible batch via a natural gas distribution system. In each embodiment, the feedstock may contain only the RNG or may contain both RNG and fossil based gas such as natural gas (e.g., the hydrogen can be produced by co-processing renewable and non-renewable methane). When the feed contains both RNG and fossil based gas, the quantity of renewable hydrogen produced can be determined using the renewable fraction of the feedstock (based on energy).|[0081] In the above-described embodiments, the feedstock for the renewable hydrogen process contains the upgraded biogas. However, in some embodiments, a portion of the upgraded biogas is fed to the combustion zone of the methane reformer (e.g., to the SMR burners). Since combusting upgraded biogas simply returns to the atmosphere carbon that was recently fixed by photosynthesis, and thus is considered relatively benign, this can reduce GHG emissions from the SMR furnace (e.g., compared to using fossil-based methane). Accordingly, the CI of renewable hydrogen produced by SMR of upgraded biogas produced from a landfill, wherein only the CO2 from the feedstock is captured and stored, could be reduced to less than 11 gCO2e/MJ. While it may be advantageous to sacrifice some of the upgraded biogas for fuel in order to improve the GHG balance of the hydrogen production and/or fuel production process, this reduces the yield of renewable hydrogen and/or the yield of renewable content of the fuel(s) produced. Accordingly, there may be a compromise between increasing the yield of renewable hydrogen/renewable content and decreasing the lifecycle GHG emissions, for a given quantity of upgraded biogas. As described herein, the CI can also be reduced to less than 11 gCO2e/MJ by capturing and storing biogenic CO2 from the biogas (e.g., as part of biogas upgrading). In some cases, in order to reduce the GHG emissions of the fuel by feeding upgraded biogas to the SMR burners, the upgraded biogas (or at least the portion fed to the SMR burners) must be transported to hydrogen production as a segregated batch (e.g., this may be dependent on the regulatory agency).|[0082] In certain embodiments, low-carbon electricity such as renewable electricity is used to provide heat for the methane reforming (e.g., for SMR). Low-carbon electricity refers to electricity generated in a process that does not emit significant amounts of fossil-based carbon dioxide and/or is produced from renewable energy sources. Without being limiting, low-carbon electricity can include electricity produced using nuclear power, hydropower, solar power, wind power, geothermal power, wave power, tidal power, or electricity produced from the combustion of a low-carbon energy source (e.g., biomass, biogenic syngas, or hydrogen) or of a fossil-based energy source with CCS. In certain embodiments, heat required for the SMR is generated using renewable electricity (i.e., electricity produced using renewable energy sources such as hydropower, solar power, wind power, geothermal power, wave power, tidal power, etc.). In certain embodiments, the low-carbon electricity is generated from gasification of agricultural and/or solid waste.|[0083] In general, any suitable technology known in the art that can use electricity to produce a sufficient amount of heat for at least part of the methane reforming can be used. The low-carbon electricity can produce the heat for methane reforming directly (e.g., to power resistive or inductive heaters that provide the heat directly for the methane reforming) and/or indirectly (e.g., using a heat storage medium and/or heat transfer fluid). In certain embodiments, the methane reformer (e.g., SMR) is an electrically heated methane reformer (e.g., electrically heated SMR), wherein the heat that would have been generated with conventional fired burners is replaced with electrically generated heat. Such methane reformers are generally configured such that there is no flue gas, and thus no carbon emissions associated with the flue gas (e.g., carbon emissions of hydrogen production may be reduced by 20-50% relative to the conventional fired SMR). In these embodiments, capturing carbon dioxide from the syngas can remove most of the carbon dioxide produced by methane reforming from one point location. Advantageously, these reduced carbon emissions are achieved without having to remove carbon dioxide from the flue gas (e.g., which can have low partial pressures of carbon dioxide and/or include nitrogen).|Carbon Capture and Storage|[0084] Capture of CO2 from the biogas (e.g., generated during anaerobic digestion) and/or capture of CO2 produced during hydrogen production can be conducted using any suitable technology or combination of technologies that can capture CO2 for storage. As the CO2 may be part of a gas mixture (e.g., biogas, syngas, flue gas, etc.), the CO2 capture can include and/or depend upon the separation of CO2 from one or more other gas components in a gas mixture. Technology that may be suitable for separating CO2 from one or more other gas components in a gas mixture includes, but is not limited to, absorption, adsorption, membrane separation, and cryogenic separation.|[0085] The CO2 from the biogas (e.g., generated during anaerobic digestion) can be captured upstream of biogas upgrading, as part of biogas upgrading, and/or from a tail gas produced from biogas upgrading. For example, since biogas upgrading can inherently include steps where CO2 is separated from CH4, such steps can be part of the CO2 capture process, or can facilitate the CO2 capture process, thereby reducing capital and operating costs. Biogas upgrading, which typically focuses on providing a relatively pure product stream (e.g., greater than 95% CH4), can produce a tail gas that contains CO2 separated from the CH4 in addition to other non-methane components separated from the CH4. For example, biogas upgrading units based on absorption, adsorption, or membrane separation, can produce a CO2 rich tail gas that is too impure for CO2 storage and/or transport without further purification and/or upstream removal of one or more components. However, in some cases, biogas upgrading (e.g., based on cryogenic separation), can yield both relatively pure CH4 (e.g., greater than about 95% CH4) and relatively pure CO2 (e.g., greater than about 95% CO2). While cryogenic biogas upgrading may require upstream biogas cleaning, it advantageously can provide the CO2 is a form that facilitates transport by vehicle and/or a CO2 distribution system (e.g., can provide the CO2 in liquid or solid form).|[0086] The CO2 generated during hydrogen production can be captured upstream of hydrogen purification (but downstream of methane reforming), as part of hydrogen purification, from a tail gas produced from hydrogen purification, and/or from the flue gas (if applicable). When hydrogen production includes SMR, the captured CO2 can be derived from the feedstock for SMR and/or the fuel for SMR. For example, the CO2 generated during SMR based hydrogen production can be captured from the syngas, the tail gas (e.g., purge gas from PSA), and/or the flue gas (see FIG. 1). Since hydrogen purification can inherently include steps where CO2 is separated from H2, such steps can be part of the CO2 capture process, or can facilitate the CO2 capture process, thereby reducing capital and operating costs. Hydrogen purification processes based on absorption, adsorption, and/or membrane separation are typically focused on provide a relatively pure product stream (e.g., greater than 95% H2), and often produce a tail gas that contains CO2 separated from the H2 in addition to, for example, CO and CH4. As this tail gas can contain CH4, which can be used to fuel the SMR or elsewhere at the facility, or may need to be flared, the configuration of the system may need to take this into account. In one embodiment, the CO2 produced from hydrogen production is only captured from the flue gas. In one embodiment, the CO2 produced from hydrogen production is only captured from the tail gas (e.g., purge gas). In one embodiment, the CO2 produced from hydrogen production is only captured from the syngas (e.g., downstream of WGS). In one embodiment, the CO2 produced from hydrogen production is captured from the syngas and the flue gas from SMR. Capturing the CO2 produced the syngas is particularly advantageous as a result of the total pressure of the syngas and partial pressure of CO2 in the syngas. Those skilled in the art can readily select suitable technology and/or configurations.|[0087] In one embodiment, the process includes at least one separate CO2 removal step for the CO2 capture (i.e., separate from the biogas upgrading and/or hydrogen production). For example, in one embodiment, a separate CO2 separation is conducted on the tail gas from biogas upgrading and/or on the tail gas from hydrogen purification to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport. In another embodiment, a separate CO2 separation is conducted upstream of biogas upgrading and/or hydrogen purification to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport. For example, in the embodiment illustrated in FIG. 3, the syngas 25 is subjected to a CO2 removal step 40 upstream of the PSA 30, which produces the H2 product 32. The CO2 removal step 40, which may for example be conducted using a MDEA capture unit, provides a CO2 product 42 suitable geological storage and/or transport in a CO2 distribution system (e.g., after dehydration and compression). The PSA 30 is then used to separate the H2 from at least CH4, thereby producing a H2 product 32 and a purge gas 34 that is used to fuel the SMR burners.|[0088] In one embodiment, the biogas upgrading and/or hydrogen purification is conducted in stages and at least one stage of the biogas upgrading and/or hydrogen purification is a CO2 capture step.|[0089] In one embodiment, the CO2 capture step is integrated with the biogas upgrading and/or hydrogen production. For example, in one embodiment, the biogas upgrading and/or hydrogen production is selected to and/or modified to provide a CO2 product suitable for geological storage and/or transport by a CO2 distribution system (e.g., after dehydration and compression). In general, this may be achieved by selecting suitable separation technology and/or modifying the configuration of the system (e.g., removing one or more components upstream of the CO2 separation). For example, in one embodiment, cryogenic CO2 capture is part of biogas upgrading and/or hydrogen purification. When cryogenic separation is used as part of biogas upgrading, the biogas may be cleaned (e.g., to remove H2S and H2O) and then subjected to a cryogenic separation that provides relatively pure CO2 (e.g., >95% CO2) while also providing a relatively pure CH4 (e.g., >95% CH4) and N2 (if present). In one embodiment, vacuum pressure swing adsorption (VPSA) is used for biogas upgrading and/or hydrogen purification. For example, consider the hydrogen production in FIG. 1. If a VPSA unit, which includes a vacuum cycle, replaces the conventional PSA 30, then both H2 purification and CO2 capture can be integrated into a single separation unit. Integrating H2 purification and CO2 capture, and/or CH4 purification and CO2 capture, is particularly advantageous as the separation of CO2 from other gases such as N2, CH4, or H2, which may be present in gas mixtures such as biogas, syngas, flue gas, etc., can be one of the most energy intensive and/or expensive steps in CCS.|[0090] Storage of CO2 captured from the biogas and/or storage of CO2 captured from hydrogen production can be conducted using any suitable technology or combination of technologies. For example, carbon storage technologies, which are well known in the art, can sequester CO2 in geological formations (i.e., subsurface formations). Suitable geological formations, which can occur in onshore or offshore settings, are often configured such that CO2 injected therein, is trapped. Appropriate storage of the CO2 can reduce GHG emissions and/or mitigate climate change. The level of GHG reduction achieved may be dependent on whether it is all biogenic, the applicable regulatory authority, the permanence of the storage, and/or whether its use displaces the use of fossil fuel products. In one embodiment, the captured CO2 is sequestered in at least one geological formation. For example, in one embodiment the captured CO2 is sequestered in a saline aquifer or is sequestered in an oil/natural gas reservoir as part of enhanced oil recovery (EOR). in one embodiment, the captured CO2 is stored in concrete. In one embodiment, storage of the captured CO2 permanently displaces fossil based. CO2 emissions.|[0091] The purity of the CO2 required for storage can be dependent upon the selected storage and/or selected mode of transportation, if applicable. For example, for geological sequestration and/or EOR, where the CO2 is often transported, at least in part, via a CO2 distribution system (e.g., pipeline), the CO2 content should be as high as possible (e.g., at least about 95%). However, for some applications (e.g., bauxite residue carbonation, etc.) lower CO2 contents may be suitable. In addition to a minimum CO2 content, the CO2 provided for storage and/or transport may have limits on the maximum amount of H2O, H2S, CO, CH4, N2, Ar, H2, etc.|[0092] In general, when the CO2 is captured far from storage, the process includes transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). In order to transport CO2 for storage, the CO2 typically requires significant compression and/or cooling. When CO2 is transported by vehicle (e.g., truck, ship, rail car) it is often transported as a liquid (e.g., a pressure of about 290 psig and a temperature of about −20° C., or a pressure of about 100 psig and a temperature of about −50° C.). When CO2 is transported by a CO2 distribution system (e.g., a CO2 pipeline) it is often transported as a supercritical fluid (critical point is ˜31° C., ˜1070 psig). For example, many CO2 pipelines are operated between about 1250 psig and about 2200 psig, or higher. In some embodiments, the collected CO2 is also stored locally at a relatively high pressure (e.g., −1600 psig) prior to transport by pipeline. In general, the CO2 can be compressed to the desired pressure using a gas compressor, or alternatively, the collected CO2 can be liquified at a lower pressure using a refrigeration system (e.g., 235 psig) and then pumped to the desired pressure. In one embodiment, the process produces a compressed stream of relatively pure CO2 (e.g., at least 95% CO2). In one embodiment, the CO2 is transported to storage. at least in part, as a fungible batch using a CO2 distribution system.|[0093] The CO2 captured from the biogas upgrading and from the hydrogen production can be stored together or separately (e.g., in the same geological formation or in different geological formations). In general, how and where the captured CO2 is stored may be dependent upon the closest storage site. In one embodiment, the CO2 captured from the biogas upgrading and from the hydrogen production is, at least in part, transported using a CO2 distribution system. In this embodiment, depending upon the distance between the biogas upgrading and the hydrogen production, the CO2 captured from the biogas upgrading and from the hydrogen production may be injected at the same or different injection points of the CO2 distribution system. For example, consider the embodiment in FIG. 4.|[0094] In FIG. 4, the CO2 captured from hydrogen production 200, which is optionally temporarily stored 320, is compressed (e.g., to 1800 psig) and injected into a first CO2 distribution system at first injection point 322. The CO2 captured from biogas upgrading 100 is compressed and liquified and transported by vehicle (e.g., rail car and/or tanker truck) for injection into the first injection point 322 or a second other injection point 312. The first and second injection points may be on the same CO2 distribution system or different CO2 distribution systems. Once transported, the CO2 from biogas upgrading is unloaded from the vehicle (e.g., using a liquid CO2 pump) into optional temporary storage 310, 320 before compression and injection. Transporting the CO2 (e.g., 150, 250) by vehicle to an injection point of a CO2 distribution system facilitates pooled injection. One skilled in the art would readily select the appropriate configuration in dependent upon distance between the biogas upgrading 100 and hydrogen production 200 and the proximity to a CO2 distribution system.|[0095] In one embodiment, at least 50% of the CO2 from the biogas is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 from the biogas is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 from the syngas is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 produced from hydrogen production is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the each of the CO2 from the biogas and the CO2 from the syngas is captured and stored.|[0096] In one embodiment, the CO2 captured and stored during hydrogen production includes at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the carbon in the transported upgraded biogas provided as feedstock for the methane reforming (on a mass of carbon basis). According to Eqs. (1) and (2), hydrogen production produces 1 mole of CO2 from 1 mole of CH4. If at least 50% of the carbon in the feedstock is captured and stored, then for about every 16 grams of methane provided as feedstock (i.e., 1 mole, containing 12 grams of carbon) at least about 22 grams of CO2 is captured and stored (i.e., at least 0.5 moles, containing 6 grams of carbon, or 50% of the feedstock carbon input).|[0097] One advantage of the process(es)/system(s) of the instant disclosure it that low CI hydrogen can be produced without capturing and storing more than 70% of the CO2 produced during hydrogen production (e.g., only capturing CO2 derived from the feedstock) and/or when capturing less than 90% of the CO2 from the biogas. Rather, negative CI hydrogen can be produced by capturing less than about 60%-65% from hydrogen production and capturing at least 50% of the CO2 from the biogas upgrading, thereby providing a more economically feasible solution. Capturing a lower percentage of the CO2 (e.g., <80%) from at least one of the stages is advantageous as it can be more energy intensive to remove the last 5-10% of a component.|[0098] Additionally, or alternatively, hydrogen can be produced without capturing and storing more than 70% of the CO2 produced during hydrogen production (e.g., only capturing CO2 derived from the feedstock) and/or when capturing less than 90% of the CO2 from the biogas, by providing CCS of carbon obtained or derived from the biomass that is not present as CO2. For example, in certain embodiments, carbon containing material obtained or derived from the digestate from anaerobic digestion of the biomass is provided for storage as part of CCS. In certain embodiments, the digestate is treated prior to CCS. For example, digestate can be subjected to a hydrothermal liquefaction to provide a bio-oil that can be sequestered. In some cases, the sequestration method is selected to prevent biodegradation of the material and/or trap GHGs in the event of biodegradation. In some cases, the material is treated in a process to reduce the potential for biodegradation. The amount of carbon obtained or derived from the digestate and provided as part of CCS can be expressed as kg C per m3 (dry weight). Advantageously, storing a liquid or solid by-product produced from the process as part of CCS can further reduce the carbon intensity of the hydrogen produced and/or a fuel or product produced from the hydrogen. Further advantageously, this three-tiered CCS (e.g., where carbon is captured from the biogas and the digestate and from hydrogen production), can significantly reduce the lifecycle GHG emissions of the renewable hydrogen.|Fuel or Chemical Production|[0099] In general, the process produces renewable hydrogen and/or at least one fuel or chemical product produced using the renewable hydrogen. In one embodiment, the fuel is renewable hydrogen. For example, in one embodiment, the process produces renewable hydrogen that is used to power fuel cell electric vehicles (FCEVs), produce electricity (e.g., at a power plant), or used as rocket fuel. In one embodiment, the process produces fuel or chemical product using the renewable hydrogen. For example, in one embodiment, the process produces methanol using the renewable hydrogen. In one embodiment, the process produces fuel using the renewable hydrogen. For example, in one embodiment, the fuel is gasoline, diesel, and/or jet fuel. In one embodiment, the fuel is an aviation fuel. In one embodiment, the fuel is a transportation fuel. While producing renewable hydrogen for use as a fuel is advantageous, it is particularly advantageous when the renewable hydrogen is used to produce a transportation fuel. For example, using the renewable hydrogen to produce fuel can impart renewable content to the fuel and/or can reduce the CI of the fuel, particularly when the renewable hydrogen has a negative CI.|[0100] In general, the fuel may be produced by processing the renewable hydrogen with one or more other renewable feedstocks or one or more non-renewable feedstocks. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the fuel can have renewable content. The term “renewable content”, as used herein, refers the portion of the fuel(s) that is recognized and/or qualifies as renewable (e.g., a biofuel) under applicable regulations. The quantification of the renewable content can be determined using any suitable method and is typically dependent upon the applicable regulations.|[0101] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon such that the renewable hydrogen is incorporated into a crude-oil derived liquid hydrocarbon to produce gasoline, diesel, and/or jet fuel having renewable content (e.g., see U.S. Pat. Nos. 8,658,026, 8,753,854, 8,945,373, 9,040,271, 10,093,540, 10,421,663, and 10,723,621, 10,981,784). In this embodiment, use of the renewable hydrogen can produce gasoline, diesel, and/or jet fuel having renewal content. Advantageously, such fuels can replace and/or be used with non-renewable gasoline, diesel, and/or jet fuel without affecting performance and/or operation (e.g., are drop-in fuels). Further advantageously, such fuels can be produced at existing oil refineries using existing equipment. The term “crude oil derived liquid hydrocarbon”, as used herein, refers to any carbon-containing material obtained and/or derived from crude oil that is liquid at standard ambient temperature and pressure. The term “crude oil”, as used herein, refers to petroleum extracted from geological formations (e.g., in its unrefined form). Crude oil includes liquid, gaseous, and/or solid carbon-containing material from geological formations, including oil reservoirs, such as hydrocarbons found within rock formations, oil sands, or oil shale. In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon to produce aviation fuel having renewable content. This embodiment is particularly advantageous as it could help decarbonize commercial air travel and/or extend the life of older aircraft types by lowering their carbon footprint.|[0102] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of renewable fats and/or oils (e.g., algae, jatropha, tallows, camelina, pyrolysis oil produced from biomass, etc.) to produce gasoline, diesel, and/or jet fuel. This embodiment is particularly advantageous as the resulting fuel can be fully renewable.|[0103] In general, the renewable hydrogen can be used in any suitable fuel or chemical production process. For example, in one embodiment, the renewable hydrogen is used in a Fischer-Tropsch type process to produce a liquid transportation fuel. In one embodiment, the renewable hydrogen is used as an industrial feedstock to produce one or more fuels and/or chemical products. In one embodiment, the renewable hydrogen is used to produce ammonia (e.g., in a Haber-Bosch process). In the Haber-Bosch process, which is well-known to those skilled in the art, nitrogen is converted to ammonia in a process conducted under high temperatures and pressures with a metal catalyst. Ammonia has an important role in the agricultural industry for production of fertilizers. Ammonia may also be used as a fuel and/or an energy carrier for energy storage and transportation.|[0104] In general, the renewable hydrogen may be produced at a commercial hydrogen plant or at a hydrogen plant at the fuel production facility. In both cases, the renewable hydrogen may be provided for fuel production via a H2 pipeline or local H2 pipe system as a fungible batch. More specifically, the renewable hydrogen may be allocated for the desired use (e.g., a specific fuel production process or a specific hydroprocessing unit). The term “allocating”, as used herein in respect of a particular element, refers to designating the element for a specific purpose.|Carbon Intensity and/or Fuel Credits|[0105] In general, the carbon intensity of the fuel (e.g., renewable hydrogen or fuel produced using the renewable hydrogen) can be negative and/or relatively low because the CO2 from both the biogas and the hydrogen production is captured and stored. While providing a zero carbon hydrogen is generally advantageous, it may be particularly advantageous if the CI is as low as possible when the hydrogen is used as a fuel or to produce a fuel, for fuel credit purposes.|[0106] Fuel credits are used to incentivize renewable fuels, often in the transportation sector. For example, fuel credits can be used to demonstrate compliance with some government initiative, standard, and/or program, where the goal is to reduce GHG emissions (e.g., reduce CI in transportation fuels as compared to some baseline level related to conventional petroleum fuels) and/or produce a certain amount of biofuel (e.g., produce a mandated volume or a certain percentage of biofuels). The target GHG reductions and/or target biofuel amounts may be set per year or for a given target date. Some non-limiting examples of such initiatives, standards, and/or programs include the Renewable Fuel Standard Program (RFS2) in the United States, the Renewable Energy Directive (RED II) in Europe, the Fuel Quality Directive in Europe, the Renewable Transport Fuel Obligation (RTFO) in the United Kingdom, and/or the Low Carbon Fuel Standards (LCFS) in California, Oregon, or British Columbia).|[0107] The term “fuel credit”, as used herein, refers to any rights, credits, revenues, offsets, GHG gas rights, or similar rights related to carbon credits, rights to any GHG gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract, or otherwise. A fuel credit can be a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline (e.g., a gasoline baseline) set by a government authority. Non-limiting examples of fuel credits include RINs and LCFS credits. A Renewable Identification Number (or RIN), which is a certificate that acts as a tradable currency for managing compliance under the RFS2, may be generated for each gallon of biofuel (e.g., ethanol, biodiesel, etc.) produced. A Low Carbon Fuel Standard (LCFS) credit, which is a certificate which acts as a tradable currency for managing compliance under California's LCFS, may be generated for each metric ton (MT) of CO2 reduced.|[0108] In general, the requirements for generating or causing the generation of fuel credits can vary by country, the agency, and or the prevailing regulations in/under which the fuel credit is generated. In many cases, fuel credit generation may be dependent upon a compliance pathway (e.g., predetermined or applied for) and/or the biofuel meeting a predetermined GHG emission threshold. For example, with regard to the former, the RFS2 categorizes biofuel as cellulosic biofuel, advanced biofuel, renewable biofuel, and biomass-based diesel. With regard to the latter, to be a renewable biofuel under the RFS2, corn ethanol should have lifecycle GHG emissions at least 20% lower than an energy-equivalent quantity of gasoline (e.g., 20% lower than the 2005 EPA average gasoline baseline of 93.08 gCO2e/MJ). In low carbon-related fuel standards, biofuels may be credited according to the carbon reductions of their pathway. For example, under California's LCFS, each biofuel is given a CI score indicating their GHG emissions as grams of CO2 equivalent per megajoule (MJ) of fuel, and fuel credits are generated based on a comparison of their emissions reductions to a target or standard that may decrease each year (e.g., in 2019, ethanol was compared to the gasoline average CI of 93.23 gCO2e/MJ), where lower CIs generate proportionally more credits. In one embodiment, the fuel produced is a transportation fuel, and a fuel credit is generated or is caused to be generated. In one embodiment, the transportation fuel and/or renewable content has lifecycle GHG emissions that are at least 20% less than the lifecycle GHG emissions of a gasoline baseline using EPA methodology, preferably at least 50% or 60% less.|[0109] With respect to renewable hydrogen produced according to the instant disclosure, it can be advantageous for the CI of the hydrogen to be as low as possible, particularly when the hydrogen is used as a fuel or to produce a fuel, so that more valuable fuel credits can be generated. In one embodiment, the process produces fuel (i.e., renewable hydrogen or fuel produced using the renewable hydrogen), where the renewable hydrogen has a CI that is not more than −10 gCO2e/MJ, −20 gCO2e/MJ, −30 gCO2e/MJ, −40 gCO2e/MJ, −50 gCO2e/MJ, −60 gCO2e/MJ, or −70 gCO2/MJ of H2. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the CI is measured for the resulting product from each of the co-processed feedstocks (i.e., there is a different CI for each the renewable and non-renewable feedstocks). In one embodiment, the process includes producing hydrogen associated with one or more producer credits. | (US11760630)|TECHNICAL FIELD|[0001] The present disclosure relates to a process and/or system for producing renewable hydrogen, and in particular, to a process and/or system where carbon dioxide from the process is captured and stored.|BACKGROUND|[0002] Hydrogen is largely produced from the processing of fossil fuels. For example, hydrogen is often produced from the steam methane reforming (SMR) of natural gas or the gasification of coal. Unfortunately, the production of hydrogen from fossil fuels is associated with significant greenhouse gas (GHG) emissions, and in particular, with significant carbon dioxide (CO2) emissions.|[0003] One approach to reduce the GHG emissions associated with hydrogen production is to use carbon capture and storage (CCS). CCS may, for example, involve capturing CO2 emissions and storing them underground in suitable geological formations, which is also referred to as carbon sequestration. In integrating CCS with hydrogen production from fossil fuels, the fossil based CO2 produced during the hydrogen production is captured and stored in order to prevent it from being released to the atmosphere, thereby reducing GHG emissions of the process (e.g., a reduction of about 80-90%).|[0004] Another approach to reduce the GHG emissions associated with hydrogen production is to use biomass rather than fossil fuels as feedstock. Such hydrogen, may for example, be produced from the gasification or pyrolysis of biomass, or by reforming biogas produced by the anaerobic digestion of biomass. Any CO2 derived from biomass and produced during such processing is biogenic. As the release of biogenic CO2 to the atmosphere simply returns to the atmosphere carbon that was recently fixed by photosynthesis, biogenic CO2 is generally considered to be carbon neutral (e.g., its release does not result in an increase in net GHG emissions). Accordingly, in integrating CCS with hydrogen production from biomass, where biogenic CO2 produced during the hydrogen production is captured and stored, there is the potential for so-called “negative emissions.”|[0005] Negative emissions can be the basis for BECCS, which stands for bioenergy with carbon capture and storage. For example, in some cases, BECCS, which is a group of technologies that combine extracting bioenergy from biomass with CCS, can be viewed as a process where biomass (e.g., plants) is used to extract CO2 from the atmosphere, the biomass is processed to produce bioenergy (e.g., heat, electricity, fuels) while releasing CO2, and the CO2 produced during the processing is captured and stored such that there is there is a transfer of CO2 from the atmosphere to storage.|[0006] While BECCS is increasing discussed as a means to decrease CO2 emissions and/or CO2 concentrations in the atmosphere, some potential challenges that may hinder its success include 1) energy intensive biomass supply chains, 2) low energy conversion efficiencies, and/or 3) high costs (e.g., incentives and/or funding may be required). With regard to the first two points, it is generally preferable that the process provide a net energy gain (e.g., as opposed to a net energy loss, where the bioenergy provided from the process is lower than the energy put into the process) and/or that the process actually deliver net negative CO2 emissions (e.g., as opposed to net positive emissions, where the CO2 emissions from the bioenergy production process and CCS processes exceed the quantity of CO2 captured and stored). CO2 emissions from the bioenergy production process may arise from any point in the process (e.g., biomass production, transport, conversion, and/or utilization), and may for example, be attributed to non-renewable energy use within the process, waste management, and/or land use changes. With regard to the third point, for established bioenergy technologies, the cost of BECCS may be largely limited by the cost of CCS. Since the cost of CCS is typically scale sensitive, and since the capture of CO2 is often considered to be one of most expensive parts of CCS, BECCS has been generally considered for applications where the CO2 emissions are relatively pure and/or can be captured from a large point source.|[0007] Some potential applications of BECCS have been identified as power stations wherein biomass is combusted (e.g., where biogenic CO2 generated from the combustion process is captured and stored), biogas upgrading processes (e.g., where CO2 separated from the biogas captured and stored), and ethanol production processes (e.g., where CO2 produced by fermentation of corn grain is captured and stored). Unfortunately, at least in part due to one or more of the challenges listed above, BECCS deployment has been slow.|[0008] In terms of hydrogen production, BECCS has been discussed for the generation of hydrogen from the gasification of biomass. Gasification is a process that converts organic or fossil-based carbonaceous materials at high temperatures (>700° C.), without combustion, with a controlled amount of oxygen and/or steam into syngas (i.e., a gas mixture primarily composed of carbon monoxide (CO) and H2 and sometimes CO2). The gasification of biomass, including waste, is an evolving technology for producing hydrogen. In terms of BECCS it has the advantage that it is relatively simple, can be conducted on relatively large scale, and is generally configured such that all of the CO2 produced during the gasification is collected from one point source. Unfortunately, it may require some preprocessing of the feedstock (e.g., drying, grinding, etc.), may require treatment of the syngas to remove contaminants and/or reduce particulate matter emissions, and/or may require a large land footprint (e.g., for on-site storage of feedstock).|[0009] The reforming of biogas for hydrogen production has some advantages over the gasification of biomass, however, in terms of BECCS it is generally more complicated. First, raw biogas is generally regarded as low-quality fuel, which can require upgrading prior to hydrogen production. While biogas upgrading is a proven technology, it can be energy intensive and/or the cost can be a significant deterrent (e.g., in many countries, only a small share of overall biogas output is upgraded, with the remainder used in power generation, co-generation, and/or heat for buildings). Second, biogas plants (i.e., where biogas is upgraded) are often small and located close the source of biogas (e.g., remote locations). The small scale and/or distributed nature typical of biogas plants can make hydrogen production and/or CCS more challenging (e.g., both can be scale sensitive and/or energy intensive). In addition, such processes involve at least two conversions, namely, biomass to upgraded biogas and upgraded biogas to hydrogen, and thus the process is more complicated than the direct gasification of biomass. As a result, the resulting hydrogen may have net positive CO2 emissions.|SUMMARY|[0010] The present disclosure relates to a novel approach to produce renewable hydrogen from biogas, wherein the renewable hydrogen has a negative carbon intensity (CI). In particular, the present disclosure relates to a process(es)/system(s) wherein biogas is upgraded, the upgraded biogas is transported to at least one hydrogen plant, and carbon dioxide from both the biogas upgrading and the hydrogen production is captured and stored. The renewable hydrogen of the present invention can be used for many applications that are known in the art, e.g., for producing fuel, chemical product, fuel or chemical intermediates, or any combination thereof using the renewable hydrogen. For example, in certain embodiments, processes of the instant disclosure produce fuel (e.g., one or more fuels such as hydrogen, gasoline, diesel, jet fuel, methanol, ethanol, etc.), chemical product (e.g., methanol, ammonia, fertilizer, etc.), or intermediates (e.g., methanol, hydrogen, ammonia, ethanol, etc.), and include one or more steps wherein biogas is upgraded, the upgraded biogas is transported to fuel/product production, and carbon dioxide from both the biogas upgrading and the hydrogen production is captured and stored.|[0011] Advantageously, in capturing CO2 at multiple stages in the process, the CO2 capture process at each stage can be optimized for that stage in the process (e.g., bioenergy process), and/or a greater quantity of CO2 can be stored (e.g., relative to capturing CO2 from only one stage). Further advantageously, since the biogas is transported after it is upgraded, the distance between the biogas plant and the hydrogen plant can be increased (e.g., which can increase the number of potential biogas plants that can provide upgraded biogas for the hydrogen production). Accordingly, the present disclosure defies one or more common assumptions for BECCS projects (i.e., that the distance between the biomass source and the bioenergy production should be limited and/or that it is preferable to capture CO2 derived from the biomass from a single, relatively large, point source), while still yielding renewable hydrogen having a negative CI.|[0012] In accordance with one aspect of the instant invention there is provided a process for producing fuel, the fuel selected from renewable hydrogen and fuel produced from renewable hydrogen, the process comprising: providing biogas, the biogas comprising methane and carbon dioxide; removing at least 50% of the carbon dioxide from the biogas, thereby producing upgraded biogas; transporting the upgraded biogas to a hydrogen plant; processing the upgraded biogas at the hydrogen plant to produce syngas, the processing comprising providing the transported upgraded biogas as feedstock for methane reforming, the syngas comprising carbon dioxide and hydrogen; and purifying at least one of the syngas or a stream derived from the syngas to produce a hydrogen product comprising renewable hydrogen, and providing a quantity of the renewable hydrogen for at least one of (i) use as a fuel or (ii) producing a fuel, wherein the process further comprises: capturing and storing a first quantity of carbon dioxide, the carbon dioxide in the first quantity removed from the biogas; and capturing and storing a second quantity of carbon dioxide, the carbon dioxide in the second quantity removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, wherein the quantity of renewable hydrogen has a carbon intensity less than 0 gCO2-eq/MJ, and wherein the carbon intensity is dependent on steps a) and b).|[0013] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen, the process comprising: providing biogas, the biogas comprising methane and carbon dioxide; removing at least 50% of the carbon dioxide from the biogas, thereby producing upgraded biogas; providing the upgraded biogas for transport; providing the transported upgraded biogas as feedstock for methane reforming, thereby producing syngas, the processing comprising the syngas comprising carbon dioxide and hydrogen; and purifying a stream selected from the syngas and a stream derived from the syngas to produce a hydrogen product gas comprising renewable hydrogen, and providing a quantity of the renewable hydrogen, wherein the process further comprises: capturing and storing a first quantity of carbon dioxide, the carbon dioxide in the first quantity removed from the biogas; and capturing and storing a second quantity of carbon dioxide, the carbon dioxide in the second quantity removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, wherein the second quantity of carbon dioxide comprises at least 50% of the carbon dioxide produced from the feedstock from the methane reforming, and wherein the quantity of renewable hydrogen has a carbon intensity less than 0 gCO2-eq/MJ, and wherein the carbon intensity is dependent on steps a) and b).|[0014] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen having low carbon intensity, the process comprising: providing biogas, the biogas comprising methane and carbon dioxide; processing the biogas in a biogas upgrading process to produce upgraded biogas, the biogas upgrading process removing at least 50% of the carbon dioxide from the biogas; providing the upgraded biogas for transport; producing hydrogen from a hydrogen production process, a feedstock for the hydrogen production process comprising the upgraded biogas, the hydrogen production process comprising subjecting the feedstock to methane reforming to produce syngas comprising carbon dioxide and hydrogen, and purifying a stream selected from the syngas and a stream derived from the syngas to produce a hydrogen product gas comprising renewable hydrogen, wherein the process further comprises: capturing and storing a first quantity of carbon dioxide, the carbon dioxide in the first quantity removed from the biogas; and capturing and storing a second quantity of carbon dioxide, the carbon dioxide in the second quantity removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, and wherein the renewable hydrogen has a carbon intensity dependent on steps a) and b).|[0015] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen having low carbon intensity, the process comprising: providing biogas produced from a biogas production process, the biogas comprising methane and carbon dioxide, the biogas production process producing digestate; processing the biogas in a biogas upgrading process to produce upgraded biogas, the biogas upgrading process removing at least 50% of the carbon dioxide from the biogas; producing hydrogen from a hydrogen production process, a feedstock for the hydrogen production process comprising the upgraded biogas, the biogas upgrading process and the hydrogen production process conducted at different geographical locations, the hydrogen production process comprising subjecting the feedstock to methane reforming to produce syngas comprising carbon dioxide and hydrogen, and purifying a stream selected from the syngas and a stream derived from the syngas to produce hydrogen comprising renewable hydrogen, wherein the process further comprises: capturing and storing a first quantity of carbon from the biogas production process, the biogas upgrading process, or a combination thereof; capturing and storing a second quantity of carbon from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas, the second quantity of carbon comprising carbon dioxide, and wherein the renewable hydrogen has a carbon intensity dependent on steps a) and b).|[0016] In accordance with one aspect of the instant invention there is provided a process for producing renewable hydrogen having low carbon intensity, the process comprising: producing hydrogen from a hydrogen production process, a feedstock for the hydrogen production process comprising upgraded biogas, the upgraded biogas produced in a process comprising subjecting biomass to an anaerobic digestion, thereby producing biogas and digestate, the biogas comprising methane and carbon dioxide, subjecting the biogas to biogas upgrading, thereby removing at least 50% of carbon dioxide from the biogas and producing upgraded biogas, transporting the upgraded biogas, and providing carbon containing material derived from the biomass for storage as part of a first carbon capture and storage process, the carbon containing material comprising carbon dioxide from the biogas, carbon containing material obtained or derived from the digestate, or a combination thereof, the hydrogen production process comprising subjecting the feedstock to methane reforming to produce syngas comprising carbon dioxide and hydrogen, purifying a stream selected from the syngas and a stream derived from the syngas to produce hydrogen comprising renewable hydrogen, and providing carbon dioxide produced from hydrogen production for storage as part of a second carbon capture and storage process, wherein a carbon intensity of the renewable hydrogen is reduced as a result of steps (iv) and (c).|(US11760630)|BRIEF DESCRIPTION OF THE DRAWINGS|[0017] FIG. 1 is a simplified process flow diagram of one embodiment of an SMR based hydrogen plant;|[0018] FIG. 2 is a simplified process flow diagram illustrating an embodiment wherein biogas is upgraded, the upgraded biogas is converted to hydrogen, and CO2 from both the biogas upgrading and hydrogen production is captured and stored;|[0019] FIG. 3 is a simplified process flow diagram of another embodiment of an SMR based hydrogen plant; and|[0020] FIG. 4 is a schematic diagram illustrating how the CO2 captured from the biogas upgrading and hydrogen production can be stored by injection into the same injection point of a CO2 distribution system or using different injection points of the same or different CO2 distribution systems.|(US11760630)|DETAILED DESCRIPTION|[0021] Certain exemplary embodiments of the invention now will be described in more detail, with reference to the drawings, in which like features are identified by like reference numerals. The invention may, however, be embodied in many different forms and should not be construed as limited to the embodiments set forth herein.|[0022] The terminology used herein is for the purpose of describing certain embodiments only and is not intended to be limiting of the invention. For example, as used herein, the singular forms “a,” “an,” and “the” may include plural references unless the context clearly dictates otherwise. The terms “comprises”, “comprising”, “including”, and/or “includes”, as used herein, are intended to mean “including but not limited to.” The term “and/or”, as used herein, is intended to refer to either or both of the elements so conjoined. The phrase “at least one” in reference to a list of one or more elements, is intended to refer to at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements. Thus, as a non-limiting example, the phrase “at least one of A and B” may refer to at least one A with no B present, at least one B with no A present, or at least one A and at least one B in combination. In the context of describing the combining of components by the “addition” or “adding” of one component to another, or the separating of components by the “removal” or “removing” of one component from another, those skilled in the art will understand that the order of addition/removal is not critical (unless stated otherwise). The terms “remove”, “removing”, and “removal”, with reference to one or more impurities, contaminants, and/or constituents of biogas, includes partial removal. The terms “cause” or “causing”, as used herein, may include arranging or bringing about a specific result (e.g., a withdrawal of a gas), either directly or indirectly, or to play a role in a series of activities through commercial arrangements such as a written agreement, verbal agreement, or contract. The term “associated with”, as used herein with reference to two elements (e.g., a fuel credit associated with the transportation fuel), is intended to refer to the two elements being connected with each other, linked to each other, related in some way, dependent upon each other in some way, and/or in some relationship with each other. The terms “first”, “second”, etc., may be used to distinguish one element from another, and these elements should not be limited by these terms. The term “plurality”, as used herein, refers to two or more. The term “providing” as used herein with respect to an element, refers to directly or indirectly obtaining the element and/or making the element available for use. The terms “upstream” and “downstream”, as used herein, refer to the disposition of a step/stage in the process with respect to the disposition of other steps/stages of the process. For example, the term upstream can be used to describe to a step/stage that occurs at an earlier point of the process, whereas the term downstream can be used to describe a step/stage that occurs later in the process. Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art.|[0023] The term “biomass”, as used herein, refers to organic material originating from plants, animals, or micro-organisms (e.g., including plants, agricultural crops or residues, municipal wastes, and algae). Biomass is a renewable resource, which can be naturally replenished on a human timescale, and which can be used to produce bioenergy and/or biofuels (e.g., biogas).|[0024] The term “biogas”, as used herein, refers to a gas mixture that contains methane produced from biomass. While biogas is predominately produced from the anaerobic digestion (AD) of biomass, it is also possible to produce biogas from the gasification of biomass. For example, the gasification of biomass may produce syngas, which may be cleaned up, and methanated. When produced from the anaerobic digestion of biomass, raw biogas typically includes methane (CH4), carbon dioxide (CO2), and can contain water (H2O), nitrogen (N2), hydrogen sulfide (H2S), ammonia (NH3), oxygen (O2), volatile organic compounds (VOCs), and/or siloxanes, depending up its source. The term biogas, as used herein, can refer to raw biogas, cleaned biogas, or upgraded biogas.|[0025] The term “raw biogas”, as used herein, refers to biogas as obtained from its source (e.g., anaerobic digester or landfill) before it is treated to remove any chemical components (e.g., CO2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates). Raw biogas can be subjected to biogas cleaning to produce cleaned biogas or subjected to biogas upgrading to produce upgraded biogas.|[0026] The term “biogas cleaning”, as used herein refers to a process where biogas (e.g., raw biogas) is treated to remove one or more components (e.g., H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), but does not remove a significant amount of CO2 and/or N2 (e.g., the calorific value of the biogas may not change significantly as a result of biogas cleaning).|[0027] The term “biogas upgrading”, as used herein, refers to a process where biogas (e.g., raw or cleaned biogas) is treated to remove one or more components (e.g., CO2, N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), wherein the treatment increases the calorific value of the biogas. For example, biogas upgrading typically includes removing CO2 and/or N2. Biogas upgrading, which can include biogas cleaning, produces upgraded biogas. The term “upgraded biogas”, as used herein, can refer to a partially purified biogas (i.e., requires further treatment in order to meet applicable specifications) or renewable natural gas (RNG).|[0028] The term “renewable natural gas” or “RNG”, as used herein, refers to biogas that has been upgraded to meet or exceed applicable natural gas pipeline specifications, meet or exceed applicable quality specifications for vehicle use (e.g., CNG specifications), and/or natural gas withdrawn from a natural gas distribution system that is associated with the environmental attributes of biogas injected into the natural gas distribution system (e.g., a gas that qualifies as RNG under applicable regulations). For example, the term RNG can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of RNG, upgraded from biogas, that was injected into the natural gas distribution system. Pipeline specifications include specifications required for biogas for injection into a natural gas distribution system. Pipeline quality standards or specifications may vary by region and/or country in terms of value and units. For example, pipelines standards may require the RNG to have a CH4 level that is at least 95% or have a heating value of at least 950 BTU/scf. The percentages used to quantify gas composition and/or a specific gas content, as used herein, are expressed as mol%, unless otherwise specified. More specifically, they are expressed by mole fraction at standard temperature and pressure (STP), which is equivalent to volume fraction.|[0029] The term “natural gas” or “NG”, as used herein, refers a gas mixture rich in hydrocarbons, where the primary component is CH4. The term “gas” or “gas mixture”, as used herein, refers to a fluid that is gaseous at standard temperatures and pressures, unless indicated otherwise.|[0030] The term “environmental attributes”, as used herein with regard to a specific material (e.g., biogas), refers to any and all attributes related to the material, including all rights, credits, benefits, or payments associated with the renewable nature of the material and/or the reduction in or avoidance of fossil fuel consumption or reduction in lifecycle GHG gas emissions associated with the use of the material. Some non-limiting examples of environmental attributes include verified emission reductions, voluntary emission reductions, offsets, allowances, credits, avoided compliance costs, emission rights and authorizations, certificates, voluntary carbon units, under any law or regulation, or any emission reduction registry, trading system, or reporting or reduction program for GHG gas emissions that is established, certified, maintained, or recognized by any international, governmental, or nongovernmental agency.|[0031] The terms “capturing and storing”, as used herein with reference to CO2, refers to capturing the CO2 and storing the captured CO2 to prevent the captured CO2, or an equal quantity of CO2 displaced physically by the captured CO2, from being released to the atmosphere. Capturing the CO2 can include removing CO2 from a gas mixture (e.g., biogas, syngas) using any suitable separation technology, or if the CO2 is relatively pure, capturing the CO2 can simply refer to collecting the CO2 (e.g., in a pipe). Storing the captured CO2 can include sequestering it underground (e.g., trapping it in geological formations, such as saline aquifers, or using it for enhanced oil recovery (EOR)), or can include storing the captured CO2 in one or more products (e.g., using the captured CO2 as a resource to create valuable products such plastics, concrete, etc.). For example, “capturing and storing CO2” can be part of one or more processes commonly referred to as “carbon capture and sequestration”, “carbon capture and utilization” or CCU, or “carbon capture, utilization and storage” or CCUS. In most cases, capturing and storing CO2 also includes compressing the captured CO2 (e.g., to produce liquid CO2 or for injection into a CO2 distribution system) and transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). As will be understood by those skilled in the art, it can be advantageous to store the captured CO2 using a method recognized by the applicable regulatory authority for reducing GHG emissions and/or mitigating climate change.|[0032] The term “carbon intensity” or “CI” refers to the quantity of lifecycle GHG emissions, per unit of fuel energy, and is often expressed in grams of CO2 equivalent emissions per unit of fuel (e.g., gCO2e/MJ or gCO2e/MMBTU). As will be understood by those skilled in the art, CI is often determined using Lifecycle Analysis (LCA), which identifies and estimates all GHG emissions in producing a fuel/product (e.g., renewable hydrogen), from the growing or extraction of raw materials, to the production of the fuel/product, through to the end use of the fuel/product (e.g., well-to-wheel). Those skilled in the art will understand that CI values for a given fuel/product can be dependent on the LCA methodology used (e.g., as required by the applicable regulatory authority). Methodologies for calculating carbon intensities and/or lifecycle GHG emissions according to various regulatory bodies are well known in the art and can be readily calculated by those of ordinary skill in the art. The CI values recited herein are determined using the CA-GREET 3.0 model (e.g., see, https://ww2.arb.ca.gov/resources/documents/lcfs-life-cycle-analysis-models-and-documentation), unless otherwise specified.|[0033] The present disclosure relates to producing renewable hydrogen having a negative CI from biogas, which can be used as fuel, as industrial feedstock (e.g., to produce fuel, fuel intermediates, or chemical products), or in fuel cells (e.g., to generate heat and/or electricity). For example, hydrogen is commonly used in oil refining, ammonia production, methanol production, and steel production.|[0034] Raw biogas produced from the anaerobic digestion of biomass can have a significant CO2 content (e.g., about 35%), which reduces the calorific value of the biogas (i.e., relative to pure methane). As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings. Alternatively, raw or cleaned biogas can be upgraded (e.g., to RNG) and used as a substitute for fossil based natural gas (e.g., used as a transportation fuel in the form of compressed RNG (bio-CNG) or liquefied RNG (bio-LNG)).|[0035] As a substitute for fossil based natural gas, upgraded biogas (e.g., RNG) may be used to produce renewable hydrogen using any technology suitable for converting natural gas to hydrogen (e.g., methane reforming). Renewable hydrogen, which can be used as a fuel in gas or liquid form, is very versatile as it can be used as a fuel, converted into electricity, and/or converted to one or more fuels. For example, renewable hydrogen can power fuel cell electric vehicles (FCEVs), which emit no tailpipe emissions other than water, or can be run through a fuel cell to power the electricity grid. Alternatively, renewable hydrogen can be used to produce liquid fuels (e.g., gasoline, diesel, jet fuel) that are renewable and/or have renewable content.|[0036] Converting upgraded biogas (e.g., RNG) to renewable hydrogen by SMR is advantageous in that it exploits technology that is well established for natural gas. Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations. While the relatively small scale and/or remote locations may be advantageous when the goal is to produce a grid of hydrogen refueling stations for FCEVs (e.g., where multiple geographically spaced small scale hydrogen plants can avoid transport and storage problems with hydrogen), such distributed hydrogen production cannot take advantage of economies of scale (e.g., SMR based hydrogen production is more economical when operated at a large scale), and thus is more expensive. Given the low value of raw biogas, the relatively small scale of many biogas plants, the cost of biogas upgrading, and/or the cost of SMR, it may be challenging to find facility owners willing to collect biogas and convert it to hydrogen, particularly since other uses of biogas are more economical.|[0037] It may be particularly challenging to find facility owners further willing to integrate CCS with such processes. Distributed carbon capture may be considered unfavorable compared to centralized large-scale carbon capture. For example, the cost of CCS is typically scale sensitive, and since distributed hydrogen production is generally small scale, the cost of CCS for distributed hydrogen production may be prohibitive. In addition, a lack infrastructure (e.g., CO2 pipelines) and/or space-consuming CO2 purification and capture equipment may be a deterrent for distributed CCS.|[0038] While large-scale CCS has been demonstrated for SMR plants that process fossil based natural gas, it is not cheap, and is not necessarily simple. For example, consider the hydrogen plant illustrated in FIG. 1. A stream of preheated natural gas 1 is desulfurized (not shown) and fed, along with steam 2, into the reactor tubes for the SMR 10, which contain the reforming catalyst. Streams of natural gas 3 and combustion air 4 are fed into the SMR burners, which provide the heat required for the endothermic reforming reaction. The syngas 15 produced from the SMR is fed to water gas shift (WGS) 20 to produce more hydrogen. The resulting syngas 25, which may also be referred to as shifted gas, is cooled (not shown) and purified using pressure swing adsorption (PSA) 30, which produces a stream enriched in hydrogen 32 and a purge stream 34. The purge stream 34, which may contain unconverted CH4, H2, CO2, and/or CO, is fed back to SMR 10, where it is used to provide process heat for the SMR (e.g., fuel the SMR burners). More specifically, the purge stream 34 is combusted together with the stream of natural gas 3.|[0039] In the hydrogen production process illustrated in FIG. 1, there are two sources of CO2, namely, CO2 produced from the feedstock 1 for the SMR (e.g., CO2 in the syngas 25), which can make up about 60% of the total CO2 produced, and CO2 produced from the fuel 3 for SMR (e.g., CO2 in the flue gas 12), which can make up about 40% of the total CO2 produced, depending upon the configuration of the hydrogen plant. In terms of capturing CO2, there are various options of how and where the CO2 may be captured, each with different energy requirements and/or yields. FIG. 1 identifies three possible options.|[0040] The first option, which is labelled A, captures CO2 from the flue gas 12, and thus captures both CO2 from the feedstock and CO2 from the fuel (e.g., may capture up to about 90% of the total CO2 produced). The second option, which is labelled B, captures CO2 from the syngas 25, and thus captures only the CO2 from the feedstock (e.g., about 60% of the CO2). The third option, which is labelled C, captures CO2 from the purge gas 34, and thus also captures only the CO2 from the feedstock. While the first option theoretically can capture more CO2 from the hydrogen production, capturing carbon dioxide from the syngas 25 (e.g., using vacuum pressure swing adsorption (VPSA) or an absorption amine unit) or from the purge gas 34 (e.g., using an activated amine process) may be more technically and/or economically feasible. For example, relative to the syngas 25, the flue gas may have a relatively low CO2 concentration (e.g., relatively low partial pressure) and/or may be at a lower pressure (e.g., atmospheric). In addition, the flue gas may contain N2 (N2-CH4 separations may be more challenging than CO2-CH4 separations).|[0041] In general, the SMR of fossil based natural gas to produce hydrogen can produce significant GHG emissions. While cooling of the syngas can allow heat recovery back into the process (e.g., steam generation and boiler feed water pre-heating), thereby preventing GHG emissions that would be associated with the heat, the resulting hydrogen can still have a high CI. For example, hydrogen produced from the SMR of fossil based natural gas, which is often referred to as “grey hydrogen,” may have a CI of about 100 gCO2e/MJ. When CCS is integrated with the SMR of fossil based natural gas, the resulting hydrogen it is often referred to as “blue hydrogen.” As will be understood by those skilled in the art, the CI of blue hydrogen is dependent on both the hydrogen production and how much of the fossil based CO2 is captured and stored. For example, in the case where only the CO2 from the feedstock is captured and stored (i.e., not the flue gas), blue hydrogen may have a CI of about 45 gCO2e/MJ.|[0042] As discussed herein, another approach to reduce the CI of hydrogen is to use a renewable feedstock (e.g., use RNG instead of fossil based natural gas), thereby producing renewable hydrogen. The CI of renewable hydrogen produced by the SMR of RNG can be dependent on the CI of the RNG, which can be dependent upon its source. For example, compared to the CI of fossil based natural gas, which can be about 80 gCO2e/MJ, RNG produced from a landfill may have a CI of about 46 gCO2e/MJ, whereas RNG produced from manure may have a CI of about −271 gCO2e/MJ of CH4 (e.g., as a result of avoided GHG emissions). Assuming that fossil based natural gas is used to fuel the SMR (e.g., fuel stream 3 is fossil based natural gas), the CI of renewable hydrogen produced by the SMR of landfill based RNG may be about 65 gCO2e/MJ (e.g., higher than blue hydrogen). If this process is integrated with CCS, wherein only the CO2 from the feedstock is captured and stored, the renewable hydrogen may have a CI of about 11 gCO2e/MJ. Such calculations are discussed in further detail with regard to Table 1. For comparative purposes, the CI of compressed H2 from electrolysis run with green electricity, which can be referred to as “green hydrogen”, may be less than 10 gCO2e/MJ.|[0043] While a CI of about 10 gCO2e/MJ is generally preferable to 100 gCO2e/MJ, it would be advantageous to provide renewable hydrogen having a lower CI, and in particular, a negative CI. In theory, the CI of renewable hydrogen produced by the SMR of RNG produced from a landfill may be able to be reach below 10 gCO2e/MJ if the CO2 from the flue gas is also, or alternatively, captured. However, capturing CO2 from the flue gas can be costly. Additionally, or alternatively, the CI of the renewable hydrogen produced by the SMR of RNG may reach below 10 gCO2e/MJ if the feedstock for producing the RNG is manure (e.g., CH4 having a CI of about −271 gCO2e/MJ). Unfortunately, biogas production from manure can be more costly and/or may be associated with a limited supply (e.g., relative to landfill gas).|[0044] The present disclosure relates to at least one process/system wherein the CI of renewable hydrogen is low as a result of capturing and storing CO2 not only from the hydrogen production (e.g., from the feedstock and/or fuel) but also from the biogas upgrading. Accordingly, the renewable hydrogen can have a negative CI regardless of whether the biogas is generated from a landfill or from manure and/or whether the CO2 is collected from the flue gas of the SMR. For example, consider the schematic diagram illustrated in FIG. 2.|[0045] Referring to FIG. 2, biomass is converted to biogas at biogas production 50. Biogas production 50 provides biogas from at least one biogas source 50, (e.g., a landfill or anaerobic digester). The biogas (e.g., raw or cleaned) is subjected to biogas upgrading 100. The biogas upgrading 100 can be conducted at or near at the biogas source 50, (e.g., at a biogas plant at the landfill or farm) or can be conducted at a centralized biogas upgrading facility that also processes biogas from other biogas sources (e.g., 50ii). The upgraded biogas (e.g., RNG) 125 is transported to hydrogen production 200 (e.g., to a commercial hydrogen plant or a hydrogen plant at a fuel production facility). Hydrogen production 200 converts at least a portion of the upgraded biogas (e.g., RNG) to renewable hydrogen (e.g., via SMR). The renewable hydrogen in the H2 product 275 can be used as a transportation fuel (e.g., direct combustion or in a fuel cell), used for generating electricity (e.g., in a fuel cell), and/or used as an industrial feedstock (e.g., to produce a fuel such as a transportation fuel).|[0046] At least a portion of the CO2 from the biogas (e.g., generated during anaerobic digestion) 150, and at least a portion of the CO2 produced from hydrogen production 250, is captured and provided for storage 300. In general, the upgraded biogas 125 may be transported to hydrogen production 200 and the CO2 150, 250 may be transported to storage 300 (if required) using any suitable mode of transportation, including transport by pipeline and/or vehicle (e.g., ship, rail car, truck). For example, in one particularly advantageous embodiment, the upgraded biogas 125 is injected into a natural gas distribution system near the biogas upgrading 100 and is withdrawn from the same natural gas distribution system for hydrogen production 200 (e.g., is transported as a fungible batch to the hydrogen plant and/or fuel production facility). In general, the CO2 captured from the biogas upgrading 150 and from the hydrogen production 250 can be stored together or separately. For example, the CO2 captured from the biogas upgrading 150 may be used for CCSU, while the CO2 captured from the hydrogen production 250 may be used for CCS. In some embodiments, the CO2 captured from the biogas upgrading 150 and from the hydrogen production 250 are transported to storage, at least in part, using one or more CO2 distribution systems. For example, in one particularly advantageous embodiment, the captured CO2 (e.g., 150 and/or 250) is injected into a CO2 distribution system for transport and is withdrawn from the same CO2 distribution system for storage (e.g., is transported as a fungible batch(es) to storage). CO2 distributions systems, which typically transfer large quantities of CO2 by pipeline, are increasingly used to facilitate enhanced oil recovery (EOR).|[0047] Although this process relies on at least two CO2 capture steps, which are often considered to be energy-consuming steps, there are various advantages and/or synergetic benefits of using this process for producing renewable hydrogen.|[0048] For example, compare the process discussed with reference to FIG. 2 to the gasification of biomass. Biomass gasification may offer large scale centralized hydrogen production, facilitates collecting the biogenic carbon dioxide from one point source, and avoids some intermediate steps (e.g., the conversion of biomass to biogas and biogas upgrading). Nevertheless, there are challenges to hydrogen production via biomass gasification, many of which relate to the costs associated with capital equipment and biomass feedstocks. A facility producing 100 tonnes of hydrogen per day may be very large (e.g., require 1,350 dry tonnes of biomass feedstock per day), and thus may not be feasible based on regional supplies. Smaller facilities may be more feasible from a feedstock availability perspective but may drive up the capital expenditures. The cost of the biomass feedstocks can be dependent on costs for storage and transportation of the biomass, the latter of which may be dependent on the collection radius. Feedstock costs may be modest where agricultural residues can be collected and transported over short distances, but can be high when significant transport distances are involved, at least in part due to the low energy density of biomass.|[0049] Alternatively, compare the process discussed with reference to FIG. 2 to the SMR of biogas, wherein biomass is transported to a centralized processing facility that conducts the anaerobic digestion, biogas upgrading, and hydrogen production (i.e., upgraded biogas is not transported). As with the gasification of biomass, the feedstock costs for such a process can be largely dependent on the storage and transportation of the biomass. When the feedstock has a large moisture content (e.g., manure or food waste) the transportation cost may be even higher.|[0050] In contrast, in the process illustrated in FIG. 2, the upgraded biogas is transported for hydrogen production (i.e., biogas upgrading 100 and hydrogen production 200 are conducted at different locations). Transporting upgraded biogas over extended distances can be more cost efficient than transporting feedstock for anaerobic digestion and/or gasification. In particular, upgraded biogas such as RNG may be transported using any method suitable for transporting natural gas (e.g., a truck designed for transporting liquified natural gas (LNG) or compressed natural gas (CNG), the latter of which is often transported at pressures above about 3600 psig (24.8 MPa)). Transporting the upgraded biogas as bio-LNG or bio-CNG allows more MJ to be delivered per truck (e.g., relative to biomass for gasification or anaerobic digestion) and/or can increase the collection radius for the renewable feedstock. Alternatively, or additionally, the upgraded biogas can be transported by pipeline (e.g., in a natural gas distribution system such as the US natural gas grid), where it is transported as a fungible batch.|[0051] Transporting the upgraded biogas via a natural gas distribution system is particularly advantageous. In particular, it is a cost effective method that uses existing infrastructure, and depending upon the applicable regulatory agency, may have only a small penalty (cost and/or GHG emissions) for transporting the upgraded biogas over extended distances. Accordingly, the collection zone for the renewable feedstock is not limited to the area around a centralized facility conducting anaerobic digestion, biogas upgrading, and hydrogen production, but rather can include any area that provides feedstock for biogas production, where the biogas production is near the natural gas distribution system or can be economically transported to an injection point of the natural gas distribution system. This can increase the area from which the feedstock is collected, thereby making more feedstock available for the process and increasing the feasible scale of the renewable hydrogen production and/or CCS. Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).|[0052] Co-processing renewable and non-renewable feedstock can increase the possible scale of hydrogen production and/or CCS (e.g., biogenic and fossil CO2 can be captured and stored together), can facilitate using existing hydrogen plant(s) configured to process natural gas, and/or can reduce operational complications associated with intermittent renewable feedstock supply (e.g., cold start-up times may be between about 15 and 24 hours). Accordingly, the costs of hydrogen production and/or CCS can be reduced. In addition to the economies of scale, the costs of CCS may be reduced when the hydrogen plant is in close proximity to a CO2 pipeline.|[0053] Advantageously, providing multiple CO2 capture steps (e.g., the disaggregation of CO2 capture processes) for CO2 storage allows each capture process to be optimized for that stage of the process (e.g., bioenergy process). For example, since biogas upgrading typically includes separating CO2 from CH4, many biogas upgrading technologies can include CO2 capture, can be readily modified to include CO2 capture, or may facilitate CO2 capture, thereby reducing costs of at least one CO2 capture step.|[0054] Further advantageously, providing multiple CO2 capture steps, each at a different stage of the process, can result in the renewable hydrogen having not only a negative CI, but a CI that is not higher than −10 gCO2e/MJ, −20 gCO2e/MJ, −30 gCO2e/MJ, −40 gCO2e/MJ, −50 gCO2e/MJ, −60 gCO2e/MJ, or −70 gCO2/MJ of H2. For example, consider the example where biogas having a CH4 content of about 60% and a CO2 content of about 40% is upgraded and subjected to SMR to produce hydrogen. Even if 100% of the CO2 generated from the hydrogen production is captured and stored (i.e., from feedstock and fuel), without capturing the CO2 from the biogas upgrading, a lot of the carbon from the biogas will be released to the atmosphere as CO2 (e.g., 40% of the biogas on a volume basis, or about 65% of the biogas on a mass basis). While providing a zero carbon hydrogen is generally advantageous, it may be particularly advantageous if the CI is as low as possible when the hydrogen is used as a fuel or to produce a fuel, for fuel credit purposes.|[0055] Further details about the biogas production 50, the biogas upgrading 100, hydrogen production 200, capture and/or storage 300, and optional fuel production and/or fuel credits, are discussed below.|Biogas Production|[0056] In general, the biogas can be produced from any suitable biomass. For example, the biogas can be produced from the anaerobic digestion of any suitable feedstock. Anaerobic digestion, which refers to the biological breakdown of organic matter by anaerobic microorganisms, is typically conducted in anaerobic or low oxygen conditions, and may involve a series of microorganism types and processes (e.g., hydrolysis, acidogenesis, acetogenesis, and methanogenesis).|[0057] In one embodiment, the biogas is produced from the anaerobic digestion of any suitable feedstock, where the feedstock is and/or comprises: (i) an energy crop (e.g., switchgrass, sorghum, etc.); (ii) residues, byproducts, or waste from the processing of plant material in a facility, or feedstock derived therefrom (e.g., sugarcane bagasse, sugarcane tops/leaves, corn stover, etc.); (iii) agricultural residues (e.g., wheat straw, corn cobs, barley straw, corn stover, etc.); (iv) forestry material; (v) pulp and paper residues; and/or (vi) municipal waste or components removed or derived from municipal waste. In one embodiment, the feedstock for the anaerobic digestion is or includes cellulosic and/or lignocellulosic material(s).|[0058] In one embodiment, the biogas is produced from the anaerobic digestion of “organic waste.” Using organic waste as the feedstock for anaerobic digestion is particularly advantageous. Organic waste, may for example, include the organic fraction of municipal solid waste (MSW), sludge from a wastewater treatment plant (WWTP), manure from a livestock farm (e.g., a dairy or swine farm), or food or yard waste collected from households, restaurants, supermarkets, food-processing companies, schools, businesses, etc. In one embodiment, the feedstock for the anaerobic digestion is manure (e.g., swine or dairy) or other farm waste, the organic fraction of MSW, or agricultural residues (e.g., straw, stover, etc.).|[0059] The composition of biogas produced from anaerobic digestion can be dependent upon the feedstock. For example, although biogas produced from anaerobic digestion generally has a CH4 content between about 35% and 75% (e.g., about 60%) and a CO2 content between about 15% and 65% (e.g., about 35%), the CH4 content can tend towards the high end of this range when the feedstock is agricultural waste (e.g., between about 50% and 75%) and towards the low end of this range when the feedstock is the organic fraction of municipal solid waste (e.g., between about 25% and 65%). In addition to CH4 and CO2 biogas produced from anaerobic digestion may also include N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates, in dependence upon its source. For example, biogas produced from a landfill often has a higher N2 content than biogas produced in anaerobic digester. In one embodiment, the raw biogas has a CH4 content between about 25% and 75% and a CO2 content between about 15% and 65%, and the CO2 and CH4 make up at least 75% of the biogas by volume.|[0060] The anaerobic digestion of the feedstocks (e.g., solid or liquid) can be conducted in any suitable environment, including a natural environment (e.g., a landfill) or a controlled environment (e.g., an anaerobic digester). An anaerobic digester can be a holding tank, or another contained volume, such as a covered lagoon or sealed structure, configured to facilitate the breakdown of organic material by microorganisms under anaerobic or low oxygen conditions. Anaerobic digestion may be carried out in one or multiple anaerobic digesters connected in series and/or parallel, where each digester may be a single-stage or multi-stage digestion system, and/or may be designed and/or operated in a number of configurations including batch or continuous, mesophilic or thermophilic temperature ranges, and low, medium, or high rates. The term “anaerobic digester”, as used herein, can refer to plurality of fluidly connected anaerobic digesters. The operation of an anaerobic digester may be dependent on nature of the organic matter fed to the anaerobic digester and/or the level of digestion required. The appropriate selection of operating parameters, including but not limited to residence time, temperature, pH, and/or the nutrients supplied, will be known to those skilled in the art.|[0061] When conducted in one or more anaerobic digesters, the anaerobic digestion of biomass also produces a potentially usable digestate. Digestate refers to the material remaining after one or more stages of the anaerobic digestion (e.g., may refer to acidogenic digestate, methanogenic digestate, or a combination thereof). Digestate can include organic material not digested by the anaerobic microorganisms, by-products of the anaerobic digestion released by the microorganisms, and/or the microorganisms themselves. For example, the digestate can include carbohydrates, nutrients (such as nitrogen compounds and phosphates), other organics, and/or wild yeasts. The composition of digestate can vary depending on the biomass from which it is derived. Digestate often has both a solid and liquid component. A common use of digestate is as a soil conditioner, where it can provide nutrients for plant growth and/or displace the use of fossil-based fertilizers. In one embodiment, the digestate is processed to provide carbon-containing material that is stored as part of CCS.|[0062] In general, the biogas can be produced from one or more sources (e.g., one or more landfills and/or anaerobic digesters). In one embodiment, the biogas is produced from a single biogas source. In one embodiment, the biogas is produced from multiple biogas sources.|Biogas Upgrading|[0063] In general, the biogas produced from the feedstock(s) is upgraded in one or more stages to provide upgraded biogas (i.e., prior to transport to hydrogen production). Biogas upgrading, which increases the calorific value of the biogas, typically provides a CH4-rich gas having a CH4 content of at least 90%. In one embodiment, the upgraded biogas has a CH4 content of at least 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95%, at least 96%, at least 97%, or at least at least 98%. It can be particularly advantageous to produce upgraded biogas having a CH4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system. In one embodiment, the biogas upgrading produces RNG. In one embodiment, the biogas upgrading produces biogas having a CH4 content of at least 95%. In one embodiment, the biogas upgrading produces biogas having a heating value of at least 950 BTU/ft3.|[0064] Biogas upgrading can be conducted using any suitable technology or combination of technologies that can separate CH4 from one or more non-methane components in the biogas (e.g., CO2, N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates). For example, biogas upgrading technologies are often based on absorption, adsorption, membrane separation, and/or cryogenic separation. As will be understood by those skilled in the art, the technology used for the biogas upgrading can be dependent up the composition of the biogas and the desired purity of the upgraded biogas.|[0065] As biogas typically has a significant CO2 content, biogas plants often include at least one system for separating CH4 from CO2. Some examples of technologies that can remove CO2 from biogas include, but are not limited to, absorption (e.g., water scrubbing, organic physical scrubbing, chemical scrubbing), adsorption (e.g., pressure swing adsorption (PSA)), membrane separation (e.g., CO2 selective membranes based on polyimide, polysulfone, cellulose acetate, polydimethylsiloxane), and cryogenic separation.|[0066] While some CO2 removal systems may remove one or more other non-methane components in addition to CO2 (e.g., N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates), biogas plants often include one or more other systems (e.g., dehydration units, H2S removal units, N2 rejection units, etc.). For example, some CO2 removal systems require that the biogas be cleaned upstream of CO2 removal (e.g., remove impurities that can negatively affect the CO2 removal unit. Alternatively, or additionally, the biogas can be cleaned and/or upgraded downstream of CO2 removal. In general, the non-methane components can be removed by any combination of chemical and/or physical technologies, in one or more stages. For example. H2O may be removed using a standard biogas dehumidifier, whereas H2S may be removed using a commercial H2S removal unit (e.g., based on activated carbon, molecular sieve, iron sponge, water scrubbing, NaOH washing, and/or biofilter or biotrickling filter technologies). In some cases, one stage may remove more than one non-methane component. For example. in some cases, some H2S may also be removed during the water removal step.|[0067] In general, the biogas upgrading can be conducted close to the biogas source (e.g., at a biogas plant at the landfill site or near the anaerobic digester) or at a centralized biogas plant (e.g., which receives raw, cleaned, or partially purified biogas from multiple sources). For example, a centralized biogas plant may be connected to one or more anaerobic digesters (e.g., each at a separate farm) via a biogas pipeline and/or grid. Alternatively, or additionally, the centralized biogas plant may receive biogas from one or more biogas sources by vehicle (e.g., see U.S. Pat. No. 10,760,024). In one embodiment, the biogas source is a centralized anaerobic digester, wherein the feedstock for anaerobic digestion is transported from multiple locations (e.g., multiple farms).|[0068] The upgraded biogas is transported to hydrogen production (e.g., to a stand-alone hydrogen plant or to a production facility having at least one hydrogen plant). As the upgraded biogas may be relatively pure (e.g., have a CH4 content greater than about 92%), it may be transported using methods used to transport natural gas. For example, if the biogas is upgraded to RNG it can be transported in a CNG tanker (e.g., at a pressure of about 3600 psig) and/or transported by pipeline (e.g., a natural gas distribution system such as the US natural gas grid). In some cases, upgraded biogas that does not meet pipeline standards can be mixed with another gas (e.g., propane or fossil based natural gas) in order to facilitate injection into the natural gas distribution system.|[0069] In general, when upgraded biogas is transported by pipeline, it is transferred as a fluid (e.g., in gaseous or liquid form), and may be provided as a segregated batch or a fungible batch. The term “batch”, as used herein, refers to a certain amount of the gas (e.g., energy delivered) and does not imply or exclude an interruption in the production and/or delivery.|[0070] When upgraded biogas is transported as a fungible batch in a natural gas distribution system, a quantity of the upgraded biogas (e.g., in MJ) is injected into the natural gas distribution system (optionally after being blended with another gas having a relatively high calorific value), where it can comingle with non-renewable natural gas, and an equivalent quantity of gas (e.g., in MJ) is withdrawn at another location (i.e., as long as there is a physical link between the injection point and the withdrawal point). Since the transfer or allocation of the environmental attributes of the upgraded biogas injected into the natural gas distribution system to gas withdrawn at a different location is typically recognized, the withdrawn gas is recognized as the upgraded biogas and/or qualifies as RNG under applicable regulations (e.g., even though the withdrawn gas may not contain actual molecules from the original biomass and/or contains methane from fossil sources). Such transfer may be carried out on a displacement basis, where transactions within the natural gas distribution system involve a matching and balancing of inputs and outputs. Typically, the direction of the physical flow of gas is not considered. Establishing that a gas is recognized as and/or qualifies as RNG (e.g., originates from renewable sources) under applicable regulations can depend on whether the gas is transported by truck or by pipeline and the practices and requirements of the applicable regulatory agency, where such practices may include, for example, the use of chain of custody accounting methods such as identity preservation, book-and-claim, and/or mass balance.|[0071] Transporting the upgraded biogas via a natural gas grid is particularly advantageous as it facilitates transporting the renewable feedstock anywhere where the grid delivers without significant additional cost (e.g., financially and/or GHG emissions). In one embodiment, the upgraded biogas is transported to hydrogen production, at least in part, via a natural gas distribution system. In one embodiment, the upgraded production is transported to hydrogen production, at least in part, by vehicle.|Hydrogen Production|[0072] In general, the renewable hydrogen may be produced at one or more hydrogen plants. The term “hydrogen plant”, as used herein, refers to a system or combination of systems primarily used for hydrogen production. The term “renewable hydrogen”, as used herein, refers to hydrogen produced using biogas (e.g., upgraded biogas and/or RNG). For example, the term “renewable hydrogen” can refer to hydrogen produced by methane reforming a feed withdrawn from a natural gas distribution system, when at least a portion of the withdrawn feed is recognized as and/or qualifies as RNG under applicable regulations.|[0073] In general, the hydrogen production may use any suitable technology known in the art that can convert upgraded biogas and/or natural gas to hydrogen. Examples of technologies that may be suitable include, but are not limited to, steam methane reforming (SMR), autothermal reforming (ATR), partial oxidation (PDX), and dry methane reforming (DMR). SMR, ATR, and DMR, which are types of catalytic reforming, may operate by exposing natural gas to a catalyst at high temperature and pressure to produce syngas. PDX reactions, which include thermal partial oxidation reactions (TPDX) and catalytic partial oxidation reactions (CPDX), may occur when a sub-stoichiometric fuel-oxygen mixture is partially combusted in a reformer. PDX also may be referred to as oxidative reforming. For purposes herein, the term “methane reforming” may refer to SMR, ATR, DMR, or PDX.|[0074] Of the various types of methane reforming, SMR is the most common. In SMR, which is an endothermic process, methane is reacted with steam under pressure in the presence of a catalyst to produce carbon monoxide (CO) and H2 according to the following reaction:|CH4+H2O+heat→CO+3H2 (1)|[0075] Referring to the hydrogen plant in FIG. 1, this reaction may occur in the SMR reactor tubes, which contain the reforming catalyst. Without being limiting, the catalyst may be nickel-based, the operating pressure may be between 200 psig (1.38 MPa) and 600 psig (4.14 MPa), and the operating temperature may be between about 450 to 1000° C. The heat required for the catalytic reforming of Eq. 1 can be provided by the combustion in the SMR burners (e.g., the combustion chamber may surround the reformer tubes in which the reaction is conducted).|[0076] The syngas produced from Eq. (1) may be further reacted in the WGS 20. The WGS is based on the water gas shift reaction, wherein carbon monoxide is converted to carbon dioxide and hydrogen:|CO+H2O→CO2+H2+small amount of heat (2)|[0077] Providing WGS downstream of SMR increases the yield of H2, and thus is commonly included in hydrogen production. For example, in addition to H2, the syngas produced from the SMR may have a CO2 content between about 7-10%, a CO content between about 12-19%, and a CH4 content between about 2-6%, whereas the syngas produced from the WGS may have a CO2 content between about 15-16%, a CO content between about 4-5%, and a CH4 content between about 3-4%.|[0078] The gas produced from methane reforming (e.g., the syngas 25) is subjected to a hydrogen purification, wherein H2 is separated from CO, CO2, and/or CH4 in one or more stages to produce a hydrogen product (e.g., containing at least 80% hydrogen). For example, in one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 90, 92, 94, 96, 98, 99, or 99.5%. In one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 99.9%. Without being limiting, some examples of suitable hydrogen purification technologies include, but are not limited to: a) absorption, b) adsorption, c) membrane separation, d) cryogenic separation, and e) methanation. Some examples of absorption systems that may be suitable include, but are not limited to, a monoethanolamine (MEA) unit or a methyl-diethanolamine (MDEA) unit. A MEA unit may include one or more absorption columns containing an aqueous solution of MEA at about 30 wt%. The outlet liquid stream of solvent may be treated to regenerate the MEA and separate CO2. Some examples of adsorption systems that may be suitable include, but are not limited to, systems that use adsorbent bed (e.g., molecular sieves, activated carbon, active alumina, or silica gel) to remove impurities such as CH4, CO2, CO, N2, and/or water from the syngas gas. For example, hydrogen purification systems that are based on PSA are commonly used for hydrogen plants, as such systems produces a purge gas that can be recycled to fuel the SMR burners, thereby improving energy efficiency (e.g., see FIG. 1). In one embodiment, hydrogen purification uses vacuum PSA system (VPSA). Some examples of membranes systems that may be suitable include, but are not limited to, H2 selective membranes. A hydrogen purification unit that is based on cryogenic separation may cool the syngas gas down to temperatures where the impurities condense or sublimate and can be separated as a liquid or a solid fraction, while the hydrogen accumulates in the gas phase. For example, cryogenic separations may use temperatures below −10° C. or below −50° C. Methanation is a catalytic process that can be conducted to convert the residual carbon monoxide and/or carbon dioxide in the syngas to methane. For example, see equation 3.|CO+3H→CH4+H2O (3)|Since the methanation reaction consumes hydrogen, a hydrogen purification unit that includes a methanation may include CO2 removal prior to methanation.|[0079] In general, hydrogen production is well known and those skilled in the art will understand that the hydrogen plant(s) may use any suitable technology and/or have any suitable configuration. For example, the hydrogen production may be based on any suitable methane reforming technology combined with any suitable hydrogen purification. With specific regard to FIG. 1, those skilled in the art will understand that each of the SMR unit 10 and WGS unit 20 may include a single reactor or multiple reactors (e.g., the WGS unit 20 may include a high temperature WGS reactor (e.g., 350° C.) followed by a low temperature WGS reactor (e.g., 200° C.)), that the SMR reactor(s) may be top-fired reformers, side-fired reformers, bottom-fired reformers, etc., that the SMR reformer may be downstream of a purification unit to remove sulfur, chloride, olefin, and/or other compounds that may be detrimental to the SMR reforming catalysts, or that the SMR reformer may be downstream a pre-reforming unit, which allows a higher inlet feed temperature with minimal risk of carbon deposition. Those skilled in the art will also understand that although a steam methane reformer may be referred to as a “methane reformer,” typically they can convert any of the hydrocarbons present in the natural gas to syngas (i.e., not just the methane).|[0080] In the above-described embodiments, the feedstock for the hydrogen production process contains the upgraded biogas (e.g., RNG), which can be transported to the hydrogen plant(s) by vehicle and/or as a fungible batch via a natural gas distribution system. In each embodiment, the feedstock may contain only the RNG or may contain both RNG and fossil based gas such as natural gas (e.g., the hydrogen can be produced by co-processing renewable and non-renewable methane). When the feed contains both RNG and fossil based gas, the quantity of renewable hydrogen produced can be determined using the renewable fraction of the feedstock (based on energy).|[0081] In the above-described embodiments, the feedstock for the renewable hydrogen process contains the upgraded biogas. However, in some embodiments, a portion of the upgraded biogas is fed to the combustion zone of the methane reformer (e.g., to the SMR burners). Since combusting upgraded biogas simply returns to the atmosphere carbon that was recently fixed by photosynthesis, and thus is considered relatively benign, this can reduce GHG emissions from the SMR furnace (e.g., compared to using fossil-based methane). Accordingly, the CI of renewable hydrogen produced by SMR of upgraded biogas produced from a landfill, wherein only the CO2 from the feedstock is captured and stored, could be reduced to less than 11 gCO2e/MJ. While it may be advantageous to sacrifice some of the upgraded biogas for fuel in order to improve the GHG balance of the hydrogen production and/or fuel production process, this reduces the yield of renewable hydrogen and/or the yield of renewable content of the fuel(s) produced. Accordingly, there may be a compromise between increasing the yield of renewable hydrogen/renewable content and decreasing the lifecycle GHG emissions, for a given quantity of upgraded biogas. As described herein, the CI can also be reduced to less than 11 gCO2e/MJ by capturing and storing biogenic CO2 from the biogas (e.g., as part of biogas upgrading). In some cases, in order to reduce the GHG emissions of the fuel by feeding upgraded biogas to the SMR burners, the upgraded biogas (or at least the portion fed to the SMR burners) must be transported to hydrogen production as a segregated batch (e.g., this may be dependent on the regulatory agency).|[0082] In certain embodiments, low-carbon electricity such as renewable electricity is used to provide heat for the methane reforming (e.g., for SMR). Low-carbon electricity refers to electricity generated in a process that does not emit significant amounts of fossil-based carbon dioxide and/or is produced from renewable energy sources. Without being limiting, low-carbon electricity can include electricity produced using nuclear power, hydropower, solar power, wind power, geothermal power, wave power, tidal power, or electricity produced from the combustion of a low-carbon energy source (e.g., biomass, biogenic syngas, or hydrogen) or of a fossil-based energy source with CCS. In certain embodiments, heat required for the SMR is generated using renewable electricity (i.e., electricity produced using renewable energy sources such as hydropower, solar power, wind power, geothermal power, wave power, tidal power, etc.). In certain embodiments, the low-carbon electricity is generated from gasification of agricultural and/or solid waste.|[0083] In general, any suitable technology known in the art that can use electricity to produce a sufficient amount of heat for at least part of the methane reforming can be used. The low-carbon electricity can produce the heat for methane reforming directly (e.g., to power resistive or inductive heaters that provide the heat directly for the methane reforming) and/or indirectly (e.g., using a heat storage medium and/or heat transfer fluid). In certain embodiments, the methane reformer (e.g., SMR) is an electrically heated methane reformer (e.g., electrically heated SMR), wherein the heat that would have been generated with conventional fired burners is replaced with electrically generated heat. Such methane reformers are generally configured such that there is no flue gas, and thus no carbon emissions associated with the flue gas (e.g., carbon emissions of hydrogen production may be reduced by 20-50% relative to the conventional fired SMR). In these embodiments, capturing carbon dioxide from the syngas can remove most of the carbon dioxide produced by methane reforming from one point location. Advantageously, these reduced carbon emissions are achieved without having to remove carbon dioxide from the flue gas (e.g., which can have low partial pressures of carbon dioxide and/or include nitrogen).|Carbon Capture and Storage|[0084] Capture of CO2 from the biogas (e.g., generated during anaerobic digestion) and/or capture of CO2 produced during hydrogen production can be conducted using any suitable technology or combination of technologies that can capture CO2 for storage. As the CO2 may be part of a gas mixture (e.g., biogas, syngas, flue gas, etc.), the CO2 capture can include and/or depend upon the separation of CO2 from one or more other gas components in a gas mixture. Technology that may be suitable for separating CO2 from one or more other gas components in a gas mixture includes, but is not limited to, absorption, adsorption, membrane separation, and cryogenic separation.|[0085] The CO2 from the biogas (e.g., generated during anaerobic digestion) can be captured upstream of biogas upgrading, as part of biogas upgrading, and/or from a tail gas produced from biogas upgrading. For example, since biogas upgrading can inherently include steps where CO2 is separated from CH4, such steps can be part of the CO2 capture process, or can facilitate the CO2 capture process, thereby reducing capital and operating costs. Biogas upgrading, which typically focuses on providing a relatively pure product stream (e.g., greater than 95% CH4), can produce a tail gas that contains CO2 separated from the CH4 in addition to other non-methane components separated from the CH4. For example, biogas upgrading units based on absorption, adsorption, or membrane separation, can produce a CO2 rich tail gas that is too impure for CO2 storage and/or transport without further purification and/or upstream removal of one or more components. However, in some cases, biogas upgrading (e.g., based on cryogenic separation), can yield both relatively pure CH4 (e.g., greater than about 95% CH4) and relatively pure CO2 (e.g., greater than about 95% CO2). While cryogenic biogas upgrading may require upstream biogas cleaning, it advantageously can provide the CO2 is a form that facilitates transport by vehicle and/or a CO2 distribution system (e.g., can provide the CO2 in liquid or solid form).|[0086] The CO2 generated during hydrogen production can be captured upstream of hydrogen purification (but downstream of methane reforming), as part of hydrogen purification, from a tail gas produced from hydrogen purification, and/or from the flue gas (if applicable). When hydrogen production includes SMR, the captured CO2 can be derived from the feedstock for SMR and/or the fuel for SMR. For example, the CO2 generated during SMR based hydrogen production can be captured from the syngas, the tail gas (e.g., purge gas from PSA), and/or the flue gas (see FIG. 1). Since hydrogen purification can inherently include steps where CO2 is separated from H2, such steps can be part of the CO2 capture process, or can facilitate the CO2 capture process, thereby reducing capital and operating costs. Hydrogen purification processes based on absorption, adsorption, and/or membrane separation are typically focused on provide a relatively pure product stream (e.g., greater than 95% H2), and often produce a tail gas that contains CO2 separated from the H2 in addition to, for example, CO and CH4. As this tail gas can contain CH4, which can be used to fuel the SMR or elsewhere at the facility, or may need to be flared, the configuration of the system may need to take this into account. In one embodiment, the CO2 produced from hydrogen production is only captured from the flue gas. In one embodiment, the CO2 produced from hydrogen production is only captured from the tail gas (e.g., purge gas). In one embodiment, the CO2 produced from hydrogen production is only captured from the syngas (e.g., downstream of WGS). In one embodiment, the CO2 produced from hydrogen production is captured from the syngas and the flue gas from SMR. Capturing the CO2 produced the syngas is particularly advantageous as a result of the total pressure of the syngas and partial pressure of CO2 in the syngas. Those skilled in the art can readily select suitable technology and/or configurations.|[0087] In one embodiment, the process includes at least one separate CO2 removal step for the CO2 capture (i.e., separate from the biogas upgrading and/or hydrogen production). For example, in one embodiment, a separate CO2 separation is conducted on the tail gas from biogas upgrading and/or on the tail gas from hydrogen purification to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport. In another embodiment, a separate CO2 separation is conducted upstream of biogas upgrading and/or hydrogen purification to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport. For example, in the embodiment illustrated in FIG. 3, the syngas 25 is subjected to a CO2 removal step 40 upstream of the PSA 30, which produces the H2 product 32. The CO2 removal step 40, which may for example be conducted using a MDEA capture unit, provides a CO2 product 42 suitable geological storage and/or transport in a CO2 distribution system (e.g., after dehydration and compression). The PSA 30 is then used to separate the H2 from at least CH4, thereby producing a H2 product 32 and a purge gas 34 that is used to fuel the SMR burners.|[0088] In one embodiment, the biogas upgrading and/or hydrogen purification is conducted in stages and at least one stage of the biogas upgrading and/or hydrogen purification is a CO2 capture step.|[0089] In one embodiment, the CO2 capture step is integrated with the biogas upgrading and/or hydrogen production. For example, in one embodiment, the biogas upgrading and/or hydrogen production is selected to and/or modified to provide a CO2 product suitable for geological storage and/or transport by a CO2 distribution system (e.g., after dehydration and compression). In general, this may be achieved by selecting suitable separation technology and/or modifying the configuration of the system (e.g., removing one or more components upstream of the CO2 separation). For example, in one embodiment, cryogenic CO2 capture is part of biogas upgrading and/or hydrogen purification. When cryogenic separation is used as part of biogas upgrading, the biogas may be cleaned (e.g., to remove H2S and H2O) and then subjected to a cryogenic separation that provides relatively pure CO2 (e.g., >95% CO2) while also providing a relatively pure CH4 (e.g., >95% CH4) and N2 (if present). In one embodiment, vacuum pressure swing adsorption (VPSA) is used for biogas upgrading and/or hydrogen purification. For example, consider the hydrogen production in FIG. 1. If a VPSA unit, which includes a vacuum cycle, replaces the conventional PSA 30, then both H2 purification and CO2 capture can be integrated into a single separation unit. Integrating H2 purification and CO2 capture, and/or CH4 purification and CO2 capture, is particularly advantageous as the separation of CO2 from other gases such as N2, CH4, or H2, which may be present in gas mixtures such as biogas, syngas, flue gas, etc., can be one of the most energy intensive and/or expensive steps in CCS.|[0090] Storage of CO2 captured from the biogas and/or storage of CO2 captured from hydrogen production can be conducted using any suitable technology or combination of technologies. For example, carbon storage technologies, which are well known in the art, can sequester CO2 in geological formations (i.e., subsurface formations). Suitable geological formations, which can occur in onshore or offshore settings, are often configured such that CO2 injected therein, is trapped. Appropriate storage of the CO2 can reduce GHG emissions and/or mitigate climate change. The level of GHG reduction achieved may be dependent on whether it is all biogenic, the applicable regulatory authority, the permanence of the storage, and/or whether its use displaces the use of fossil fuel products. In one embodiment, the captured CO2 is sequestered in at least one geological formation. For example, in one embodiment the captured CO2 is sequestered in a saline aquifer or is sequestered in an oil/natural gas reservoir as part of enhanced oil recovery (EOR). in one embodiment, the captured CO2 is stored in concrete. In one embodiment, storage of the captured CO2 permanently displaces fossil based. CO2 emissions.|[0091] The purity of the CO2 required for storage can be dependent upon the selected storage and/or selected mode of transportation, if applicable. For example, for geological sequestration and/or EOR, where the CO2 is often transported, at least in part, via a CO2 distribution system (e.g., pipeline), the CO2 content should be as high as possible (e.g., at least about 95%). However, for some applications (e.g., bauxite residue carbonation, etc.) lower CO2 contents may be suitable. In addition to a minimum CO2 content, the CO2 provided for storage and/or transport may have limits on the maximum amount of H2O, H2S, CO, CH4, N2, Ar, H2, etc.|[0092] In general, when the CO2 is captured far from storage, the process includes transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). In order to transport CO2 for storage, the CO2 typically requires significant compression and/or cooling. When CO2 is transported by vehicle (e.g., truck, ship, rail car) it is often transported as a liquid (e.g., a pressure of about 290 psig and a temperature of about −20° C., or a pressure of about 100 psig and a temperature of about −50° C.). When CO2 is transported by a CO2 distribution system (e.g., a CO2 pipeline) it is often transported as a supercritical fluid (critical point is ˜31° C., ˜1070 psig). For example, many CO2 pipelines are operated between about 1250 psig and about 2200 psig, or higher. In some embodiments, the collected CO2 is also stored locally at a relatively high pressure (e.g., −1600 psig) prior to transport by pipeline. In general, the CO2 can be compressed to the desired pressure using a gas compressor, or alternatively, the collected CO2 can be liquified at a lower pressure using a refrigeration system (e.g., 235 psig) and then pumped to the desired pressure. In one embodiment, the process produces a compressed stream of relatively pure CO2 (e.g., at least 95% CO2). In one embodiment, the CO2 is transported to storage. at least in part, as a fungible batch using a CO2 distribution system.|[0093] The CO2 captured from the biogas upgrading and from the hydrogen production can be stored together or separately (e.g., in the same geological formation or in different geological formations). In general, how and where the captured CO2 is stored may be dependent upon the closest storage site. In one embodiment, the CO2 captured from the biogas upgrading and from the hydrogen production is, at least in part, transported using a CO2 distribution system. In this embodiment, depending upon the distance between the biogas upgrading and the hydrogen production, the CO2 captured from the biogas upgrading and from the hydrogen production may be injected at the same or different injection points of the CO2 distribution system. For example, consider the embodiment in FIG. 4.|[0094] In FIG. 4, the CO2 captured from hydrogen production 200, which is optionally temporarily stored 320, is compressed (e.g., to 1800 psig) and injected into a first CO2 distribution system at first injection point 322. The CO2 captured from biogas upgrading 100 is compressed and liquified and transported by vehicle (e.g., rail car and/or tanker truck) for injection into the first injection point 322 or a second other injection point 312. The first and second injection points may be on the same CO2 distribution system or different CO2 distribution systems. Once transported, the CO2 from biogas upgrading is unloaded from the vehicle (e.g., using a liquid CO2 pump) into optional temporary storage 310, 320 before compression and injection. Transporting the CO2 (e.g., 150, 250) by vehicle to an injection point of a CO2 distribution system facilitates pooled injection. One skilled in the art would readily select the appropriate configuration in dependent upon distance between the biogas upgrading 100 and hydrogen production 200 and the proximity to a CO2 distribution system.|[0095] In one embodiment, at least 50% of the CO2 from the biogas is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 from the biogas is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 from the syngas is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 produced from hydrogen production is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the each of the CO2 from the biogas and the CO2 from the syngas is captured and stored.|[0096] In one embodiment, the CO2 captured and stored during hydrogen production includes at least 50%, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the carbon in the transported upgraded biogas provided as feedstock for the methane reforming (on a mass of carbon basis). According to Eqs. (1) and (2), hydrogen production produces 1 mole of CO2 from 1 mole of CH4. If at least 50% of the carbon in the feedstock is captured and stored, then for about every 16 grams of methane provided as feedstock (i.e., 1 mole, containing 12 grams of carbon) at least about 22 grams of CO2 is captured and stored (i.e., at least 0.5 moles, containing 6 grams of carbon, or 50% of the feedstock carbon input).|[0097] One advantage of the process(es)/system(s) of the instant disclosure it that low CI hydrogen can be produced without capturing and storing more than 70% of the CO2 produced during hydrogen production (e.g., only capturing CO2 derived from the feedstock) and/or when capturing less than 90% of the CO2 from the biogas. Rather, negative CI hydrogen can be produced by capturing less than about 60%-65% from hydrogen production and capturing at least 50% of the CO2 from the biogas upgrading, thereby providing a more economically feasible solution. Capturing a lower percentage of the CO2 (e.g., <80%) from at least one of the stages is advantageous as it can be more energy intensive to remove the last 5-10% of a component.|[0098] Additionally, or alternatively, hydrogen can be produced without capturing and storing more than 70% of the CO2 produced during hydrogen production (e.g., only capturing CO2 derived from the feedstock) and/or when capturing less than 90% of the CO2 from the biogas, by providing CCS of carbon obtained or derived from the biomass that is not present as CO2. For example, in certain embodiments, carbon containing material obtained or derived from the digestate from anaerobic digestion of the biomass is provided for storage as part of CCS. In certain embodiments, the digestate is treated prior to CCS. For example, digestate can be subjected to a hydrothermal liquefaction to provide a bio-oil that can be sequestered. In some cases, the sequestration method is selected to prevent biodegradation of the material and/or trap GHGs in the event of biodegradation. In some cases, the material is treated in a process to reduce the potential for biodegradation. The amount of carbon obtained or derived from the digestate and provided as part of CCS can be expressed as kg C per m3 (dry weight). Advantageously, storing a liquid or solid by-product produced from the process as part of CCS can further reduce the carbon intensity of the hydrogen produced and/or a fuel or product produced from the hydrogen. Further advantageously, this three-tiered CCS (e.g., where carbon is captured from the biogas and the digestate and from hydrogen production), can significantly reduce the lifecycle GHG emissions of the renewable hydrogen.|Fuel or Chemical Production|[0099] In general, the process produces renewable hydrogen and/or at least one fuel or chemical product produced using the renewable hydrogen. In one embodiment, the fuel is renewable hydrogen. For example, in one embodiment, the process produces renewable hydrogen that is used to power fuel cell electric vehicles (FCEVs), produce electricity (e.g., at a power plant), or used as rocket fuel. In one embodiment, the process produces fuel or chemical product using the renewable hydrogen. For example, in one embodiment, the process produces methanol using the renewable hydrogen. In one embodiment, the process produces fuel using the renewable hydrogen. For example, in one embodiment, the fuel is gasoline, diesel, and/or jet fuel. In one embodiment, the fuel is an aviation fuel. In one embodiment, the fuel is a transportation fuel. While producing renewable hydrogen for use as a fuel is advantageous, it is particularly advantageous when the renewable hydrogen is used to produce a transportation fuel. For example, using the renewable hydrogen to produce fuel can impart renewable content to the fuel and/or can reduce the CI of the fuel, particularly when the renewable hydrogen has a negative CI.|[0100] In general, the fuel may be produced by processing the renewable hydrogen with one or more other renewable feedstocks or one or more non-renewable feedstocks. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the fuel can have renewable content. The term “renewable content”, as used herein, refers the portion of the fuel(s) that is recognized and/or qualifies as renewable (e.g., a biofuel) under applicable regulations. The quantification of the renewable content can be determined using any suitable method and is typically dependent upon the applicable regulations.|[0101] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon such that the renewable hydrogen is incorporated into a crude-oil derived liquid hydrocarbon to produce gasoline, diesel, and/or jet fuel having renewable content (e.g., see U.S. Pat. Nos. 8,658,026, 8,753,854, 8,945,373, 9,040,271, 10,093,540, 10,421,663, and 10,723,621, 10,981,784). In this embodiment, use of the renewable hydrogen can produce gasoline, diesel, and/or jet fuel having renewal content. Advantageously, such fuels can replace and/or be used with non-renewable gasoline, diesel, and/or jet fuel without affecting performance and/or operation (e.g., are drop-in fuels). Further advantageously, such fuels can be produced at existing oil refineries using existing equipment. The term “crude oil derived liquid hydrocarbon”, as used herein, refers to any carbon-containing material obtained and/or derived from crude oil that is liquid at standard ambient temperature and pressure. The term “crude oil”, as used herein, refers to petroleum extracted from geological formations (e.g., in its unrefined form). Crude oil includes liquid, gaseous, and/or solid carbon-containing material from geological formations, including oil reservoirs, such as hydrocarbons found within rock formations, oil sands, or oil shale. In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon to produce aviation fuel having renewable content. This embodiment is particularly advantageous as it could help decarbonize commercial air travel and/or extend the life of older aircraft types by lowering their carbon footprint.|[0102] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of renewable fats and/or oils (e.g., algae, jatropha, tallows, camelina, pyrolysis oil produced from biomass, etc.) to produce gasoline, diesel, and/or jet fuel. This embodiment is particularly advantageous as the resulting fuel can be fully renewable.|[0103] In general, the renewable hydrogen can be used in any suitable fuel or chemical production process. For example, in one embodiment, the renewable hydrogen is used in a Fischer-Tropsch type process to produce a liquid transportation fuel. In one embodiment, the renewable hydrogen is used as an industrial feedstock to produce one or more fuels and/or chemical products. In one embodiment, the renewable hydrogen is used to produce ammonia (e.g., in a Haber-Bosch process). In the Haber-Bosch process, which is well-known to those skilled in the art, nitrogen is converted to ammonia in a process conducted under high temperatures and pressures with a metal catalyst. Ammonia has an important role in the agricultural industry for production of fertilizers. Ammonia may also be used as a fuel and/or an energy carrier for energy storage and transportation.|[0104] In general, the renewable hydrogen may be produced at a commercial hydrogen plant or at a hydrogen plant at the fuel production facility. In both cases, the renewable hydrogen may be provided for fuel production via a H2 pipeline or local H2 pipe system as a fungible batch. More specifically, the renewable hydrogen may be allocated for the desired use (e.g., a specific fuel production process or a specific hydroprocessing unit). The term “allocating”, as used herein in respect of a particular element, refers to designating the element for a specific purpose.|Carbon Intensity and/or Fuel Credits|[0105] In general, the carbon intensity of the fuel (e.g., renewable hydrogen or fuel produced using the renewable hydrogen) can be negative and/or relatively low because the CO2 from both the biogas and the hydrogen production is captured and stored. While providing a zero carbon hydrogen is generally advantageous, it may be particularly advantageous if the CI is as low as possible when the hydrogen is used as a fuel or to produce a fuel, for fuel credit purposes.|[0106] Fuel credits are used to incentivize renewable fuels, often in the transportation sector. For example, fuel credits can be used to demonstrate compliance with some government initiative, standard, and/or program, where the goal is to reduce GHG emissions (e.g., reduce CI in transportation fuels as compared to some baseline level related to conventional petroleum fuels) and/or produce a certain amount of biofuel (e.g., produce a mandated volume or a certain percentage of biofuels). The target GHG reductions and/or target biofuel amounts may be set per year or for a given target date. Some non-limiting examples of such initiatives, standards, and/or programs include the Renewable Fuel Standard Program (RFS2) in the United States, the Renewable Energy Directive (RED II) in Europe, the Fuel Quality Directive in Europe, the Renewable Transport Fuel Obligation (RTFO) in the United Kingdom, and/or the Low Carbon Fuel Standards (LCFS) in California, Oregon, or British Columbia).|[0107] The term “fuel credit”, as used herein, refers to any rights, credits, revenues, offsets, GHG gas rights, or similar rights related to carbon credits, rights to any GHG gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract, or otherwise. A fuel credit can be a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline (e.g., a gasoline baseline) set by a government authority. Non-limiting examples of fuel credits include RINs and LCFS credits. A Renewable Identification Number (or RIN), which is a certificate that acts as a tradable currency for managing compliance under the RFS2, may be generated for each gallon of biofuel (e.g., ethanol, biodiesel, etc.) produced. A Low Carbon Fuel Standard (LCFS) credit, which is a certificate which acts as a tradable currency for managing compliance under California's LCFS, may be generated for each metric ton (MT) of CO2 reduced.|[0108] In general, the requirements for generating or causing the generation of fuel credits can vary by country, the agency, and or the prevailing regulations in/under which the fuel credit is generated. In many cases, fuel credit generation may be dependent upon a compliance pathway (e.g., predetermined or applied for) and/or the biofuel meeting a predetermined GHG emission threshold. For example, with regard to the former, the RFS2 categorizes biofuel as cellulosic biofuel, advanced biofuel, renewable biofuel, and biomass-based diesel. With regard to the latter, to be a renewable biofuel under the RFS2, corn ethanol should have lifecycle GHG emissions at least 20% lower than an energy-equivalent quantity of gasoline (e.g., 20% lower than the 2005 EPA average gasoline baseline of 93.08 gCO2e/MJ). In low carbon-related fuel standards, biofuels may be credited according to the carbon reductions of their pathway. For example, under California's LCFS, each biofuel is given a CI score indicating their GHG emissions as grams of CO2 equivalent per megajoule (MJ) of fuel, and fuel credits are generated based on a comparison of their emissions reductions to a target or standard that may decrease each year (e.g., in 2019, ethanol was compared to the gasoline average CI of 93.23 gCO2e/MJ), where lower CIs generate proportionally more credits. In one embodiment, the fuel produced is a transportation fuel, and a fuel credit is generated or is caused to be generated. In one embodiment, the transportation fuel and/or renewable content has lifecycle GHG emissions that are at least 20% less than the lifecycle GHG emissions of a gasoline baseline using EPA methodology, preferably at least 50% or 60% less.|[0109] With respect to renewable hydrogen produced according to the instant disclosure, it can be advantageous for the CI of the hydrogen to be as low as possible, particularly when the hydrogen is used as a fuel or to produce a fuel, so that more valuable fuel credits can be generated. In one embodiment, the process produces fuel (i.e., renewable hydrogen or fuel produced using the renewable hydrogen), where the renewable hydrogen has a CI that is not more than −10 gCO2e/MJ, −20 gCO2e/MJ, −30 gCO2e/MJ, −40 gCO2e/MJ, −50 gCO2e/MJ, −60 gCO2e/MJ, or −70 gCO2/MJ of H2. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the CI is measured for the resulting product from each of the co-processed feedstocks (i.e., there is a different CI for each the renewable and non-renewable feedstocks). In one embodiment, the process includes producing hydrogen associated with one or more producer credits.|(US11760630)|EXAMPLE|[0110] Referring to Table 1, there is shown a list of estimated GHG emission values for hydrogen produced by various processes. As summarized in Table 2, these processes produce: 1) grey hydrogen from the SMR of natural gas with no CCS; 2) blue hydrogen from the SMR of natural gas with CCS (i.e., where the CO2 is captured from the feedstock); 3) renewable hydrogen labelled “RH” from the SMR of RNG with no CCS; 4) renewable hydrogen labelled “RH+CCSH2” from the SMR of RNG with CCS (i.e., where the CO2 is captured from the feedstock only); 5) renewable hydrogen labelled “RH+CCSH2+CCSBG” from the SMR of RNG with CCS (i.e., where the CO2 is captured from the feedstock and from the biogas); and 6) renewable hydrogen labelled “RH+CCSBG” from the SMR of RNG with CCS (i.e., where the CO2 is captured from the biogas only).|[0111] For each process, it was assumed that the fuel for the SMR burners is fossil based natural gas and that the feedstock for the methane reforming is RNG produced from landfill gas (i.e., is upgraded landfill gas). In order to compare the different processes, which can use different feedstocks, the GHG emissions for the hydrogen production were split into the contributions from the feedstock (i.e., upstream emissions) and from the hydrogen production. Each emission (positive number) and emission credit (negative number) is an estimation based on one or more published values and/or determined using stoichiometry. For example, the feedstock emissions of 10 gCO2e/MJ of H2 for natural gas and 35 gCO2e/MJ of H2 for landfill gas are estimated from the CA-GREET 3.0 model. The feedstock emission credit of −42 gCO2e/MJ of H2, which is a net credit at least partially based on theoretical calculations, assumes that the emissions for CCS of the biogas is 5 gCO2e/MJ of H2. For the hydrogen production, emissions from the combustion of fuel for the SMR burners is assumed to be 28 gCO2e/MJ of H2, electricity is assumed to be 2 gCO2e/MJ of H2, and emissions from the conversion of the feedstock to syngas is assumed to be 60 gCO2e per MJ of H2. Assuming all of the CO2 from the feedstock is captured and stored, and if the CCS process from hydrogen production results in 5 gCO2e/MJ of H2 of emissions, the CCSH2 process provides a net credit of −55 gCO2e/MJ of H2.|[0112] TABLE 1 GHG Emission Values, in gCO2e/MJ of H2,for various SMR based H2 production processes Hydrogen Plant Feedstock Hydrogen Feedstock Plant CO2FuelFeedstock CO2 ProcessFeedstockcaptureCombustionconversionElectricitycaptureCI Grey H210 28602 100Blue H210 28602−5545RH35 28 2 65RH + CCSH235 28 2−5511RH + CCSH2 +35−4228 2−55−31CCSBG RH + CCSBG35−4228 2 24 |[0113] TABLE 2 Summary of the various SMR based H2 production processesProcessDescriptionFeedstockCO2 capture 1Grey H2Natural GasNone2Blue H2Natural GasYes - Syngas3Renewable H2 (RH)RNG (landfill)None4Renewable H2 and CCSH2RNG (landfill)Yes - Syngas only5Renewable H2 and CCSH2 RNG (landfill)Yes - Syngas and and CCSBG upstream6Renewable H2 and CCSBGRNG (landfill)Yes - upstream only |[0114] While the GHG emission values in Table 1 are estimations provided for comparative purposes, they do appear reasonable. For example, Table 1 lists the CI of grey hydrogen as 100 gCO2e/MJ, which is within a published range of 94.8 to 101.4 g CO2e/MJ. With regard to the CI of blue hydrogen, which Table 1 lists as 45 gCO2e/MJ (with CCS of about 60% of the total CO2 produced), some published values are 19.6 gCO2e/MJ (with CCS of about 90% of the total CO2 produced) and 34.5 gCO2e/MJ (with CCS of about 80% of the total CO2 produced).|[0115] As evident from Table 1, simply using RNG as a feedstock, using RNG as a feedstock and capturing CO2 from the feedstock, or using RNG as a feedstock and capturing CO2 from the biogas, does not necessarily produce hydrogen having a negative CI, and can produce hydrogen having a higher CI than green hydrogen (e.g., which can be less than 10 gCO2e/MJ).|[0116] However, by including the capture and storage of both CO2 from the biogas and CO2 derived from the feedstock for hydrogen production, the CI of the resulting renewable hydrogen is not only negative, but is quite low at −31 gCO2e/MJ. Advantageously, this low value is achieved without having to capture and store CO2 from the flue gas, without having to sacrifice a portion of the RNG to fuel the SMR, and/or without having to use RNG having a negative CI.|[0117] Of course, the above embodiments have been provided as examples only. It will be appreciated by those of ordinary skill in the art that various modifications, alternate configurations, and/or equivalents will be employed without departing from the scope of the invention. For example, although the instant disclosure provides a process that provides renewable hydrogen having a negative CI without CCS of CO2 from the flue gas, without sacrificing a portion of the RNG to fuel the SMR, and/or without using a negative CI RNG, in some embodiments, the CI of the renewable hydrogen is further reduced by capturing and storing CO2 from the flue gas, using a portion of the RNG to fuel the SMR, and/or using RNG having a negative CI (e.g., based on the anaerobic digestion of manure). For example, in the above described example, while the carbon intensity of the hydrogen is dependent on capturing and storing CO2 from the biogas and from the feedstock for hydrogen production, it is also dependent on the carbon intensity of the RNG and/or other factors. Using RNG having a negative value can further reduce the carbon intensity of the hydrogen. Accordingly, the scope of the invention is therefore intended to be limited solely by the scope of the appended claims, | Family Number|(102196477)|102196477|Advantages / Prev. Drawbacks|(WO2022217365 A1)|In terms of BECCS it has the advantage that it is relatively simple, can be conducted on relatively large scale, and is generally configured such that all of the CO2 produced during the gasification is collected from one point source.|The reforming of biogas for hydrogen production has some advantages over the gasification of biomass, however, in terms of BECCS it is generally more complicated.|With regard to the third point, for established bioenergy technologies, the cost of BECCS may be largely limited by the cost of CCS.|(CA3214940 A1)|In terms of BECCS it has the advantage that it is relatively simple, can be conducted on relatively large scale, and is generally configured such that all of the CO2 produced during the gasification is collected from one point source.|The reforming of biogas for hydrogen production has some advantages over the gasification of biomass, however, in terms of BECCS it is generally more complicated.|With regard to the third 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https://ec.europa.eu/info/law/better-regulation/have-your-say/initiatives/12711-Renewable-energy-method-for-calculating-the-share-of-renewables-in-the-case-of-co-processing/F3325697_en, Access Date: Oct. 26, 2022.|-“Hydrogen in a Low-Carbon Economy”, Committee on Climate Change, Nov. 2018.|||(WO2022/217365)|International Search Report [Examiner]|-MURADOV, N. ; SMITH, F. ; T-RAISSI, A.: "Hydrogen production by catalytic processing of renewable methane-rich gases", INTERNATIONAL JOURNAL OF HYDROGEN ENERGY, ELSEVIER, AMSTERDAM, NL, vol. 33, no. 8, 1 April 2008 (2008-04-01), AMSTERDAM, NL, pages 2023 - 2035, XP022650886, ISSN: 0360-3199, DOI: 10.1016/j.ijhydene.2008.02.026|-ANTONINI CRISTINA, TREYER KARIN, STREB ANNE, VAN DER SPEK MIJNDERT, BAUER CHRISTIAN, MAZZOTTI MARCO: "Hydrogen production from natural gas and biomethane with carbon capture and storage – A techno-environmental analysis", SUSTAINABLE ENERGY & FUELS, vol. 4, no. 6, 2 June 2020 (2020-06-02), pages 2967 - 2986, 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OCCURRED|ST27 STATUS EVENT CODE: A-1-1-W10-W00-W100 (AS PROVIDED BY THE NATIONAL OFFICE)|Event text: LETTER SENT|Effective date of the event=2026-04-02 | (EP4323308)|Contracting States: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, LI, RO, NL, TR|(WO2022/217365)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2022/217365)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2022/217365)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2022/217365)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2022/217365)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, JM, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, ME, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4323308)|EP; DE|(US11760630)|US|(US20240025739)|US|(WO2022/217365)|CA; DE; EP; US|(DE22787208)|DE|(CA3214940)|CA | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=8TP/cX+h8x6DGiWpmNvaMHmXtI+wKb3KNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000021406690&ekey=1992&xpn=EP4323308&kind=A4 | https://register.epo.org/application?number=EP22787208 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=a14lS%252B9ZqpkbWDK85JFymXfDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2022/217365)|CA | (WO2022/217365)|NAME=IOGEN CORPORATION 310 Hunt Club Road, Suite 101 Ottawa, Ontario K1V 1C1 , COUNTRY=CA | (EP4323308)|GB||(WO2022/217365)|CA|(DE22787208)|DE|(CA3214940)|CA | (EP4323308)|NAME=Keltie LLP No. 1 London Bridge , CITY=London SE1 9BA , COUNTRY=GB , REG=101927740|(US11760630)|NAME=Knobbe Martens Olson & Bear LLP|(WO2022/217365)|NAME=LAMSON, Wendy 1256 Tompkins Street Ottawa, Ontario K2C 3B7 , POSTCODE=K2C 3B7 , COUNTRY=CA|(DE22787208)|NAME=KUHNEN & WACKER Patent- und Rechtsanwaltsbüro PartG mbB , CITY=Freising , POSTCODE=85354 , COUNTRY=DE|(CA3214940)|NAME=LAMSON, WENDY , COUNTRY=CA | |(EP4323308)|CA|(US11760630)|CA|(US20230183064)|CA|(US20240025739)|CA|(WO2022/217365)|CA|(DE22787208)|CA|(CA3214940)|CA | (EP4323308)|NAME=FOODY, Patrick J.|(EP4323308)|NAME=FOODY, Patrick J., CITY=Ottawa, Ontario K1V 1C1, COUNTRY=CA|(US11760630)|NAME=Foody Patrick J., CITY=Ottawa, COUNTRY=CA|(US20230183064)|NAME=Foody Patrick J., CITY=Ottawa, COUNTRY=CA|(US20240025739)|NAME=Foody Patrick J., CITY=Ottawa, COUNTRY=CA|(WO2022/217365)|NAME=FOODY, Patrick J. 310 Hunt Club Road, Suite 101 Ottawa, Ontario K1V 1C1, POSTCODE=K1V 1C1, COUNTRY=CA|(DE22787208)|NAME=FOODY, Patrick J., CITY=Ottawa, Ontario K1V 1C1, COUNTRY=CA|(CA3214940)|NAME=FOODY, PATRICK J. C/O IOGEN CORPORATION 310 Hunt Club Road, Suite 101, CITY=OTTAWA, POSTCODE=K1V 1C1, STATE=O1 , COUNTRY=CA | (WO2022/217365)|4|(US20240025739)|4|(US11760630)|4|(CA3214940)|4 | 5 | 6 | (EP4323308)|WO2022/217365|(US11760630)|WO2022/217365|(US20240025739)|WO2022/217365|(DE22787208)|WO2022/217365|(CA3214940)|WO2022/217365 | (DE22787208)|EP22787208 | (US11760630)|Number of Claims: NCL=23|Number of Drawings: NDR=4|Number of Figures: NFG=4|Independent Claim Number: ICL=1,22|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1|Primary examiner: Vanoy Timothy C|Art Unit.: ART =1736||(US20230183064)|Number of Claims: NCL=23|Number of Drawings: NDR=4|Number of Figures: NFG=4|Independent Claim Number: ICL=25,46|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=25|Primary examiner: Vanoy Timothy C|Art Unit.: ART =1736||(US20240025739)|Number of Claims: NCL=21|Number of Drawings: NDR=4|Number of Figures: NFG=4|Independent Claim Number: ICL=25,44,45|Number of Independent Claims: NICL=3|Exemplary Claim Number: ECL=25||(WO2022/217365)|Number of Claims: NCL=24|Extended kind: EXTK=x|Independent Claim Number: ICL=1,21,22,23,24|Number of Independent Claims: NICL=5|Exemplary Claim Number: ECL=1||(DE22787208)|Number of Claims: NCL=15||(CA3214940)|Number of Claims: NCL=24| | (US11760630)|Continuation of: WOCA2022/050586 FDD=2022-04-14 [2022WO-CA50586] PENDING|Provisional Appl: US63/201,168 FDD=2021-04-15 [2021US-63201168]|Previous publication: US20230183064 A1 2023-06-15 [US20230183064]|(US20240025739)|Continuation of: US18/069,041 FDD=2022-12-20 [2022US-18069041]|Continuation of: US11760630 |Continuation of: WOCA2022/050586 FDD=2022-04-14 [2022WO-CA50586] PENDING|Provisional Appl: US63/201,168 FDD=2021-04-15 [2021US-63201168] | (EP4323308)|ENGLISH (ENG) | (EP4323308)|Patent|(DE22787208T)|Patent|(EP4323308)|Patent|(US20240025739)|Patent|(US11760630)|Patent|(US20230183064)|Patent|(CA3214940)|Patent|(WO2022217365)|Patent | Titre: (EP4323308)|Process and system for producing low carbon intensity renewable hydrogen Résumé: (EP4323308)|A process and/or system for producing fuel that includes providing biogas, removing at least 50% of the carbon dioxide from the biogas, transporting the upgraded biogas to a hydrogen plant; providing the transported upgraded biogas as feedstock for hydrogen production. The carbon intensity of the fuel is less than 0 gCO2-eq/MJ, at least in part because carbon dioxide removed from the biogas and carbon dioxide from hydrogen production is captured and stored. Autre: (US11760630)|The invention claimed is:|1. A method of producing low carbon intensity hydrogen, the method comprising:| providing transported upgraded biogas for a hydrogen production process, the transported upgraded biogas produced from a biogas upgrading process comprising:| a) subjecting biogas comprising methane and carbon dioxide to biogas upgrading, thereby producing the upgraded biogas,| b) capturing a first quantity of carbon dioxide and providing the first quantity of carbon dioxide for storage, the first quantity of carbon dioxide captured (i) as part of the biogas upgrading, (ii) from a stream produced from the biogas upgrading, or (iii) a combination of (i) and (ii), and| c) transporting the upgraded biogas;| generating hydrogen from the hydrogen production process using fossil-based natural gas and the transported upgraded biogas, the hydrogen production process comprising methane reforming and hydrogen purification, the methane reforming producing syngas comprising carbon dioxide and hydrogen, the hydrogen purification comprising purifying at least one of the syngas or a stream derived from the syngas to produce the low carbon intensity hydrogen; and| capturing a second quantity of carbon dioxide from the hydrogen production process, and providing the second quantity of carbon dioxide for storage,| wherein the low carbon intensity hydrogen has a carbon intensity that is dependent, at least in part, on storage of the first and second quantities of carbon dioxide.|2. The method according to claim 1, wherein the second quantity of carbon dioxide comprises biogenic carbon dioxide generated from the transported upgraded biogas and fossil based carbon dioxide generated from the fossil-based natural gas.|3. The method according to claim 1, wherein at least some of the carbon dioxide in the second quantity is removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas.|4. The method according to claim 3, wherein the methane reforming comprises steam methane reforming, the steam methane reforming producing flue gas, and wherein at least some of the carbon dioxide in the second quantity is removed from the flue gas.|5. The method according to claim 1, wherein all of the carbon dioxide in the second quantity is removed from at least one of (i′) the syngas or (ii′) a stream at least partially derived from the syngas.|6. The method according to claim 1, wherein the methane reforming comprises steam methane reforming, the steam methane reforming producing flue gas, and wherein all of the carbon dioxide in the second quantity is removed from the flue gas.|7. The method according to claim 1, wherein storage of the first and second quantities of carbon dioxide comprises geological sequestration.|8. The method according to claim 1, wherein at least a portion of the transported upgraded biogas is used as feedstock for the methane reforming.|9. The method according to claim 8, wherein at least a portion of the fossil-based natural gas is used as feedstock for the methane reforming.|10. The method according to claim 8, wherein the methane reforming comprises steam methane reforming, and wherein at least a portion of the transported upgraded biogas is fed to a combustion zone of the steam methane reformer.|11. The method according to claim 1, wherein at least a portion of the fossil-based natural gas is used as feedstock for methane reforming.|12. The method according to claim 1, wherein the methane reforming comprises steam methane reforming, and wherein at least a portion of the transported upgraded biogas is fed to a combustion zone of the steam methane reformer.|13. The method according to claim 1, wherein transporting the upgraded biogas comprises transporting at least a portion of the upgraded biogas to the hydrogen plant as a fungible batch.|14. The method according to claim 1, wherein transporting the upgraded biogas comprises transporting at least a portion of the upgraded biogas to the hydrogen plant as a segregated batch.|15. The method according to claim 1, wherein the second quantity of carbon dioxide contains not more than 75% of a total amount of carbon dioxide produced from hydrogen production.|16. The method according to claim 1, wherein the biogas is landfill gas.|17. The method according to claim 16, wherein the biogas is produced from anaerobic digestion of organic waste, swine manure, dairy manure, or any combination thereof.|18. The method according to claim 1, further comprising providing the low carbon intensity hydrogen for use in ammonia production.|19. The method according to claim 1, further comprising providing the low carbon intensity hydrogen for use in producing a fuel.|20. The method according to claim 19, wherein the fuel is produced in a fuel production process comprising hydrogenating crude oil derived liquid hydrocarbon with the low carbon intensity hydrogen.|21. The method according to claim 1, wherein the low carbon intensity hydrogen has a carbon intensity that is less than 11 gCO2eq/MJ.|22. A method of producing low carbon intensity hydrogen, the method comprising:| providing transported upgraded biogas for a hydrogen production process, the transported upgraded biogas produced from a process comprising:| a) subjecting biogas comprising methane and carbon dioxide to biogas upgrading, thereby producing the upgraded biogas, and| b) transporting the upgraded biogas; and| generating hydrogen from the hydrogen production process using fossil-based natural gas and the transported upgraded biogas, the hydrogen production process comprising methane reforming and hydrogen purification, the methane reforming producing syngas comprising carbon dioxide and hydrogen, the hydrogen purification comprising purifying at least one of the syngas or a stream derived from the syngas to produce the low carbon intensity hydrogen,| wherein a first quantity of carbon dioxide is captured and provided for storage, transport, or a combination thereof, the first quantity of carbon dioxide captured (i) as part of the biogas upgrading, (ii) from a stream produced from the biogas upgrading, or (iii) a combination of (i) and (ii),| wherein a second quantity of carbon dioxide is captured and provided for storage, transport, or a combination thereof, the second quantity of carbon dioxide captured from the hydrogen production process, and| wherein the low carbon intensity hydrogen has a carbon intensity that is less than 11 gCO2eq/MJ.|23. The method of producing low carbon intensity hydrogen according to claim 22, wherein the low carbon intensity hydrogen has a carbon intensity that is less than 0 gCO2eq/MJ. | 22 | Abstract | gpt-4o-mini | no | The article focuses on hydrogen production from biogas with CO₂ removal and storage, but does not involve energy production from biomass in the context of BECCS. | |||||||||||||
| 23 | US63/201,301P|WOCA2022/050612|US18/325,532|US18/351,862|US19/233,978 | WOCA2022/050612|US19/233,978|US18/325,532|EP22790640|US18/351,862|CA3214954 | US20250304862|US12359134|EP4326671|US11946001|EP4326671|US20230374394|US20230295523|CA3214954|WO2022/221954 | 102292005 | WO2022/221954 A1 2022-10-27 [WO2022221954]|US20250304862 A1 2025-10-02 [US20250304862]|US12359134 B2 2025-07-15 [US12359134]|US20230295523 A1 2023-09-21 [US20230295523]|EP4326671 A4 2024-11-06 [EP4326671]|EP4326671 A1 2024-02-28 [EP4326671]|US11946001 B2 2024-04-02 [US11946001]|US20230374394 A1 2023-11-23 [US20230374394]|CA3214954 A1 2022-10-27 [CA3214954] | 2021-04-22|2022-04-21|2023-05-30|2023-07-13|2025-06-10 | 2022-04-21|2025-06-10|2022-04-21|2022-04-21|2022-04-21|2022-04-21 | 2025-10-02|2025-07-15|2024-11-06|2024-04-02|2024-02-28|2023-11-23|2023-09-21|2022-10-27|2022-10-27 | |(US12359134)|2025-07-15|(US11946001)|2024-04-02||| | (EP4326671)|2042-04-21|(US12359134)|2042-12-11|(US11946001)|2042-04-21|(US20250304862)|2042-04-21|(WO2022/221954)|2024-10-22|(CA3214954)|2042-04-21 | (EP4326671)|Process and system for producing fuel | (EP4326671)|A process and/or system for producing fuel using renewable hydrogen having a reduced carbon intensity. The renewable hydrogen is produced in a hydrogen production process comprising methane reforming, wherein at least a portion of the feedstock for the hydrogen production process comprises upgraded biogas sourced from a plurality of biogas plants. Each of the upgraded biogases is produced in a process that includes collecting biogas comprising methane and carbon dioxide, capturing at least 50% of the carbon dioxide originally present in the collected biogas and producing the upgraded biogas. Storage of the captured carbon dioxide reducing a carbon intensity of the fuel, without having to provide carbon capture and storage of carbon dioxide from hydrogen production. | IOGEN | (EP4326671)|Iogen Corporation|(EP4326671)|Iogen Corporation ([CA])|(US12359134)|Iogen Corporation ([CA])|(US20230295523)|Iogen Corporation ([CA])|(US11946001)|Iogen Corporation ([CA])|(US20230374394)|Iogen Corporation ([CA])|(US20250304862)|Iogen Corporation ([CA])|(WO2022/221954)|IOGEN CORPORATION ([CA])|(CA3214954)|IOGEN CORPORATION ([CA]) | FOODY PATRICK J | (EP4326671)|FOODY, Patrick J.|(EP4326671)|FOODY, Patrick J. | (EP4326671)|Keltie LLP ([GB])|Reg. Nb: 101927740|(US12359134)|Knobbe Martens Olson & Bear LLP|(US11946001)|Knobbe Martens Olson & Bear LLP|(WO2022/221954)|LAMSON ([CA])|(CA3214954)|LAMSON, WENDY ([CA]) | (US12359134)|It can be particularly advantageous to produce upgraded biogas having a CH_4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system.|Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).|Yet another advantage is that it facilitates the aggregation of upgraded biogas from several locations (e.g., several biogas plants) and several CCS storage sites (e.g., basins) into one hydrogen production process.|As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings.|Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations.|While CCS at a plurality of biogas plants can be more expensive than CCS at a single hydrogen plant, there are various advantages and/or synergistic benefits of the process(es)/system(s) of instant disclosure.| | (US12359134)|1. A method of producing product, the method comprising: sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising: a) collecting biogas comprising methane and carbon dioxide, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, and c) providing the captured carbon dioxide for storage; providing the at least two upgraded biogases and fossil-based gas for methane reforming, the methane reforming producing syngas; and, producing the product from a production process that uses at least part of the syngas produced from the methane reforming, wherein the captured carbon dioxide provided in step (c) of each of the processes is stored and reduces lifecycle greenhouse gas (GHG) emissions associated with the product.|22. A method of producing product, the process comprising: (i) sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising: a) collecting biogas comprising methane and carbon dioxide, and, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, wherein the at least two upgraded biogases and fossil-based gas are used in methane reforming, the methane reforming producing syngas, at least part of the syngas used to produce the product; and ii) storing the captured carbon dioxide produced from each process, thereby preventing the captured carbon dioxide, or an equal quantity of carbon dioxide displaced by the captured carbon dioxide, from being released to the atmosphere, and reducing lifecycle greenhouse gas (GHG) emissions associated with the product.|23. A method of producing product, the method comprising: providing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising: a) collecting biogas comprising methane and carbon dioxide, b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas; feeding at least a portion of each upgraded biogas and fossil-based gas to methane reforming, the methane reforming producing syngas, at least part of the syngas used for producing the product; and wherein at least some of the carbon dioxide removed in step (b) of each of the processes is provided for at least one carbon capture and storage process to reduce lifecycle greenhouse gas (GHG) emissions associated with the product.| | (US12359134)|The present disclosure relates to a process and/or system for producing fuel and/or product(s), and in particular, to a process and/or system for producing fuel and/or products(s) having renewable content that includes carbon capture and storage of carbon dioxide from biogas.|The present disclosure relates to at least one process/system wherein at least a portion of the feedstock for hydrogen production and/or the fuel and/or product production is sourced from a plurality of biogas plants.|The present disclosure relates to producing fuel and/or product in a process (e.g., fuel production process) that uses hydrogen and includes carbon capture and storage, wherein the carbon capture and storage includes the carbon capture and storage of CO_2 removed from biogas (e.g., raw biogas).| | (US12359134)|PRODUCT PRODUCTION(100,12)|UPGRADED BIOGAS(99,68)|METHANE REFORMING(79,30)|UPGRADED BIOGAS AGGREGATION(53,1)|RENEWABLE FEEDSTOCK COPROCESSING(47,3)|BIOGAS(39,194)|FOSSIL GAS(39,8)|RENEWABLE FEEDSTOCK HYDROGENATION(37,1)|BIOGAS COLLECTION(36,5)|CAPTURED CARBON DIOXIDE(34,26)|STEAM METHANE REFORMING(32,3)|RENEWABLE FEEDSTOCK(31,11)|SYNGA(27,28)|CARBON DIOXIDE(26,82)|NONRENEWABLE FEEDSTOCK(24,6)|SYNERGISTIC BENEFIT(22,1)|BIOGAS PLANT(20,12)|GEOLOGICAL SEQUESTRATION(20,4)|ANAEROBIC DIGESTER(18,15)|FEEDSTOCK(17,50)|FUEL PRODUCTION(17,15)|DAIRY MANURE(17,2)|LIFECYCLE REDUCTION(17,2)|SWINE MANURE(17,2)|RENEWABLE CONTENT(15,24)|METHANE(15,21)|LIFECYCLE(15,12)|RAW BIOGAS(15,9)|COGENERATION(15,1)|FEEDSTOCK ANAEROBIC DIGESTION(14,4)|RENEWABLE FAT(14,3)|CARBON CAPTURE(13,18)|CRYOGENIC SEPARATION(13,11)|HYDROGENIZING CRUDE OIL(12,1)|STORAGE SITE(12,1)|NATURAL GAS DISTRIBUTION(11,26)|FOSSIL NATURAL GAS(11,9)|COMBUSTION ZONE(11,2)|RENEWABLE OIL(11,2)|BASIN(11,1)|PROCESS SYNERGISTIC BENEFIT(11,1)|FUNGIBLE BATCH(10,9)|CARBON DIOXIDE STORAGE(9,3)|AMINE SOLVENT(9,2)|HYDROGEN PRODUCTION(8,96)|GREENHOUSE GAS(8,42)|WITHDRAWN GAS(8,3)|HEAT PRODUCTION(8,1)|CARBON DIOXIDE CAPTURE(7,2)|SINGLE HYDROGEN PLANT(7,2)|GCO(6,26)|BIO GAS CLEANING(6,3)|CENTRALIZED BIOGAS PLANT(6,3)|ANAEROBIC MICROORGANISM(6,2)|CARBON DIOXIDE DISTRIBUTION(6,2)|RENEWABLE BIOFUEL(6,2)|TRADABLE CURRENCY(6,2)|BIOMASS FEEDSTOCK DRY TONNE(6,1)|NATURAL GAS(5,39)|APPLICABLE REGULATION(5,6)|BIOGAS STREAM(5,4)|CONCRETE(5,4)|RAW(5,3)|BATCH SEGREGATION(5,2)|BIOMASS TRANSPORTATION(5,2)|FUEL CREDIT GENERATION(5,2)|MANAGING(5,2)|REFORMING CATALYST(5,2)|SALINE AQUIFER(5,2)|BIOGAS ATTRIBUTE(5,1)|FEEDSTOCK RENEWABLE FRACTION(5,1)|GASOLINE BASELINE EMISSION(5,1)|JET FUEL(4,7)|MEMBRANE SEPARATION(4,7)|BLUE HYDROGEN(4,6)|PARTICULATE(4,6)|LANDFILL GAS(4,5)|HYDROPROCESSING(4,4)|GRAY HYDROGEN(4,3)|ANAEROBIC OXYGEN(4,2)|APPLICABLE REGULATORY AGENCY(4,2)|CAPITAL BENEFIT(4,2)|ENRICHED HYDROGEN STREAM(4,2)|FACILITY OWNER(4,2)|NET CREDIT(4,2)|REMOTE LOCATION(4,2)|31CCS BG RH(4,1)|BIO GAS PIPELINE(4,1)|BIOGENIC SYNGA(4,1)|BIOMASS DIESEL(4,1)|BOILER FEEDWATER(4,1)|CARBON INTENSITY REDUCTION(4,1)|COPROCESSED FEEDSTOCK(4,1)|CRYOGENIC BIOGAS(4,1)|ENDOTHERMIC REFORMING REACTION(4,1)|EXTRACTING BIOENERGY(4,1)|FIRED BURNER(4,1)|FOSSIL FERTILIZER(4,1)|FOSSIL METHANE(4,1)|GOVERNMENT AUTHORITY(4,1)|GOVERNMENT INITIATIVE(4,1)|GOVERNMENTAL AUTHORITY(4,1)|INCENTIVIZE RENEWABLE FUEL(4,1)|INCREMENTAL TRANSITIONING(4,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(4,1)|LIVESTOCK FARM(4,1)|NONGOVERNMENTAL AGENCY(4,1)|NONRENEWABLE GASOLINE(4,1)|NONRENEWABLE METHANE(4,1)|OXIDATIVE REFORMING(4,1)|PRODUCER CREDIT(4,1)|RENEWABLE CONTENT QUANTIFICATION(4,1)|SUGARCANE BAGASSE(4,1)|VALUABLE FUEL CREDIT(4,1)|GEOLOGICAL FORMATION(3,11)|HYDROGEN PURIFICATION(3,9)|PSIG(3,8)|ADSORPTION(3,5)|MONOETHANOLAMINE(3,5)|ORGANIC WASTE(3,5)|CERTIFICATE(3,4)|IMPURITY(3,4)|RFS(3,4)|HYDROCRACKING(3,3)|ORGANIC FRACTION(3,3)|PURGE GAS(3,3)|RAILCAR(3,3)|TAIL GAS(3,3)|BIOGENIC CARBON DIOXIDE(3,2)|CAPTURED STREAM(3,2)|COLLECTION RADIUS(3,2)|HYDROGEN PRODUCTION(3,2)|LIFECYCLE GREENHOUSE GAS EMISSION(3,2)|LIQUID TRANSPORTATION FUEL(3,2)|NEGATIVE EMISSION(3,2)|REDUCING LIFECYCLE(3,2)|SYNGA GAS(3,2)|AUTOTHERMAL REFORMING HYDROGEN PLANT(3,1)|AVERAGE GASOLINE BASELINE(3,1)|BARLEY STRAW(3,1)|BAUXITE RESIDUE CARBONATION(3,1)|BIOTRICKLING FILTER(3,1)|CENTRALIZED FACILITY(3,1)|COMPLIANCE PATHWAY(3,1)|ELECTRICALLY HEATED METHANE REFORMER(3,1)|ENERGY INTENSIVE BIOMASS(3,1)|EQ CATALYTIC REFORMING(3,1)|FEEDSTOCK EMANATION(3,1)|FEEDSTOCK EMISSION CREDIT(3,1)|FEEDSTOCK TRANSPORTATION(3,1)|FUEL RENEWABLE CONTENT(3,1)|LACK INFRASTRUCTURE(3,1)|OPERATIVE COMPLICATION(3,1)|PREVAILING REGULATION(3,1)|PRIVATE CONTRACT(3,1)|QUANTIFIABLE BENEFIT(3,1)|SYNERGETIC BENEFIT(3,1)|TRANSPORTATION SECTOR(3,1)|UPGRADED BIOGAS 150(3,1)|WHEAT STRAW(3,1)|DERIVED LIQUID HYDROCARBON(2,5)|ENHANCED OIL RECOVERY(2,5)|TRUCK(2,5)|AGRICULTURAL RESIDUE(2,3)|AVIATION FUEL(2,3)|BIO GAS SOURCE(2,3)|EMISSION VALUE(2,3)|ALLOWANCE(2,2)|BIODEGRADATION(2,2)|CARBONIZING ATMOSPHERE(2,2)|CORN STOVER(2,2)|DEHYDRATION(2,2)|FEEDSTOCK COST(2,2)|GREEN HYDROGEN(2,2)|HYDROGEN CONTENT(2,2)|HYDROPOWER(2,2)|NUTRIENT(2,2)|PHOTOSYNTHESIS(2,2)|PIPELINE STANDARD(2,2)|PRODUCING RENEWABLE HYDROGEN(2,2)|REACTOR TUBE(2,2)|RENEWABLE ELECTRICITY(2,2)|RENEWABLE HYDROGEN YIELD(2,2)|SUBSTITUTE(2,2)|ABSORPTION AMINE(2,1)|ABSORPTION COLUMN(2,1)|ADSORBENT BED(2,1)|APPLICABLE REGULATORY AUTHORITY(2,1)|BECCS COST(2,1)|CELLULOSE ACETATE(2,1)|CENTRALIZED PROCESSING FACILITY(2,1)|COLLECTION ZONE(2,1)|CORN ETHANOL(2,1)|CORN GRAIN(2,1)|COVERED LAGOON(2,1)|DISAGGREGATION(2,1)|ECONOMIC REASON(2,1)|EMISSION THRESHOLD(2,1)|EQUIVALENT EMISSION(2,1)|EVIDENCE PRODUCTION(2,1)|FARM WASTE(2,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(2,1)|FEEDSTOCK HYDROGEN(2,1)|FOSSIL BASED FEEDSTOCK(2,1)|FOSSIL CARBON DIOXIDE(2,1)|FOSSIL FUEL CONSUMPTION(2,1)|FUEL MEETING LIFE CYCLE(2,1)|GAS FERMENTATION(2,1)|GEOLOGICAL STORAGE(2,1)|HYDROGEN REFUELING STATION GRID(2,1)|HYDROGEN TONNE(2,1)|HYDROTHERMAL LIQUEFACTION(2,1)|HYDROTHERMAL TREATMENT(2,1)|IRON SPONGE(2,1)|MANDATED VOLUME(2,1)|MESOPHILIC TEMPERATURE(2,1)|METHANATION REACTION(2,1)|NAOH WASHING(2,1)|OFFSHORE SETTING(2,1)|ONSHORE SETTING(2,1)|ORGANIC PHYSICAL SCRUBBING(2,1)|PIPE INTERCONNECTION(2,1)|POLYDIMETHYLSILOXANE(2,1)|PURGE STREAM(2,1)|REFINERY GAS(2,1)|REFORMER TUBE(2,1)|REFRIGERATION(2,1)|RENEWABLE ENERGY DIRECTIVE(2,1)|RENEWABLE PRODUCT(2,1)|STANDARD BIOGAS(2,1)|STEAM GENERATION(2,1)|STORAGE PERMANENCE(2,1)|STREAM COMPRESSION(2,1)|SUBSURFACE FORMATION(2,1)|SUPPLY REGION(2,1)|TERM BIOGAS(2,1)|UNREFINED(2,1)|UPSTREAM EMISSION(2,1)|VIABLE SCALE(2,1)|VOLUNTARY CARBON(2,1)|VOLUNTARY EMISSION REDUCTION(2,1)|WITHDRAWN FEED(2,1)|FLUE GAS(1,9)|ACETOGENESIS(1,1)|ACIDOGENESIS(1,1)|ACTIVE ALUMINA(1,1)|ADVANCED BIOFUEL(1,1)|AGRICULTURAL CROP(1,1)|AMMONIA PRODUCTION(1,1)|APPLICABLE QUALITY(1,1)|AUTHORIZATION(1,1)|AVOIDANCE(1,1)|BASELINE LEVEL(1,1)|BIO DEGRADATION PREVENTION(1,1)|BIODIESEL(1,1)|BIOFILTER(1,1)|BUSINESS(1,1)|BYPRODUCT(1,1)|CAPITAL EXPENDITURE(1,1)|CARBOHYDRATE(1,1)|CARBON STORAGE(1,1)|CELLULOSIC BIOFUEL(1,1)|CO2E MEGAJOULE(1,1)|COMPONENT UPSTREAM REMOVAL(1,1)|COMPROMISE(1,1)|CONTAMINANT(1,1)|DAIRY(1,1)|DEHUMIDIFIER(1,1)|DETERRENT(1,1)|DIGESTER(1,1)|DIGESTION LEVEL(1,1)|DISTRIBUTED CARBON CAPTURE(1,1)|ELECTRICITY GRID(1,1)|ELECTROLYSIS(1,1)|EMISSION REDUCTION REGISTRY(1,1)|EMISSIONS REDUCTION COMPARISON(1,1)|FOSSIL FUEL PRODUCTION(1,1)|FOSSIL SOURCE(1,1)|FUEL ENERGY(1,1)|FUEL STREAM(1,1)|FUNDING(1,1)|GAS CONTENT(1,1)|GASOLINE ENERGY EQUIVALENT(1,1)||(US20230295523)|UPGRADED BIOGAS(100,61)|FUEL PRODUCTION(100,20)|UPGRADED BIOGAS AGGREGATION(76,1)|RENEWABLE FEEDSTOCK COPROCESSING(67,3)|METHANE REFORMING(53,21)|BIOGAS(46,186)|RENEWABLE FEEDSTOCK(45,11)|BIOGAS COLLECTION(38,4)|CAPTURED CARBON DIOXIDE(37,23)|NONRENEWABLE FEEDSTOCK(34,6)|SYNERGISTIC BENEFIT(32,1)|STEAM METHANE REFORMING(31,2)|BIOGAS PLANT(29,12)|GEOLOGICAL SEQUESTRATION(28,4)|ANAEROBIC DIGESTER(27,15)|CARBON DIOXIDE(26,73)|DAIRY MANURE(25,2)|SWINE MANURE(25,2)|FEEDSTOCK(22,49)|RENEWABLE CONTENT(22,24)|RAW BIOGAS(22,9)|COGENERATION(22,1)|RENEWABLE FAT(21,3)|FEEDSTOCK ANAEROBIC DIGESTION(20,4)|CRYOGENIC SEPARATION(19,11)|HYDROGENIZING CRUDE OIL(18,1)|STORAGE SITE(17,1)|CARBON CAPTURE(16,17)|FOSSIL NATURAL GAS(16,9)|RENEWABLE OIL(16,2)|BASIN(16,1)|PROCESS SYNERGISTIC BENEFIT(16,1)|FUNGIBLE BATCH(15,9)|NATURAL GAS DISTRIBUTION(14,25)|CARBON DIOXIDE STORAGE(14,3)|HYDROGEN PRODUCTION(13,98)|METHANE(13,19)|CO2 STORAGE(13,8)|AMINE SOLVENT(13,2)|GCO2E MEGAJOULE(12,23)|HEAT PRODUCTION(12,1)|CARBON DIOXIDE CAPTURE(11,2)|CO2 DISTRIBUTION(10,9)|PRODUCT PRODUCTION(10,2)|SINGLE HYDROGEN PLANT(10,2)|RENEWABLE BIOFUEL(9,2)|TRADABLE CURRENCY(9,2)|BIOMASS FEEDSTOCK DRY TONNE(9,1)|NATURAL GAS(8,43)|CARBON INTENSITY(8,11)|APPLICABLE REGULATION(8,6)|CO2 SEPARATION(8,6)|BIOGAS STREAM(8,4)|CONCRETE(8,4)|BIO GAS CLEANING(8,3)|CENTRALIZED BIOGAS PLANT(8,3)|ANAEROBIC MICROORGANISM(8,2)|BIOMASS TRANSPORTATION(8,2)|CARBON DIOXIDE DISTRIBUTION(8,2)|CO2 CAPTURE DISAGGREGATION(8,1)|FEEDSTOCK RENEWABLE FRACTION(8,1)|JET FUEL(7,7)|MEMBRANE SEPARATION(7,7)|CAPTURE CO2(7,3)|CO2 PIPELINE(7,3)|RAW(7,3)|BATCH SEGREGATION(7,2)|FUEL CREDIT GENERATION(7,2)|MANAGING(7,2)|REFORMING CATALYST(7,2)|SALINE AQUIFER(7,2)|BIOGAS ATTRIBUTE(7,1)|GASOLINE BASELINE EMISSION(7,1)|BLUE HYDROGEN(6,6)|CO2 REMOVAL(6,6)|PARTICULATE(6,6)|LANDFILL GAS(6,5)|HYDROPROCESSING(6,4)|HYDROGEN PRODUCTION(6,3)|REMOTE LOCATION(6,2)|BIOGENIC SYNGA(6,1)|CARBON INTENSITY REDUCTION(6,1)|COPROCESSED FEEDSTOCK(6,1)|CRYOGENIC CO2 CAPTURE(6,1)|FOSSIL FERTILIZER(6,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(6,1)|NONGOVERNMENTAL AGENCY(6,1)|NONRENEWABLE GASOLINE(6,1)|PRODUCER CREDIT(6,1)|RENEWABLE CONTENT QUANTIFICATION(6,1)|SUGARCANE BAGASSE(6,1)|VALUABLE FUEL CREDIT(6,1)|GEOLOGICAL FORMATION(5,11)|HYDROGEN PURIFICATION(5,9)|ADSORPTION(5,5)|CERTIFICATE(5,4)|IMPURITY(5,4)|GRAY HYDROGEN(5,3)|LIFECYCLE GREENHOUSE GAS EMISSION(5,3)|ANAEROBIC OXYGEN(5,2)|APPLICABLE REGULATORY AGENCY(5,2)|CAPITAL BENEFIT(5,2)|CAPTURED CO2 STORAGE(5,2)|CAPTURING CO2(5,2)|ENRICHED HYDROGEN STREAM(5,2)|FACILITY OWNER(5,2)|NET CREDIT(5,2)|AUTOTHERMAL REFORMING HYDROGEN PLANT(5,1)|AVERAGE GASOLINE BASELINE(5,1)|BARLEY STRAW(5,1)|BAUXITE RESIDUE CARBONATION(5,1)|BIO GAS PIPELINE(5,1)|BIOGENIC CO2 RELEASE(5,1)|BIOMASS DIESEL(5,1)|BIOTRICKLING FILTER(5,1)|BOILER FEEDWATER(5,1)|CAPTURED STREAM CO2(5,1)|CENTRALIZED FACILITY(5,1)|CO2 CAPTURED STREAM(5,1)|CO2 COMPRESSED STREAM(5,1)|CO2 EQUIVALENT EMISSION GRAM(5,1)|CO2 SELECTIVE MEMBRANE(5,1)|COMPLIANCE PATHWAY(5,1)|CRYOGENIC BIOGAS(5,1)|ELECTRICALLY HEATED METHANE REFORMER(5,1)|ENDOTHERMIC REFORMING REACTION(5,1)|ENERGY INTENSIVE BIOMASS(5,1)|EQ CATALYTIC REFORMING(5,1)|EXTRACTING BIOENERGY(5,1)|FEEDSTOCK EMANATION(5,1)|FEEDSTOCK EMISSION CREDIT(5,1)|FEEDSTOCK TRANSPORTATION(5,1)|FIRED BURNER(5,1)|FOSSIL CO2(5,1)|FOSSIL METHANE(5,1)|FUEL RENEWABLE CONTENT(5,1)|GOVERNMENT AUTHORITY(5,1)|GOVERNMENT INITIATIVE(5,1)|GOVERNMENTAL AUTHORITY(5,1)|HYDROGEN PROVISION(5,1)|INCENTIVIZE RENEWABLE FUEL(5,1)|INCREMENTAL TRANSITIONING(5,1)|LACK INFRASTRUCTURE(5,1)|LIVESTOCK FARM(5,1)|NONRENEWABLE METHANE(5,1)|OPERATIVE COMPLICATION(5,1)|OXIDATIVE REFORMING(5,1)|PREVAILING REGULATION(5,1)|PRIVATE CONTRACT(5,1)|QUANTIFIABLE BENEFIT(5,1)|SYNERGETIC BENEFIT(5,1)|TRANSPORTATION SECTOR(5,1)|WHEAT STRAW(5,1)|PSIG(4,8)|MONOETHANOLAMINE(4,5)|ORGANIC WASTE(4,5)|RFS(4,4)|CO2 PRODUCT(4,3)|HYDROCRACKING(4,3)|ORGANIC FRACTION(4,3)|PURGE GAS(4,3)|RAILCAR(4,3)|BIOGENIC CARBON DIOXIDE(4,2)|CO2 COLLECTION(4,2)|COLLECTION RADIUS(4,2)|FEEDSTOCK COST(4,2)|FOSSIL GAS(4,2)|LIQUID TRANSPORTATION FUEL(4,2)|NEGATIVE EMISSION(4,2)|REDUCING LIFECYCLE(4,2)|SYNGA GAS(4,2)|ADSORBENT BED(4,1)|APPLICABLE REGULATORY AUTHORITY(4,1)|CENTRALIZED PROCESSING FACILITY(4,1)|CO2 BIOGAS(4,1)|CO2 GRAM(4,1)|CO2 PURITY(4,1)|CO2 RICH TAIL GAS(4,1)|CORN GRAIN(4,1)|COVERED LAGOON(4,1)|FARM WASTE(4,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(4,1)|HYDROTHERMAL TREATMENT(4,1)|METHANATION REACTION(4,1)|NEGATIVE CO2 EMISSION(4,1)|ONSHORE SETTING(4,1)|PIPE INTERCONNECTION(4,1)|RENEWABLE ENERGY DIRECTIVE(4,1)|STEAM METHANE(4,1)|STORAGE PERMANENCE(4,1)|UPSTREAM EMISSION(4,1)|VOLUNTARY CARBON(4,1)|DERIVED LIQUID HYDROCARBON(3,5)|ENHANCED OIL RECOVERY(3,5)|TRUCK(3,5)|CCSH(3,4)|AVIATION FUEL(3,3)|H2O(3,3)|ALLOWANCE(3,2)|BIODEGRADATION(3,2)|CARBONIZING ATMOSPHERE(3,2)|CORN STOVER(3,2)|DEHYDRATION(3,2)|GREEN HYDROGEN(3,2)|HYDROGEN CONTENT(3,2)|HYDROPOWER(3,2)|NUTRIENT(3,2)|PHOTOSYNTHESIS(3,2)|PIPELINE STANDARD(3,2)|PRODUCING RENEWABLE HYDROGEN(3,2)|REACTOR TUBE(3,2)|RENEWABLE ELECTRICITY(3,2)|RENEWABLE HYDROGEN YIELD(3,2)|SUBSTITUTE(3,2)|WITHDRAWN GAS(3,2)|ABSORPTION AMINE(3,1)|ABSORPTION COLUMN(3,1)|BECCS COST(3,1)|CELLULOSE ACETATE(3,1)|CO2 CONTENT(3,1)|COLLECTION ZONE(3,1)|COMBUSTION ZONE(3,1)|CORN ETHANOL(3,1)|ECONOMIC REASON(3,1)|EMISSION THRESHOLD(3,1)|EVIDENCE PRODUCTION(3,1)|FOSSIL BASED CO2 EMISSION(3,1)|FOSSIL BASED FEEDSTOCK(3,1)|FOSSIL CARBON DIOXIDE(3,1)|FOSSIL FUEL CONSUMPTION(3,1)|FUEL MEETING LIFE CYCLE(3,1)|GAS FERMENTATION(3,1)|GEOLOGICAL STORAGE(3,1)|HYDROGEN REFUELING STATION GRID(3,1)|HYDROTHERMAL LIQUEFACTION(3,1)|IRON SPONGE(3,1)|LIFECYCLE REDUCTION(3,1)|MANDATED VOLUME(3,1)|MESOPHILIC TEMPERATURE(3,1)|NAOH WASHING(3,1)|OFFSHORE SETTING(3,1)|ORGANIC PHYSICAL SCRUBBING(3,1)|POLYDIMETHYLSILOXANE(3,1)|PURGE STREAM(3,1)|REFINERY GAS(3,1)|REFORMER TUBE(3,1)|REFRIGERATION(3,1)|RELEASING CO2(3,1)|RENEWABLE PRODUCT(3,1)|STANDARD BIOGAS(3,1)|STEAM GENERATION(3,1)|STREAM COMPRESSION(3,1)|SUBSURFACE FORMATION(3,1)|SUPPLY REGION(3,1)|TERM BIOGAS(3,1)|TRANSPORT CO2(3,1)|UNREFINED(3,1)|VIABLE SCALE(3,1)|VOLUNTARY EMISSION REDUCTION(3,1)|WITHDRAWN FEED(3,1)|FLUE GAS(2,9)|RENEWABLE H2(2,5)|AGRICULTURAL RESIDUE(2,3)|BIO GAS SOURCE(2,3)|CO2 CAPTURE(2,2)|ACETOGENESIS(2,1)|ACIDOGENESIS(2,1)|ACTIVE ALUMINA(2,1)|ADVANCED BIOFUEL(2,1)|AGRICULTURAL CROP(2,1)|AMMONIA PRODUCTION(2,1)|APPLICABLE QUALITY(2,1)|AUTHORIZATION(2,1)|AVOIDANCE(2,1)|BASELINE LEVEL(2,1)|BIO DEGRADATION PREVENTION(2,1)|BIODIESEL(2,1)|BIOFILTER(2,1)|BUSINESS(2,1)|BYPRODUCT(2,1)|CAPITAL EXPENDITURE(2,1)|CAPTURED CO2 GAS(2,1)|CARBOHYDRATE(2,1)|CARBON STORAGE(2,1)|CELLULOSIC BIOFUEL(2,1)|CO2 CAPTURE REDUCING COST(2,1)|CO2 SEPARATED(2,1)|CO2 TRANSFER(2,1)|COMPONENT UPSTREAM REMOVAL(2,1)|CONTAMINANT(2,1)|DAIRY(2,1)|DEHUMIDIFIER(2,1)|DETERRENT(2,1)|DIGESTER(2,1)|DIGESTION LEVEL(2,1)|DISTRIBUTED CARBON CAPTURE(2,1)|ELECTRICITY GRID(2,1)|ELECTROLYSIS(2,1)|EMISSION REDUCTION REGISTRY(2,1)|EMISSIONS REDUCTION COMPARISON(2,1)|FOSSIL FUEL PRODUCTION(2,1)|FOSSIL SOURCE(2,1)|FUEL ENERGY(2,1)|FUEL STREAM(2,1)||(US11946001)|UPGRADED BIOGAS(100,65)|FUEL PRODUCTION(100,20)|UPGRADED BIOGAS AGGREGATION(67,1)|METHANE REFORMING(63,24)|RENEWABLE FEEDSTOCK COPROCESSING(59,3)|BIOGAS(41,186)|RENEWABLE FEEDSTOCK(40,11)|CAPTURED CARBON DIOXIDE(33,23)|BIOGAS COLLECTION(33,4)|BIOGAS PLANT(31,13)|NONRENEWABLE FEEDSTOCK(30,6)|SYNERGISTIC BENEFIT(29,1)|STEAM METHANE REFORMING(27,2)|GEOLOGICAL SEQUESTRATION(25,4)|CARBON DIOXIDE(23,73)|ANAEROBIC DIGESTER(23,15)|DAIRY MANURE(22,2)|SWINE MANURE(22,2)|FEEDSTOCK(21,50)|COGENERATION(20,1)|RENEWABLE CONTENT(19,24)|RAW BIOGAS(19,9)|RENEWABLE FAT(18,3)|CRYOGENIC SEPARATION(17,11)|FEEDSTOCK ANAEROBIC DIGESTION(17,4)|HYDROGENIZING CRUDE OIL(16,1)|STORAGE SITE(15,1)|CARBON CAPTURE(14,17)|FOSSIL NATURAL GAS(14,9)|COMBUSTION ZONE(14,2)|RENEWABLE OIL(14,2)|BASIN(14,1)|PROCESS SYNERGISTIC BENEFIT(14,1)|FUNGIBLE BATCH(13,9)|HYDROGEN PRODUCTION(12,99)|NATURAL GAS DISTRIBUTION(12,25)|METHANE(12,19)|CO2 STORAGE(12,8)|CARBON DIOXIDE STORAGE(12,3)|AMINE SOLVENT(11,2)|HEAT PRODUCTION(11,1)|GCO2E MEGAJOULE(10,24)|CARBON DIOXIDE CAPTURE(10,2)|CO2 DISTRIBUTION(8,9)|RENEWABLE BIOFUEL(8,2)|SINGLE HYDROGEN PLANT(8,2)|TRADABLE CURRENCY(8,2)|BIOMASS FEEDSTOCK DRY TONNE(8,1)|NATURAL GAS(7,41)|CARBON INTENSITY(7,10)|PRODUCT PRODUCTION(7,7)|APPLICABLE REGULATION(7,6)|CO2 SEPARATION(7,6)|BIOGAS STREAM(7,4)|CONCRETE(7,4)|BIO GAS CLEANING(7,3)|CENTRALIZED BIOGAS PLANT(7,3)|ANAEROBIC MICROORGANISM(7,2)|BIOMASS TRANSPORTATION(7,2)|CARBON DIOXIDE DISTRIBUTION(7,2)|CO2 CAPTURE DISAGGREGATION(7,1)|FEEDSTOCK RENEWABLE FRACTION(7,1)|JET FUEL(6,7)|MEMBRANE SEPARATION(6,7)|CO2 REMOVAL(6,6)|LANDFILL GAS(6,5)|HYDROGEN PRODUCTION(6,4)|CAPTURE CO2(6,3)|CO2 PIPELINE(6,3)|HYDROGEN PROVISION(6,3)|RAW(6,3)|BATCH SEGREGATION(6,2)|FUEL CREDIT GENERATION(6,2)|MANAGING(6,2)|REFORMING CATALYST(6,2)|SALINE AQUIFER(6,2)|BIOGAS ATTRIBUTE(6,1)|GASOLINE BASELINE EMISSION(6,1)|BLUE HYDROGEN(5,6)|PARTICULATE(5,6)|ADSORPTION(5,5)|HYDROPROCESSING(5,4)|GRAY HYDROGEN(5,3)|ANAEROBIC OXYGEN(5,2)|APPLICABLE REGULATORY AGENCY(5,2)|CAPITAL BENEFIT(5,2)|CAPTURING CO2(5,2)|ENRICHED HYDROGEN STREAM(5,2)|FACILITY OWNER(5,2)|NET CREDIT(5,2)|REMOTE LOCATION(5,2)|BIO GAS PIPELINE(5,1)|BIOGENIC CO2 RELEASE(5,1)|BIOGENIC SYNGA(5,1)|BIOMASS DIESEL(5,1)|BOILER FEEDWATER(5,1)|CARBON INTENSITY REDUCTION(5,1)|COPROCESSED FEEDSTOCK(5,1)|CRYOGENIC BIOGAS(5,1)|CRYOGENIC CO2 CAPTURE(5,1)|ENDOTHERMIC REFORMING REACTION(5,1)|EXTRACTING BIOENERGY(5,1)|FEEDSTOCK CAPTURE COMBUSTION(5,1)|FEEDSTOCK HYDROGEN CO2(5,1)|FEEDSTOCK PLANT CO2(5,1)|FIRED BURNER(5,1)|FOSSIL FERTILIZER(5,1)|FOSSIL METHANE(5,1)|GOVERNMENT AUTHORITY(5,1)|GOVERNMENT INITIATIVE(5,1)|GOVERNMENTAL AUTHORITY(5,1)|INCENTIVIZE RENEWABLE FUEL(5,1)|INCREMENTAL TRANSITIONING(5,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(5,1)|LIVESTOCK FARM(5,1)|NONGOVERNMENTAL AGENCY(5,1)|NONRENEWABLE GASOLINE(5,1)|NONRENEWABLE METHANE(5,1)|OXIDATIVE REFORMING(5,1)|PRODUCER CREDIT(5,1)|RENEWABLE CONTENT QUANTIFICATION(5,1)|SUGARCANE BAGASSE(5,1)|VALUABLE FUEL CREDIT(5,1)|GEOLOGICAL FORMATION(4,11)|HYDROGEN PURIFICATION(4,9)|PSIG(4,8)|MONOETHANOLAMINE(4,5)|ORGANIC WASTE(4,5)|CERTIFICATE(4,4)|IMPURITY(4,4)|RFS(4,4)|BIOGENIC CARBON DIOXIDE(4,2)|CAPTURED CO2 STORAGE(4,2)|CO2 COLLECTION(4,2)|COLLECTION RADIUS(4,2)|FOSSIL GAS(4,2)|LIFECYCLE GREENHOUSE GAS EMISSION(4,2)|LIQUID TRANSPORTATION FUEL(4,2)|NEGATIVE EMISSION(4,2)|REDUCING LIFECYCLE(4,2)|SYNGA GAS(4,2)|AUTOTHERMAL REFORMING HYDROGEN PLANT(4,1)|AVERAGE GASOLINE BASELINE(4,1)|BARLEY STRAW(4,1)|BAUXITE RESIDUE CARBONATION(4,1)|BIOTRICKLING FILTER(4,1)|CAPTURED STREAM CO2(4,1)|CENTRALIZED FACILITY(4,1)|CO2 CAPTURED STREAM(4,1)|CO2 COMPRESSED STREAM(4,1)|CO2 EQUIVALENT EMISSION GRAM(4,1)|CO2 SELECTIVE MEMBRANE(4,1)|COMPLIANCE PATHWAY(4,1)|ELECTRICALLY HEATED METHANE REFORMER(4,1)|ENERGY INTENSIVE BIOMASS(4,1)|EQ CATALYTIC REFORMING(4,1)|FEEDSTOCK EMANATION(4,1)|FEEDSTOCK EMISSION CREDIT(4,1)|FEEDSTOCK TRANSPORTATION(4,1)|FOSSIL CO2(4,1)|FUEL RENEWABLE CONTENT(4,1)|LACK INFRASTRUCTURE(4,1)|OPERATIVE COMPLICATION(4,1)|PREVAILING REGULATION(4,1)|PRIVATE CONTRACT(4,1)|QUANTIFIABLE BENEFIT(4,1)|SYNERGETIC BENEFIT(4,1)|TRANSPORTATION SECTOR(4,1)|WHEAT STRAW(4,1)|CCSH(3,5)|DERIVED LIQUID HYDROCARBON(3,5)|ENHANCED OIL RECOVERY(3,5)|TRUCK(3,5)|AVIATION FUEL(3,3)|CO2 PRODUCT(3,3)|H2O(3,3)|HYDROCRACKING(3,3)|ORGANIC FRACTION(3,3)|PURGE GAS(3,3)|RAILCAR(3,3)|ALLOWANCE(3,2)|BIODEGRADATION(3,2)|CARBONIZING ATMOSPHERE(3,2)|CORN STOVER(3,2)|DEHYDRATION(3,2)|FEEDSTOCK COST(3,2)|GREEN HYDROGEN(3,2)|HYDROGEN CONTENT(3,2)|HYDROPOWER(3,2)|NUTRIENT(3,2)|PHOTOSYNTHESIS(3,2)|PIPELINE STANDARD(3,2)|PRODUCING RENEWABLE HYDROGEN(3,2)|REACTOR TUBE(3,2)|RENEWABLE ELECTRICITY(3,2)|RENEWABLE HYDROGEN YIELD(3,2)|SUBSTITUTE(3,2)|WITHDRAWN GAS(3,2)|ADSORBENT BED(3,1)|APPLICABLE REGULATORY AUTHORITY(3,1)|CENTRALIZED PROCESSING FACILITY(3,1)|CO2 BIOGAS(3,1)|CO2 GRAM(3,1)|CO2 PURITY(3,1)|CO2 RICH TAIL GAS(3,1)|CONVERSION ELECTRICITY(3,1)|CORN GRAIN(3,1)|COVERED LAGOON(3,1)|FARM WASTE(3,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(3,1)|HYDROGEN TONNE(3,1)|HYDROTHERMAL TREATMENT(3,1)|METHANATION REACTION(3,1)|NEGATIVE CO2 EMISSION(3,1)|ONSHORE SETTING(3,1)|PIPE INTERCONNECTION(3,1)|RENEWABLE ENERGY DIRECTIVE(3,1)|STEAM METHANE(3,1)|STORAGE PERMANENCE(3,1)|UPSTREAM EMISSION(3,1)|VOLUNTARY CARBON(3,1)|FLUE GAS(2,9)|RENEWABLE H2(2,9)|CCSBG(2,4)|AGRICULTURAL RESIDUE(2,3)|BIO GAS SOURCE(2,3)|EMISSION VALUE(2,3)|CO2 CAPTURE(2,2)|ABSORPTION AMINE(2,1)|ABSORPTION COLUMN(2,1)|ACETOGENESIS(2,1)|ACIDOGENESIS(2,1)|ACTIVE ALUMINA(2,1)|ADVANCED BIOFUEL(2,1)|AGRICULTURAL CROP(2,1)|AMMONIA PRODUCTION(2,1)|APPLICABLE QUALITY(2,1)|AUTHORIZATION(2,1)|AVOIDANCE(2,1)|BASELINE LEVEL(2,1)|BECCS COST(2,1)|BIO DEGRADATION PREVENTION(2,1)|BIODIESEL(2,1)|BIOFILTER(2,1)|BUSINESS(2,1)|BYPRODUCT(2,1)|CAPITAL EXPENDITURE(2,1)|CAPTURED CO2 GAS(2,1)|CARBOHYDRATE(2,1)|CARBON STORAGE(2,1)|CELLULOSE ACETATE(2,1)|CELLULOSIC BIOFUEL(2,1)|CO2 CAPTURE REDUCING COST(2,1)|CO2 CONTENT(2,1)|CO2 SEPARATED(2,1)|CO2 TRANSFER(2,1)|COLLECTION ZONE(2,1)|COMPONENT UPSTREAM REMOVAL(2,1)|CONTAMINANT(2,1)|CORN ETHANOL(2,1)|DAIRY(2,1)|DEHUMIDIFIER(2,1)|DETERRENT(2,1)|DIGESTER(2,1)|DIGESTION LEVEL(2,1)|DISTRIBUTED CARBON CAPTURE(2,1)|ECONOMIC REASON(2,1)|ELECTRICITY GRID(2,1)|ELECTROLYSIS(2,1)|EMISSION REDUCTION REGISTRY(2,1)|EMISSION THRESHOLD(2,1)|EMISSIONS REDUCTION COMPARISON(2,1)|EVIDENCE PRODUCTION(2,1)|FOSSIL BASED CO2 EMISSION(2,1)|FOSSIL BASED FEEDSTOCK(2,1)|FOSSIL CARBON DIOXIDE(2,1)|FOSSIL FUEL CONSUMPTION(2,1)|FOSSIL FUEL PRODUCTION(2,1)|FOSSIL SOURCE(2,1)|FUEL MEETING LIFE CYCLE(2,1)|GAS FERMENTATION(2,1)|GEOLOGICAL STORAGE(2,1)|HYDROGEN REFUELING STATION GRID(2,1)|HYDROTHERMAL LIQUEFACTION(2,1)|HZ YIELD(2,1)|IRON SPONGE(2,1)|LIFECYCLE REDUCTION(2,1)|MANDATED VOLUME(2,1)|MESOPHILIC TEMPERATURE(2,1)|NAOH WASHING(2,1)|OFFSHORE SETTING(2,1)|ORGANIC PHYSICAL SCRUBBING(2,1)|PDX REACTION(2,1)|POLYDIMETHYLSILOXANE(2,1)|PURGE STREAM(2,1)|REFINERY GAS(2,1)|REFORMER TUBE(2,1)|REFRIGERATION(2,1)|RELEASING CO2(2,1)|RENEWABLE PRODUCT(2,1)|STANDARD BIOGAS(2,1)|STEAM GENERATION(2,1)|STREAM COMPRESSION(2,1)|SUBSURFACE FORMATION(2,1)|SUPPLY REGION(2,1)|TERM BIOGAS(2,1)|TRANSPORT CO2(2,1)|UNREFINED(2,1)|VIABLE SCALE(2,1)|VOLUNTARY EMISSION REDUCTION(2,1)|WITHDRAWN FEED(2,1)||(US20230374394)|UPGRADED BIOGAS(100,61)|FUEL PRODUCTION(100,20)|UPGRADED BIOGAS AGGREGATION(76,1)|RENEWABLE FEEDSTOCK COPROCESSING(67,3)|METHANE REFORMING(53,21)|BIOGAS(45,184)|RENEWABLE FEEDSTOCK(45,11)|BIOGAS COLLECTION(38,4)|FUEL RENEWABLE CONTENT(38,1)|CAPTURED CARBON DIOXIDE(37,23)|NONRENEWABLE FEEDSTOCK(34,6)|SYNERGISTIC BENEFIT(32,1)|STEAM METHANE REFORMING(31,2)|BIOGAS PLANT(29,12)|GEOLOGICAL SEQUESTRATION(28,4)|RENEWABLE CONTENT(27,24)|ANAEROBIC DIGESTER(27,15)|CARBON DIOXIDE(26,73)|DAIRY MANURE(25,2)|SWINE MANURE(25,2)|FEEDSTOCK(22,49)|RAW BIOGAS(22,9)|COGENERATION(22,1)|RENEWABLE FAT(21,3)|FEEDSTOCK ANAEROBIC DIGESTION(20,4)|CRYOGENIC SEPARATION(19,11)|RENEWABLE HYDROGEN YIELD(18,2)|HYDROGENIZING CRUDE OIL(18,1)|RENEWABLE HYDROGEN(17,51)|STORAGE SITE(17,1)|CARBON CAPTURE(16,17)|FOSSIL NATURAL GAS(16,9)|RENEWABLE OIL(16,2)|BASIN(16,1)|PROCESS SYNERGISTIC BENEFIT(16,1)|FUNGIBLE BATCH(15,9)|HYDROGEN PRODUCTION(14,98)|CARBON DIOXIDE STORAGE(14,3)|METHANE(13,19)|CO2 STORAGE(13,8)|AMINE SOLVENT(13,2)|NATURAL GAS DISTRIBUTION(12,25)|GCO2E MEGAJOULE(12,24)|HEAT PRODUCTION(12,1)|CARBON DIOXIDE CAPTURE(11,2)|CO2 DISTRIBUTION(10,9)|PRODUCT PRODUCTION(10,2)|SINGLE HYDROGEN PLANT(10,2)|RENEWABLE BIOFUEL(9,2)|TRADABLE CURRENCY(9,2)|BIOMASS FEEDSTOCK DRY TONNE(9,1)|NATURAL GAS(8,43)|CARBON INTENSITY(8,10)|APPLICABLE REGULATION(8,6)|CO2 SEPARATION(8,6)|BIOGAS STREAM(8,4)|CONCRETE(8,4)|BIO GAS CLEANING(8,3)|CENTRALIZED BIOGAS PLANT(8,3)|ANAEROBIC MICROORGANISM(8,2)|BIOMASS TRANSPORTATION(8,2)|CARBON DIOXIDE DISTRIBUTION(8,2)|CO2 CAPTURE DISAGGREGATION(8,1)|FEEDSTOCK RENEWABLE FRACTION(8,1)|JET FUEL(7,7)|MEMBRANE SEPARATION(7,7)|CAPTURE CO2(7,3)|CO2 PIPELINE(7,3)|RAW(7,3)|BATCH SEGREGATION(7,2)|FUEL CREDIT GENERATION(7,2)|MANAGING(7,2)|MULTIPLEX ASSAY BIOGAS(7,2)|REFORMING CATALYST(7,2)|SALINE AQUIFER(7,2)|BIOGAS ATTRIBUTE(7,1)|GASOLINE BASELINE EMISSION(7,1)|GREENHOUSE GAS(6,39)|BLUE HYDROGEN(6,6)|CO2 REMOVAL(6,6)|PARTICULATE(6,6)|LANDFILL GAS(6,5)|HYDROPROCESSING(6,4)|HYDROGEN PRODUCTION(6,3)|REMOTE LOCATION(6,2)|BIOGENIC SYNGA(6,1)|CARBON INTENSITY REDUCTION(6,1)|COPROCESSED FEEDSTOCK(6,1)|CRYOGENIC CO2 CAPTURE(6,1)|FEEDSTOCK CAPTURE COMBUSTION(6,1)|FOSSIL FERTILIZER(6,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(6,1)|NONGOVERNMENTAL AGENCY(6,1)|NONRENEWABLE GASOLINE(6,1)|PRODUCER CREDIT(6,1)|RENEWABLE CONTENT QUANTIFICATION(6,1)|SUGARCANE BAGASSE(6,1)|VALUABLE FUEL CREDIT(6,1)|GEOLOGICAL FORMATION(5,11)|HYDROGEN PURIFICATION(5,9)|ADSORPTION(5,5)|CERTIFICATE(5,4)|IMPURITY(5,4)|GRAY HYDROGEN(5,3)|LIFECYCLE GREENHOUSE GAS EMISSION(5,3)|ANAEROBIC OXYGEN(5,2)|APPLICABLE REGULATORY AGENCY(5,2)|CAPITAL BENEFIT(5,2)|CAPTURED CO2 STORAGE(5,2)|CAPTURING CO2(5,2)|ENRICHED HYDROGEN STREAM(5,2)|FACILITY OWNER(5,2)|NET CREDIT(5,2)|AUTOTHERMAL REFORMING HYDROGEN PLANT(5,1)|AVERAGE GASOLINE BASELINE(5,1)|BARLEY STRAW(5,1)|BAUXITE RESIDUE CARBONATION(5,1)|BIO GAS PIPELINE(5,1)|BIOGENIC CO2 RELEASE(5,1)|BIOMASS DIESEL(5,1)|BIOTRICKLING FILTER(5,1)|BOILER FEEDWATER(5,1)|CAPTURED STREAM CO2(5,1)|CENTRALIZED FACILITY(5,1)|CO2 CAPTURED STREAM(5,1)|CO2 COMPRESSED STREAM(5,1)|CO2 EQUIVALENT EMISSION GRAM(5,1)|CO2 SELECTIVE MEMBRANE(5,1)|COMPLIANCE PATHWAY(5,1)|CRYOGENIC BIOGAS(5,1)|ELECTRICALLY HEATED METHANE REFORMER(5,1)|ENDOTHERMIC REFORMING REACTION(5,1)|ENERGY INTENSIVE BIOMASS(5,1)|EQ CATALYTIC REFORMING(5,1)|EXTRACTING BIOENERGY(5,1)|FEEDSTOCK EMANATION(5,1)|FEEDSTOCK EMISSION CREDIT(5,1)|FEEDSTOCK HYDROGEN CO2(5,1)|FEEDSTOCK PLANT CO2(5,1)|FEEDSTOCK TRANSPORTATION(5,1)|FIRED BURNER(5,1)|FOSSIL CO2(5,1)|FOSSIL METHANE(5,1)|FUEL PRODUCT PRODUCTION(5,1)|GOVERNMENT AUTHORITY(5,1)|GOVERNMENT INITIATIVE(5,1)|GOVERNMENTAL AUTHORITY(5,1)|HYDROGEN PROVISION(5,1)|INCENTIVIZE RENEWABLE FUEL(5,1)|INCREMENTAL TRANSITIONING(5,1)|LACK INFRASTRUCTURE(5,1)|LIVESTOCK FARM(5,1)|NONRENEWABLE METHANE(5,1)|OPERATIVE COMPLICATION(5,1)|OXIDATIVE REFORMING(5,1)|PREVAILING REGULATION(5,1)|PRIVATE CONTRACT(5,1)|QUANTIFIABLE BENEFIT(5,1)|SYNERGETIC BENEFIT(5,1)|TRANSPORTATION SECTOR(5,1)|WHEAT STRAW(5,1)|PSIG(4,8)|CCSH(4,5)|MONOETHANOLAMINE(4,5)|ORGANIC WASTE(4,5)|RFS(4,4)|CO2 PRODUCT(4,3)|HYDROCRACKING(4,3)|ORGANIC FRACTION(4,3)|PURGE GAS(4,3)|RAILCAR(4,3)|BIOGENIC CARBON DIOXIDE(4,2)|CO2 COLLECTION(4,2)|COLLECTION RADIUS(4,2)|FEEDSTOCK COST(4,2)|FOSSIL GAS(4,2)|LIQUID TRANSPORTATION FUEL(4,2)|NEGATIVE EMISSION(4,2)|REDUCING LIFECYCLE(4,2)|SYNGA GAS(4,2)|ADSORBENT BED(4,1)|APPLICABLE REGULATORY AUTHORITY(4,1)|CENTRALIZED PROCESSING FACILITY(4,1)|CO2 BIOGAS(4,1)|CO2 GRAM(4,1)|CO2 PURITY(4,1)|CO2 RICH TAIL GAS(4,1)|CONVERSION ELECTRICITY(4,1)|CORN GRAIN(4,1)|COVERED LAGOON(4,1)|FARM WASTE(4,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(4,1)|HYDROTHERMAL TREATMENT(4,1)|METHANATION REACTION(4,1)|NEGATIVE CO2 EMISSION(4,1)|ONSHORE SETTING(4,1)|PIPE INTERCONNECTION(4,1)|RENEWABLE ENERGY DIRECTIVE(4,1)|STEAM METHANE(4,1)|STORAGE PERMANENCE(4,1)|UPSTREAM EMISSION(4,1)|VOLUNTARY CARBON(4,1)|RENEWABLE H2(3,9)|DERIVED LIQUID HYDROCARBON(3,5)|ENHANCED OIL RECOVERY(3,5)|TRUCK(3,5)|CCSBG(3,4)|AVIATION FUEL(3,3)|H2O(3,3)|ALLOWANCE(3,2)|BIODEGRADATION(3,2)|CARBONIZING ATMOSPHERE(3,2)|CORN STOVER(3,2)|DEHYDRATION(3,2)|GREEN HYDROGEN(3,2)|HYDROGEN CONTENT(3,2)|HYDROPOWER(3,2)|NUTRIENT(3,2)|PHOTOSYNTHESIS(3,2)|PIPELINE STANDARD(3,2)|PRODUCING RENEWABLE HYDROGEN(3,2)|REACTOR TUBE(3,2)|RENEWABLE ELECTRICITY(3,2)|SUBSTITUTE(3,2)|WITHDRAWN GAS(3,2)|ABSORPTION AMINE(3,1)|BECCS COST(3,1)|CELLULOSE ACETATE(3,1)|CO2 CONTENT(3,1)|COLLECTION ZONE(3,1)|COMBUSTION ZONE(3,1)|CORN ETHANOL(3,1)|ECONOMIC REASON(3,1)|EMISSION THRESHOLD(3,1)|EVIDENCE PRODUCTION(3,1)|FOSSIL BASED CO2 EMISSION(3,1)|FOSSIL BASED FEEDSTOCK(3,1)|FOSSIL CARBON DIOXIDE(3,1)|FOSSIL FUEL CONSUMPTION(3,1)|FUEL MEETING LIFE CYCLE(3,1)|GAS FERMENTATION(3,1)|GEOLOGICAL STORAGE(3,1)|HYDROGEN REFUELING STATION GRID(3,1)|HYDROTHERMAL LIQUEFACTION(3,1)|HZ YIELD(3,1)|IRON SPONGE(3,1)|LIFECYCLE REDUCTION(3,1)|MANDATED VOLUME(3,1)|MESOPHILIC TEMPERATURE(3,1)|NAOH WASHING(3,1)|OFFSHORE SETTING(3,1)|ORGANIC PHYSICAL SCRUBBING(3,1)|PDX REACTION(3,1)|POLYDIMETHYLSILOXANE(3,1)|PURGE STREAM(3,1)|REFINERY GAS(3,1)|REFORMER TUBE(3,1)|REFRIGERATION(3,1)|RELEASING CO2(3,1)|RENEWABLE PRODUCT(3,1)|STANDARD BIOGAS(3,1)|STEAM GENERATION(3,1)|STREAM COMPRESSION(3,1)|SUBSURFACE FORMATION(3,1)|SUPPLY REGION(3,1)|TERM BIOGAS(3,1)|TRANSPORT CO2(3,1)|UNREFINED(3,1)|VIABLE SCALE(3,1)|VOLUNTARY EMISSION REDUCTION(3,1)|WITHDRAWN FEED(3,1)|FLUE GAS(2,9)|AGRICULTURAL RESIDUE(2,3)|BIO GAS SOURCE(2,3)|EMISSION VALUE(2,3)|CO2 CAPTURE(2,2)|ACETOGENESIS(2,1)|ACIDOGENESIS(2,1)|ACTIVE ALUMINA(2,1)|ADVANCED BIOFUEL(2,1)|AGRICULTURAL CROP(2,1)|AMMONIA PRODUCTION(2,1)|APPLICABLE QUALITY(2,1)|AUTHORIZATION(2,1)|AVOIDANCE(2,1)|BASELINE LEVEL(2,1)|BIO DEGRADATION PREVENTION(2,1)|BIODIESEL(2,1)|BIOFILTER(2,1)|BUSINESS(2,1)|BYPRODUCT(2,1)|CAPITAL EXPENDITURE(2,1)|CAPTURED CO2 GAS(2,1)|CARBOHYDRATE(2,1)|CARBON STORAGE(2,1)|CELLULOSIC BIOFUEL(2,1)|CO2 CAPTURE REDUCING COST(2,1)|CO2 SEPARATED(2,1)|CO2 TRANSFER(2,1)|COMPONENT UPSTREAM REMOVAL(2,1)|CONTAMINANT(2,1)|DAIRY(2,1)|DEHUMIDIFIER(2,1)|DETERRENT(2,1)|DIGESTER(2,1)|DIGESTION LEVEL(2,1)|DISTRIBUTED CARBON CAPTURE(2,1)|ELECTRICITY GRID(2,1)|ELECTROLYSIS(2,1)|EMISSION REDUCTION REGISTRY(2,1)|EMISSIONS REDUCTION COMPARISON(2,1)||(US20250304862)|UPGRADED BIOGAS(100,61)|FUEL PRODUCTION(100,19)|UPGRADED BIOGAS AGGREGATION(68,1)|RENEWABLE FEEDSTOCK COPROCESSING(60,3)|METHANE REFORMING(51,21)|BIOGAS(46,190)|RENEWABLE FEEDSTOCK(33,10)|BIOGAS COLLECTION(33,4)|RENEWABLE CONTENT(31,26)|NONRENEWABLE FEEDSTOCK(30,6)|SYNERGISTIC BENEFIT(29,1)|CARBON DIOXIDE(28,76)|FEEDSTOCK(28,52)|BIOGAS PLANT(26,12)|GEOLOGICAL SEQUESTRATION(25,4)|ANAEROBIC DIGESTER(24,15)|DAIRY MANURE(22,2)|SWINE MANURE(22,2)|CAPTURED CARBON DIOXIDE(21,17)|REDUCING LIFECYCLE(21,3)|RAW BIOGAS(20,9)|COGENERATION(20,1)|PRODUCT PRODUCTION(18,9)|FEEDSTOCK ANAEROBIC DIGESTION(18,4)|CRYOGENIC SEPARATION(17,11)|HYDROGEN PRODUCTION(16,102)|RENEWABLE HYDROGEN(15,52)|METHANE(15,20)|BASIN(15,1)|PROCESS SYNERGISTIC BENEFIT(15,1)|STORAGE SITE(15,1)|CARBON CAPTURE(14,17)|FUNGIBLE BATCH(13,9)|CARBON DIOXIDE STORAGE(12,3)|NATURAL GAS DISTRIBUTION(11,24)|FACILITY(11,16)|FOSSIL NATURAL GAS(11,8)|REMOVED CARBON DIOXIDE(11,5)|CARBON DIOXIDE(11,3)|AMINE SOLVENT(11,2)|HEAT PRODUCTION(11,1)|BIOGAS PRODUCTION(9,14)|SINGLE HYDROGEN PLANT(9,2)|RENEWABLE BIOFUEL(8,2)|TRADABLE CURRENCY(8,2)|BIOMASS FEEDSTOCK DRY TONNE(8,1)|GCO(7,26)|CARBON INTENSITY(7,11)|APPLICABLE REGULATION(7,6)|BIOGAS STREAM(7,4)|CONCRETE(7,4)|BIO GAS CLEANING(7,3)|CENTRALIZED BIOGAS PLANT(7,3)|ANAEROBIC MICROORGANISM(7,2)|BIOMASS TRANSPORTATION(7,2)|CARBON DIOXIDE DISTRIBUTION(7,2)|FEEDSTOCK RENEWABLE FRACTION(7,1)|NATURAL GAS(6,38)|JET FUEL(6,7)|MEMBRANE SEPARATION(6,7)|LANDFILL GAS(6,5)|BIOGAS PRODUCTION(6,4)|HYDROPROCESSING(6,4)|RAW(6,3)|BATCH SEGREGATION(6,2)|FUEL CREDIT GENERATION(6,2)|MANAGING(6,2)|REFORMING CATALYST(6,2)|RENEWABLE FAT(6,2)|SALINE AQUIFER(6,2)|BIOGAS ATTRIBUTE(6,1)|BIOGENIC SYNGA(6,1)|CARBON INTENSITY REDUCTION(6,1)|COPROCESSED FEEDSTOCK(6,1)|FOSSIL FERTILIZER(6,1)|GASOLINE BASELINE EMISSION(6,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(6,1)|NONGOVERNMENTAL AGENCY(6,1)|NONRENEWABLE GASOLINE(6,1)|PRODUCER CREDIT(6,1)|RENEWABLE CONTENT QUANTIFICATION(6,1)|STEAM METHANE REFORMING(6,1)|SUGARCANE BAGASSE(6,1)|VALUABLE FUEL CREDIT(6,1)|GREENHOUSE GAS(5,40)|BLUE HYDROGEN(5,6)|PARTICULATE(5,6)|ADSORPTION(5,5)|GRAY HYDROGEN(5,3)|ANAEROBIC OXYGEN(5,2)|APPLICABLE REGULATORY AGENCY(5,2)|CAPITAL BENEFIT(5,2)|ENRICHED HYDROGEN STREAM(5,2)|FACILITY OWNER(5,2)|NET CREDIT(5,2)|REMOTE LOCATION(5,2)|31CCS BG RH(5,1)|BIO GAS PIPELINE(5,1)|BIOMASS DIESEL(5,1)|BOILER FEEDWATER(5,1)|CRYOGENIC BIOGAS(5,1)|ENDOTHERMIC REFORMING REACTION(5,1)|EXTRACTING BIOENERGY(5,1)|FIRED BURNER(5,1)|FOSSIL METHANE(5,1)|GOVERNMENT AUTHORITY(5,1)|GOVERNMENT INITIATIVE(5,1)|GOVERNMENTAL AUTHORITY(5,1)|INCENTIVIZE RENEWABLE FUEL(5,1)|INCREMENTAL TRANSITIONING(5,1)|LIVESTOCK FARM(5,1)|NONRENEWABLE METHANE(5,1)|OXIDATIVE REFORMING(5,1)|GEOLOGICAL FORMATION(4,11)|HYDROGEN PURIFICATION(4,9)|PSIG(4,8)|MONOETHANOLAMINE(4,5)|ORGANIC WASTE(4,5)|CERTIFICATE(4,4)|IMPURITY(4,4)|RFS(4,4)|BIOGENIC CARBON DIOXIDE(4,2)|CAPTURED STREAM(4,2)|COLLECTION RADIUS(4,2)|FOSSIL GAS(4,2)|HYDROGEN PRODUCTION(4,2)|LIFECYCLE GREENHOUSE GAS EMISSION(4,2)|LIQUID TRANSPORTATION FUEL(4,2)|NEGATIVE EMISSION(4,2)|SYNGA GAS(4,2)|AUTOTHERMAL REFORMING HYDROGEN PLANT(4,1)|AVERAGE GASOLINE BASELINE(4,1)|BARLEY STRAW(4,1)|BAUXITE RESIDUE CARBONATION(4,1)|BIOTRICKLING FILTER(4,1)|CENTRALIZED FACILITY(4,1)|COMPLIANCE PATHWAY(4,1)|ELECTRICALLY HEATED METHANE REFORMER(4,1)|ENERGY INTENSIVE BIOMASS(4,1)|EQ CATALYTIC REFORMING(4,1)|FEEDSTOCK EMANATION(4,1)|FEEDSTOCK EMISSION CREDIT(4,1)|FEEDSTOCK TRANSPORTATION(4,1)|FUEL RENEWABLE CONTENT(4,1)|LACK INFRASTRUCTURE(4,1)|OPERATIVE COMPLICATION(4,1)|PREVAILING REGULATION(4,1)|PRIVATE CONTRACT(4,1)|QUANTIFIABLE BENEFIT(4,1)|SYNERGETIC BENEFIT(4,1)|TRANSPORTATION SECTOR(4,1)|UPGRADED BIOGAS 150(4,1)|WHEAT STRAW(4,1)|DERIVED LIQUID HYDROCARBON(3,5)|ENHANCED OIL RECOVERY(3,5)|MEGAJOULE(3,5)|TRUCK(3,5)|AVIATION FUEL(3,3)|HYDROCRACKING(3,3)|ORGANIC FRACTION(3,3)|PURGE GAS(3,3)|RAILCAR(3,3)|TAIL GAS(3,3)|ALLOWANCE(3,2)|BIODEGRADATION(3,2)|CARBONIZING ATMOSPHERE(3,2)|CORN STOVER(3,2)|DEHYDRATION(3,2)|FEEDSTOCK COST(3,2)|GREEN HYDROGEN(3,2)|HYDROGEN CONTENT(3,2)|HYDROPOWER(3,2)|NUTRIENT(3,2)|PHOTOSYNTHESIS(3,2)|PIPELINE STANDARD(3,2)|PRODUCING RENEWABLE HYDROGEN(3,2)|REACTOR TUBE(3,2)|RENEWABLE ELECTRICITY(3,2)|RENEWABLE HYDROGEN YIELD(3,2)|SUBSTITUTE(3,2)|WITHDRAWN GAS(3,2)|ABSORPTION AMINE(3,1)|ABSORPTION COLUMN(3,1)|ADSORBENT BED(3,1)|APPLICABLE REGULATORY AUTHORITY(3,1)|BECCS COST(3,1)|CELLULOSE ACETATE(3,1)|CENTRALIZED PROCESSING FACILITY(3,1)|COLLECTION ZONE(3,1)|COMBUSTION ZONE(3,1)|CORN ETHANOL(3,1)|CORN GRAIN(3,1)|COVERED LAGOON(3,1)|DISAGGREGATION(3,1)|ECONOMIC REASON(3,1)|EMISSION THRESHOLD(3,1)|EQUIVALENT EMISSION(3,1)|EVIDENCE PRODUCTION(3,1)|FARM WASTE(3,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(3,1)|FEEDSTOCK HYDROGEN(3,1)|FOSSIL BASED FEEDSTOCK(3,1)|FOSSIL CARBON DIOXIDE(3,1)|FOSSIL FUEL CONSUMPTION(3,1)|FUEL MEETING LIFE CYCLE(3,1)|GAS FERMENTATION(3,1)|GEOLOGICAL STORAGE(3,1)|HYDROGEN REFUELING STATION GRID(3,1)|HYDROGEN TONNE(3,1)|HYDROTHERMAL LIQUEFACTION(3,1)|HYDROTHERMAL TREATMENT(3,1)|IRON SPONGE(3,1)|LIFECYCLE REDUCTION(3,1)|MANDATED VOLUME(3,1)|MESOPHILIC TEMPERATURE(3,1)|METHANATION REACTION(3,1)|NAOH WASHING(3,1)|OFFSHORE SETTING(3,1)|ONSHORE SETTING(3,1)|ORGANIC PHYSICAL SCRUBBING(3,1)|PIPE INTERCONNECTION(3,1)|POLYDIMETHYLSILOXANE(3,1)|PURGE STREAM(3,1)|REDUCING LIFECYCLE(3,1)|REFINERY GAS(3,1)|REFORMER TUBE(3,1)|REFRIGERATION(3,1)|RENEWABLE ENERGY DIRECTIVE(3,1)|RENEWABLE OIL(3,1)|RENEWABLE PRODUCT(3,1)|STANDARD BIOGAS(3,1)|STEAM GENERATION(3,1)|STORAGE PERMANENCE(3,1)|STREAM COMPRESSION(3,1)|SUBSURFACE FORMATION(3,1)|SUPPLY REGION(3,1)|TERM BIOGAS(3,1)|UNREFINED(3,1)|UPSTREAM EMISSION(3,1)|VIABLE SCALE(3,1)|VOLUNTARY CARBON(3,1)|VOLUNTARY EMISSION REDUCTION(3,1)|WITHDRAWN FEED(3,1)|FLUE GAS(2,9)|AGRICULTURAL RESIDUE(2,3)|BIO GAS SOURCE(2,3)|EMISSION VALUE(2,3)|ACETOGENESIS(2,1)|ACIDOGENESIS(2,1)|ACTIVE ALUMINA(2,1)|ADVANCED BIOFUEL(2,1)|AGRICULTURAL CROP(2,1)|AMMONIA PRODUCTION(2,1)|APPLICABLE QUALITY(2,1)|AUTHORIZATION(2,1)|AVOIDANCE(2,1)|BASELINE LEVEL(2,1)|BIO DEGRADATION PREVENTION(2,1)|BIODIESEL(2,1)|BIOFILTER(2,1)|BUSINESS(2,1)|BYPRODUCT(2,1)|CAPITAL EXPENDITURE(2,1)|CARBOHYDRATE(2,1)|CARBON DIOXIDE CAPTURE(2,1)|CARBON STORAGE(2,1)|CELLULOSIC BIOFUEL(2,1)|COMPONENT UPSTREAM REMOVAL(2,1)|COMPROMISE(2,1)|CONTAMINANT(2,1)|DAIRY(2,1)|DEHUMIDIFIER(2,1)|DETERRENT(2,1)|DIGESTER(2,1)|DIGESTION LEVEL(2,1)|DISTRIBUTED CARBON CAPTURE(2,1)|ELECTRICITY GRID(2,1)|ELECTROLYSIS(2,1)|EMISSION REDUCTION REGISTRY(2,1)|EMISSIONS REDUCTION COMPARISON(2,1)|FOSSIL FUEL PRODUCTION(2,1)|FOSSIL SOURCE(2,1)|FUEL ENERGY(2,1)|FUEL STREAM(2,1)|FUNDING(2,1)|GAS CONTENT(2,1)|GASOLINE ENERGY EQUIVALENT(2,1)|GOV RESOURCE(2,1)||(WO2022/221954)|HYDROGEN PRODUCTION(100,121)|UPGRADED BIOGAS(100,75)|HYDROGEN(100,48)|RENEWABLE CONTENT(100,29)|FUEL PRODUCTION(100,27)|GREENHOUSE GAS EMISSION(100,7)|LIFECYCLE GREENHOUSE GAS EMISSION(100,5)|METHANE REFORMING(56,26)|BIOGAS(43,212)|UPGRADED BIOGAS AGGREGATION(40,1)|RENEWABLE FEEDSTOCK COPROCESSING(38,2)|CAPTURED CARBON DIOXIDE(34,29)|BIOGAS COLLECTION(34,5)|BIOGAS STREAM(32,8)|CARBON DIOXIDE(31,99)|ANAEROBIC DIGESTION(30,34)|FEEDSTOCK(28,59)|RENEWABLE FEEDSTOCK(23,11)|REDUCING LIFECYCLE(20,4)|METHANE(19,26)|NONRENEWABLE FEEDSTOCK(18,6)|ANEROBIC DIGESTION(17,1)|STEAM METHANE REFORMING(16,2)|GEOLOGICAL SEQUESTRATION(15,4)|FACILITY(14,19)|ANAEROBIC DIGESTER(14,15)|DAIRY MANURE(13,2)|LIFECYCLE REDUCTION(13,2)|SWINE MANURE(13,2)|BECCS COST(13,1)|RENEWABLE HYDROGEN(12,55)|CARBON CAPTURE(12,23)|RENEWABLE FAT(11,3)|COGENERATION(11,1)|CAPTURED CO2(10,20)|CARBON INTENSITY(10,13)|CRYOGENIC SEPARATION(10,11)|CARBON DIOXIDE(10,4)|FEEDSTOCK ANAEROBIC DIGESTION(10,4)|CARBON DIOXIDE STORAGE(10,3)|BIOGAS PLANT(9,12)|CARBON(9,2)|HYDROGENIZING CRUDE OIL(9,1)|FOSSIL NATURAL GAS(8,11)|BIOGAS PRODUCTION(8,6)|PRODUCING RENEWABLE HYDROGEN(8,3)|RENEWABLE OIL(8,2)|BASIN(8,1)|NATURAL GAS DISTRIBUTION(7,25)|FUNGIBLE BATCH(7,9)|CPU CONTENT(7,4)|STORAGE SITE(7,2)|RAW BIOGAS(6,9)|STORAGE(6,6)|FB GCCBE MEGAJOULE(6,4)|REMOVED CARBON DIOXIDE(6,4)|AMINE SOLVENT(6,2)|PRODUCT GREENHOUSE GAS EMISSION(6,2)|HEAT PRODUCTION(6,1)|BIOGAS PRODUCTION(5,15)|CO2 DISTRIBUTION(5,9)|CARBON DIOXIDE CAPTURE(5,2)|RENEWABLE BIOFUEL(5,2)|TRADABLE CURRENCY(5,2)|GREENHOUSE GAS(4,45)|GCCKE MEGAJOULE(4,10)|APPLICABLE REGULATION(4,6)|CO2 SEPARATION(4,6)|AVIATION FUEL(4,4)|CONCRETE(4,4)|BIO GAS CLEANING(4,3)|CENTRALIZED BIOGAS PLANT(4,3)|CO2 PIPELINE(4,3)|FUEL PRODUCTION(4,3)|ANAEROBIC MICROORGANISM(4,2)|BIOMASS TRANSPORTATION(4,2)|CAPITAL CL BENEFIT(4,2)|CARBON DIOXIDE DISTRIBUTION(4,2)|BIOMASS FEEDSTOCK DRY TONNE(4,1)|CO2 CAPTURE DISAGGREGATION(4,1)|FEEDSTOCK RENEWABLE FRACTION(4,1)|NATURAL GAS(3,43)|JET FUEL(3,8)|MEMBRANE SEPARATION(3,7)|CO2 REMOVAL(3,6)|PARTICULATE(3,6)|LANDFILL GAS(3,5)|HYDROPROCESSING(3,4)|NONMETHANE COMPONENT(3,4)|APPLICABLE REGULATORY AUTHORITY(3,3)|BIO GAS PROCESSING(3,3)|CAPTURE CO2(3,3)|RAW(3,3)|RENEWABLE HYDROGEN CL(3,3)|ANAEROBIC OXYGEN(3,2)|APPLICABLE REGULATORY AGENCY(3,2)|BATCH SEGREGATION(3,2)|BLUE HYDROGEN CL(3,2)|CAPTURING CO2(3,2)|COM STOVER(3,2)|ENRICHED HYDROGEN STREAM(3,2)|FACILITY OWNER(3,2)|FOSSIL CO2(3,2)|FUEL CREDIT GENERATION(3,2)|MANAGING(3,2)|NET CREDIT(3,2)|REFORMING CATALYST(3,2)|SALINE AQUIFER(3,2)|BIO GAS PIPELINE(3,1)|BIOGAS ATTRIBUTE(3,1)|BIOGENIC CO2 RELEASE(3,1)|BIOGENIC SYNGA(3,1)|BIOMASS DIESEL(3,1)|BOILER FEEDWATER(3,1)|CARBON INTENSITY REDUCTION(3,1)|COM GRAIN FERMENTATION(3,1)|COMPRESSED FH CL(3,1)|COPROCESSED FEEDSTOCK(3,1)|CRYOGENIC BIOGAS(3,1)|CRYOGENIC CO2 CAPTURE(3,1)|EH GCCBE MEGAJOULE(3,1)|ENDOTHERMIC REFORMING REACTION(3,1)|EXTRACTING BIOENERGY(3,1)|FH SELECTIVE MEMBRANE(3,1)|FIRED BURNER(3,1)|FOSSIL FERTILIZER(3,1)|FOSSIL METHANE(3,1)|GASOLINE BASELINE EMISSION(3,1)|GOVERNMENT AUTHORITY(3,1)|GOVERNMENT INITIATIVE(3,1)|GOVERNMENTAL AUTHORITY(3,1)|INCENTIVIZE RENEWABLE FUEL(3,1)|INCREMENTAL TRANSITIONING(3,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(3,1)|LIVESTOCK FARM(3,1)|NONGOVERNMENTAL AGENCY(3,1)|NONRENEWABLE METHANE(3,1)|OXIDATIVE REFORMING(3,1)|PRODUCER CREDIT(3,1)|RENEWABLE CONTENT QUANTIFICATION(3,1)|SEPARATING CFLIFROM CO2(3,1)|STEAM METHANE REFORMER(3,1)|SUGARCANE BAGASSE(3,1)|VALUABLE FUEL CREDIT(3,1)|GEOLOGICAL FORMATION(2,11)|HYDROGEN PURIFICATION(2,9)|PSIG(2,8)|LOW CARBON ELECTRICITY(2,6)|ADSORPTION(2,5)|MONOETHANOLAMINE(2,5)|ORGANIC WASTE(2,5)|VENTILATION(2,5)|CERTIFICATE(2,4)|IMPURITY(2,4)|RFS(2,4)|CO2 PRODUCT(2,3)|HYDROCRACKING(2,3)|NUTRIENT(2,3)|ORGANIC FRACTION(2,3)|PURGE GAS(2,3)|RAILCAR(2,3)|BIOGENIC CARBON DIOXIDE(2,2)|CO2 COLLECTION(2,2)|COLLECTION RADIUS(2,2)|FEEDSTOCK COST(2,2)|FOSSIL GAS(2,2)|HYDROGEN PRODUCTION(2,2)|LIQUID TRANSPORTATION FUEL(2,2)|NEGATIVE EMISSION(2,2)|SYNGA GAS(2,2)|ADSORBENT BED(2,1)|AUTOTHERMAL REFORMING HYDROGEN PLANT(2,1)|AVERAGE GASOLINE BASELINE(2,1)|BARLEY STRAW(2,1)|BAUXITE RESIDUE CARBONATION(2,1)|BIOTRICKLING FILTER(2,1)|CAPTURED CCKFROM STORAGE(2,1)|CAPTURED STREAM CO2(2,1)|CENTRALIZED FACILITY(2,1)|CENTRALIZED PROCESSING FACILITY(2,1)|CL SCORE(2,1)|CO2 BIOGAS(2,1)|CO2 CAPTURED STREAM(2,1)|CO2 COMPRESSED STREAM(2,1)|CO2 EQUIVALENT EMISSION GRAM(2,1)|CO2 GRAM(2,1)|CO2 PURITY(2,1)|CO2 RICH TAIL GAS(2,1)|CO2 SELECTIVE MEMBRANE(2,1)|COMPLIANCE PATHWAY(2,1)|COVERED LAGOON(2,1)|ELECTRICALLY HEATED METHANE REFORMER(2,1)|EMISSION FB(2,1)|ENERGY INTENSIVE BIOMASS(2,1)|EQ CATALYTIC REFORMING(2,1)|FARM WASTE(2,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(2,1)|FEEDSTOCK EMANATION(2,1)|FEEDSTOCK EMISSION CREDIT(2,1)|FEEDSTOCK TRANSPORTATION(2,1)|FUEL RENEWABLE CONTENT(2,1)|GRAY HYDROGEN CL(2,1)|HYDROTHERMAL TREATMENT(2,1)|LACK INFRASTRUCTURE(2,1)|METHANATION REACTION(2,1)|NEGATIVE CO2 EMISSION(2,1)|ONSHORE SETTING(2,1)|OPERATIVE COMPLICATION(2,1)|PIPE INTERCONNECTION(2,1)|PREVAILING REGULATION(2,1)|PRIVATE CONTRACT(2,1)|QUANTIFIABLE BENEFIT(2,1)|RENEWABLE ENERGY DIRECTIVE(2,1)|STORAGE PERMANENCE(2,1)|SYNERGETIC BENEFIT(2,1)|TRANSPORTATION SECTOR(2,1)|UPSTREAM EMISSION(2,1)|VOLUNTARY CARBON(2,1)|WHEAT STRAW(2,1)|FLUE GAS(1,9)|BECCS(1,5)|DERIVED LIQUID HYDROCARBON(1,5)|ENHANCED OIL RECOVERY(1,5)|TRUCK(1,5)|AGRICULTURAL RESIDUE(1,3)|BIO GAS SOURCE(1,3)|EMISSION VALUE(1,3)|ALLOWANCE(1,2)|BIODEGRADATION(1,2)|CARBONIZING ATMOSPHERE(1,2)|CO2 CAPTURE(1,2)|DEHYDRATION(1,2)|GCCHE MEGAJOULE(1,2)|GREEN HYDROGEN(1,2)|HYDROGEN CONTENT(1,2)|HYDROPOWER(1,2)|METHYL DIETHANOLAMINE(1,2)|PHOTOSYNTHESIS(1,2)|PIPELINE STANDARD(1,2)|REACTOR TUBE(1,2)|RENEWABLE ELECTRICITY(1,2)|RENEWABLE HYDROGEN YIELD(1,2)|SUBSTITUTE(1,2)|WITHDRAWN GAS(1,2)|ABSORPTION AMINE(1,1)|ABSORPTION COLUMN(1,1)|ACETOGENESIS(1,1)|ACIDOGENESIS(1,1)|ACTIVE ALUMINA(1,1)|ADVANCED BIOFUEL(1,1)|AGRICULTURAL CROP(1,1)|AMMONIA PRODUCTION(1,1)|ANALOGY(1,1)|APPLICABLE QUALITY(1,1)|AUTHORIZATION(1,1)|AVOIDANCE(1,1)|BASELINE LEVEL(1,1)|BIO DEGRADATION PREVENTION(1,1)|BIODIESEL(1,1)|BIOFILTER(1,1)|BUSINESS(1,1)|BYPRODUCT(1,1)|C02E MEGAJOULE(1,1)|CALCULATING CL VALUE(1,1)|CAPITAL EXPENDITURE(1,1)|CAPTURED CO2 GAS(1,1)|CAPTURED CO2 STORAGE(1,1)|CARBOHYDRATE(1,1)|CARBON STORAGE(1,1)|CCKFROM HYDROGEN PRODUCTION(1,1)|CEE CONTENT(1,1)|CELLULOSIC BIOFUEL(1,1)|CFB CONTENT(1,1)|CFB RICH GAS(1,1)|CO2 CAPTURE REDUCING COST(1,1)|CO2 CONTENT(1,1)|CO2 SEPARATED(1,1)|CO2 TRANSFER(1,1)|COLLECTION ZONE(1,1)|COMBUSTION ZONE(1,1)|COMPONENT UPSTREAM REMOVAL(1,1)|CONTAMINANT(1,1)|CORN ETHANOL(1,1)|DAIRY(1,1)|DEHUMIDIFIER(1,1)|DETERRENT(1,1)|DIGESTER(1,1)|DIGESTION LEVEL(1,1)|DISTRIBUTED CARBON CAPTURE(1,1)|ECONOMIC REASON(1,1)|ELECTRICITY GRID(1,1)|ELECTROLYSIS(1,1)|EMISSION REDUCTION REGISTRY(1,1)|EMISSION THRESHOLD(1,1)|EMISSIONS REDUCTION COMPARISON(1,1)|EVIDENCE PRODUCTION(1,1)|FH YIELD(1,1)|FOSSIL BASED CO2 EMISSION(1,1)|FOSSIL BASED FEEDSTOCK(1,1)|FOSSIL CARBON DIOXIDE(1,1)|FOSSIL FUEL CONSUMPTION(1,1)|FOSSIL FUEL PRODUCTION(1,1)|FOSSIL NATURAL GAS CL(1,1)|FOSSIL SOURCE(1,1)|FUEL ENERGY(1,1)|FUEL MEETING LIFE CYCLE(1,1)|GAS FERMENTATION(1,1)|GEOLOGICAL STORAGE(1,1)|H2O CO2(1,1)|HYDROGEN REFUELING STATION GRID(1,1)|HYDROTHERMAL LIQUEFACTION(1,1)|IRON SPONGE(1,1)|MANDATED VOLUME(1,1)|MESOPHILIC TEMPERATURE(1,1)|NAOH WASHING(1,1)|NON RENEWABLE GASOLINE(1,1)|OFFSHORE SETTING(1,1)|ORGANIC PHYSICAL SCRUBBING(1,1)|POLYDIMETHYLSILOXANE(1,1)|PURGE STREAM(1,1)|REFINERY GAS(1,1)|REFORMER TUBE(1,1)|REFRIGERATION(1,1)|RELEASING CO2(1,1)|RENEWABLE PRODUCT(1,1)|RENEWAL CONTENT(1,1)|STANDARD BIOGAS(1,1)|STEAM GENERATION(1,1)|STREAM COMPRESSION(1,1)|SUBSURFACE FORMATION(1,1)|SUPPLY REGION(1,1)|TERM BIOGAS(1,1)|TRANSPORT CO2(1,1)|UNREFINED(1,1)|VIABLE SCALE(1,1)|VOLUNTARY EMISSION REDUCTION(1,1)|WITHDRAWN FEED(1,1)||(CA3214954)|HYDROGEN PRODUCTION(100,116)|UPGRADED BIOGAS(100,73)|HYDROGEN(100,48)|RENEWABLE CONTENT(100,29)|FUEL PRODUCTION(100,23)|PRODUCT PRODUCTION(100,13)|GREENHOUSE GAS EMISSION(100,7)|PRODUCT GREENHOUSE GAS EMISSION(100,4)|REDUCING LIFECYCLE(100,2)|METHANE REFORMING(55,25)|BIOGAS(44,213)|UPGRADED BIOGAS AGGREGATION(41,1)|RENEWABLE FEEDSTOCK COPROCESSING(36,3)|CAPTURED CARBON DIOXIDE(34,28)|BIOGAS STREAM(33,8)|BIOGAS COLLECTION(32,4)|CARBON DIOXIDE(31,95)|ANAEROBIC DIGESTION(31,33)|FEEDSTOCK(28,58)|RENEWABLE FEEDSTOCK(24,11)|REDUCING LIFECYCLE(21,4)|METHANE(19,24)|NONRENEWABLE FEEDSTOCK(18,6)|LIFECYCLE GREENHOUSE GAS EMISSION(18,3)|ANEROBIC DIGESTION(17,1)|STEAM METHANE REFORMING(16,2)|FACILITY(15,19)|GEOLOGICAL SEQUESTRATION(15,4)|ANAEROBIC DIGESTER(14,15)|BECCS COST(14,1)|DAIRY MANURE(13,2)|LIFECYCLE REDUCTION(13,2)|SWINE MANURE(13,2)|COGENERATION(12,1)|CARBON CAPTURE(11,22)|RENEWABLE FAT(11,3)|RENEWABLE HYDROGEN(10,52)|CARBON INTENSITY(10,12)|CRYOGENIC SEPARATION(10,11)|CARBON DIOXIDE(10,4)|FEEDSTOCK ANAEROBIC DIGESTION(10,4)|HYDROGENIZING CRUDE OIL(10,1)|FOSSIL NATURAL GAS(9,9)|CARBON(9,2)|CARBON DIOXIDE STORAGE(9,2)|RENEWABLE OIL(9,2)|BASIN(9,1)|STORAGE SITE(9,1)|FUNGIBLE BATCH(8,9)|BIOGAS PRODUCTION(8,6)|PRODUCING RENEWABLE HYDROGEN(8,3)|NATURAL GAS DISTRIBUTION(7,25)|BIOGAS PLANT(7,11)|AMINE SOLVENT(7,2)|GCO2E MEGAJOULE(6,22)|RAW BIOGAS(6,9)|STORAGE(6,6)|REMOVED CARBON DIOXIDE(6,4)|CARBON DIOXIDE CAPTURE(6,2)|COPROCESSING RENEWABLE FEEDSTOCK(6,1)|HEAT PRODUCTION(6,1)|BIOGAS PRODUCTION(5,15)|CO2 DISTRIBUTION(5,9)|RENEWABLE BIOFUEL(5,2)|TRADABLE CURRENCY(5,2)|BIOMASS FEEDSTOCK DRY TONNE(5,1)|GREENHOUSE GAS(4,41)|APPLICABLE REGULATION(4,6)|CO2 SEPARATION(4,6)|AVIATION FUEL(4,4)|CONCRETE(4,4)|BIO GAS CLEANING(4,3)|CENTRALIZED BIOGAS PLANT(4,3)|CO2 PIPELINE(4,3)|FUEL PRODUCTION(4,3)|ANAEROBIC MICROORGANISM(4,2)|BIOMASS TRANSPORTATION(4,2)|CARBON DIOXIDE DISTRIBUTION(4,2)|BIOGAS ATTRIBUTE(4,1)|CO2 CAPTURE DISAGGREGATION(4,1)|FEEDSTOCK RENEWABLE FRACTION(4,1)|GASOLINE BASELINE EMISSION(4,1)|NATURAL GAS(3,41)|GEOLOGICAL FORMATION(3,11)|JET FUEL(3,7)|MEMBRANE SEPARATION(3,7)|BLUE HYDROGEN(3,6)|CO2 REMOVAL(3,6)|PARTICULATE(3,6)|ADSORPTION(3,5)|LANDFILL GAS(3,5)|HYDROPROCESSING(3,4)|CAPTURE CO2(3,3)|RAW(3,3)|ANAEROBIC OXYGEN(3,2)|APPLICABLE REGULATORY AGENCY(3,2)|BATCH SEGREGATION(3,2)|CAPITAL BENEFIT(3,2)|CAPTURING CO2(3,2)|ENRICHED HYDROGEN STREAM(3,2)|FACILITY OWNER(3,2)|FUEL CREDIT GENERATION(3,2)|MANAGING(3,2)|NET CREDIT(3,2)|REFORMING CATALYST(3,2)|SALINE AQUIFER(3,2)|BIO GAS PIPELINE(3,1)|BIOGENIC CO2 RELEASE(3,1)|BIOGENIC SYNGA(3,1)|BIOMASS DIESEL(3,1)|BOILER FEEDWATER(3,1)|COPROCESSED FEEDSTOCK(3,1)|CRYOGENIC BIOGAS(3,1)|CRYOGENIC CO2 CAPTURE(3,1)|ENDOTHERMIC REFORMING REACTION(3,1)|EXTRACTING BIOENERGY(3,1)|FIRED BURNER(3,1)|FOSSIL FERTILIZER(3,1)|FOSSIL METHANE(3,1)|GOVERNMENT AUTHORITY(3,1)|GOVERNMENT INITIATIVE(3,1)|GOVERNMENTAL AUTHORITY(3,1)|HUMAN TI MESCAL(3,1)|INCENTIVIZE RENEWABLE FUEL(3,1)|INCREMENTAL TRANSITIONING(3,1)|INTERMITTENT RENEWABLE FEEDSTOCK SUPPLY(3,1)|LIVESTOCK FARM(3,1)|NONGOVERNMENTAL AGENCY(3,1)|NONRENEWABLE GASOLINE(3,1)|NONRENEWABLE METHANE(3,1)|OXIDATIVE REFORMING(3,1)|PRODUCER CREDIT(3,1)|RENEWABLE CONTENT QUANTIFICATION(3,1)|SUGARCANE BAGASSE(3,1)|VALUABLE FUEL CREDIT(3,1)|HYDROGEN PURIFICATION(2,9)|PSIG(2,7)|LOW CARBON ELECTRICITY(2,6)|BECCS(2,5)|DERIVED LIQUID HYDROCARBON(2,5)|ENHANCED OIL RECOVERY(2,5)|MONOETHANOLAMINE(2,5)|ORGANIC WASTE(2,5)|TRUCK(2,5)|CERTIFICATE(2,4)|IMPURITY(2,4)|RFS(2,4)|CO2 PRODUCT(2,3)|HYDROCRACKING(2,3)|ORGANIC FRACTION(2,3)|PURGE GAS(2,3)|RAILCAR(2,3)|BIOGENIC CARBON DIOXIDE(2,2)|CAPTURED CO2 STORAGE(2,2)|CO2 COLLECTION(2,2)|COLLECTION RADIUS(2,2)|FEEDSTOCK COST(2,2)|FOSSIL GAS(2,2)|HYDROGEN PRODUCTION(2,2)|LIQUID TRANSPORTATION FUEL(2,2)|METHYLDIETHANOLAMINE(2,2)|NEGATIVE EMISSION(2,2)|SYNGA GAS(2,2)|ADSORBENT BED(2,1)|APPLICABLE REGULATORY AUTHORITY(2,1)|AUTOTHERMAL REFORMING HYDROGEN PLANT(2,1)|AVERAGE GASOLINE BASELINE(2,1)|BARLEY STRAW(2,1)|BAUXITE RESIDUE CARBONATION(2,1)|BIOTRICKLING FILTER(2,1)|CAPTURED STREAM CO2(2,1)|CENTRALIZED FACILITY(2,1)|CENTRALIZED PROCESSING FACILITY(2,1)|CO2 BIOGAS(2,1)|CO2 CAPTURED STREAM(2,1)|CO2 COMPRESSED STREAM(2,1)|CO2 EQUIVALENT EMISSION GRAM(2,1)|CO2 GRAM(2,1)|CO2 PURITY(2,1)|CO2 RICH TAIL GAS(2,1)|CO2 SELECTIVE MEMBRANE(2,1)|COMPLIANCE PATHWAY(2,1)|CORN GRAIN(2,1)|COVERED LAGOON(2,1)|ELECTRICALLY HEATED METHANE REFORMER(2,1)|ENERGY INTENSIVE BIOMASS(2,1)|EQ CATALYTIC REFORMING(2,1)|FARM WASTE(2,1)|FEEDSTOCK AVAILABILITY PERSPECTIVE(2,1)|FEEDSTOCK CO2(2,1)|FEEDSTOCK EMANATION(2,1)|FEEDSTOCK EMISSION CREDIT(2,1)|FEEDSTOCK TRANSPORTATION(2,1)|FOSSIL CO2(2,1)|FUEL RENEWABLE CONTENT(2,1)|GRAY HYDROGEN CL(2,1)|HYDROGEN TONNE(2,1)|HYDROTHERMAL TREATMENT(2,1)|LACK INFRASTRUCTURE(2,1)|METHANATION REACTION(2,1)|NEGATIVE CO2 EMISSION(2,1)|ONSHORE SETTING(2,1)|OPERATIVE COMPLICATION(2,1)|PIPE INTERCONNECTION(2,1)|PREVAILING REGULATION(2,1)|PRIVATE CONTRACT(2,1)|QUANTIFIABLE BENEFIT(2,1)|RENEWABLE ENERGY DIRECTIVE(2,1)|STORAGE PERMANENCE(2,1)|SUB STOI CHI(2,1)|TRANSPORTATION SECTOR(2,1)|UPSTREAM EMISSION(2,1)|VOLUNTARY CARBON(2,1)|WHEAT STRAW(2,1)|FLUE GAS(1,9)|RENEWABLE H2(1,5)|AGRICULTURAL RESIDUE(1,3)|BIO GAS SOURCE(1,3)|CCSBG(1,3)|EMISSION VALUE(1,3)|H2O(1,3)|ALLOWANCE(1,2)|BIODEGRADATION(1,2)|CARBONIZING ATMOSPHERE(1,2)|CCSH(1,2)|CO2 CAPTURE(1,2)|CORN STOVER(1,2)|DEHYDRATION(1,2)|GREEN HYDROGEN(1,2)|HYDROGEN CONTENT(1,2)|HYDROPOWER(1,2)|NUTRIENT(1,2)|PHOTOSYNTHESIS(1,2)|PIPELINE STANDARD(1,2)|REACTOR TUBE(1,2)|RENEWABLE ELECTRICITY(1,2)|RENEWABLE HYDROGEN YIELD(1,2)|SUBSTITUTE(1,2)|WITHDRAWN GAS(1,2)|ABSORPTION AMINE(1,1)|ABSORPTION COLUMN(1,1)|ACETOGENESIS(1,1)|ACIDOGENESIS(1,1)|ACTIVE ALUMINA(1,1)|ADVANCED BIOFUEL(1,1)|AGRICULTURAL CROP(1,1)|AMMONIA PRODUCTION(1,1)|APPLICABLE QUALITY(1,1)|AUTHORIZATION(1,1)|AVOIDANCE(1,1)|BASELINE LEVEL(1,1)|BIO DEGRADATION PREVENTION(1,1)|BIODIESEL(1,1)|BIOFILTER(1,1)|BUSINESS(1,1)|BYPRODUCT(1,1)|CALCULATING CL VALUE(1,1)|CAPITAL EXPENDITURE(1,1)|CAPTURED CO2 GAS(1,1)|CARBON STORAGE(1,1)|CELLULOSE ACETATE(1,1)|CELLULOSIC BIOFUEL(1,1)|CO2 CAPTURE REDUCING COST(1,1)|CO2 CONTENT(1,1)|CO2 SEPARATED(1,1)|CO2 TRANSFER(1,1)|COLLECTION ZONE(1,1)|COMBUSTION ZONE(1,1)|COMPONENT UPSTREAM REMOVAL(1,1)|CONTAMINANT(1,1)|CORN ETHANOL(1,1)|DAIRY(1,1)|DEHUMIDIFIER(1,1)|DETERRENT(1,1)|DIGESTER(1,1)|DIGESTION LEVEL(1,1)|DISTRIBUTED CARBON CAPTURE(1,1)|DOCUMENTATION(1,1)|ECONOMIC REASON(1,1)|ELECTRICITY GRID(1,1)|ELECTROLYSIS(1,1)|EMISSION THRESHOLD(1,1)|EVIDENCE PRODUCTION(1,1)|FOSSIL BASED CO2 EMISSION(1,1)|FOSSIL BASED FEEDSTOCK(1,1)|FOSSIL CARBON DIOXIDE(1,1)|FOSSIL FUEL CONSUMPTION(1,1)|FUEL MEETING LIFE CYCLE(1,1)|GAS FERMENTATION(1,1)|GEOLOGICAL STORAGE(1,1)|HYDROGEN REFUELING STATION GRID(1,1)|HYDROTHERMAL LIQUEFACTION(1,1)|IRON SPONGE(1,1)|MANDATED VOLUME(1,1)|MESOPHILIC TEMPERATURE(1,1)|NAOH WASHING(1,1)|NONMETHANE COMPONENT(1,1)|OFFSHORE SETTING(1,1)|ORGANIC PHYSICAL SCRUBBING(1,1)|PDX REACTION(1,1)|POLYDIMETHYLSILOXANE(1,1)|PURGE STREAM(1,1)|REFINERY GAS(1,1)|REFORMER TUBE(1,1)|REFRIGERATION(1,1)|RELEASING CO2(1,1)|RENEWABLE HYDROGEN CL(1,1)|RENEWABLE PRODUCT(1,1)|STANDARD BIOGAS(1,1)|STEAM GENERATION(1,1)|STREAM COMPRESSION(1,1)|SUBSURFACE FORMATION(1,1)|SUPPLY REGION(1,1)|TERM BIOGAS(1,1)|TRANSPORT CO2(1,1)|UNREFINED(1,1)|VIABLE SCALE(1,1)|VOLUNTARY EMISSION REDUCTION(1,1)|WITHDRAWN FEED(1,1)| | (US12359134)|The invention claimed is:|1. A method of producing product, the method comprising:| sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising:| a) collecting biogas comprising methane and carbon dioxide,| b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, and| c) providing the captured carbon dioxide for storage;| providing the at least two upgraded biogases and fossil-based gas for methane reforming, the methane reforming producing syngas; and,| producing the product from a production process that uses at least part of the syngas produced from the methane reforming,| wherein the captured carbon dioxide provided in step (c) of each of the processes is stored and reduces lifecycle greenhouse gas (GHG) emissions associated with the product.|2. The method according to claim 1, wherein the product comprises fuel, wherein the syngas is purified to produce a stream enriched in hydrogen, and wherein the stream enriched in hydrogen is provided for hydrogenating crude oil derived liquid.|3. The method according to claim 1, wherein the product comprises fuel, wherein the syngas is purified to produce a stream enriched in hydrogen, wherein the stream enriched in hydrogen is provided for hydrogenating renewable feedstock, the renewable feedstock comprising renewable oil, renewable fat, or a combination thereof.|4. The method according to claim 1, wherein the product comprises fuel.|5. The method according to claim 4, wherein the fuel comprises gasoline, diesel, jet fuel, or any combination thereof.|6. The method according to claim 1, wherein the product comprises methanol.|7. The method according to claim 1, wherein the product comprises ammonia, fertilizer, or a combination thereof.|8. The method according to claim 1, wherein carbon dioxide captured from one of the processes is provided for storage at a separate location than carbon dioxide captured from another of the processes.|9. The method according to claim 1, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for geological sequestration.|10. The method according to claim 1, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for enhanced oil recovery.|11. The method according to claim 1, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for sequestration in concrete.|12. The method according to claim 1, wherein step (c) of at least one of the processes comprises compressing the captured carbon dioxide and injecting the captured carbon dioxide into a carbon dioxide distribution system configured to transport the captured carbon dioxide to storage.|13. The method according to claim 1, wherein step (b) of at least one of the processes comprises capturing the carbon dioxide using carbon dioxide capture selected from cryogenic separation, membrane separation, and absorption with amine solvent.|14. The method according to claim 1, wherein step (b) of at least one of the processes comprises capturing at least 70% of the carbon dioxide originally present in the biogas.|15. The method according to claim 1, wherein the fossil-based gas comprises fossil-based natural gas.|16. The method according to claim 1, wherein the method does not include storing carbon dioxide produced from the methane reforming.|17. The method according to claim 1, wherein at least one of the at least two upgraded biogases is derived from organic waste.|18. The method according to claim 1, wherein at least one of the at least two upgraded biogases is derived from manure, the manure selected from swine manure and dairy manure.|19. The method according to claim 1, wherein at least one of the at least two upgraded biogases is derived from landfill gas.|20. The method according to claim 1, wherein the process in which at least one of the upgraded biogases is produced further comprises injecting the upgraded biogas into a natural gas distribution system, wherein providing the at least two upgraded biogas comprises withdrawing gas from the natural gas distribution system, the withdrawn gas is associated with environmental attributes of the injected upgraded biogas.|21. The method according to claim 1, wherein the methane reforming comprises steam methane reforming, and wherein at least part of the at least two upgraded biogases and fossil-based gas provided for methane reforming is feedstock for the methane reforming and another part of the at least two upgraded biogases and fossil-based gas is fed to a combustion zone for the steam methane reforming to produce heat for the steam methane reforming.|22. A method of producing product, the process comprising:| (i) sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising:| a) collecting biogas comprising methane and carbon dioxide, and,| b) capturing carbon dioxide from the collected biogas and producing upgraded biogas,| wherein the at least two upgraded biogases and fossil-based gas are used in methane reforming, the methane reforming producing syngas, at least part of the syngas used to produce the product; and| ii) storing the captured carbon dioxide produced from each process, thereby preventing the captured carbon dioxide, or an equal quantity of carbon dioxide displaced by the captured carbon dioxide, from being released to the atmosphere, and reducing lifecycle greenhouse gas (GHG) emissions associated with the product.|23. A method of producing product, the method comprising:| providing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising:| a) collecting biogas comprising methane and carbon dioxide,| b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas;| feeding at least a portion of each upgraded biogas and fossil-based gas to methane reforming, the methane reforming producing syngas, at least part of the syngas used for producing the product; and| wherein at least some of the carbon dioxide removed in step (b) of each of the processes is provided for at least one carbon capture and storage process to reduce lifecycle greenhouse gas (GHG) emissions associated with the product. | (US12359134)|TECHNICAL FIELD|[0001] The present disclosure relates to a process and/or system for producing fuel and/or product(s), and in particular, to a process and/or system for producing fuel and/or products(s) having renewable content that includes carbon capture and storage of carbon dioxide from biogas.|BACKGROUND|[0002] Hydrogen is largely produced from the processing of fossil fuels. For example, hydrogen is often produced from the steam methane reforming (SMR) of natural gas or the gasification of coal. Unfortunately, the production of hydrogen from fossil fuels is associated with significant greenhouse gas (GHG) emissions, and in particular, with significant carbon dioxide (CO2) emissions.|[0003] One approach to reduce the GHG emissions associated with hydrogen production is to use carbon capture and storage (CCS). CCS may, for example, involve capturing CO2 emissions and storing them underground in suitable geological formations (i.e., carbon sequestration). In integrating CCS with hydrogen production from fossil fuels, the fossil based CO2 produced during the hydrogen production is captured and stored in order to prevent it from being released to the atmosphere, thereby reducing GHG emissions of the process (e.g., a reduction of about 80-90%).|[0004] Another approach to reduce the GHG emissions associated with hydrogen production is to use biomass rather than fossil fuels as feedstock. Such hydrogen, may for example, be produced from the gasification or pyrolysis of biomass, or by reforming biogas produced by the anaerobic digestion of biomass. Any CO2 derived from biomass and produced during such processing is biogenic. As the release of biogenic CO2 to the atmosphere simply returns to the atmosphere carbon that was recently fixed by photosynthesis, biogenic CO2 is generally considered to be carbon neutral (e.g., its release does not result in an increase in net GHG emissions). Accordingly, such hydrogen production can have reduced GHG emissions. In addition, such hydrogen (e.g., produced by reforming biogas) may be considered renewable hydrogen.|[0005] In integrating CCS with hydrogen production from biomass, where biogenic CO2 produced during the hydrogen production is captured and stored, there is the potential for so-called “negative emissions.” Negative emissions can be the basis for BECCS, which stands for bioenergy with carbon capture and storage. For example, in some cases, BECCS, which is a group of technologies that combine extracting bioenergy from biomass with CCS, can be viewed as a process where biomass (e.g., plants) is used to extract CO2 from the atmosphere, the biomass is processed to produce bioenergy (e.g., heat, electricity, fuels) while releasing CO2, and the CO2 produced during the processing is captured and stored such that there is there is a transfer of CO2 from the atmosphere to storage.|[0006] While BECCS is increasing discussed as a means to decrease CO2 emissions and/or CO2 concentrations in the atmosphere, some potential challenges that may hinder its success include 1) energy intensive biomass supply chains, 2) low energy conversion efficiencies, and/or 3) high costs (e.g., incentives and/or funding may be required). For example, the cost of BECCS may be largely limited by the cost of CCS. Since the cost of CCS is typically scale sensitive, and since the capture of CO2 is often considered to be one of most expensive parts of CCS, BECCS has been generally considered for applications where the CO2 emissions are relatively pure and/or can be captured from a large point source. Some potential applications of BECCS have been identified as power stations wherein biomass is combusted (e.g., where biogenic CO2 generated from the combustion process is captured and stored), biogas upgrading processes (e.g., where CO2 separated from the biogas captured and stored), and ethanol production processes (e.g., where CO2 produced by fermentation of corn grain is captured and stored).|[0007] It has also been proposed to combine CCS with hydrogen production from upgraded biogas, wherein at least a portion of the biogenic CO2 produced from hydrogen production is captured and stored. Such processes benefit from established technologies for capturing CO2 from hydrogen production (e.g., which can be a large point source). In some cases, the captured and stored CO2 can be accounted for as negative CO2 emission.|SUMMARY|[0008] The present disclosure relates to producing fuel and/or product in a process that uses hydrogen and/or includes the production of hydrogen, wherein a carbon intensity or lifecycle greenhouse gas emissions of at least a portion of the fuel and/or product is reduced by the capture and storage of carbon dioxide from biogas used to produce feedstock for the process (e.g., for hydrogen production). Accordingly, CCS can be incorporated into the process even when the hydrogen production is conducted in areas that do not practically support CCS.|[0009] In accordance with one aspect of the instant invention there is provided a method for producing fuel, the method comprising: sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising: a) collecting biogas comprising methane and carbon dioxide, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, and c) providing the captured carbon dioxide for storage; providing the at least two upgraded biogases for use as feedstock at a facility that has hydrogen production, the hydrogen production comprising methane reforming; and, producing a fuel having renewable content in a fuel production process that uses hydrogen produced from the hydrogen production as a feedstock, wherein the captured carbon dioxide provided in step (c) of each of the processes is stored and reduces the carbon intensity of the fuel. In some aspects, the fuel production comprises hydrogenating crude oil derived liquid hydrocarbon with the renewable hydrogen to produce the fuel. In some aspects, the fuel production comprises hydrogenating a renewable feedstock selected from renewable oil and renewable fat to produce the fuel. In some aspects, the fuel is selected from gasoline, diesel, and jet fuel. In some aspects, the fuel is aviation fuel. In some aspects, carbon dioxide captured from one of the processes is provided for storage at a separate location than carbon dioxide captured from another of the processes. In some aspects, step (c) of at least one of the processes comprises providing the captured carbon dioxide for geological sequestration. In some aspects, step (c) of at least one of the processes comprises providing the captured carbon dioxide for enhanced oil recovery. In some aspects, step (c) of at least one of the processes comprises providing the captured carbon dioxide for sequestration in concrete. In some aspects, step (c) of at least one of the processes comprises compressing the captured carbon dioxide and injecting the captured carbon dioxide into a carbon dioxide distribution system configured to transport the captured carbon dioxide to storage. In some aspects, step (b) of at least one of the processes comprises capturing the carbon dioxide using carbon dioxide capture selected from cryogenic separation, membrane separation, and absorption with amine solvent. In some aspects, step (b) of at least one of the processes comprises capturing at least 70% of the carbon dioxide originally present in the biogas. In some aspects, feedstock for the hydrogen production comprises the least two upgraded biogases and fossil based natural gas. In some aspects, the process does not include storing carbon dioxide produced from the hydrogen production. In some aspects, at least one of the at least two upgraded biogases is derived from organic waste. In some aspects, at least one of the at least two upgraded biogases is derived from manure, the manure selected from swine manure and dairy manure. In some aspects, at least one of the at least two upgraded biogases is derived from landfill gas. In some aspects, at least one of the at least two upgraded biogases is transported to the hydrogen plant using a natural gas distribution system.|[0010] In accordance with one aspect of the instant invention there is provided a process for producing fuel having renewable content, the process comprising: a) providing at least two biogas streams, each of the at least two biogas streams comprising methane and carbon dioxide; b) processing each of the at least two biogas streams, the processing comprising carbon capture and biogas upgrading, the processing of each of the at least two biogas streams producing upgraded biogas and captured carbon dioxide; c) providing the upgraded biogas produced from the processing of the at least two biogas streams for use as a feedstock at a facility that has hydrogen production, the hydrogen production comprising methane reforming, the hydrogen production producing hydrogen used as a feedstock in a fuel production process, the fuel production process producing fuel having renewable content; and d) storing the captured carbon dioxide produced from the processing of the at least two biogas streams, thereby preventing the captured carbon dioxide, or an equal quantity of carbon dioxide displaced by the captured carbon dioxide, from being released to the atmosphere, and reducing a carbon intensity of the fuel.|[0011] In accordance with one aspect of the instant invention there is provided a process for producing fuel having renewable content, the process comprising: sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a biogas production process comprising: a) collecting biogas comprising methane and carbon dioxide, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, c) providing the captured carbon dioxide for storage; providing the at least two upgraded biogases for use as feedstock at a facility that has hydrogen production, the hydrogen production comprising methane reforming; and producing a fuel having renewable content in a fuel production process that uses hydrogen produced from the hydrogen production as a feedstock; and storing the captured carbon dioxide provided in step (c) of each of the biogas production processes, thereby reducing a carbon intensity of the fuel.|[0012] In accordance with one aspect of the instant invention there is provided a method for producing one or more products, the method comprising: providing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising: a) collecting biogas comprising methane and carbon dioxide, b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas; providing at least a portion of each upgraded biogas from the plurality as feedstock for hydrogen production, the hydrogen production comprising methane reforming, renewable hydrogen produced from the hydrogen production used for producing the one or more products; and storing carbon dioxide removed in b) from at least two of the processes, thereby preventing the removed carbon dioxide, or an equal quantity of carbon dioxide displaced by the removed carbon dioxide, from being released to the atmosphere, the storing reducing lifecycle GHG emissions of the one or more products.|[0013] In accordance with one aspect of the instant invention there is provided a method for producing one or more products, the method comprising: providing a plurality of upgraded biogases for producing renewable hydrogen via methane reforming, the renewable hydrogen for use in producing the one or more products, each upgraded biogas in the plurality produced in a respective process comprising: a) collecting biogas comprising methane and carbon dioxide, b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas; reducing lifecycle greenhouse gas emissions of the one or more products, the reducing comprising carrying out a plurality of carbon capture and storage processes, each of the carbon capture and storage processes in the plurality storing at least a portion of the carbon dioxide removed in step b) of one of the biogas production processes.|[0014] In accordance with one aspect of the instant invention there is provided a method for producing one or more products, the method comprising: producing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising: a) feeding biogas comprising methane and carbon dioxide into biogas upgrading, the biogas produced by anaerobic digestion, the biogas upgrading removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas, and b) processing digestate from the anaerobic digestion; providing at least a portion of each upgraded biogas from the plurality as feedstock for hydrogen production, the hydrogen production comprising methane reforming, renewable hydrogen produced from the hydrogen production used for producing the one or more products; and storing carbon dioxide removed in a) and carbon-containing material produced in b) from at least two of the biogas production processes, the storing reducing lifecycle GHG emissions of the one or more products.|[0015] In accordance with one aspect of the instant invention there is provided a method for reducing a lifecycle greenhouse gas emissions of one or more products, the one or products produced in a production process that consumes hydrogen, the hydrogen produced in a hydrogen production process that comprises methane reforming, the method comprising: providing a plurality of upgraded biogases, at least a portion of each of the upgraded biogases in the plurality provided as feedstock for the hydrogen production or a production process comprising the hydrogen production, each of the upgraded biogases produced in a respective process comprising: a) collecting biogas produced from anaerobic digestion of biomass, the biogas comprising methane and carbon dioxide, and b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas, storing carbon-containing material obtained or derived from at least two of the respective processes as part one or more carbon capture and storage processes, thereby reducing the lifecycle greenhouse gas emissions of the one or more products, the carbon-containing material comprising carbon dioxide.|(US12359134)|BRIEF DESCRIPTION OF THE DRAWINGS|[0016] FIG. 1 is a simplified process flow diagram of one embodiment of an SMR based hydrogen plant;|[0017] FIG. 2 is a simplified process flow diagram according to an embodiment of the invention; and|[0018] FIG. 3 is a simplified process flow diagram according to an embodiment of the invention.|(US12359134)|DETAILED DESCRIPTION|[0019] Certain exemplary embodiments of the invention now will be described in more detail, with reference to the drawings, in which like features are identified by like reference numerals. The invention may, however, be embodied in many different forms and should not be construed as limited to the embodiments set forth herein.|[0020] The terminology used herein is for the purpose of describing certain embodiments only and is not intended to be limiting of the invention. For example, as used herein, the singular forms “a,” “an,” and “the” may include plural references unless the context clearly dictates otherwise. The terms “comprises”, “comprising”, “including”, and/or “includes”, as used herein, are intended to mean “including but not limited to.” The term “and/or”, as used herein, is intended to refer to either or both of the elements so conjoined. The phrase “at least one” in reference to a list of one or more elements, is intended to refer to at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements. Thus, as a non-limiting example, the phrase “at least one of A and B” may refer to at least one A with no B present, at least one B with no A present, or at least one A and at least one B in combination. In the context of describing the combining of components by the “addition” or “adding” of one component to another, or the separating of components by the “removal” or “removing” of one component from another, those skilled in the art will understand that the order of addition/removal is not critical (unless stated otherwise). The terms “remove”, “removing”, and “removal”, with reference to one or more impurities, contaminants, and/or constituents of biogas, includes partial removal. The terms “cause” or “causing”, as used herein, may include arranging or bringing about a specific result (e.g., a withdrawal of a gas), either directly or indirectly, or to play a role in a series of activities through commercial arrangements such as a written agreement, verbal agreement, or contract. The term “associated with”, as used herein with reference to two elements (e.g., a fuel credit associated with the transportation fuel), is intended to refer to the two elements being connected with each other, linked to each other, related in some way, dependent upon each other in some way, and/or in some relationship with each other. The terms “first”, “second”, etc., may be used to distinguish one element from another, and these elements should not be limited by these terms. The term “plurality”, as used herein, refers to two or more. The term “providing” as used herein with respect to an element, refers to directly or indirectly obtaining the element and/or making the element available for use. The terms “upstream” and “downstream”, as used herein, refer to the disposition of a step/stage in the process with respect to the disposition of other steps/stages of the process. For example, the term upstream can be used to describe to a step/stage that occurs at an earlier point of the process, whereas the term downstream can be used to describe a step/stage that occurs later in the process. Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art.|[0021] The term “biomass”, as used herein, refers to organic material originating from plants, animals, or micro-organisms (e.g., including plants, agricultural crops or residues, municipal wastes, and algae). Biomass is a renewable resource, which can be naturally replenished on a human timescale, and which can be used to produce bioenergy, biofuels (e.g., biogas), and/or renewable products (e.g., chemicals).|[0022] The term “biogas”, as used herein, refers to a gas mixture that contains methane produced from biomass. While biogas is predominately produced from the anaerobic digestion (AD) of biomass, it is also possible to produce biogas from the gasification of biomass. For example, the gasification of biomass may produce syngas, which may be cleaned up, and methanated. When produced from the anaerobic digestion of biomass, raw biogas typically includes methane (CH4), carbon dioxide (CO2), and can contain water (H2O), nitrogen (N2), hydrogen sulfide (H2S), ammonia (NH3), oxygen (O2), volatile organic compounds (VOCs), and/or siloxanes, depending up its source. The term biogas, as used herein, can refer to raw biogas, cleaned biogas, or upgraded biogas.|[0023] The term “raw biogas”, as used herein, refers to biogas as obtained from its source (e.g., anaerobic digester or landfill) before it is treated to remove any chemical components (e.g., CO2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates). Raw biogas can be subjected to biogas cleaning to produce cleaned biogas or subjected to biogas upgrading to produce upgraded biogas.|[0024] The term “biogas cleaning”, as used herein, refers to a process where biogas (e.g., raw biogas) is treated to remove one or more components (e.g., H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), but does not remove a significant amount of CO2 and/or N2 (e.g., the calorific value of the biogas may not change significantly as a result of biogas cleaning).|[0025] The term “biogas upgrading”, as used herein, refers to a process where biogas (e.g., raw or cleaned biogas) is treated to remove one or more components (e.g., CO2, N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), wherein the treatment is selected to increase the calorific value of the biogas. For example, biogas upgrading typically includes removing CO2 and/or N2. Biogas upgrading, which can include biogas cleaning, produces upgraded biogas. The term “upgraded biogas”, as used herein, can refer to a partially purified biogas (i.e., requires further treatment in order to meet applicable specifications) or renewable natural gas (RNG). The term “upgraded biogas”, as used herein, can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of upgraded biogas that was injected into the natural gas distribution system (e.g., upgraded biogas that was transported as a fungible batch in a natural gas pipeline).|[0026] The term “renewable natural gas” or “RNG”, as used herein, refers to biogas that has been upgraded to meet or exceed applicable natural gas pipeline specifications, meet or exceed applicable quality specifications for vehicle use (e.g., CNG specifications), and/or natural gas withdrawn from a natural gas distribution system that is associated with the environmental attributes of biogas injected into the natural gas distribution system (e.g., a gas that qualifies as RNG under applicable regulations). For example, the term RNG can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of RNG, upgraded from biogas, that was injected into the natural gas distribution system. Pipeline specifications include specifications required for biogas for injection into a natural gas distribution system. Pipeline quality standards or specifications may vary by region and/or country in terms of value and units. For example, pipelines standards may require the RNG to have a CH4 level that is at least 95% or have a heating value of at least 950 BTU/scf. The percentages used to quantify gas composition and/or a specific gas content, as used herein, are expressed as mol %, unless otherwise specified. More specifically, they are expressed by mole fraction at standard temperature and pressure (STP), which is equivalent to volume fraction.|[0027] The term “natural gas” or “NG”, as used herein, refers a gas mixture rich in hydrocarbons, where the primary component is CH4. The term “gas” or “gas mixture”, as used herein, refers to a fluid that is gaseous at standard temperatures and pressures, unless indicated otherwise.|[0028] The term “environmental attributes”, as used herein with regard to a specific material (e.g., biogas), refers to any and all attributes related to the material, including all rights, credits, benefits, or payments associated with the renewable nature of the material and/or the reduction in or avoidance of fossil fuel consumption or reduction in lifecycle GHG gas emissions associated with the use of the material. Some non-limiting examples of environmental attributes include verified emission reductions, voluntary emission reductions, offsets, allowances, credits, avoided compliance costs, emission rights and authorizations, certificates, voluntary carbon units, under any law or regulation, or any emission reduction registry, trading system, or reporting or reduction program for GHG gas emissions that is established, certified, maintained, or recognized by any international, governmental, or nongovernmental agency.|[0029] The terms “capturing and storing”, as used herein with reference to CO2, refers to capturing the CO2 and storing the captured CO2 to prevent the captured CO2, or an equal quantity of CO2 displaced physically by the captured CO2, from being released to the atmosphere. Capturing the CO2 can include removing CO2 from a gas mixture (e.g., biogas, syngas) using any suitable separation technology, or if the CO2 is relatively pure, capturing the CO2 can simply refer to collecting the CO2 (e.g., in a pipe). Storing the captured CO2 can include sequestering it underground (e.g., trapping it in geological formations, such as saline aquifers, or using it for enhanced oil recovery (EOR)), or can include storing the captured CO2 in one or more products (e.g., using the captured CO2 as a resource to create valuable products such plastics, concrete, etc.). For example, “capturing and storing CO2” can be part of one or more processes commonly referred to as “carbon capture and sequestration”, “carbon capture and utilization” or CCU, or “carbon capture, utilization and storage” or CCUS. In general, capturing and storing CO2 can also include compressing the captured CO2 (e.g., to produce liquid CO2 or for injection into a CO2 distribution system) and transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). As will be understood by those skilled in the art, it can be advantageous to store the captured CO2, using a method recognized by the applicable regulatory authority for reducing GHG emissions and/or mitigating climate change.|[0030] The term “carbon intensity” or “CI” refers to the quantity of lifecycle GHG emissions, per unit of fuel energy, and is often expressed in grams of CO2 equivalent emissions per unit of fuel (e.g., gCO2e/MJ or gCO2e/MMBTU). As will be understood by those skilled in the art, CI and/or lifecycle GHG emissions are often determined using Lifecycle Analysis (LCA), which identifies and estimates all GHG emissions in producing fuel and/or product, from the growing or extraction of raw materials, to the production of the fuel and/or product, through to the end use (e.g., well-to-wheel). Those skilled in the art will understand that CI values and/or lifecycle GHG emissions for a given fuel and/or product can be dependent upon the LCA methodology used (e.g., as required by the applicable regulatory authority). Methodologies for calculating CI values and/or lifecycle GHG emissions according to various regulatory bodies are well known in the art and can be readily calculated by those of ordinary skill in the art. The CI values recited herein are determined using the CA-GREET3.0 model (e.g., see, https://ww2.arb.ca.gov/resources/documents/lcfs-life-cycle-analysis-models-and-documentation), unless otherwise specified.|[0031] The present disclosure relates to producing fuel and/or product in a process (e.g., fuel production process) that uses hydrogen and includes carbon capture and storage, wherein the carbon capture and storage includes the carbon capture and storage of CO2 removed from biogas (e.g., raw biogas).|[0032] Raw biogas produced from the anaerobic digestion of biomass can have a significant CO2 content (e.g., about 35%), which reduces the calorific value of the biogas (i.e., relative to pure methane). As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings. Alternatively, raw or cleaned biogas can be upgraded (e.g., to RNG) and used as a substitute for fossil based natural gas (e.g., used as a transportation fuel in the form of compressed RNG (bio-CNG) or liquefied RNG (bio-LNG)).|[0033] As a substitute for fossil based natural gas, upgraded biogas (e.g., RNG) may be used to produce renewable hydrogen using any technology suitable for converting natural gas to hydrogen (e.g., methane reforming). Renewable hydrogen, which can be in gas or liquid form, is very versatile as it can be used as fuel, converted into electricity, and/or used as industrial feedstock (e.g., to produce fuel, fuel intermediates, or products). For example, renewable hydrogen can power fuel cell electric vehicles (FCEVs), which emit no tailpipe emissions other than water, can be run through a fuel cell to power the electricity grid, or can be used in oil refining, ammonia production, fertilizer production, methanol production, and/or steel production. As described herein, renewable hydrogen also can be used to produce fuels (e.g., liquid fuel such gasoline, diesel, and/or jet fuel) that are renewable and/or have renewable content.|[0034] Converting upgraded biogas (e.g., RNG) to renewable hydrogen by SMR is advantageous in that it exploits technology that is well established for natural gas. Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations. While the relatively small scale and/or remote locations may be advantageous when the goal is to produce a grid of hydrogen refueling stations for FCEVs (e.g., where multiple geographically spaced small scale hydrogen plants can avoid transport and storage problems with hydrogen), such distributed hydrogen production cannot take advantage of economies of scale (e.g., SMR based hydrogen production is more economical when operated at a large scale), and thus is more expensive. Given the low value of raw biogas, the relatively small scale of many biogas plants, the cost of biogas upgrading, and/or the cost of SMR, it may be challenging to find facility owners willing to collect biogas and convert it to hydrogen, particularly since other uses of biogas are more economical.|[0035] It may be particularly challenging to find facility owners further willing to integrate CCS with such processes. Distributed carbon capture may be considered unfavorable compared to centralized large-scale carbon capture. For example, the cost of CCS is typically scale sensitive, and since distributed hydrogen production is generally small scale, the cost of CCS for distributed hydrogen production may be prohibitive. In addition, a lack infrastructure (e.g., CO2 pipelines) and/or space-consuming CO2 purification and capture equipment may be a deterrent for distributed CCS.|[0036] While large-scale CCS has been demonstrated for SMR plants that process fossil based natural gas, it is not cheap, and is not necessarily simple. For example, consider the hydrogen plant illustrated in FIG. 1. A stream of preheated natural gas 1 is desulfurized (not shown) and fed, along with steam 2, into the reactor tubes for the SMR 10, which contain the reforming catalyst. Streams of natural gas 3 and combustion air 4 are fed into the SMR burners, which provide the heat required for the endothermic reforming reaction. The syngas 15 produced from the SMR is fed to water gas shift (WGS) 20 to produce more hydrogen. The resulting syngas 25, which may also be referred to as shifted gas, is cooled (not shown) and purified using pressure swing adsorption (PSA) 30, which produces a stream enriched in hydrogen 32 and a purge stream 34. The purge stream 34, which may contain unconverted CH4, H2, CO2, and/or CO, is fed back to SMR 10, where it is used to provide process heat for the SMR (e.g., fuel the SMR burners). More specifically, the purge stream 34 is combusted together with the stream of natural gas 3.|[0037] In the hydrogen production process illustrated in FIG. 1, there are two sources of CO2, namely, CO2 produced from the feedstock 1 for the SMR (e.g., CO2 in the syngas 25), which can make up about 60% of the total CO2 produced, and CO2 produced from the fuel 3 for SMR (e.g., CO2 in the flue gas 12), which can make up about 40% of the total CO2 produced, depending upon the configuration of the hydrogen plant. In terms of capturing CO2, there are various options of how and where the CO2 may be captured, each with different energy requirements and/or yields. FIG. 1 identifies three possible options.|[0038] The first option, which is labelled A, captures CO2 from the flue gas 12, and thus captures both CO2 from the feedstock and CO2 from the fuel (e.g., may capture up to about 90% of the total CO2 produced). The second option, which is labelled B, captures CO2 from the syngas 25, and thus captures only the CO2 from the feedstock (e.g., about 60% of the CO2). The third option, which is labelled C, captures CO2 from the purge gas 34, and thus also captures only the CO2 from the feedstock. While the first option theoretically can capture more CO2 from the hydrogen production, capturing carbon dioxide from the syngas 25 (e.g., using vacuum pressure swing adsorption (VPSA) or an absorption amine unit) or from the purge gas 34 (e.g., using an activated amine process) may be more technically and/or economically feasible. For example, relative to the syngas 25, the flue gas may have a relatively low CO2 concentration (e.g., relatively low partial pressure) and/or may be at a lower pressure (e.g., atmospheric). In addition, the flue gas may contain N2 (N2—CH4 separations may be more challenging than CO2—CH4 separations).|[0039] In general, the SMR of fossil based natural gas to produce hydrogen can produce significant GHG emissions. While cooling of the syngas can allow heat recovery back into the process (e.g., steam generation and boiler feed water pre-heating), thereby preventing GHG emissions that would be associated with the heat, the resulting hydrogen can still have a high CI. For example, hydrogen produced from the SMR of fossil based natural gas, which is often referred to as “grey hydrogen,” may have a CI of about 100 gCO2e/MJ. When CCS is integrated with the SMR of fossil based natural gas, the resulting hydrogen it is often referred to as “blue hydrogen.” As will be understood by those skilled in the art, the CI of blue hydrogen is dependent on both the hydrogen production and how much of the fossil based CO2 is captured and stored. For example, in the case where only the CO2 from the feedstock is captured and stored (i.e., not the flue gas), blue hydrogen may have a CI of about 45 gCO2e/MJ.|[0040] As discussed herein, another approach to reduce the CI of hydrogen is to use a renewable feedstock (e.g., use RNG instead of fossil based natural gas), thereby producing renewable hydrogen. The CI of renewable hydrogen produced by the SMR of RNG can be dependent on the CI of the RNG, which can be dependent upon its source. For example, compared to the CI of fossil based natural gas, which can be about 80 gCO2e/MJ, RNG produced from a landfill may have a CI of about 46 gCO2e/MJ, whereas RNG produced from manure may have a CI of about −271 gCO2e/MJ of CH4 (e.g., as a result of avoided GHG emissions). Assuming that fossil based natural gas is used to fuel the SMR (e.g., fuel stream 3 is fossil based natural gas), the CI of renewable hydrogen produced by the SMR of landfill based RNG may be about 65 gCO2e/MJ (e.g., higher than blue hydrogen). If this process is integrated with CCS, wherein only the CO2 from the feedstock for SMR is captured and stored, the renewable hydrogen may have a CI of about 11 gCO2e/MJ. Such calculations are discussed in further detail with regard to Table 1. For comparative purposes, the CI of compressed H2 from electrolysis run with green electricity, which can be referred to as “green hydrogen”, may be less than 10 gCO2e/MJ.|[0041] The present disclosure relates to at least one process/system wherein at least a portion of the feedstock for hydrogen production and/or the fuel and/or product production is sourced from a plurality of biogas plants. Accordingly, the hydrogen production and/or fuel/product production can benefit from the economies of scale and/or higher efficiency. However, rather than relying on the capture and storage of CO2 produced from hydrogen production, the carbon capture and storage is distributed (i.e., biogenic CO2 is captured at a plurality of biogas plants).|[0042] While CCS at a plurality of biogas plants can be more expensive than CCS at a single hydrogen plant, there are various advantages and/or synergistic benefits of the process(es)/system(s) of instant disclosure. For example, it allows the benefits of CCS to accrue to hydrogen plants where CCS is not feasible (e.g., for economic reasons and/or technical reasons, such as extensive distances between the hydrogen plant and the storage site). Another advantage is that it can allow incremental transitioning, where upgraded biogas (associated with the distributed CCS) is co-processed with fossil based natural gas, thereby gradually increasing the production of hydrogen having a low CI. Advantageously, this can be achieved using existing hydrogen plants without modification. Yet another advantage is that it facilitates the aggregation of upgraded biogas from several locations (e.g., several biogas plants) and several CCS storage sites (e.g., basins) into one hydrogen production process.|[0043] One potential synergistic advantage of the process(es)/system(s) disclosure disclosed herein relates to capital efficiency. While the capital cost of distributed CCS from a plurality of biogas plants can be higher than the cost of CCS at a single hydrogen plant, the CI benefits of the capital for the distributed CCS accrues only to the upgraded biogas. In contrast, the CI benefits of the capital for CCS from centralized hydrogen production can accrue equally to all H2 produced (e.g., the CCS can be conducted on both renewable and fossil based feedstocks, and thus can be conducted on a much larger scale). In circumstances where biofuels are treated differently, this can create special advantages.|[0044] Referring to FIG. 2, there is shown an embodiment of the disclosure. Biomass is converted to biogas via multiple biogas productions 50i, 50ii, 50iii, 50iv. For example, each of the multiple biogas productions 50i, 50ii, 50iii, 50iv can include the anaerobic digestion of one or more feedstocks. In general, the feedstock for the multiple biogas productions 50i, 50ii, 50iii, 50iv can be the same or different. For example, each of the multiple biogas productions 50i, 50ii, 50iii, 50iv, may be conducted at landfill or anaerobic digester. Each of the multiple biogas productions 50i, 50ii, 50iii, 50iv produces biogas (e.g., raw biogas) that is treated in respective processing 100i, 100ii, 100iii, 100iv, to provide upgraded biogas 150i, 150ii, 150iii, 150iv, at least a portion of each provided to a facility 400a having hydrogen production 200. For example, at least part of the processing 100i, 100ii, 100iii, 100iv maybe conducted at a biogas plant (e.g., located close to the source of biogas) and may be transported to the facility that has hydrogen production 400a. Hydrogen production 200 converts at least a portion of the upgraded biogas (e.g., RNG) to renewable hydrogen (e.g., via SMR). The renewable hydrogen in the H2 product 275 is used in a fuel and/or product production process 500 that produces the fuel/product 575 (e.g., a transportation fuel). In addition to biogas upgrading, the processing 100i, 100ii, 100iii, 100iv also includes carbon capture wherein at least a portion of the CO2 from each of the biogases (e.g., generated during anaerobic digestion) is captured. The captured CO2 170i, 170ii, 170iii, 170iv is provided for storage 300.|[0045] In FIG. 2, the facility 400a having hydrogen production 200 is separate from the fuel and/or product production facility (e.g., is commercial hydrogen plant). In FIG. 3, the facility 400b having hydrogen production 200 is the fuel and/or product production facility.|[0046] In general, the upgraded biogas 150i, 150ii, 150iii, 150iv may be transported to hydrogen production 200, the captured CO2 170i, 170ii, 170iii, 170iv may be transported to storage 300, and/or the hydrogen product 275 may be transported to the fuel and/or product production facility, using any suitable mode of transportation, including transport by a commercial distribution system (e.g., pipeline) and/or vehicle (e.g., ship, rail car, and/or truck). For example, each of the upgraded biogases 150i, 150ii, 150iii, 150iv, each of the captured streams of CO2 170i, 170ii, 170iii, 170iv, and/or the hydrogen product 275 may be provided as segregated batch and/or a fungible batch. In one particularly advantageous embodiment, one or more of the upgraded biogases 150i, 150ii, 150iii, 150iv is injected into a natural gas distribution system near the corresponding processing 100i, 100ii, 100iii, 100iv and is withdrawn from the same natural gas distribution system for hydrogen production 200 (e.g., is transported as a fungible batch to the hydrogen plant and/or fuel and/or product production facility).|[0047] In general, the captured CO2 170i, 170ii, 170iii, 170iv can be stored at one or more locations. For example, since the processing 100i, 100ii, 100iii, 100iv may be conducted at different locations (e.g., different states or provinces), in some embodiments at least two of the captured streams CO2 170i, 170ii, 170iii, 170iv are provided for storage in different geological formations. In one embodiment, all of the captured CO2 170i, 170ii, 170iii, 170iv is stored in the same storage 300. In one embodiment, each of the captured CO2 gases 170i, 170ii, 170iii, 170iv is stored at respective storage sites 300i, 300ii, 300iii, 300iv. In one embodiment, at least one of the CO2 gases 170i, 170ii, 170iii, 170iv is used for CCSU, while another is used for CCS. In another example, all of the CO2 gases 170i, 170ii, 170iii, 170iv are provided for geological sequestration, but are sequestered in more than one geological formation (e.g., based on proximity of the storage to processing).|[0048] Although this process relies on multiple CO2 capture steps, which are often considered to be energy-consuming steps, there are various advantages and/or synergetic benefits of using this process for producing fuel having renewable content and/or renewable hydrogen.|[0049] For example, compare the process discussed with reference to FIGS. 2 and 3 to the gasification of biomass. Biomass gasification may offer large scale centralized hydrogen production, facilitates collecting the biogenic carbon dioxide from one point source, and avoids some intermediate steps (e.g., the conversion of biomass to biogas and biogas upgrading). Nevertheless, there are challenges to hydrogen production via biomass gasification, many of which relate to the costs associated with capital equipment and biomass feedstocks. A facility producing 100 tonnes of hydrogen per day may be very large (e.g., require 1,350 dry tonnes of biomass feedstock per day), and thus may not be feasible based on regional supplies. Smaller facilities may be more feasible from a feedstock availability perspective but may drive up the capital expenditures. The cost of the biomass feedstocks can be dependent on costs for storage and transportation of the biomass, the latter of which may be dependent on the collection radius. Feedstock costs may be modest where agricultural residues can be collected and transported over short distances, but can be high when significant transport distances are involved, at least in part due to the low energy density of biomass.|[0050] Alternatively, compare the process discussed with reference to FIGS. 2 and 3 to the SMR of biogas, wherein biomass is transported to a centralized processing facility that conducts the anaerobic digestion, biogas upgrading, and hydrogen production (i.e., upgraded biogas is not transported). As with the gasification of biomass, the feedstock costs for such a process can be largely dependent on the storage and transportation of the biomass. When the feedstock has a large moisture content (e.g., manure or food waste) the transportation cost may be even higher.|[0051] In contrast, in the process illustrated in FIGS. 2 and 3, the upgraded biogas is transported to a facility having the hydrogen production 200. Transporting upgraded biogas over extended distances can be more cost efficient than transporting feedstock for anaerobic digestion and/or gasification. In particular, upgraded biogas such as RNG may be transported using any method suitable for transporting natural gas (e.g., a truck designed for transporting liquified natural gas (LNG) or compressed natural gas (CNG), the latter of which is often transported at pressures above about 3600 psig (24.8 MPa)). Transporting the upgraded biogas as bio-LNG or bio-CNG allows more MJ to be delivered per truck (e.g., relative to biomass for gasification or anaerobic digestion) and/or can increase the collection radius for the renewable feedstock. Alternatively, or additionally, the upgraded biogas can be transported by pipeline (e.g., in a natural gas distribution system such as the US natural gas grid), where it is transported as a fungible batch.|[0052] Transporting the upgraded biogas via a natural gas distribution system is particularly advantageous. In particular, it is a cost effective method that uses existing infrastructure, and depending upon the applicable regulatory agency, may have only a small penalty (cost and/or GHG emissions) for transporting the upgraded biogas over extended distances. Accordingly, the collection zone for the renewable feedstock is not necessarily limited to the area around a centralized facility conducting anaerobic digestion, biogas upgrading, and hydrogen production, but rather can include any area that provides feedstock for biogas production, where the biogas production is near the natural gas distribution system or can be economically transported to an injection point of the natural gas distribution system. This can increase the area from which the feedstock is collected, thereby making more feedstock available for the process and increasing the feasible scale of the renewable hydrogen production and/or CCS. Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).|[0053] Coprocessing renewable and non-renewable feedstock can increase the possible scale of hydrogen production, can facilitate using existing hydrogen plant(s) configured to process natural gas, and/or can reduce operational complications associated with intermittent renewable feedstock supply (e.g., cold start-up times may be between about 15 and 24 hours). Accordingly, the costs of hydrogen production can be reduced.|[0054] Advantageously, providing multiple CO2 capture steps (e.g., the disaggregation of CO2 capture process) for CO2 storage allows each capture process to be optimized for the CO2 capture. For example, since biogas upgrading typically includes separating CO2 from CH4, many biogas upgrading technologies can include CO2 capture, can be readily modified to include CO2 capture, or may facilitate CO2 capture, thereby reducing costs of the CO2 capture.|[0055] Further details about the biogas production 50i, 50ii, 50iii, 50iv, the biogas processing 100i, 100ii, 100iii, 100iv, hydrogen production 200, capture and/or storage 300, and fuel/product production 500, are discussed below.|Biogas Production|[0056] In general, the multiple biogas productions 50i, 50ii, 50iii, 50iv produce multiple biogases (i.e., each biogas production produces a respective biogas). Each biogas can be produced from any suitable biomass. For example, each biogas can be produced from the anaerobic digestion of any suitable feedstock. Anaerobic digestion, which refers to the biological breakdown of organic matter by anaerobic microorganisms, is typically conducted in anaerobic or low oxygen conditions, and may involve a series of microorganism types and processes (e.g., hydrolysis, acidogenesis, acetogenesis, and methanogenesis).|[0057] In one embodiment, one or more of the biogases is produced from the anaerobic digestion of a feedstock, where the feedstock is and/or comprises: (i) an energy crop (e.g., switchgrass, sorghum, etc.); (ii) residues, byproducts, or waste from the processing of plant material in a facility, or feedstock derived therefrom (e.g., sugarcane bagasse, sugarcane tops/leaves, corn stover, etc.); (iii) agricultural residues (e.g., wheat straw, corn cobs, barley straw, corn stover, etc.); (iv) forestry material; (v) pulp and paper residues; and/or (vi) municipal waste or components removed or derived from municipal waste. In one embodiment, the feedstock for the anaerobic digestion is or includes cellulosic and/or lignocellulosic material(s).|[0058] In one embodiment, one or more of the biogases is produced from the anaerobic digestion of “organic waste.” Using organic waste as the feedstock for anaerobic digestion is particularly advantageous. Organic waste, may for example, include the organic fraction of municipal solid waste (MSW), sludge from a wastewater treatment plant (WWTP), manure from a livestock farm (e.g., a dairy or swine farm), or food or yard waste collected from households, restaurants, supermarkets, food-processing companies, schools, businesses, etc. In one embodiment, the feedstock for the anaerobic digestion is manure (e.g., swine or dairy) or other farm waste, the organic fraction of MSW, or agricultural residues (e.g., straw, stover, etc.).|[0059] The composition of biogas produced from each anaerobic digestion can be dependent upon the feedstock. For example, although biogas produced from anaerobic digestion generally has a CH4 content between about 35% and 75% (e.g., about 60%) and a CO2 content between about 15% and 65% (e.g., about 35%), the CH4 content can tend towards the high end of this range when the feedstock is agricultural waste (e.g., between about 50% and 75%) and towards the low end of this range when the feedstock is the organic fraction of municipal solid waste (e.g., between about 25% and 65%). In addition to CH4 and CO2 biogas produced from anaerobic digestion may also include N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates, in dependence upon its source. For example, biogas produced from a landfill often has a higher N2 content than biogas produced in anaerobic digester. In one embodiment, each biogas has a CH4 content between about 25% and 75% and a CO2 content between about 15% and 65%, and the CO2 and CH4 make up at least 75% of the biogas by volume.|[0060] The anaerobic digestion of the feedstocks (e.g., solid or liquid) can be conducted in any suitable environment, including a natural environment (e.g., a landfill) or a controlled environment (e.g., an anaerobic digester). An anaerobic digester can be a holding tank, or another contained volume, such as a covered lagoon or sealed structure, configured to facilitate the breakdown of organic material by microorganisms under anaerobic or low oxygen conditions. Anaerobic digestion may be carried out in one or multiple anaerobic digesters connected in series and/or parallel, where each digester may be a single-stage or multi-stage digestion system, and/or may be designed and/or operated in a number of configurations including batch or continuous, mesophilic or thermophilic temperature ranges, and low, medium, or high rates. The term “anaerobic digester”, as used herein, can refer to plurality of fluidly connected anaerobic digesters. The operation of an anaerobic digester may be dependent on nature of the organic matter fed to the anaerobic digester and/or the level of digestion required. The appropriate selection of operating parameters, including but not limited to residence time, temperature, pH, and/or the nutrients supplied, will be known to those skilled in the art. When conducted in one or more anaerobic digesters, the anaerobic digestion of biomass also produces a potentially usable digestate. Digestate refers to the material remaining after one or more stages of the anaerobic digestion (e.g., may refer to acidogenic digestate, methanogenic digestate, or a combination thereof). Digestate can include organic material not digested by the anaerobic microorganisms, by-products of the anaerobic digestion released by the microorganisms, and/or the microorganisms themselves. For example, the digestate can include carbohydrates, nutrients (such as nitrogen compounds and phosphates), other organics, and/or wild yeasts. The composition of digestate, can vary depending on the biomass from which it is derived. Digestate often has both a solid and liquid component. A common use of digestate is as a soil conditioner, where it can provide nutrients for plant growth and/or displace the use of fossil-based fertilizers. In one embodiment, the digestate is processed to provide carbon-containing material that is stored as part of CCS. Processing of the digestate can include any type of processing, including but not limited to, solid liquid separations (e.g., feeding it into a screw press), heating, combustion, pyrolysis, hydrothermal treatment, etc.|[0061] In one embodiment, each of the biogases is produced from a single source (e.g., a landfill or anaerobic digester). In one embodiment, one or more of the biogases is produced from multiple sources (e.g., one or more landfills and/or one or more anaerobic digesters).|Biogas Upgrading|[0062] In general, at least part of each processing 100i, 100ii, 100iii, 100iv includes biogas upgrading. Biogas upgrading, which can be conducted in a biogas plant situated at or close the biogas production, refers to a process where biogas is purified in one or more stages to provide upgraded biogas. Biogas upgrading, which increases the calorific value of the biogas, typically provides a CH4-rich gas having a CH4 content of at least 90%. In one embodiment, the upgraded biogases have a CH4 content of at least 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95%, at least 96%, at least 97%, or at least at least 98%. It can be particularly advantageous to produce upgraded biogas having a CH4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system. In one embodiment, the biogas upgrading produces RNG. In one embodiment, the biogas upgrading produces biogas having a CH4 content of at least 95%. In one embodiment, the biogas upgrading produces biogas having a heating value of at least 950 BTU/ft3.|[0063] Biogas upgrading can be conducted using any suitable technology or combination of technologies that can separate CH4 from one or more non-methane components in the biogas (e.g., CO2, N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates). For example, biogas upgrading technologies are often based on absorption, adsorption, membrane separation, and/or cryogenic separation. As will be understood by those skilled in the art, the technology used for the biogas upgrading can be dependent up the composition of the biogas and the desired purity of the upgraded biogas.|[0064] As biogas typically has a significant CO2 content, biogas plants often include at least one system for separating CH4 from CO2. Some examples of technologies that can remove CO2 from biogas include, but are not limited to, absorption (e.g., water scrubbing, organic physical scrubbing, chemical scrubbing), adsorption (e.g., pressure swing adsorption (PSA)), membrane separation (e.g., CO2 selective membranes based on polyimide, polysulfone, cellulose acetate, polydimethylsiloxane), and cryogenic separation.|[0065] While some CO2 removal systems may remove one or more other non-methane components in addition to CO2 (e.g., N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates), biogas plants often include one or more other systems (e.g., dehydration units, H2S removal units, N2 rejection units, etc.). For example, some CO2 removal systems require that the biogas be cleaned upstream of CO2 removal (e.g., remove impurities that can negatively affect the CO2 removal unit. Alternatively, or additionally, the biogas can be cleaned and/or upgraded downstream of CO2 removal. In general, the non-methane components can be removed by any combination of chemical and/or physical technologies, in one or more stages. For example, H2O may be removed using a standard biogas dehumidifier, whereas H2S may be removed using a commercial H2S removal unit (e.g., based on activated carbon, molecular sieve, iron sponge, water scrubbing, NaOH washing, and/or biofilter or biotrickling filter technologies). In some cases, one stage may remove more than one non-methane component. For example, in some cases, some H2S may also be removed during the water removal step.|[0066] In general, the biogas upgrading can be conducted close to the biogas source (e.g., at a biogas plant at the landfill site or near the anaerobic digester) and/or at a centralized biogas plant (e.g., which receives raw, cleaned, or partially purified biogas from multiple sources). For example, a centralized biogas plant may be connected to one or more anaerobic digesters (e.g., each at a separate farm) via a biogas pipeline and/or grid. Alternatively, or additionally, the centralized biogas plant may receive biogas from one or more biogas sources by vehicle (e.g., see U.S. Pat. No. 10,760,024). In one embodiment, each biogas processing 100i, 100ii, 100iii, 100iv is conducted on biogas from a single biogas source. In one embodiment, at least one biogas processing 100i, 100ii, 100iii, 100iv is conducted at a centralized processing plant that receives biogas from multiple biogas sources (e.g., multiple farms).|[0067] Each of the upgraded biogases 150i, 150ii, 150iii, 150iv is transported to a facility having hydrogen production (e.g., to a stand-alone hydrogen plant or to a production facility having at least one hydrogen production process). As each upgraded biogas may be relatively pure (e.g., have a CH4 content greater than about 92%), it may be transported using methods used to transport natural gas. For example, if the biogas is upgraded to RNG it can be transported in a CNG tanker (e.g., at a pressure of about 3600 psig) and/or transported by pipeline (e.g., a natural gas distribution system such as the US natural gas grid). In some cases, upgraded biogas that does not meet pipeline standards can be mixed with another gas (e.g., propane or fossil based natural gas) in order to facilitate injection into the natural gas distribution system.|[0068] In general, when upgraded biogas is transported by pipeline, it is transferred as a fluid (e.g., in gaseous or liquid form), and may be provided as a segregated batch or a fungible batch. The term “batch”, as used herein, refers to a certain amount of the gas (e.g., energy delivered) and does not imply or exclude an interruption in the production and/or delivery.|[0069] When upgraded biogas is transported as a fungible batch in a natural gas distribution system, a quantity of the upgraded biogas (e.g., in MJ) is injected into the natural gas distribution system, where it can comingle with non-renewable natural gas, and an equivalent quantity of gas (e.g., in MJ) is withdrawn at another location (i.e., as long as there is a physical link between the injection point and the withdrawal point). The transfer or allocation of the environmental attributes of the upgraded biogas injected into the natural gas distribution system to gas withdrawn at a different location is typically recognized. Accordingly, the withdrawn gas can be recognized as the transported upgraded biogas and/or can qualify as RNG under applicable regulations (e.g., even though the withdrawn gas may not contain actual molecules from the original biomass and/or contains methane from fossil sources). Such transport may be carried out on a displacement basis, where transactions within the natural gas distribution system involve a matching and balancing of inputs and outputs. Typically, the direction of the physical flow of gas is not considered. Establishing that a gas is recognized as and/or qualifies as RNG (e.g., originates from renewable sources) under applicable regulations can depend on whether the gas is transported by truck or by pipeline and the practices and requirements of the applicable regulatory agency, where such practices may include, for example, the use of chain of custody accounting methods such as identity preservation, book-and-claim, and/or mass balance.|[0070] Transporting the upgraded biogas via a natural gas grid is particularly advantageous as it facilitates transporting the renewable feedstock anywhere where the grid delivers without significant additional cost (e.g., financially and/or GHG emissions). In one embodiment, the upgraded biogas is transported to a facility having hydrogen production, at least in part, via a natural gas distribution system. In one embodiment, each of the upgraded biogases is transported to a facility having hydrogen production, at least in part, by vehicle. In one embodiment, each of the upgraded biogases is transported to a facility having hydrogen production, at least in part, using a transportation system.|[0071] The term “transportation system”, as used herein with reference to an element (e.g., natural gas or CO2 or H2), refers to a system configured to transport the element, and/or a fungible element, by a distribution system and/or vehicle. For example, a transportation system can include a mobile pressure vessel configured to be transported by vehicle (e.g., truck, rail car, ship). The term “distribution system”, as used herein with reference to an element (e.g., natural gas or CO2 or H2), refers to a system configured to transport the element, and/or a fungible element, in one or more interconnected pipes (e.g., by pipeline). For example, a natural gas distribution system such as the US natural gas grid can be used to transport natural gas and/or upgraded biogas.|Hydrogen Production|[0072] In general, the hydrogen production may be conducted at one or more hydrogen plants. The term “hydrogen plant”, as used herein, refers to a system or combination of systems primarily used for hydrogen production. The term “renewable hydrogen”, as used herein, refers to hydrogen produced using biogas (e.g., upgraded biogas and/or RNG). For example, the term “renewable hydrogen” can refer to hydrogen produced by methane reforming a feed withdrawn from a natural gas distribution system, when at least a portion of the withdrawn feed is recognized as and/or qualifies as RNG under applicable regulations.|[0073] In general, the hydrogen production may use any suitable technology known in the art that can convert one or more of the upgraded biogases and/or natural gas to hydrogen. Examples of technologies that may be suitable include, but are not limited to, steam methane reforming (SMR), autothermal reforming (ATR), partial oxidation (POX), and dry methane reforming (DMR). SMR, ATR, and DMR, which are types of catalytic reforming, may operate by exposing natural gas to a catalyst at high temperature and pressure to produce syngas. POX reactions, which include thermal partial oxidation reactions (TPOX) and catalytic partial oxidation reactions (CPOX), may occur when a sub-stoichiometric fuel-oxygen mixture is partially combusted in a reformer. POX also may be referred to as oxidative reforming. For purposes herein, the term “methane reforming” may refer to SMR, ATR, DMR, or POX.|[0074] Of the various types of methane reforming, SMR is the most common. In SMR, which is an endothermic process, methane is reacted with steam under pressure in the presence of a catalyst to produce carbon monoxide (CO) and H2 according to the following reaction:|CH4+H2O+heat→CO+3H2 (1)|[0075] Referring to the hydrogen plant in FIG. 1, this reaction may occur in the SMR reactor tubes, which contain the reforming catalyst. Without being limiting, the catalyst may be nickel-based, the operating pressure may be between 200 psig (1.38 MPa) and 600 psig (4.14 MPa), and the operating temperature may be between about 450 to 1000° C. The heat required for the catalytic reforming of Eq. 1 can be provided by the combustion in the SMR burners (e.g., the combustion chamber may surround the reformer tubes in which the reaction is conducted).|[0076] The syngas produced from Eq. (1) may be further reacted in the WGS 20. The WGS is based on the water gas shift reaction, wherein carbon monoxide is converted to carbon dioxide and hydrogen:|CO+H2O→CO2+H2+small amount of heat (2)|[0077] Providing WGS downstream of SMR increases the yield of H2, and thus is commonly included in hydrogen production. For example, in addition to H2, the syngas produced from the SMR may have a CO2 content between about 7-10%, a CO content between about 12-19%, and a CH4 content between about 2-6%, whereas the syngas produced from the WGS may have a CO2 content between about 15-16%, a CO content between about 4-5%, and a CH4 content between about 3-4%.|[0078] The gas produced from methane reforming (e.g., the syngas 25) is subjected to a hydrogen purification, wherein H2 is separated from CO, CO2, and/or CH4 in one or more stages to produce a hydrogen product (e.g., containing at least 80% hydrogen). For example, in one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 90, 92, 94, 96, 98, 99, or 99.5%. In one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 99.9%. Without being limiting, some examples of suitable hydrogen purification technologies include, but are not limited to: a) absorption, b) adsorption, c) membrane separation, d) cryogenic separation, and e) methanation. Some examples of absorption systems that may be suitable include, but are not limited to, a monoethanolamine (MEA) unit or a methyl-diethanolamine (MDEA) unit. A MEA unit may include one or more absorption columns containing an aqueous solution of MEA at about 30 wt %. The outlet liquid stream of solvent may be treated to regenerate the MEA and separate CO2. Some examples of adsorption systems that may be suitable include, but are not limited to, systems that use adsorbent bed (e.g., molecular sieves, activated carbon, active alumina, or silica gel) to remove impurities such as CH4, CO2, CO, N2, and/or water from the syngas gas. For example, hydrogen purification systems that are based on PSA are commonly used for hydrogen plants, as such systems produces a purge gas that can be recycled to fuel the SMR burners, thereby improving energy efficiency (e.g., see FIG. 1). In one embodiment, hydrogen purification uses vacuum PSA system (VPSA). Some examples of membranes systems that may be suitable include, but are not limited to, H2 selective membranes. A hydrogen purification unit that is based on cryogenic separation may cool the syngas gas down to temperatures where the impurities condense or sublimate and can be separated as a liquid or a solid fraction, while the hydrogen accumulates in the gas phase. For example, cryogenic separations may use temperatures below −10° C. or below −50° C. Methanation is a catalytic process that can be conducted to convert the residual carbon monoxide and/or carbon dioxide in the syngas to methane. For example, see equation 3.|CO+3H2→CH4+H2O (3)|Since the methanation reaction consumes hydrogen, a hydrogen purification unit that includes a methanation may include CO2 removal prior to methanation.|[0079] In general, hydrogen production is well known and those skilled in the art will understand that the hydrogen plant(s) may use any suitable technology and/or have any suitable configuration. For example, the hydrogen production may be based on any suitable methane reforming technology combined with any suitable hydrogen purification. With specific regard to FIG. 1, those skilled in the art will understand that each of the SMR unit 10 and WGS unit 20 may include a single reactor or multiple reactors (e.g., the WGS unit 20 may include a high temperature WGS reactor (e.g., 350° C.) followed by a low temperature WGS reactor (e.g., 200° C.)), that the SMR reactor(s) may be top-fired reformers, side-fired reformers, bottom-fired reformers, etc., that the SMR reformer may be downstream of a purification unit to remove sulfur, chloride, olefin, and/or other compounds that may be detrimental to the SMR reforming catalysts, or that the SMR reformer may be downstream a pre-reforming unit, which allows a higher inlet feed temperature with minimal risk of carbon deposition. Those skilled in the art will also understand that although a steam methane reformer may be referred to as a “methane reformer,” typically they can convert any of the hydrocarbons present in the natural gas to syngas (i.e., not just the methane).|[0080] In the above-described embodiments, the feedstock for the hydrogen production process contains at least a portion of one or more of the upgraded biogases (e.g., RNG), which can be transported to the facility containing the hydrogen production (e.g., at least one hydrogen plant) by vehicle and/or as a fungible batch via a natural gas distribution system. In each embodiment, the feedstock may contain only the upgraded biogas or may contain both upgraded biogas and fossil based gas such as natural gas (e.g., the hydrogen can be produced by coprocessing renewable and non-renewable methane). When the feed contains both upgraded biogas and fossil based gas (e.g., natural gas or refinery gas), the quantity of renewable hydrogen produced can be determined using the renewable fraction of the feedstock (based on energy).|[0081] In the above-described embodiments, the feedstock for the renewable hydrogen process contains at least a portion of one or more of the upgraded biogases. However, in some embodiments, a portion of one or more of the upgraded biogases is fed to the combustion zone of the methane reformer (e.g., to the SMR burners). Since combusting upgraded biogas simply returns to the atmosphere carbon that was recently fixed by photosynthesis, and thus is considered relatively benign, this can reduce GHG emissions from the SMR furnace (e.g., compared to using fossil-based methane). Accordingly, the CI of renewable hydrogen could be reduced. While it may be advantageous to sacrifice some of the upgraded biogas for fuel in order to improve the GHG balance of the hydrogen production and/or fuel/product production process, this reduces the yield of renewable hydrogen and/or the yield of renewable content of the fuel(s)/product(s) produced. Accordingly, there may be a compromise between increasing the yield of renewable hydrogen/renewable content and decreasing the lifecycle GHG emissions, for a given quantity of upgraded biogas. In certain embodiments, low-carbon electricity such as renewable electricity is used to provide heat for the methane reforming (e.g., for SMR). Low-carbon electricity refers to electricity generated in a process that does not emit significant amounts of fossil-based carbon dioxide and/or is produced from renewable energy sources. Without being limiting, low-carbon electricity can include electricity produced using nuclear power, hydropower, solar power, wind power, geothermal power, wave power, tidal power, or electricity produced from the combustion of a low-carbon energy source (e.g., biomass, biogenic syngas, or hydrogen) or of a fossil-based energy source with CCS. In certain embodiments, heat required for the SMR is generated using renewable electricity (i.e., electricity produced using renewable energy sources such as hydropower, solar power, wind power, geothermal power, wave power, tidal power, etc.). In certain embodiments, the low-carbon electricity is generated from gasification of agricultural and/or solid waste. In general, any suitable technology known in the art that can use electricity to produce a sufficient amount of heat for at least part of the methane reforming can be used. The low-carbon electricity can produce the heat for methane reforming directly (e.g., to power resistive or inductive heaters that provide the heat directly for the methane reforming) and/or indirectly (e.g., using a heat storage medium and/or heat transfer fluid). In certain embodiments, the methane reformer (e.g., SMR) is an electrically heated methane reformer (e.g., electrically heated SMR), wherein the heat that would have been generated with conventional fired burners is replaced with electrically generated heat. Such methane reformers are generally configured such that there is no flue gas, and thus there are no carbon emissions associated with the flue gas (e.g., carbon emissions of hydrogen production may be reduced by 20-50% relative to the conventional fired SMR).|Carbon Capture and Storage|[0082] In general, at least part of each processing 100i, 100ii, 100iii, 100iv includes carbon capture, wherein at least a portion of the CO2 from the biogas produced (e.g., generated during anaerobic digestion) is captured. The capture of CO2 from each biogas produced can be conducted using any suitable technology or combination of technologies that can capture CO2 for storage. As the CO2 may be part of a gas mixture (e.g., biogas, syngas, flue gas, etc.), the CO2 capture can include and/or depend upon the separation of CO2 from one or more other gas components in a gas mixture. Technology that may be suitable for separating CO2 from one or more other gas components in a gas mixture includes, but is not limited to, absorption, adsorption, membrane separation, and cryogenic separation.|[0083] The CO2 from each of the biogases (e.g., generated during anaerobic digestion) can be captured upstream of biogas upgrading, as part of biogas upgrading, and/or from a tail gas produced from biogas upgrading. For example, since biogas upgrading can include steps where CO2 is separated from CH4, such steps can be part of the CO2 capture process, or can facilitate the CO2 capture process, thereby reducing capital and operating costs. Biogas upgrading, which typically focuses on providing a relatively pure product stream (e.g., greater than 95% CH4), can produce a tail gas that contains CO2 separated from the CH4 in addition to other non-methane components separated from the CH4. For example, biogas upgrading units based on absorption, adsorption, or membrane separation, can produce a CO2 rich tail gas that is too impure for CO2 storage and/or transport without further purification and/or upstream removal of one or more components. However, in some cases, biogas upgrading (e.g., based on cryogenic separation), can yield both relatively pure CH4 (e.g., greater than about 95% CH4) and relatively pure CO2 (e.g., greater than about 95% CO2). While cryogenic biogas upgrading may require upstream biogas cleaning, it advantageously can provide the CO2 is a form that facilitates transport by vehicle and/or a CO2 distribution system (e.g., can provide the CO2 in liquid or solid form).|[0084] In one embodiment, at least one of the processing steps 100i, 100ii, 100iii, 100iv includes a separate CO2 removal step for the CO2 capture (i.e., separate from the biogas upgrading). For example, in one embodiment, a separate CO2 separation is conducted on the tail gas from biogas upgrading to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport. In another embodiment, a separate CO2 separation is conducted upstream of biogas upgrading to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport.|[0085] In one embodiment, the biogas upgrading is conducted in stages and at least one stage of the biogas upgrading is a CO2 capture step.|[0086] In one embodiment, the CO2 capture step is integrated with the biogas upgrading. For example, in one embodiment, the biogas upgrading is selected to and/or modified to provide a CO2 product suitable for geological storage and/or transport by a CO2 distribution system (e.g., after dehydration and compression). In general, this may be achieved by selecting suitable separation technology and/or modifying the configuration of the system (e.g., removing one or more components upstream of the CO2 separation). For example, in one embodiment, cryogenic CO2 capture is part of biogas upgrading. When cryogenic separation is used as part of biogas upgrading, the biogas may be cleaned (e.g., to remove H2S and H2O) and then subjected to a cryogenic separation that provides relatively pure CO2 (e.g., >95% CO2) while also providing a relatively pure CH4 (e.g., >95% CH4) and N2 (if present).|[0087] Storage of CO2 captured from the biogases can be conducted using any suitable technology or combination of technologies. For example, carbon storage technologies, which are well known in the art, can sequester CO2 in geological formations (i.e., subsurface formations). Suitable geological formations, which can occur in onshore or offshore settings, are often configured such that CO2 injected therein, is trapped. Appropriate storage of the CO2 can reduce GHG emissions and/or mitigate climate change. The level of GHG reduction achieved may be dependent on whether it is all biogenic, the applicable regulatory authority, the permanence of the storage, and/or whether its use displaces the use of fossil fuel products. In one embodiment, the captured CO2 from one or more of the biogases is sequestered in at least one geological formation. For example, in one embodiment the captured CO2 from one or more of the biogases is sequestered in a saline aquifer or is sequestered in an oil/natural gas reservoir as part of enhanced oil recovery (EOR)). In one embodiment, the captured CO2 from one or more of the biogases is stored in concrete. In one embodiment, storage of the captured CO2 from one or more of the biogases permanently displaces fossil based CO2 emissions.|[0088] The purity of the CO2 required for storage can be dependent upon the selected storage and/or selected mode of transportation, if applicable. For example, for geological sequestration and/or EOR, where the CO2 is often transported, at least in part, via a CO2 distribution system (e.g., pipeline), the CO2 content should be as high as possible (e.g., at least about 95%). However, for some applications (e.g., bauxite residue carbonation, etc.) lower CO2 contents may be suitable. In addition to a minimum CO2 content, the CO2 provided for storage and/or transport may have limits on the maximum amount of H2O, H2S, CO, CH4, N2, Ar, H2, etc.|[0089] In general, when the CO2 is captured far from storage, the process includes transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). In order to transport CO2 for storage, the CO2 typically requires significant compression and/or cooling. When CO2 is transported by vehicle (e.g., truck, ship, rail car) it is often transported as a liquid (e.g., a pressure of about 290 psig and a temperature of about −20° C., or a pressure of about 100 psig and a temperature of about −50° C.). When CO2 is transported by a CO2 distribution system (e.g., a CO2 pipeline) it is often transported as a supercritical fluid (critical point is −31° C., −1070 psig). For example, many CO2 pipelines are operated between about 1250 psig and about 2200 psig, or higher. In some embodiments, the collected CO2 is also stored locally at a relatively high pressure (e.g., −1600 psig) prior to transport by pipeline. In general, the CO2 can be compressed to the desired pressure using a gas compressor, or alternatively, the collected CO2 can be liquified at a lower pressure using a refrigeration system (e.g., 235 psig) and then pumped to the desired pressure. In one embodiment, the process produces a compressed stream of relatively pure CO2 (e.g., at least 95% CO2). In one embodiment, the CO2 is transported to storage, at least in part, as a fungible batch using a CO2 distribution system.|[0090] The CO2 captured from the multiple biogas upgrading processes can be stored together or separately (e.g., in the same geological formation or in different geological formations). In general, how and where the captured CO2 is stored may be dependent upon the closest storage site. In one embodiment, the CO2 captured from one or more of the biogases is, at least in part, transported using a CO2 distribution system.|[0091] In one embodiment, at least 50% of the CO2 from each of one or more of the biogases is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 from each of one or more of the biogases is captured and stored.|[0092] In certain embodiments, the carbon intensity and/or lifecycle GHG emissions of the fuel/product(s) is further reduced by storing carbon containing material obtained or derived from the biogas production/biogas upgrading. For example, in certain embodiments, digestate from anaerobic digestion of the biomass is provided for storage as part of CCS. In certain embodiments, the digestate is treated prior to CCS. For example, digestate can be subjected to a hydrothermal liquefaction to provide a bio-oil that can be sequestered. In some cases, the sequestration method is selected to prevent biodegradation of the material and/or trap GHGs in the event of biodegradation. In some cases, the material is treated in a process to reduce the potential for biodegradation. The amount of carbon obtained or derived from the digestate and provided as part of CCS can be expressed as kg C per m3 (dry weight). Advantageously, storing a liquid or solid by-product produced from the process as part of CCS can further reduce the carbon intensity of the hydrogen produced and/or a fuel or product produced from the hydrogen.|Fuel or Product Production|[0093] In general, the process produces fuel and/or product (e.g., having renewable content) using renewable hydrogen. In one embodiment, the process produces fuel. In one embodiment, the fuel is methanol. In one embodiment, the fuel is gasoline, diesel, and/or jet fuel. In one embodiment, the fuel is an aviation fuel. In one embodiment, the fuel is a transportation fuel. In one embodiment, the fuel is a liquid transportation fuel. In one embodiment, the process produces one or more products (e.g., the renewable hydrogen is used as an industrial feedstock to produce one or more fuels and/or chemical products). In one embodiment, the renewable hydrogen is used to produce ammonia (e.g., in a Haber-Bosch process). In the Haber-Bosch process, which is well-known to those skilled in the art, nitrogen is converted to ammonia in a process conducted under high temperatures and pressures with a metal catalyst. Ammonia has an important role in the agricultural industry for production of fertilizers. Ammonia may also be used as a fuel and/or an energy carrier for energy storage and transportation. In one embodiment, the renewable hydrogen is used to produce fertilizer. Using the upgraded biogas and/or renewable hydrogen to produce fuel and/or product can provide the fuel and/or product with renewable content and/or can reduce the lifecycle GHG emissions of the fuel and/or product, particularly when the upgraded biogas and/or renewable hydrogen has a low CI attributed to CCS.|[0094] In general, the fuel and/or product may be produced by processing the upgraded biogas and/or renewable hydrogen with one or more other renewable feedstocks and/or one or more non-renewable feedstocks. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the fuel can have renewable content (e.g., be a partially renewable fuel). The term “renewable content”, as used herein, refers the portion of the fuel(s)/product(s) that is recognized and/or qualifies as renewable (e.g., a biofuel) under applicable regulations. The quantification of the renewable content can be determined using any suitable method and is typically dependent upon the applicable regulations.|[0095] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon such that the renewable hydrogen is incorporated into a crude-oil derived liquid hydrocarbon to produce gasoline, diesel, and/or jet fuel having renewable content (e.g., see U.S. Pat. Nos. 8,658,026, 8,753,854, 8,945,373, 9,040,271, 10,093,540, 10,421,663, and 10,723,621, 10,981,784). In this embodiment, use of the renewable hydrogen can produce gasoline, diesel, and/or jet fuel having renewal content. Advantageously, such fuels can replace and/or be used with non-renewable gasoline, diesel, and/or jet fuel without affecting performance and/or operation (e.g., are drop-in fuels). Further advantageously, such fuels can be produced at existing oil refineries using existing equipment. The term “crude oil derived liquid hydrocarbon”, as used herein, refers to any carbon-containing material obtained and/or derived from crude oil that is liquid at standard ambient temperature and pressure. The term “crude oil”, as used herein, refers to petroleum extracted from geological formations (e.g., in its unrefined form). Crude oil includes liquid, gaseous, and/or solid carbon-containing material from geological formations, including oil reservoirs, such as hydrocarbons found within rock formations, oil sands, or oil shale. In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon to produce aviation fuel having renewable content. This embodiment is particularly advantageous as it could help decarbonize commercial air travel and/or extend the life of older aircraft types by lowering their carbon footprint.|[0096] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of renewable fats and/or oils (e.g., algae, jatropha, tallows, camelina, pyrolysis oil produced from biomass, etc.) to produce renewable gasoline, diesel, and/or jet fuel. This embodiment is particularly advantageous as the resulting fuel can be fully renewable and have a reduced CI (i.e., relative to an analogy process where the hydrogen is produced from fossil based natural gas).|[0097] In general, the renewable hydrogen can be used in any suitable fuel and/or product production process. For example, in one embodiment, the renewable hydrogen is used in a Fischer-Tropsch type process to produce a liquid transportation fuel. In one embodiment, the renewable hydrogen and biogenic carbon dioxide are subjected to a gas fermentation to produce an alcohol such as ethanol.|[0098] In general, the renewable hydrogen may be produced at a commercial hydrogen plant or at a hydrogen plant at the production facility. In both cases, the renewable hydrogen may be provided for fuel/product production via a H2 distribution system (e.g., a H2 pipeline or local H2 pipe system) as a fungible batch. More specifically, the renewable hydrogen may be allocated for the desired use (e.g., a specific fuel production process or a specific hydroprocessing unit). The term “allocating”, as used herein in respect of a particular element, refers to designating the element for a specific purpose.|Carbon Intensity and/or Fuel Credits|[0099] In general, the carbon intensity and/or lifecycle GHG emissions of the fuel and/or product having renewable content is relatively low as a result of the use of renewable hydrogen and/or storage of captured CO2 170i, 170ii, 170iii, 170iv (i.e., low relative to fuel produced by an analogous process using hydrogen produced using fossil based natural gas or an analogous process where the biogenic CO2 170i, 170ii, 170iii, 170iv is not stored). Advantageously, when the process produces fuel, the renewable content attributed to the use of renewable hydrogen and/or the low CI attributed to storing the captured CO2 170i, 170ii, 170iii, 170iv can facilitate the generation of fuel credits.|[0100] Fuel credits are used to incentivize renewable fuels, often in the transportation sector. For example, fuel credits can be used to demonstrate compliance with some government initiative, standard, and/or program, where the goal is to reduce GHG emissions (e.g., reduce CI in transportation fuels as compared to some baseline level related to conventional petroleum fuels) and/or produce a certain amount of biofuel (e.g., produce a mandated volume or a certain percentage of biofuels). The target GHG reductions and/or target biofuel amounts may be set per year or for a given target date. Some non-limiting examples of such initiatives, standards, and/or programs include the Renewable Fuel Standard Program (RFS2) in the United States, the Renewable Energy Directive (RED II) in Europe, the Fuel Quality Directive in Europe, the Renewable Transport Fuel Obligation (RTFO) in the United Kingdom, and/or the Low Carbon Fuel Standards (LCFS) in California, Oregon, or British Columbia).|[0101] The term “fuel credit”, as used herein, refers to any rights, credits, revenues, offsets, GHG gas rights, or similar rights related to carbon credits, rights to any GHG gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract, or otherwise. A fuel credit can be a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline (e.g., a gasoline baseline) set by a government authority. Non-limiting examples of fuel credits include RINs and LCFS credits. A Renewable Identification Number (or RIN), which is a certificate that acts as a tradable currency for managing compliance under the RFS2, may be generated for each gallon of biofuel (e.g., ethanol, biodiesel, etc.) produced. A Low Carbon Fuel Standard (LCFS) credit, which is a certificate which acts as a tradable currency for managing compliance under California's LCFS, may be generated for each metric ton (MT) of CO2 reduced.|[0102] In general, the requirements for generating or causing the generation of fuel credits can vary by country, the agency, and or the prevailing regulations in/under which the fuel credit is generated. In many cases, fuel credit generation may be dependent upon a compliance pathway (e.g., predetermined or applied for) and/or the biofuel meeting a predetermined GHG emission threshold. For example, with regard to the former, the RFS2 categorizes biofuel as cellulosic biofuel, advanced biofuel, renewable biofuel, and biomass-based diesel. With regard to the latter, to be a renewable biofuel under the RFS2, corn ethanol should have lifecycle GHG emissions at least 20% lower than an energy-equivalent quantity of gasoline (e.g., 20% lower than the 2005 EPA average gasoline baseline of 93.08 gCO2e/MJ). In low carbon-related fuel standards, biofuels may be credited according to the carbon reductions of their pathway. For example, under California's LCFS, each biofuel is given a CI score indicating their GHG emissions as grams of CO2 equivalent per megajoule (MJ) of fuel, and fuel credits are generated based on a comparison of their emissions reductions to a target or standard that may decrease each year (e.g., in 2019, ethanol was compared to the gasoline average CI of 93.23 gCO2e/MJ), where lower CIs generate proportionally more credits. In one embodiment, the fuel produced is a transportation fuel, and a fuel credit is generated or is caused to be generated. In one embodiment, the transportation fuel and/or renewable content has lifecycle GHG emissions that are at least 20% less than the lifecycle GHG emissions of a gasoline baseline using EPA methodology, preferably at least 50% or 60% less.|[0103] With respect to renewable hydrogen produced according to the instant disclosure, it can be advantageous for the CI of the hydrogen to be as low as possible, particularly when the hydrogen is used as a fuel or to produce a fuel, so that more valuable fuel credits can be generated. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the CI is measured for the resulting product from each of the co-processed feedstocks (i.e., there is a different CI for each the renewable and non-renewable feedstocks). In one embodiment, the process includes producing hydrogen associated with one or more producer credits. | (US12359134)|TECHNICAL FIELD|[0001] The present disclosure relates to a process and/or system for producing fuel and/or product(s), and in particular, to a process and/or system for producing fuel and/or products(s) having renewable content that includes carbon capture and storage of carbon dioxide from biogas.|BACKGROUND|[0002] Hydrogen is largely produced from the processing of fossil fuels. For example, hydrogen is often produced from the steam methane reforming (SMR) of natural gas or the gasification of coal. Unfortunately, the production of hydrogen from fossil fuels is associated with significant greenhouse gas (GHG) emissions, and in particular, with significant carbon dioxide (CO2) emissions.|[0003] One approach to reduce the GHG emissions associated with hydrogen production is to use carbon capture and storage (CCS). CCS may, for example, involve capturing CO2 emissions and storing them underground in suitable geological formations (i.e., carbon sequestration). In integrating CCS with hydrogen production from fossil fuels, the fossil based CO2 produced during the hydrogen production is captured and stored in order to prevent it from being released to the atmosphere, thereby reducing GHG emissions of the process (e.g., a reduction of about 80-90%).|[0004] Another approach to reduce the GHG emissions associated with hydrogen production is to use biomass rather than fossil fuels as feedstock. Such hydrogen, may for example, be produced from the gasification or pyrolysis of biomass, or by reforming biogas produced by the anaerobic digestion of biomass. Any CO2 derived from biomass and produced during such processing is biogenic. As the release of biogenic CO2 to the atmosphere simply returns to the atmosphere carbon that was recently fixed by photosynthesis, biogenic CO2 is generally considered to be carbon neutral (e.g., its release does not result in an increase in net GHG emissions). Accordingly, such hydrogen production can have reduced GHG emissions. In addition, such hydrogen (e.g., produced by reforming biogas) may be considered renewable hydrogen.|[0005] In integrating CCS with hydrogen production from biomass, where biogenic CO2 produced during the hydrogen production is captured and stored, there is the potential for so-called “negative emissions.” Negative emissions can be the basis for BECCS, which stands for bioenergy with carbon capture and storage. For example, in some cases, BECCS, which is a group of technologies that combine extracting bioenergy from biomass with CCS, can be viewed as a process where biomass (e.g., plants) is used to extract CO2 from the atmosphere, the biomass is processed to produce bioenergy (e.g., heat, electricity, fuels) while releasing CO2, and the CO2 produced during the processing is captured and stored such that there is there is a transfer of CO2 from the atmosphere to storage.|[0006] While BECCS is increasing discussed as a means to decrease CO2 emissions and/or CO2 concentrations in the atmosphere, some potential challenges that may hinder its success include 1) energy intensive biomass supply chains, 2) low energy conversion efficiencies, and/or 3) high costs (e.g., incentives and/or funding may be required). For example, the cost of BECCS may be largely limited by the cost of CCS. Since the cost of CCS is typically scale sensitive, and since the capture of CO2 is often considered to be one of most expensive parts of CCS, BECCS has been generally considered for applications where the CO2 emissions are relatively pure and/or can be captured from a large point source. Some potential applications of BECCS have been identified as power stations wherein biomass is combusted (e.g., where biogenic CO2 generated from the combustion process is captured and stored), biogas upgrading processes (e.g., where CO2 separated from the biogas captured and stored), and ethanol production processes (e.g., where CO2 produced by fermentation of corn grain is captured and stored).|[0007] It has also been proposed to combine CCS with hydrogen production from upgraded biogas, wherein at least a portion of the biogenic CO2 produced from hydrogen production is captured and stored. Such processes benefit from established technologies for capturing CO2 from hydrogen production (e.g., which can be a large point source). In some cases, the captured and stored CO2 can be accounted for as negative CO2 emission.|SUMMARY|[0008] The present disclosure relates to producing fuel and/or product in a process that uses hydrogen and/or includes the production of hydrogen, wherein a carbon intensity or lifecycle greenhouse gas emissions of at least a portion of the fuel and/or product is reduced by the capture and storage of carbon dioxide from biogas used to produce feedstock for the process (e.g., for hydrogen production). Accordingly, CCS can be incorporated into the process even when the hydrogen production is conducted in areas that do not practically support CCS.|[0009] In accordance with one aspect of the instant invention there is provided a method for producing fuel, the method comprising: sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising: a) collecting biogas comprising methane and carbon dioxide, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, and c) providing the captured carbon dioxide for storage; providing the at least two upgraded biogases for use as feedstock at a facility that has hydrogen production, the hydrogen production comprising methane reforming; and, producing a fuel having renewable content in a fuel production process that uses hydrogen produced from the hydrogen production as a feedstock, wherein the captured carbon dioxide provided in step (c) of each of the processes is stored and reduces the carbon intensity of the fuel. In some aspects, the fuel production comprises hydrogenating crude oil derived liquid hydrocarbon with the renewable hydrogen to produce the fuel. In some aspects, the fuel production comprises hydrogenating a renewable feedstock selected from renewable oil and renewable fat to produce the fuel. In some aspects, the fuel is selected from gasoline, diesel, and jet fuel. In some aspects, the fuel is aviation fuel. In some aspects, carbon dioxide captured from one of the processes is provided for storage at a separate location than carbon dioxide captured from another of the processes. In some aspects, step (c) of at least one of the processes comprises providing the captured carbon dioxide for geological sequestration. In some aspects, step (c) of at least one of the processes comprises providing the captured carbon dioxide for enhanced oil recovery. In some aspects, step (c) of at least one of the processes comprises providing the captured carbon dioxide for sequestration in concrete. In some aspects, step (c) of at least one of the processes comprises compressing the captured carbon dioxide and injecting the captured carbon dioxide into a carbon dioxide distribution system configured to transport the captured carbon dioxide to storage. In some aspects, step (b) of at least one of the processes comprises capturing the carbon dioxide using carbon dioxide capture selected from cryogenic separation, membrane separation, and absorption with amine solvent. In some aspects, step (b) of at least one of the processes comprises capturing at least 70% of the carbon dioxide originally present in the biogas. In some aspects, feedstock for the hydrogen production comprises the least two upgraded biogases and fossil based natural gas. In some aspects, the process does not include storing carbon dioxide produced from the hydrogen production. In some aspects, at least one of the at least two upgraded biogases is derived from organic waste. In some aspects, at least one of the at least two upgraded biogases is derived from manure, the manure selected from swine manure and dairy manure. In some aspects, at least one of the at least two upgraded biogases is derived from landfill gas. In some aspects, at least one of the at least two upgraded biogases is transported to the hydrogen plant using a natural gas distribution system.|[0010] In accordance with one aspect of the instant invention there is provided a process for producing fuel having renewable content, the process comprising: a) providing at least two biogas streams, each of the at least two biogas streams comprising methane and carbon dioxide; b) processing each of the at least two biogas streams, the processing comprising carbon capture and biogas upgrading, the processing of each of the at least two biogas streams producing upgraded biogas and captured carbon dioxide; c) providing the upgraded biogas produced from the processing of the at least two biogas streams for use as a feedstock at a facility that has hydrogen production, the hydrogen production comprising methane reforming, the hydrogen production producing hydrogen used as a feedstock in a fuel production process, the fuel production process producing fuel having renewable content; and d) storing the captured carbon dioxide produced from the processing of the at least two biogas streams, thereby preventing the captured carbon dioxide, or an equal quantity of carbon dioxide displaced by the captured carbon dioxide, from being released to the atmosphere, and reducing a carbon intensity of the fuel.|[0011] In accordance with one aspect of the instant invention there is provided a process for producing fuel having renewable content, the process comprising: sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a biogas production process comprising: a) collecting biogas comprising methane and carbon dioxide, b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, c) providing the captured carbon dioxide for storage; providing the at least two upgraded biogases for use as feedstock at a facility that has hydrogen production, the hydrogen production comprising methane reforming; and producing a fuel having renewable content in a fuel production process that uses hydrogen produced from the hydrogen production as a feedstock; and storing the captured carbon dioxide provided in step (c) of each of the biogas production processes, thereby reducing a carbon intensity of the fuel.|[0012] In accordance with one aspect of the instant invention there is provided a method for producing one or more products, the method comprising: providing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising: a) collecting biogas comprising methane and carbon dioxide, b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas; providing at least a portion of each upgraded biogas from the plurality as feedstock for hydrogen production, the hydrogen production comprising methane reforming, renewable hydrogen produced from the hydrogen production used for producing the one or more products; and storing carbon dioxide removed in b) from at least two of the processes, thereby preventing the removed carbon dioxide, or an equal quantity of carbon dioxide displaced by the removed carbon dioxide, from being released to the atmosphere, the storing reducing lifecycle GHG emissions of the one or more products.|[0013] In accordance with one aspect of the instant invention there is provided a method for producing one or more products, the method comprising: providing a plurality of upgraded biogases for producing renewable hydrogen via methane reforming, the renewable hydrogen for use in producing the one or more products, each upgraded biogas in the plurality produced in a respective process comprising: a) collecting biogas comprising methane and carbon dioxide, b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas; reducing lifecycle greenhouse gas emissions of the one or more products, the reducing comprising carrying out a plurality of carbon capture and storage processes, each of the carbon capture and storage processes in the plurality storing at least a portion of the carbon dioxide removed in step b) of one of the biogas production processes.|[0014] In accordance with one aspect of the instant invention there is provided a method for producing one or more products, the method comprising: producing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising: a) feeding biogas comprising methane and carbon dioxide into biogas upgrading, the biogas produced by anaerobic digestion, the biogas upgrading removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas, and b) processing digestate from the anaerobic digestion; providing at least a portion of each upgraded biogas from the plurality as feedstock for hydrogen production, the hydrogen production comprising methane reforming, renewable hydrogen produced from the hydrogen production used for producing the one or more products; and storing carbon dioxide removed in a) and carbon-containing material produced in b) from at least two of the biogas production processes, the storing reducing lifecycle GHG emissions of the one or more products.|[0015] In accordance with one aspect of the instant invention there is provided a method for reducing a lifecycle greenhouse gas emissions of one or more products, the one or products produced in a production process that consumes hydrogen, the hydrogen produced in a hydrogen production process that comprises methane reforming, the method comprising: providing a plurality of upgraded biogases, at least a portion of each of the upgraded biogases in the plurality provided as feedstock for the hydrogen production or a production process comprising the hydrogen production, each of the upgraded biogases produced in a respective process comprising: a) collecting biogas produced from anaerobic digestion of biomass, the biogas comprising methane and carbon dioxide, and b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas, storing carbon-containing material obtained or derived from at least two of the respective processes as part one or more carbon capture and storage processes, thereby reducing the lifecycle greenhouse gas emissions of the one or more products, the carbon-containing material comprising carbon dioxide.|(US12359134)|BRIEF DESCRIPTION OF THE DRAWINGS|[0016] FIG. 1 is a simplified process flow diagram of one embodiment of an SMR based hydrogen plant;|[0017] FIG. 2 is a simplified process flow diagram according to an embodiment of the invention; and|[0018] FIG. 3 is a simplified process flow diagram according to an embodiment of the invention.|(US12359134)|DETAILED DESCRIPTION|[0019] Certain exemplary embodiments of the invention now will be described in more detail, with reference to the drawings, in which like features are identified by like reference numerals. The invention may, however, be embodied in many different forms and should not be construed as limited to the embodiments set forth herein.|[0020] The terminology used herein is for the purpose of describing certain embodiments only and is not intended to be limiting of the invention. For example, as used herein, the singular forms “a,” “an,” and “the” may include plural references unless the context clearly dictates otherwise. The terms “comprises”, “comprising”, “including”, and/or “includes”, as used herein, are intended to mean “including but not limited to.” The term “and/or”, as used herein, is intended to refer to either or both of the elements so conjoined. The phrase “at least one” in reference to a list of one or more elements, is intended to refer to at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements. Thus, as a non-limiting example, the phrase “at least one of A and B” may refer to at least one A with no B present, at least one B with no A present, or at least one A and at least one B in combination. In the context of describing the combining of components by the “addition” or “adding” of one component to another, or the separating of components by the “removal” or “removing” of one component from another, those skilled in the art will understand that the order of addition/removal is not critical (unless stated otherwise). The terms “remove”, “removing”, and “removal”, with reference to one or more impurities, contaminants, and/or constituents of biogas, includes partial removal. The terms “cause” or “causing”, as used herein, may include arranging or bringing about a specific result (e.g., a withdrawal of a gas), either directly or indirectly, or to play a role in a series of activities through commercial arrangements such as a written agreement, verbal agreement, or contract. The term “associated with”, as used herein with reference to two elements (e.g., a fuel credit associated with the transportation fuel), is intended to refer to the two elements being connected with each other, linked to each other, related in some way, dependent upon each other in some way, and/or in some relationship with each other. The terms “first”, “second”, etc., may be used to distinguish one element from another, and these elements should not be limited by these terms. The term “plurality”, as used herein, refers to two or more. The term “providing” as used herein with respect to an element, refers to directly or indirectly obtaining the element and/or making the element available for use. The terms “upstream” and “downstream”, as used herein, refer to the disposition of a step/stage in the process with respect to the disposition of other steps/stages of the process. For example, the term upstream can be used to describe to a step/stage that occurs at an earlier point of the process, whereas the term downstream can be used to describe a step/stage that occurs later in the process. Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of ordinary skill in the art.|[0021] The term “biomass”, as used herein, refers to organic material originating from plants, animals, or micro-organisms (e.g., including plants, agricultural crops or residues, municipal wastes, and algae). Biomass is a renewable resource, which can be naturally replenished on a human timescale, and which can be used to produce bioenergy, biofuels (e.g., biogas), and/or renewable products (e.g., chemicals).|[0022] The term “biogas”, as used herein, refers to a gas mixture that contains methane produced from biomass. While biogas is predominately produced from the anaerobic digestion (AD) of biomass, it is also possible to produce biogas from the gasification of biomass. For example, the gasification of biomass may produce syngas, which may be cleaned up, and methanated. When produced from the anaerobic digestion of biomass, raw biogas typically includes methane (CH4), carbon dioxide (CO2), and can contain water (H2O), nitrogen (N2), hydrogen sulfide (H2S), ammonia (NH3), oxygen (O2), volatile organic compounds (VOCs), and/or siloxanes, depending up its source. The term biogas, as used herein, can refer to raw biogas, cleaned biogas, or upgraded biogas.|[0023] The term “raw biogas”, as used herein, refers to biogas as obtained from its source (e.g., anaerobic digester or landfill) before it is treated to remove any chemical components (e.g., CO2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates). Raw biogas can be subjected to biogas cleaning to produce cleaned biogas or subjected to biogas upgrading to produce upgraded biogas.|[0024] The term “biogas cleaning”, as used herein, refers to a process where biogas (e.g., raw biogas) is treated to remove one or more components (e.g., H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), but does not remove a significant amount of CO2 and/or N2 (e.g., the calorific value of the biogas may not change significantly as a result of biogas cleaning).|[0025] The term “biogas upgrading”, as used herein, refers to a process where biogas (e.g., raw or cleaned biogas) is treated to remove one or more components (e.g., CO2, N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates), wherein the treatment is selected to increase the calorific value of the biogas. For example, biogas upgrading typically includes removing CO2 and/or N2. Biogas upgrading, which can include biogas cleaning, produces upgraded biogas. The term “upgraded biogas”, as used herein, can refer to a partially purified biogas (i.e., requires further treatment in order to meet applicable specifications) or renewable natural gas (RNG). The term “upgraded biogas”, as used herein, can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of upgraded biogas that was injected into the natural gas distribution system (e.g., upgraded biogas that was transported as a fungible batch in a natural gas pipeline).|[0026] The term “renewable natural gas” or “RNG”, as used herein, refers to biogas that has been upgraded to meet or exceed applicable natural gas pipeline specifications, meet or exceed applicable quality specifications for vehicle use (e.g., CNG specifications), and/or natural gas withdrawn from a natural gas distribution system that is associated with the environmental attributes of biogas injected into the natural gas distribution system (e.g., a gas that qualifies as RNG under applicable regulations). For example, the term RNG can refer to natural gas withdrawn from a distribution system that has been assigned environmental attributes associated with a corresponding amount of RNG, upgraded from biogas, that was injected into the natural gas distribution system. Pipeline specifications include specifications required for biogas for injection into a natural gas distribution system. Pipeline quality standards or specifications may vary by region and/or country in terms of value and units. For example, pipelines standards may require the RNG to have a CH4 level that is at least 95% or have a heating value of at least 950 BTU/scf. The percentages used to quantify gas composition and/or a specific gas content, as used herein, are expressed as mol %, unless otherwise specified. More specifically, they are expressed by mole fraction at standard temperature and pressure (STP), which is equivalent to volume fraction.|[0027] The term “natural gas” or “NG”, as used herein, refers a gas mixture rich in hydrocarbons, where the primary component is CH4. The term “gas” or “gas mixture”, as used herein, refers to a fluid that is gaseous at standard temperatures and pressures, unless indicated otherwise.|[0028] The term “environmental attributes”, as used herein with regard to a specific material (e.g., biogas), refers to any and all attributes related to the material, including all rights, credits, benefits, or payments associated with the renewable nature of the material and/or the reduction in or avoidance of fossil fuel consumption or reduction in lifecycle GHG gas emissions associated with the use of the material. Some non-limiting examples of environmental attributes include verified emission reductions, voluntary emission reductions, offsets, allowances, credits, avoided compliance costs, emission rights and authorizations, certificates, voluntary carbon units, under any law or regulation, or any emission reduction registry, trading system, or reporting or reduction program for GHG gas emissions that is established, certified, maintained, or recognized by any international, governmental, or nongovernmental agency.|[0029] The terms “capturing and storing”, as used herein with reference to CO2, refers to capturing the CO2 and storing the captured CO2 to prevent the captured CO2, or an equal quantity of CO2 displaced physically by the captured CO2, from being released to the atmosphere. Capturing the CO2 can include removing CO2 from a gas mixture (e.g., biogas, syngas) using any suitable separation technology, or if the CO2 is relatively pure, capturing the CO2 can simply refer to collecting the CO2 (e.g., in a pipe). Storing the captured CO2 can include sequestering it underground (e.g., trapping it in geological formations, such as saline aquifers, or using it for enhanced oil recovery (EOR)), or can include storing the captured CO2 in one or more products (e.g., using the captured CO2 as a resource to create valuable products such plastics, concrete, etc.). For example, “capturing and storing CO2” can be part of one or more processes commonly referred to as “carbon capture and sequestration”, “carbon capture and utilization” or CCU, or “carbon capture, utilization and storage” or CCUS. In general, capturing and storing CO2 can also include compressing the captured CO2 (e.g., to produce liquid CO2 or for injection into a CO2 distribution system) and transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). As will be understood by those skilled in the art, it can be advantageous to store the captured CO2, using a method recognized by the applicable regulatory authority for reducing GHG emissions and/or mitigating climate change.|[0030] The term “carbon intensity” or “CI” refers to the quantity of lifecycle GHG emissions, per unit of fuel energy, and is often expressed in grams of CO2 equivalent emissions per unit of fuel (e.g., gCO2e/MJ or gCO2e/MMBTU). As will be understood by those skilled in the art, CI and/or lifecycle GHG emissions are often determined using Lifecycle Analysis (LCA), which identifies and estimates all GHG emissions in producing fuel and/or product, from the growing or extraction of raw materials, to the production of the fuel and/or product, through to the end use (e.g., well-to-wheel). Those skilled in the art will understand that CI values and/or lifecycle GHG emissions for a given fuel and/or product can be dependent upon the LCA methodology used (e.g., as required by the applicable regulatory authority). Methodologies for calculating CI values and/or lifecycle GHG emissions according to various regulatory bodies are well known in the art and can be readily calculated by those of ordinary skill in the art. The CI values recited herein are determined using the CA-GREET3.0 model (e.g., see, https://ww2.arb.ca.gov/resources/documents/lcfs-life-cycle-analysis-models-and-documentation), unless otherwise specified.|[0031] The present disclosure relates to producing fuel and/or product in a process (e.g., fuel production process) that uses hydrogen and includes carbon capture and storage, wherein the carbon capture and storage includes the carbon capture and storage of CO2 removed from biogas (e.g., raw biogas).|[0032] Raw biogas produced from the anaerobic digestion of biomass can have a significant CO2 content (e.g., about 35%), which reduces the calorific value of the biogas (i.e., relative to pure methane). As a result, the use of raw and/or cleaned biogas may be limited to power generation, co-generation, or producing heat for buildings. Alternatively, raw or cleaned biogas can be upgraded (e.g., to RNG) and used as a substitute for fossil based natural gas (e.g., used as a transportation fuel in the form of compressed RNG (bio-CNG) or liquefied RNG (bio-LNG)).|[0033] As a substitute for fossil based natural gas, upgraded biogas (e.g., RNG) may be used to produce renewable hydrogen using any technology suitable for converting natural gas to hydrogen (e.g., methane reforming). Renewable hydrogen, which can be in gas or liquid form, is very versatile as it can be used as fuel, converted into electricity, and/or used as industrial feedstock (e.g., to produce fuel, fuel intermediates, or products). For example, renewable hydrogen can power fuel cell electric vehicles (FCEVs), which emit no tailpipe emissions other than water, can be run through a fuel cell to power the electricity grid, or can be used in oil refining, ammonia production, fertilizer production, methanol production, and/or steel production. As described herein, renewable hydrogen also can be used to produce fuels (e.g., liquid fuel such gasoline, diesel, and/or jet fuel) that are renewable and/or have renewable content.|[0034] Converting upgraded biogas (e.g., RNG) to renewable hydrogen by SMR is advantageous in that it exploits technology that is well established for natural gas. Unfortunately, compared to natural gas, supply of biogas may be limited, may fluctuate with the season, and/or may be from remote locations. While the relatively small scale and/or remote locations may be advantageous when the goal is to produce a grid of hydrogen refueling stations for FCEVs (e.g., where multiple geographically spaced small scale hydrogen plants can avoid transport and storage problems with hydrogen), such distributed hydrogen production cannot take advantage of economies of scale (e.g., SMR based hydrogen production is more economical when operated at a large scale), and thus is more expensive. Given the low value of raw biogas, the relatively small scale of many biogas plants, the cost of biogas upgrading, and/or the cost of SMR, it may be challenging to find facility owners willing to collect biogas and convert it to hydrogen, particularly since other uses of biogas are more economical.|[0035] It may be particularly challenging to find facility owners further willing to integrate CCS with such processes. Distributed carbon capture may be considered unfavorable compared to centralized large-scale carbon capture. For example, the cost of CCS is typically scale sensitive, and since distributed hydrogen production is generally small scale, the cost of CCS for distributed hydrogen production may be prohibitive. In addition, a lack infrastructure (e.g., CO2 pipelines) and/or space-consuming CO2 purification and capture equipment may be a deterrent for distributed CCS.|[0036] While large-scale CCS has been demonstrated for SMR plants that process fossil based natural gas, it is not cheap, and is not necessarily simple. For example, consider the hydrogen plant illustrated in FIG. 1. A stream of preheated natural gas 1 is desulfurized (not shown) and fed, along with steam 2, into the reactor tubes for the SMR 10, which contain the reforming catalyst. Streams of natural gas 3 and combustion air 4 are fed into the SMR burners, which provide the heat required for the endothermic reforming reaction. The syngas 15 produced from the SMR is fed to water gas shift (WGS) 20 to produce more hydrogen. The resulting syngas 25, which may also be referred to as shifted gas, is cooled (not shown) and purified using pressure swing adsorption (PSA) 30, which produces a stream enriched in hydrogen 32 and a purge stream 34. The purge stream 34, which may contain unconverted CH4, H2, CO2, and/or CO, is fed back to SMR 10, where it is used to provide process heat for the SMR (e.g., fuel the SMR burners). More specifically, the purge stream 34 is combusted together with the stream of natural gas 3.|[0037] In the hydrogen production process illustrated in FIG. 1, there are two sources of CO2, namely, CO2 produced from the feedstock 1 for the SMR (e.g., CO2 in the syngas 25), which can make up about 60% of the total CO2 produced, and CO2 produced from the fuel 3 for SMR (e.g., CO2 in the flue gas 12), which can make up about 40% of the total CO2 produced, depending upon the configuration of the hydrogen plant. In terms of capturing CO2, there are various options of how and where the CO2 may be captured, each with different energy requirements and/or yields. FIG. 1 identifies three possible options.|[0038] The first option, which is labelled A, captures CO2 from the flue gas 12, and thus captures both CO2 from the feedstock and CO2 from the fuel (e.g., may capture up to about 90% of the total CO2 produced). The second option, which is labelled B, captures CO2 from the syngas 25, and thus captures only the CO2 from the feedstock (e.g., about 60% of the CO2). The third option, which is labelled C, captures CO2 from the purge gas 34, and thus also captures only the CO2 from the feedstock. While the first option theoretically can capture more CO2 from the hydrogen production, capturing carbon dioxide from the syngas 25 (e.g., using vacuum pressure swing adsorption (VPSA) or an absorption amine unit) or from the purge gas 34 (e.g., using an activated amine process) may be more technically and/or economically feasible. For example, relative to the syngas 25, the flue gas may have a relatively low CO2 concentration (e.g., relatively low partial pressure) and/or may be at a lower pressure (e.g., atmospheric). In addition, the flue gas may contain N2 (N2—CH4 separations may be more challenging than CO2—CH4 separations).|[0039] In general, the SMR of fossil based natural gas to produce hydrogen can produce significant GHG emissions. While cooling of the syngas can allow heat recovery back into the process (e.g., steam generation and boiler feed water pre-heating), thereby preventing GHG emissions that would be associated with the heat, the resulting hydrogen can still have a high CI. For example, hydrogen produced from the SMR of fossil based natural gas, which is often referred to as “grey hydrogen,” may have a CI of about 100 gCO2e/MJ. When CCS is integrated with the SMR of fossil based natural gas, the resulting hydrogen it is often referred to as “blue hydrogen.” As will be understood by those skilled in the art, the CI of blue hydrogen is dependent on both the hydrogen production and how much of the fossil based CO2 is captured and stored. For example, in the case where only the CO2 from the feedstock is captured and stored (i.e., not the flue gas), blue hydrogen may have a CI of about 45 gCO2e/MJ.|[0040] As discussed herein, another approach to reduce the CI of hydrogen is to use a renewable feedstock (e.g., use RNG instead of fossil based natural gas), thereby producing renewable hydrogen. The CI of renewable hydrogen produced by the SMR of RNG can be dependent on the CI of the RNG, which can be dependent upon its source. For example, compared to the CI of fossil based natural gas, which can be about 80 gCO2e/MJ, RNG produced from a landfill may have a CI of about 46 gCO2e/MJ, whereas RNG produced from manure may have a CI of about −271 gCO2e/MJ of CH4 (e.g., as a result of avoided GHG emissions). Assuming that fossil based natural gas is used to fuel the SMR (e.g., fuel stream 3 is fossil based natural gas), the CI of renewable hydrogen produced by the SMR of landfill based RNG may be about 65 gCO2e/MJ (e.g., higher than blue hydrogen). If this process is integrated with CCS, wherein only the CO2 from the feedstock for SMR is captured and stored, the renewable hydrogen may have a CI of about 11 gCO2e/MJ. Such calculations are discussed in further detail with regard to Table 1. For comparative purposes, the CI of compressed H2 from electrolysis run with green electricity, which can be referred to as “green hydrogen”, may be less than 10 gCO2e/MJ.|[0041] The present disclosure relates to at least one process/system wherein at least a portion of the feedstock for hydrogen production and/or the fuel and/or product production is sourced from a plurality of biogas plants. Accordingly, the hydrogen production and/or fuel/product production can benefit from the economies of scale and/or higher efficiency. However, rather than relying on the capture and storage of CO2 produced from hydrogen production, the carbon capture and storage is distributed (i.e., biogenic CO2 is captured at a plurality of biogas plants).|[0042] While CCS at a plurality of biogas plants can be more expensive than CCS at a single hydrogen plant, there are various advantages and/or synergistic benefits of the process(es)/system(s) of instant disclosure. For example, it allows the benefits of CCS to accrue to hydrogen plants where CCS is not feasible (e.g., for economic reasons and/or technical reasons, such as extensive distances between the hydrogen plant and the storage site). Another advantage is that it can allow incremental transitioning, where upgraded biogas (associated with the distributed CCS) is co-processed with fossil based natural gas, thereby gradually increasing the production of hydrogen having a low CI. Advantageously, this can be achieved using existing hydrogen plants without modification. Yet another advantage is that it facilitates the aggregation of upgraded biogas from several locations (e.g., several biogas plants) and several CCS storage sites (e.g., basins) into one hydrogen production process.|[0043] One potential synergistic advantage of the process(es)/system(s) disclosure disclosed herein relates to capital efficiency. While the capital cost of distributed CCS from a plurality of biogas plants can be higher than the cost of CCS at a single hydrogen plant, the CI benefits of the capital for the distributed CCS accrues only to the upgraded biogas. In contrast, the CI benefits of the capital for CCS from centralized hydrogen production can accrue equally to all H2 produced (e.g., the CCS can be conducted on both renewable and fossil based feedstocks, and thus can be conducted on a much larger scale). In circumstances where biofuels are treated differently, this can create special advantages.|[0044] Referring to FIG. 2, there is shown an embodiment of the disclosure. Biomass is converted to biogas via multiple biogas productions 50i, 50ii, 50iii, 50iv. For example, each of the multiple biogas productions 50i, 50ii, 50iii, 50iv can include the anaerobic digestion of one or more feedstocks. In general, the feedstock for the multiple biogas productions 50i, 50ii, 50iii, 50iv can be the same or different. For example, each of the multiple biogas productions 50i, 50ii, 50iii, 50iv, may be conducted at landfill or anaerobic digester. Each of the multiple biogas productions 50i, 50ii, 50iii, 50iv produces biogas (e.g., raw biogas) that is treated in respective processing 100i, 100ii, 100iii, 100iv, to provide upgraded biogas 150i, 150ii, 150iii, 150iv, at least a portion of each provided to a facility 400a having hydrogen production 200. For example, at least part of the processing 100i, 100ii, 100iii, 100iv maybe conducted at a biogas plant (e.g., located close to the source of biogas) and may be transported to the facility that has hydrogen production 400a. Hydrogen production 200 converts at least a portion of the upgraded biogas (e.g., RNG) to renewable hydrogen (e.g., via SMR). The renewable hydrogen in the H2 product 275 is used in a fuel and/or product production process 500 that produces the fuel/product 575 (e.g., a transportation fuel). In addition to biogas upgrading, the processing 100i, 100ii, 100iii, 100iv also includes carbon capture wherein at least a portion of the CO2 from each of the biogases (e.g., generated during anaerobic digestion) is captured. The captured CO2 170i, 170ii, 170iii, 170iv is provided for storage 300.|[0045] In FIG. 2, the facility 400a having hydrogen production 200 is separate from the fuel and/or product production facility (e.g., is commercial hydrogen plant). In FIG. 3, the facility 400b having hydrogen production 200 is the fuel and/or product production facility.|[0046] In general, the upgraded biogas 150i, 150ii, 150iii, 150iv may be transported to hydrogen production 200, the captured CO2 170i, 170ii, 170iii, 170iv may be transported to storage 300, and/or the hydrogen product 275 may be transported to the fuel and/or product production facility, using any suitable mode of transportation, including transport by a commercial distribution system (e.g., pipeline) and/or vehicle (e.g., ship, rail car, and/or truck). For example, each of the upgraded biogases 150i, 150ii, 150iii, 150iv, each of the captured streams of CO2 170i, 170ii, 170iii, 170iv, and/or the hydrogen product 275 may be provided as segregated batch and/or a fungible batch. In one particularly advantageous embodiment, one or more of the upgraded biogases 150i, 150ii, 150iii, 150iv is injected into a natural gas distribution system near the corresponding processing 100i, 100ii, 100iii, 100iv and is withdrawn from the same natural gas distribution system for hydrogen production 200 (e.g., is transported as a fungible batch to the hydrogen plant and/or fuel and/or product production facility).|[0047] In general, the captured CO2 170i, 170ii, 170iii, 170iv can be stored at one or more locations. For example, since the processing 100i, 100ii, 100iii, 100iv may be conducted at different locations (e.g., different states or provinces), in some embodiments at least two of the captured streams CO2 170i, 170ii, 170iii, 170iv are provided for storage in different geological formations. In one embodiment, all of the captured CO2 170i, 170ii, 170iii, 170iv is stored in the same storage 300. In one embodiment, each of the captured CO2 gases 170i, 170ii, 170iii, 170iv is stored at respective storage sites 300i, 300ii, 300iii, 300iv. In one embodiment, at least one of the CO2 gases 170i, 170ii, 170iii, 170iv is used for CCSU, while another is used for CCS. In another example, all of the CO2 gases 170i, 170ii, 170iii, 170iv are provided for geological sequestration, but are sequestered in more than one geological formation (e.g., based on proximity of the storage to processing).|[0048] Although this process relies on multiple CO2 capture steps, which are often considered to be energy-consuming steps, there are various advantages and/or synergetic benefits of using this process for producing fuel having renewable content and/or renewable hydrogen.|[0049] For example, compare the process discussed with reference to FIGS. 2 and 3 to the gasification of biomass. Biomass gasification may offer large scale centralized hydrogen production, facilitates collecting the biogenic carbon dioxide from one point source, and avoids some intermediate steps (e.g., the conversion of biomass to biogas and biogas upgrading). Nevertheless, there are challenges to hydrogen production via biomass gasification, many of which relate to the costs associated with capital equipment and biomass feedstocks. A facility producing 100 tonnes of hydrogen per day may be very large (e.g., require 1,350 dry tonnes of biomass feedstock per day), and thus may not be feasible based on regional supplies. Smaller facilities may be more feasible from a feedstock availability perspective but may drive up the capital expenditures. The cost of the biomass feedstocks can be dependent on costs for storage and transportation of the biomass, the latter of which may be dependent on the collection radius. Feedstock costs may be modest where agricultural residues can be collected and transported over short distances, but can be high when significant transport distances are involved, at least in part due to the low energy density of biomass.|[0050] Alternatively, compare the process discussed with reference to FIGS. 2 and 3 to the SMR of biogas, wherein biomass is transported to a centralized processing facility that conducts the anaerobic digestion, biogas upgrading, and hydrogen production (i.e., upgraded biogas is not transported). As with the gasification of biomass, the feedstock costs for such a process can be largely dependent on the storage and transportation of the biomass. When the feedstock has a large moisture content (e.g., manure or food waste) the transportation cost may be even higher.|[0051] In contrast, in the process illustrated in FIGS. 2 and 3, the upgraded biogas is transported to a facility having the hydrogen production 200. Transporting upgraded biogas over extended distances can be more cost efficient than transporting feedstock for anaerobic digestion and/or gasification. In particular, upgraded biogas such as RNG may be transported using any method suitable for transporting natural gas (e.g., a truck designed for transporting liquified natural gas (LNG) or compressed natural gas (CNG), the latter of which is often transported at pressures above about 3600 psig (24.8 MPa)). Transporting the upgraded biogas as bio-LNG or bio-CNG allows more MJ to be delivered per truck (e.g., relative to biomass for gasification or anaerobic digestion) and/or can increase the collection radius for the renewable feedstock. Alternatively, or additionally, the upgraded biogas can be transported by pipeline (e.g., in a natural gas distribution system such as the US natural gas grid), where it is transported as a fungible batch.|[0052] Transporting the upgraded biogas via a natural gas distribution system is particularly advantageous. In particular, it is a cost effective method that uses existing infrastructure, and depending upon the applicable regulatory agency, may have only a small penalty (cost and/or GHG emissions) for transporting the upgraded biogas over extended distances. Accordingly, the collection zone for the renewable feedstock is not necessarily limited to the area around a centralized facility conducting anaerobic digestion, biogas upgrading, and hydrogen production, but rather can include any area that provides feedstock for biogas production, where the biogas production is near the natural gas distribution system or can be economically transported to an injection point of the natural gas distribution system. This can increase the area from which the feedstock is collected, thereby making more feedstock available for the process and increasing the feasible scale of the renewable hydrogen production and/or CCS. Transporting the upgraded biogas via a natural gas distribution system also advantageously facilitates the co-processing of renewable and non-renewable feedstock (e.g., upgraded biogas and fossil-based natural gas).|[0053] Coprocessing renewable and non-renewable feedstock can increase the possible scale of hydrogen production, can facilitate using existing hydrogen plant(s) configured to process natural gas, and/or can reduce operational complications associated with intermittent renewable feedstock supply (e.g., cold start-up times may be between about 15 and 24 hours). Accordingly, the costs of hydrogen production can be reduced.|[0054] Advantageously, providing multiple CO2 capture steps (e.g., the disaggregation of CO2 capture process) for CO2 storage allows each capture process to be optimized for the CO2 capture. For example, since biogas upgrading typically includes separating CO2 from CH4, many biogas upgrading technologies can include CO2 capture, can be readily modified to include CO2 capture, or may facilitate CO2 capture, thereby reducing costs of the CO2 capture.|[0055] Further details about the biogas production 50i, 50ii, 50iii, 50iv, the biogas processing 100i, 100ii, 100iii, 100iv, hydrogen production 200, capture and/or storage 300, and fuel/product production 500, are discussed below.|Biogas Production|[0056] In general, the multiple biogas productions 50i, 50ii, 50iii, 50iv produce multiple biogases (i.e., each biogas production produces a respective biogas). Each biogas can be produced from any suitable biomass. For example, each biogas can be produced from the anaerobic digestion of any suitable feedstock. Anaerobic digestion, which refers to the biological breakdown of organic matter by anaerobic microorganisms, is typically conducted in anaerobic or low oxygen conditions, and may involve a series of microorganism types and processes (e.g., hydrolysis, acidogenesis, acetogenesis, and methanogenesis).|[0057] In one embodiment, one or more of the biogases is produced from the anaerobic digestion of a feedstock, where the feedstock is and/or comprises: (i) an energy crop (e.g., switchgrass, sorghum, etc.); (ii) residues, byproducts, or waste from the processing of plant material in a facility, or feedstock derived therefrom (e.g., sugarcane bagasse, sugarcane tops/leaves, corn stover, etc.); (iii) agricultural residues (e.g., wheat straw, corn cobs, barley straw, corn stover, etc.); (iv) forestry material; (v) pulp and paper residues; and/or (vi) municipal waste or components removed or derived from municipal waste. In one embodiment, the feedstock for the anaerobic digestion is or includes cellulosic and/or lignocellulosic material(s).|[0058] In one embodiment, one or more of the biogases is produced from the anaerobic digestion of “organic waste.” Using organic waste as the feedstock for anaerobic digestion is particularly advantageous. Organic waste, may for example, include the organic fraction of municipal solid waste (MSW), sludge from a wastewater treatment plant (WWTP), manure from a livestock farm (e.g., a dairy or swine farm), or food or yard waste collected from households, restaurants, supermarkets, food-processing companies, schools, businesses, etc. In one embodiment, the feedstock for the anaerobic digestion is manure (e.g., swine or dairy) or other farm waste, the organic fraction of MSW, or agricultural residues (e.g., straw, stover, etc.).|[0059] The composition of biogas produced from each anaerobic digestion can be dependent upon the feedstock. For example, although biogas produced from anaerobic digestion generally has a CH4 content between about 35% and 75% (e.g., about 60%) and a CO2 content between about 15% and 65% (e.g., about 35%), the CH4 content can tend towards the high end of this range when the feedstock is agricultural waste (e.g., between about 50% and 75%) and towards the low end of this range when the feedstock is the organic fraction of municipal solid waste (e.g., between about 25% and 65%). In addition to CH4 and CO2 biogas produced from anaerobic digestion may also include N2, H2O, H2S, O2, NH3, VOCs, siloxanes, and/or particulates, in dependence upon its source. For example, biogas produced from a landfill often has a higher N2 content than biogas produced in anaerobic digester. In one embodiment, each biogas has a CH4 content between about 25% and 75% and a CO2 content between about 15% and 65%, and the CO2 and CH4 make up at least 75% of the biogas by volume.|[0060] The anaerobic digestion of the feedstocks (e.g., solid or liquid) can be conducted in any suitable environment, including a natural environment (e.g., a landfill) or a controlled environment (e.g., an anaerobic digester). An anaerobic digester can be a holding tank, or another contained volume, such as a covered lagoon or sealed structure, configured to facilitate the breakdown of organic material by microorganisms under anaerobic or low oxygen conditions. Anaerobic digestion may be carried out in one or multiple anaerobic digesters connected in series and/or parallel, where each digester may be a single-stage or multi-stage digestion system, and/or may be designed and/or operated in a number of configurations including batch or continuous, mesophilic or thermophilic temperature ranges, and low, medium, or high rates. The term “anaerobic digester”, as used herein, can refer to plurality of fluidly connected anaerobic digesters. The operation of an anaerobic digester may be dependent on nature of the organic matter fed to the anaerobic digester and/or the level of digestion required. The appropriate selection of operating parameters, including but not limited to residence time, temperature, pH, and/or the nutrients supplied, will be known to those skilled in the art. When conducted in one or more anaerobic digesters, the anaerobic digestion of biomass also produces a potentially usable digestate. Digestate refers to the material remaining after one or more stages of the anaerobic digestion (e.g., may refer to acidogenic digestate, methanogenic digestate, or a combination thereof). Digestate can include organic material not digested by the anaerobic microorganisms, by-products of the anaerobic digestion released by the microorganisms, and/or the microorganisms themselves. For example, the digestate can include carbohydrates, nutrients (such as nitrogen compounds and phosphates), other organics, and/or wild yeasts. The composition of digestate, can vary depending on the biomass from which it is derived. Digestate often has both a solid and liquid component. A common use of digestate is as a soil conditioner, where it can provide nutrients for plant growth and/or displace the use of fossil-based fertilizers. In one embodiment, the digestate is processed to provide carbon-containing material that is stored as part of CCS. Processing of the digestate can include any type of processing, including but not limited to, solid liquid separations (e.g., feeding it into a screw press), heating, combustion, pyrolysis, hydrothermal treatment, etc.|[0061] In one embodiment, each of the biogases is produced from a single source (e.g., a landfill or anaerobic digester). In one embodiment, one or more of the biogases is produced from multiple sources (e.g., one or more landfills and/or one or more anaerobic digesters).|Biogas Upgrading|[0062] In general, at least part of each processing 100i, 100ii, 100iii, 100iv includes biogas upgrading. Biogas upgrading, which can be conducted in a biogas plant situated at or close the biogas production, refers to a process where biogas is purified in one or more stages to provide upgraded biogas. Biogas upgrading, which increases the calorific value of the biogas, typically provides a CH4-rich gas having a CH4 content of at least 90%. In one embodiment, the upgraded biogases have a CH4 content of at least 90%, at least 91%, at least 92%, at least 93%, at least 94%, at least 95%, at least 96%, at least 97%, or at least at least 98%. It can be particularly advantageous to produce upgraded biogas having a CH4 content that facilitates transporting the upgraded biogas as CNG, or that facilitates injection into a natural gas distribution system. In one embodiment, the biogas upgrading produces RNG. In one embodiment, the biogas upgrading produces biogas having a CH4 content of at least 95%. In one embodiment, the biogas upgrading produces biogas having a heating value of at least 950 BTU/ft3.|[0063] Biogas upgrading can be conducted using any suitable technology or combination of technologies that can separate CH4 from one or more non-methane components in the biogas (e.g., CO2, N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates). For example, biogas upgrading technologies are often based on absorption, adsorption, membrane separation, and/or cryogenic separation. As will be understood by those skilled in the art, the technology used for the biogas upgrading can be dependent up the composition of the biogas and the desired purity of the upgraded biogas.|[0064] As biogas typically has a significant CO2 content, biogas plants often include at least one system for separating CH4 from CO2. Some examples of technologies that can remove CO2 from biogas include, but are not limited to, absorption (e.g., water scrubbing, organic physical scrubbing, chemical scrubbing), adsorption (e.g., pressure swing adsorption (PSA)), membrane separation (e.g., CO2 selective membranes based on polyimide, polysulfone, cellulose acetate, polydimethylsiloxane), and cryogenic separation.|[0065] While some CO2 removal systems may remove one or more other non-methane components in addition to CO2 (e.g., N2, H2S, H2O, NH3, O2, VOCs, siloxanes, and/or particulates), biogas plants often include one or more other systems (e.g., dehydration units, H2S removal units, N2 rejection units, etc.). For example, some CO2 removal systems require that the biogas be cleaned upstream of CO2 removal (e.g., remove impurities that can negatively affect the CO2 removal unit. Alternatively, or additionally, the biogas can be cleaned and/or upgraded downstream of CO2 removal. In general, the non-methane components can be removed by any combination of chemical and/or physical technologies, in one or more stages. For example, H2O may be removed using a standard biogas dehumidifier, whereas H2S may be removed using a commercial H2S removal unit (e.g., based on activated carbon, molecular sieve, iron sponge, water scrubbing, NaOH washing, and/or biofilter or biotrickling filter technologies). In some cases, one stage may remove more than one non-methane component. For example, in some cases, some H2S may also be removed during the water removal step.|[0066] In general, the biogas upgrading can be conducted close to the biogas source (e.g., at a biogas plant at the landfill site or near the anaerobic digester) and/or at a centralized biogas plant (e.g., which receives raw, cleaned, or partially purified biogas from multiple sources). For example, a centralized biogas plant may be connected to one or more anaerobic digesters (e.g., each at a separate farm) via a biogas pipeline and/or grid. Alternatively, or additionally, the centralized biogas plant may receive biogas from one or more biogas sources by vehicle (e.g., see U.S. Pat. No. 10,760,024). In one embodiment, each biogas processing 100i, 100ii, 100iii, 100iv is conducted on biogas from a single biogas source. In one embodiment, at least one biogas processing 100i, 100ii, 100iii, 100iv is conducted at a centralized processing plant that receives biogas from multiple biogas sources (e.g., multiple farms).|[0067] Each of the upgraded biogases 150i, 150ii, 150iii, 150iv is transported to a facility having hydrogen production (e.g., to a stand-alone hydrogen plant or to a production facility having at least one hydrogen production process). As each upgraded biogas may be relatively pure (e.g., have a CH4 content greater than about 92%), it may be transported using methods used to transport natural gas. For example, if the biogas is upgraded to RNG it can be transported in a CNG tanker (e.g., at a pressure of about 3600 psig) and/or transported by pipeline (e.g., a natural gas distribution system such as the US natural gas grid). In some cases, upgraded biogas that does not meet pipeline standards can be mixed with another gas (e.g., propane or fossil based natural gas) in order to facilitate injection into the natural gas distribution system.|[0068] In general, when upgraded biogas is transported by pipeline, it is transferred as a fluid (e.g., in gaseous or liquid form), and may be provided as a segregated batch or a fungible batch. The term “batch”, as used herein, refers to a certain amount of the gas (e.g., energy delivered) and does not imply or exclude an interruption in the production and/or delivery.|[0069] When upgraded biogas is transported as a fungible batch in a natural gas distribution system, a quantity of the upgraded biogas (e.g., in MJ) is injected into the natural gas distribution system, where it can comingle with non-renewable natural gas, and an equivalent quantity of gas (e.g., in MJ) is withdrawn at another location (i.e., as long as there is a physical link between the injection point and the withdrawal point). The transfer or allocation of the environmental attributes of the upgraded biogas injected into the natural gas distribution system to gas withdrawn at a different location is typically recognized. Accordingly, the withdrawn gas can be recognized as the transported upgraded biogas and/or can qualify as RNG under applicable regulations (e.g., even though the withdrawn gas may not contain actual molecules from the original biomass and/or contains methane from fossil sources). Such transport may be carried out on a displacement basis, where transactions within the natural gas distribution system involve a matching and balancing of inputs and outputs. Typically, the direction of the physical flow of gas is not considered. Establishing that a gas is recognized as and/or qualifies as RNG (e.g., originates from renewable sources) under applicable regulations can depend on whether the gas is transported by truck or by pipeline and the practices and requirements of the applicable regulatory agency, where such practices may include, for example, the use of chain of custody accounting methods such as identity preservation, book-and-claim, and/or mass balance.|[0070] Transporting the upgraded biogas via a natural gas grid is particularly advantageous as it facilitates transporting the renewable feedstock anywhere where the grid delivers without significant additional cost (e.g., financially and/or GHG emissions). In one embodiment, the upgraded biogas is transported to a facility having hydrogen production, at least in part, via a natural gas distribution system. In one embodiment, each of the upgraded biogases is transported to a facility having hydrogen production, at least in part, by vehicle. In one embodiment, each of the upgraded biogases is transported to a facility having hydrogen production, at least in part, using a transportation system.|[0071] The term “transportation system”, as used herein with reference to an element (e.g., natural gas or CO2 or H2), refers to a system configured to transport the element, and/or a fungible element, by a distribution system and/or vehicle. For example, a transportation system can include a mobile pressure vessel configured to be transported by vehicle (e.g., truck, rail car, ship). The term “distribution system”, as used herein with reference to an element (e.g., natural gas or CO2 or H2), refers to a system configured to transport the element, and/or a fungible element, in one or more interconnected pipes (e.g., by pipeline). For example, a natural gas distribution system such as the US natural gas grid can be used to transport natural gas and/or upgraded biogas.|Hydrogen Production|[0072] In general, the hydrogen production may be conducted at one or more hydrogen plants. The term “hydrogen plant”, as used herein, refers to a system or combination of systems primarily used for hydrogen production. The term “renewable hydrogen”, as used herein, refers to hydrogen produced using biogas (e.g., upgraded biogas and/or RNG). For example, the term “renewable hydrogen” can refer to hydrogen produced by methane reforming a feed withdrawn from a natural gas distribution system, when at least a portion of the withdrawn feed is recognized as and/or qualifies as RNG under applicable regulations.|[0073] In general, the hydrogen production may use any suitable technology known in the art that can convert one or more of the upgraded biogases and/or natural gas to hydrogen. Examples of technologies that may be suitable include, but are not limited to, steam methane reforming (SMR), autothermal reforming (ATR), partial oxidation (POX), and dry methane reforming (DMR). SMR, ATR, and DMR, which are types of catalytic reforming, may operate by exposing natural gas to a catalyst at high temperature and pressure to produce syngas. POX reactions, which include thermal partial oxidation reactions (TPOX) and catalytic partial oxidation reactions (CPOX), may occur when a sub-stoichiometric fuel-oxygen mixture is partially combusted in a reformer. POX also may be referred to as oxidative reforming. For purposes herein, the term “methane reforming” may refer to SMR, ATR, DMR, or POX.|[0074] Of the various types of methane reforming, SMR is the most common. In SMR, which is an endothermic process, methane is reacted with steam under pressure in the presence of a catalyst to produce carbon monoxide (CO) and H2 according to the following reaction:|CH4+H2O+heat→CO+3H2 (1)|[0075] Referring to the hydrogen plant in FIG. 1, this reaction may occur in the SMR reactor tubes, which contain the reforming catalyst. Without being limiting, the catalyst may be nickel-based, the operating pressure may be between 200 psig (1.38 MPa) and 600 psig (4.14 MPa), and the operating temperature may be between about 450 to 1000° C. The heat required for the catalytic reforming of Eq. 1 can be provided by the combustion in the SMR burners (e.g., the combustion chamber may surround the reformer tubes in which the reaction is conducted).|[0076] The syngas produced from Eq. (1) may be further reacted in the WGS 20. The WGS is based on the water gas shift reaction, wherein carbon monoxide is converted to carbon dioxide and hydrogen:|CO+H2O→CO2+H2+small amount of heat (2)|[0077] Providing WGS downstream of SMR increases the yield of H2, and thus is commonly included in hydrogen production. For example, in addition to H2, the syngas produced from the SMR may have a CO2 content between about 7-10%, a CO content between about 12-19%, and a CH4 content between about 2-6%, whereas the syngas produced from the WGS may have a CO2 content between about 15-16%, a CO content between about 4-5%, and a CH4 content between about 3-4%.|[0078] The gas produced from methane reforming (e.g., the syngas 25) is subjected to a hydrogen purification, wherein H2 is separated from CO, CO2, and/or CH4 in one or more stages to produce a hydrogen product (e.g., containing at least 80% hydrogen). For example, in one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 90, 92, 94, 96, 98, 99, or 99.5%. In one embodiment, the hydrogen purification produces an enriched hydrogen stream having a hydrogen content of at least 99.9%. Without being limiting, some examples of suitable hydrogen purification technologies include, but are not limited to: a) absorption, b) adsorption, c) membrane separation, d) cryogenic separation, and e) methanation. Some examples of absorption systems that may be suitable include, but are not limited to, a monoethanolamine (MEA) unit or a methyl-diethanolamine (MDEA) unit. A MEA unit may include one or more absorption columns containing an aqueous solution of MEA at about 30 wt %. The outlet liquid stream of solvent may be treated to regenerate the MEA and separate CO2. Some examples of adsorption systems that may be suitable include, but are not limited to, systems that use adsorbent bed (e.g., molecular sieves, activated carbon, active alumina, or silica gel) to remove impurities such as CH4, CO2, CO, N2, and/or water from the syngas gas. For example, hydrogen purification systems that are based on PSA are commonly used for hydrogen plants, as such systems produces a purge gas that can be recycled to fuel the SMR burners, thereby improving energy efficiency (e.g., see FIG. 1). In one embodiment, hydrogen purification uses vacuum PSA system (VPSA). Some examples of membranes systems that may be suitable include, but are not limited to, H2 selective membranes. A hydrogen purification unit that is based on cryogenic separation may cool the syngas gas down to temperatures where the impurities condense or sublimate and can be separated as a liquid or a solid fraction, while the hydrogen accumulates in the gas phase. For example, cryogenic separations may use temperatures below −10° C. or below −50° C. Methanation is a catalytic process that can be conducted to convert the residual carbon monoxide and/or carbon dioxide in the syngas to methane. For example, see equation 3.|CO+3H2→CH4+H2O (3)|Since the methanation reaction consumes hydrogen, a hydrogen purification unit that includes a methanation may include CO2 removal prior to methanation.|[0079] In general, hydrogen production is well known and those skilled in the art will understand that the hydrogen plant(s) may use any suitable technology and/or have any suitable configuration. For example, the hydrogen production may be based on any suitable methane reforming technology combined with any suitable hydrogen purification. With specific regard to FIG. 1, those skilled in the art will understand that each of the SMR unit 10 and WGS unit 20 may include a single reactor or multiple reactors (e.g., the WGS unit 20 may include a high temperature WGS reactor (e.g., 350° C.) followed by a low temperature WGS reactor (e.g., 200° C.)), that the SMR reactor(s) may be top-fired reformers, side-fired reformers, bottom-fired reformers, etc., that the SMR reformer may be downstream of a purification unit to remove sulfur, chloride, olefin, and/or other compounds that may be detrimental to the SMR reforming catalysts, or that the SMR reformer may be downstream a pre-reforming unit, which allows a higher inlet feed temperature with minimal risk of carbon deposition. Those skilled in the art will also understand that although a steam methane reformer may be referred to as a “methane reformer,” typically they can convert any of the hydrocarbons present in the natural gas to syngas (i.e., not just the methane).|[0080] In the above-described embodiments, the feedstock for the hydrogen production process contains at least a portion of one or more of the upgraded biogases (e.g., RNG), which can be transported to the facility containing the hydrogen production (e.g., at least one hydrogen plant) by vehicle and/or as a fungible batch via a natural gas distribution system. In each embodiment, the feedstock may contain only the upgraded biogas or may contain both upgraded biogas and fossil based gas such as natural gas (e.g., the hydrogen can be produced by coprocessing renewable and non-renewable methane). When the feed contains both upgraded biogas and fossil based gas (e.g., natural gas or refinery gas), the quantity of renewable hydrogen produced can be determined using the renewable fraction of the feedstock (based on energy).|[0081] In the above-described embodiments, the feedstock for the renewable hydrogen process contains at least a portion of one or more of the upgraded biogases. However, in some embodiments, a portion of one or more of the upgraded biogases is fed to the combustion zone of the methane reformer (e.g., to the SMR burners). Since combusting upgraded biogas simply returns to the atmosphere carbon that was recently fixed by photosynthesis, and thus is considered relatively benign, this can reduce GHG emissions from the SMR furnace (e.g., compared to using fossil-based methane). Accordingly, the CI of renewable hydrogen could be reduced. While it may be advantageous to sacrifice some of the upgraded biogas for fuel in order to improve the GHG balance of the hydrogen production and/or fuel/product production process, this reduces the yield of renewable hydrogen and/or the yield of renewable content of the fuel(s)/product(s) produced. Accordingly, there may be a compromise between increasing the yield of renewable hydrogen/renewable content and decreasing the lifecycle GHG emissions, for a given quantity of upgraded biogas. In certain embodiments, low-carbon electricity such as renewable electricity is used to provide heat for the methane reforming (e.g., for SMR). Low-carbon electricity refers to electricity generated in a process that does not emit significant amounts of fossil-based carbon dioxide and/or is produced from renewable energy sources. Without being limiting, low-carbon electricity can include electricity produced using nuclear power, hydropower, solar power, wind power, geothermal power, wave power, tidal power, or electricity produced from the combustion of a low-carbon energy source (e.g., biomass, biogenic syngas, or hydrogen) or of a fossil-based energy source with CCS. In certain embodiments, heat required for the SMR is generated using renewable electricity (i.e., electricity produced using renewable energy sources such as hydropower, solar power, wind power, geothermal power, wave power, tidal power, etc.). In certain embodiments, the low-carbon electricity is generated from gasification of agricultural and/or solid waste. In general, any suitable technology known in the art that can use electricity to produce a sufficient amount of heat for at least part of the methane reforming can be used. The low-carbon electricity can produce the heat for methane reforming directly (e.g., to power resistive or inductive heaters that provide the heat directly for the methane reforming) and/or indirectly (e.g., using a heat storage medium and/or heat transfer fluid). In certain embodiments, the methane reformer (e.g., SMR) is an electrically heated methane reformer (e.g., electrically heated SMR), wherein the heat that would have been generated with conventional fired burners is replaced with electrically generated heat. Such methane reformers are generally configured such that there is no flue gas, and thus there are no carbon emissions associated with the flue gas (e.g., carbon emissions of hydrogen production may be reduced by 20-50% relative to the conventional fired SMR).|Carbon Capture and Storage|[0082] In general, at least part of each processing 100i, 100ii, 100iii, 100iv includes carbon capture, wherein at least a portion of the CO2 from the biogas produced (e.g., generated during anaerobic digestion) is captured. The capture of CO2 from each biogas produced can be conducted using any suitable technology or combination of technologies that can capture CO2 for storage. As the CO2 may be part of a gas mixture (e.g., biogas, syngas, flue gas, etc.), the CO2 capture can include and/or depend upon the separation of CO2 from one or more other gas components in a gas mixture. Technology that may be suitable for separating CO2 from one or more other gas components in a gas mixture includes, but is not limited to, absorption, adsorption, membrane separation, and cryogenic separation.|[0083] The CO2 from each of the biogases (e.g., generated during anaerobic digestion) can be captured upstream of biogas upgrading, as part of biogas upgrading, and/or from a tail gas produced from biogas upgrading. For example, since biogas upgrading can include steps where CO2 is separated from CH4, such steps can be part of the CO2 capture process, or can facilitate the CO2 capture process, thereby reducing capital and operating costs. Biogas upgrading, which typically focuses on providing a relatively pure product stream (e.g., greater than 95% CH4), can produce a tail gas that contains CO2 separated from the CH4 in addition to other non-methane components separated from the CH4. For example, biogas upgrading units based on absorption, adsorption, or membrane separation, can produce a CO2 rich tail gas that is too impure for CO2 storage and/or transport without further purification and/or upstream removal of one or more components. However, in some cases, biogas upgrading (e.g., based on cryogenic separation), can yield both relatively pure CH4 (e.g., greater than about 95% CH4) and relatively pure CO2 (e.g., greater than about 95% CO2). While cryogenic biogas upgrading may require upstream biogas cleaning, it advantageously can provide the CO2 is a form that facilitates transport by vehicle and/or a CO2 distribution system (e.g., can provide the CO2 in liquid or solid form).|[0084] In one embodiment, at least one of the processing steps 100i, 100ii, 100iii, 100iv includes a separate CO2 removal step for the CO2 capture (i.e., separate from the biogas upgrading). For example, in one embodiment, a separate CO2 separation is conducted on the tail gas from biogas upgrading to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport. In another embodiment, a separate CO2 separation is conducted upstream of biogas upgrading to provide a CO2 product that is sufficiently pure for CO2 storage and/or transport.|[0085] In one embodiment, the biogas upgrading is conducted in stages and at least one stage of the biogas upgrading is a CO2 capture step.|[0086] In one embodiment, the CO2 capture step is integrated with the biogas upgrading. For example, in one embodiment, the biogas upgrading is selected to and/or modified to provide a CO2 product suitable for geological storage and/or transport by a CO2 distribution system (e.g., after dehydration and compression). In general, this may be achieved by selecting suitable separation technology and/or modifying the configuration of the system (e.g., removing one or more components upstream of the CO2 separation). For example, in one embodiment, cryogenic CO2 capture is part of biogas upgrading. When cryogenic separation is used as part of biogas upgrading, the biogas may be cleaned (e.g., to remove H2S and H2O) and then subjected to a cryogenic separation that provides relatively pure CO2 (e.g., >95% CO2) while also providing a relatively pure CH4 (e.g., >95% CH4) and N2 (if present).|[0087] Storage of CO2 captured from the biogases can be conducted using any suitable technology or combination of technologies. For example, carbon storage technologies, which are well known in the art, can sequester CO2 in geological formations (i.e., subsurface formations). Suitable geological formations, which can occur in onshore or offshore settings, are often configured such that CO2 injected therein, is trapped. Appropriate storage of the CO2 can reduce GHG emissions and/or mitigate climate change. The level of GHG reduction achieved may be dependent on whether it is all biogenic, the applicable regulatory authority, the permanence of the storage, and/or whether its use displaces the use of fossil fuel products. In one embodiment, the captured CO2 from one or more of the biogases is sequestered in at least one geological formation. For example, in one embodiment the captured CO2 from one or more of the biogases is sequestered in a saline aquifer or is sequestered in an oil/natural gas reservoir as part of enhanced oil recovery (EOR)). In one embodiment, the captured CO2 from one or more of the biogases is stored in concrete. In one embodiment, storage of the captured CO2 from one or more of the biogases permanently displaces fossil based CO2 emissions.|[0088] The purity of the CO2 required for storage can be dependent upon the selected storage and/or selected mode of transportation, if applicable. For example, for geological sequestration and/or EOR, where the CO2 is often transported, at least in part, via a CO2 distribution system (e.g., pipeline), the CO2 content should be as high as possible (e.g., at least about 95%). However, for some applications (e.g., bauxite residue carbonation, etc.) lower CO2 contents may be suitable. In addition to a minimum CO2 content, the CO2 provided for storage and/or transport may have limits on the maximum amount of H2O, H2S, CO, CH4, N2, Ar, H2, etc.|[0089] In general, when the CO2 is captured far from storage, the process includes transporting the captured CO2 to storage (e.g., by vehicle and/or a CO2 distribution system). In order to transport CO2 for storage, the CO2 typically requires significant compression and/or cooling. When CO2 is transported by vehicle (e.g., truck, ship, rail car) it is often transported as a liquid (e.g., a pressure of about 290 psig and a temperature of about −20° C., or a pressure of about 100 psig and a temperature of about −50° C.). When CO2 is transported by a CO2 distribution system (e.g., a CO2 pipeline) it is often transported as a supercritical fluid (critical point is −31° C., −1070 psig). For example, many CO2 pipelines are operated between about 1250 psig and about 2200 psig, or higher. In some embodiments, the collected CO2 is also stored locally at a relatively high pressure (e.g., −1600 psig) prior to transport by pipeline. In general, the CO2 can be compressed to the desired pressure using a gas compressor, or alternatively, the collected CO2 can be liquified at a lower pressure using a refrigeration system (e.g., 235 psig) and then pumped to the desired pressure. In one embodiment, the process produces a compressed stream of relatively pure CO2 (e.g., at least 95% CO2). In one embodiment, the CO2 is transported to storage, at least in part, as a fungible batch using a CO2 distribution system.|[0090] The CO2 captured from the multiple biogas upgrading processes can be stored together or separately (e.g., in the same geological formation or in different geological formations). In general, how and where the captured CO2 is stored may be dependent upon the closest storage site. In one embodiment, the CO2 captured from one or more of the biogases is, at least in part, transported using a CO2 distribution system.|[0091] In one embodiment, at least 50% of the CO2 from each of one or more of the biogases is captured and stored. In one embodiment, at least 55%, at least 60%, at least 65%, at least 70%, at least 75%, at least 80%, at least 85%, at least 90% of the CO2 from each of one or more of the biogases is captured and stored.|[0092] In certain embodiments, the carbon intensity and/or lifecycle GHG emissions of the fuel/product(s) is further reduced by storing carbon containing material obtained or derived from the biogas production/biogas upgrading. For example, in certain embodiments, digestate from anaerobic digestion of the biomass is provided for storage as part of CCS. In certain embodiments, the digestate is treated prior to CCS. For example, digestate can be subjected to a hydrothermal liquefaction to provide a bio-oil that can be sequestered. In some cases, the sequestration method is selected to prevent biodegradation of the material and/or trap GHGs in the event of biodegradation. In some cases, the material is treated in a process to reduce the potential for biodegradation. The amount of carbon obtained or derived from the digestate and provided as part of CCS can be expressed as kg C per m3 (dry weight). Advantageously, storing a liquid or solid by-product produced from the process as part of CCS can further reduce the carbon intensity of the hydrogen produced and/or a fuel or product produced from the hydrogen.|Fuel or Product Production|[0093] In general, the process produces fuel and/or product (e.g., having renewable content) using renewable hydrogen. In one embodiment, the process produces fuel. In one embodiment, the fuel is methanol. In one embodiment, the fuel is gasoline, diesel, and/or jet fuel. In one embodiment, the fuel is an aviation fuel. In one embodiment, the fuel is a transportation fuel. In one embodiment, the fuel is a liquid transportation fuel. In one embodiment, the process produces one or more products (e.g., the renewable hydrogen is used as an industrial feedstock to produce one or more fuels and/or chemical products). In one embodiment, the renewable hydrogen is used to produce ammonia (e.g., in a Haber-Bosch process). In the Haber-Bosch process, which is well-known to those skilled in the art, nitrogen is converted to ammonia in a process conducted under high temperatures and pressures with a metal catalyst. Ammonia has an important role in the agricultural industry for production of fertilizers. Ammonia may also be used as a fuel and/or an energy carrier for energy storage and transportation. In one embodiment, the renewable hydrogen is used to produce fertilizer. Using the upgraded biogas and/or renewable hydrogen to produce fuel and/or product can provide the fuel and/or product with renewable content and/or can reduce the lifecycle GHG emissions of the fuel and/or product, particularly when the upgraded biogas and/or renewable hydrogen has a low CI attributed to CCS.|[0094] In general, the fuel and/or product may be produced by processing the upgraded biogas and/or renewable hydrogen with one or more other renewable feedstocks and/or one or more non-renewable feedstocks. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the fuel can have renewable content (e.g., be a partially renewable fuel). The term “renewable content”, as used herein, refers the portion of the fuel(s)/product(s) that is recognized and/or qualifies as renewable (e.g., a biofuel) under applicable regulations. The quantification of the renewable content can be determined using any suitable method and is typically dependent upon the applicable regulations.|[0095] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon such that the renewable hydrogen is incorporated into a crude-oil derived liquid hydrocarbon to produce gasoline, diesel, and/or jet fuel having renewable content (e.g., see U.S. Pat. Nos. 8,658,026, 8,753,854, 8,945,373, 9,040,271, 10,093,540, 10,421,663, and 10,723,621, 10,981,784). In this embodiment, use of the renewable hydrogen can produce gasoline, diesel, and/or jet fuel having renewal content. Advantageously, such fuels can replace and/or be used with non-renewable gasoline, diesel, and/or jet fuel without affecting performance and/or operation (e.g., are drop-in fuels). Further advantageously, such fuels can be produced at existing oil refineries using existing equipment. The term “crude oil derived liquid hydrocarbon”, as used herein, refers to any carbon-containing material obtained and/or derived from crude oil that is liquid at standard ambient temperature and pressure. The term “crude oil”, as used herein, refers to petroleum extracted from geological formations (e.g., in its unrefined form). Crude oil includes liquid, gaseous, and/or solid carbon-containing material from geological formations, including oil reservoirs, such as hydrocarbons found within rock formations, oil sands, or oil shale. In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of crude-oil derived liquid hydrocarbon to produce aviation fuel having renewable content. This embodiment is particularly advantageous as it could help decarbonize commercial air travel and/or extend the life of older aircraft types by lowering their carbon footprint.|[0096] In one embodiment, the renewable hydrogen is used in the hydroprocessing (e.g., hydrocracking and/or hydrotreating) of renewable fats and/or oils (e.g., algae, jatropha, tallows, camelina, pyrolysis oil produced from biomass, etc.) to produce renewable gasoline, diesel, and/or jet fuel. This embodiment is particularly advantageous as the resulting fuel can be fully renewable and have a reduced CI (i.e., relative to an analogy process where the hydrogen is produced from fossil based natural gas).|[0097] In general, the renewable hydrogen can be used in any suitable fuel and/or product production process. For example, in one embodiment, the renewable hydrogen is used in a Fischer-Tropsch type process to produce a liquid transportation fuel. In one embodiment, the renewable hydrogen and biogenic carbon dioxide are subjected to a gas fermentation to produce an alcohol such as ethanol.|[0098] In general, the renewable hydrogen may be produced at a commercial hydrogen plant or at a hydrogen plant at the production facility. In both cases, the renewable hydrogen may be provided for fuel/product production via a H2 distribution system (e.g., a H2 pipeline or local H2 pipe system) as a fungible batch. More specifically, the renewable hydrogen may be allocated for the desired use (e.g., a specific fuel production process or a specific hydroprocessing unit). The term “allocating”, as used herein in respect of a particular element, refers to designating the element for a specific purpose.|Carbon Intensity and/or Fuel Credits|[0099] In general, the carbon intensity and/or lifecycle GHG emissions of the fuel and/or product having renewable content is relatively low as a result of the use of renewable hydrogen and/or storage of captured CO2 170i, 170ii, 170iii, 170iv (i.e., low relative to fuel produced by an analogous process using hydrogen produced using fossil based natural gas or an analogous process where the biogenic CO2 170i, 170ii, 170iii, 170iv is not stored). Advantageously, when the process produces fuel, the renewable content attributed to the use of renewable hydrogen and/or the low CI attributed to storing the captured CO2 170i, 170ii, 170iii, 170iv can facilitate the generation of fuel credits.|[0100] Fuel credits are used to incentivize renewable fuels, often in the transportation sector. For example, fuel credits can be used to demonstrate compliance with some government initiative, standard, and/or program, where the goal is to reduce GHG emissions (e.g., reduce CI in transportation fuels as compared to some baseline level related to conventional petroleum fuels) and/or produce a certain amount of biofuel (e.g., produce a mandated volume or a certain percentage of biofuels). The target GHG reductions and/or target biofuel amounts may be set per year or for a given target date. Some non-limiting examples of such initiatives, standards, and/or programs include the Renewable Fuel Standard Program (RFS2) in the United States, the Renewable Energy Directive (RED II) in Europe, the Fuel Quality Directive in Europe, the Renewable Transport Fuel Obligation (RTFO) in the United Kingdom, and/or the Low Carbon Fuel Standards (LCFS) in California, Oregon, or British Columbia).|[0101] The term “fuel credit”, as used herein, refers to any rights, credits, revenues, offsets, GHG gas rights, or similar rights related to carbon credits, rights to any GHG gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract, or otherwise. A fuel credit can be a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline (e.g., a gasoline baseline) set by a government authority. Non-limiting examples of fuel credits include RINs and LCFS credits. A Renewable Identification Number (or RIN), which is a certificate that acts as a tradable currency for managing compliance under the RFS2, may be generated for each gallon of biofuel (e.g., ethanol, biodiesel, etc.) produced. A Low Carbon Fuel Standard (LCFS) credit, which is a certificate which acts as a tradable currency for managing compliance under California's LCFS, may be generated for each metric ton (MT) of CO2 reduced.|[0102] In general, the requirements for generating or causing the generation of fuel credits can vary by country, the agency, and or the prevailing regulations in/under which the fuel credit is generated. In many cases, fuel credit generation may be dependent upon a compliance pathway (e.g., predetermined or applied for) and/or the biofuel meeting a predetermined GHG emission threshold. For example, with regard to the former, the RFS2 categorizes biofuel as cellulosic biofuel, advanced biofuel, renewable biofuel, and biomass-based diesel. With regard to the latter, to be a renewable biofuel under the RFS2, corn ethanol should have lifecycle GHG emissions at least 20% lower than an energy-equivalent quantity of gasoline (e.g., 20% lower than the 2005 EPA average gasoline baseline of 93.08 gCO2e/MJ). In low carbon-related fuel standards, biofuels may be credited according to the carbon reductions of their pathway. For example, under California's LCFS, each biofuel is given a CI score indicating their GHG emissions as grams of CO2 equivalent per megajoule (MJ) of fuel, and fuel credits are generated based on a comparison of their emissions reductions to a target or standard that may decrease each year (e.g., in 2019, ethanol was compared to the gasoline average CI of 93.23 gCO2e/MJ), where lower CIs generate proportionally more credits. In one embodiment, the fuel produced is a transportation fuel, and a fuel credit is generated or is caused to be generated. In one embodiment, the transportation fuel and/or renewable content has lifecycle GHG emissions that are at least 20% less than the lifecycle GHG emissions of a gasoline baseline using EPA methodology, preferably at least 50% or 60% less.|[0103] With respect to renewable hydrogen produced according to the instant disclosure, it can be advantageous for the CI of the hydrogen to be as low as possible, particularly when the hydrogen is used as a fuel or to produce a fuel, so that more valuable fuel credits can be generated. When the process produces a fuel from the co-processing of renewable and non-renewable feedstocks, the CI is measured for the resulting product from each of the co-processed feedstocks (i.e., there is a different CI for each the renewable and non-renewable feedstocks). In one embodiment, the process includes producing hydrogen associated with one or more producer credits.|(US12359134)|Example|[0104] Referring to Table 1, there is shown a list of estimated GHG emission values for hydrogen produced by various processes. As summarized in Table 2, these processes produce: 1) grey hydrogen from the SMR of natural gas with no CCS; 2) blue hydrogen from the SMR of natural gas with CCS (i.e., where the CO2 is captured from the feedstock); 3) renewable hydrogen labelled “RH” from the SMR of RNG with no CCS; 4) renewable hydrogen labelled “RH+CCSH2” from the SMR of RNG with CCS (i.e., where the CO2 is captured from the feedstock only); 5) renewable hydrogen labelled “RH+CCSH2+CCSBG” from the SMR of RNG with CCS (i.e., where the CO2 is captured from the feedstock and from the biogas); and 6) renewable hydrogen labelled “RH+CCSBG” from the SMR of RNG with CCS (i.e., where the CO2 is captured from the biogas only).|[0105] For each process, it was assumed that the fuel for the SMR burners is fossil based natural gas and that the feedstock for the methane reforming is RNG produced from landfill gas (i.e., is upgraded landfill gas). In order to compare the different processes, which can use different feedstocks, the emissions for the hydrogen production were split into the contributions from the feedstock (i.e., upstream emissions) and from the hydrogen production. Each emission (positive number) and emission credit (negative number) is an estimation based on one or more published values and/or determined using stoichiometry. For example, the feedstock emissions of 10 gCO2e/MJ of H2 for natural gas and 35 gCO2e/MJ of H2 for landfill gas are estimated from the CA-GREET 3.0 model. The feedstock emission credit of −42 gCO2e/MJ of H2, which is a net credit at least partially based on theoretical calculations, assumes that the emissions for CCS of the biogas is 5 gCO2e/MJ of H2. For the hydrogen production, emissions from the combustion of fuel for the SMR burners is assumed to be 28 gCO2e/MJ of H2, electricity is assumed to be 2 gCO2e/MJ of H2, and emissions from the conversion of the feedstock to syngas is assumed to be 60 gCO2e per MJ of H2. Assuming all of the CO2 from the feedstock is captured and stored, and if the CCS process from hydrogen production results in 5 gCO2e/MJ of H2 of emissions, the CCSH2 process provides a net credit of −55 gCO2e/MJ of H2.|[0106] TABLE 1 GHG Emission Values, in gCO2e/MJ of H2, for various SMR based H2production processes FeedstockHydrogen Plant Feedstock Hydrogen CO2FuelFeedstock Plant CO2 ProcessFeedstockcaptureCombustionconversionElectricitycaptureCI Grey H210 28602 100Blue H210 28602−5545RH35 28 2 65RH + CCSH235 28 2−5511RH + CCSH2 + 35−4228 2−55−31CCSBG RH + CCSBG35−4228 2 24 |[0107] TABLE 2 Summary of the various SMR based H2 production processesProcessDescriptionFeedstockCO2 capture 1Grey H2Natural GasNone2Blue H2Natural GasYes—Syngas3Renewable H2 (RH)RNG (landfill)None4Renewable H2 RNG (landfill)Yes—Syngas only and CCSH2 5Renewable H2 and RNG (landfill)Yes—Syngas and CCSH2 and CCSBG upstream6Renewable H2 RNG (landfill)Yes—Upstream only and CCSBG |[0108] While the GHG emission values in Table 1 are estimations provided for comparative purposes, they do appear reasonable. For example, Table 1 lists the CI of grey hydrogen as 100 gCO2e/MJ, which is within a published range of 94.8 to 101.4 g CO2e/MJ. With regard to the CI of blue hydrogen, which Table 1 lists as 45 gCO2e/MJ (with CCS of about 60% of the total CO2 produced), some published values are 19.6 gCO2e/MJ (with CCS of about 90% of the total CO2 produced) and 34.5 gCO2e/MJ (with CCS of about 80% of the total CO2 produced).|[0109] As evident from Table 1, simply using RNG as a feedstock for hydrogen production, using RNG as a feedstock for hydrogen production and capturing CO2 from the hydrogen production, or using RNG as a feedstock for hydrogen production and capturing CO2 from the biogas, does not necessarily produce hydrogen having a negative CI, and can produce hydrogen having a higher CI than green hydrogen (e.g., which can be less than 10 gCO2e/MJ).|[0110] However, as evident from Table 1, using RNG as a feedstock for hydrogen production and capturing CO2 from the biogas does produce hydrogen having a lower CI than blue hydrogen, without the challenges of capturing and storing CO2 from hydrogen production. Moreover, it produces renewable hydrogen. When renewable hydrogen having a relatively low CI is used in a fuel and/or product production process, the fuel and/or product produced can have renewable content, and the renewable content can have a relatively low CI (i.e., relative to the analogous process without storing the CO2 from the biogas). Accordingly, the process(es) disclosed herein can be used to produce fuel having renewable content and a relatively low CI without CCS of CO2 from hydrogen production.|[0111] Of course, the above embodiments have been provided as examples only. It will be appreciated by those of ordinary skill in the art that various modifications, alternate configurations, and/or equivalents will be employed without departing from the scope of the invention. For example, although the instant disclosure provides a process that provides renewable hydrogen and/or fuel and/or product having renewable content, with a relatively low CI without CCS of CO2 from the hydrogen production, and although this is generally advantageous, in some embodiments, the CO2 from hydrogen production is also captured and stored (e.g., from the syngas and/or the flue gas). Accordingly, the scope of the invention is therefore intended to be limited solely by the scope of the appended claims. | Family Number|(102292005)|102292005|Advantages / Prev. 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J. of Hydrogen Energy, 2008, vol. 33, pp. 2023-2035.|-Najafpour et al., “Hydrogen as clean fuel via continuous fermentation by anaerobic photosynthetic bacteria, Rhodospirillum rubrum”, African Journal of Biotechnology, Oct. 2004, vol. 3, Issue 10, pp. 503-507.|-Naqvi, Syed, “Hydrogen Production”, PEP Report 32C, SRI Consulting (2007).|-Ni, et al., “An Overview of Hydrogen Production from Biomass”, Fuel Processing Technology 87 (2006) 461-472.|-Oni et al., “Comparative Assessment of Blue Hydrogen from Steam Methane Reforming, Autothermal Reforming, and Natural Gas Decomposition Technologies for natural gas-producing regions”, Energy Conversion and Management 254 (2022) 115245.|-Parkinson et al., “Hydrogen Production using Methane: Techno-Economics of Decarbonizing Fuels and Chemicals”, International Journal of Hydrogen Energy, 43 (2018) 2540.|-Prospects for Hydrogen from Biomass, IEA Hydrogen Implementing Agreement, Annex 16, Subtask B, Final Report, Jun. 2006, pp. 1-69.|-Rapier, Robert “Estimating the Carbon Footprint of Hydrogen Production”, Forbes, Jun. 6, 2020.|-Rau et al., “Production of Hydrogen by Autothermal Reforming of Biogas”, Energy Procedia 120 (2017) 294-301.|-Regalbuto, “An NSF Perspective on Next Generation Hydrocarbon Biorefineries”, Computers and Chemical Engineering, 2010, vol. 34, pp. 1393-1396.|-Robinson et al., Practical Advances in Petroleum Processing, vol. 1, Ed. by Chang S. Hsu and Paul R. Robinson, Springer, New York, Chapter 7, “Hydrotreating and Hydrocracking: Fundamentals”, 2006, pp. 177-218.|-Rosa et al., “Potential for hydrogen production from sustainable biomass with carbon capture and storage”, Renewable and Sustainable Energy Reviews, Apr. 2022, vol. 157, 112123.|-Salary, et al., “Design of Oil Refineries Hydrogen Network Using Process Integration Principles”, Iran. J. Chem. Chem. Eng., 2008, vol. 27, No. 4, pp. 49-64.|-Sanchez et al., “Biomass Based Sustainable Ammonia Production”, 2019 AIChE Annual Meeting. 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Eng. Chem. Res. 59 (2020) 10093-10109.|-Sun, et al., “Selection of Appropriate Biogas Upgrading Technology—a Review of Biogas Cleaning, Upgrading and Utilisation”, Renewable and Sustainable Energy Reviews 51 (2015) 521-532.|-Sun, et al., “Updates of Hydrogen Production from SMR Process in GREET”. 2019.|-Taylor, R., et al., “Options for a UK low carbon hydrogen standard: Final Report”, Department for Business, Energy & Industrial Strategy, E4tech, May 2021 (this document uploaded in two parts).|-U.S. Climate Change Technology Program—Technology Options for the Near and Long Term, Methane Emissions from Energy and Waste, “Conversion of Landfill Gas to Alternative Uses”, section 4.1.2, Nov. 2003, pp. 153-155.|-Union Calendar No. 94, 117th Congress 1st Session, H.R. 5376 (Report No. 117-130) (2021).|-Van Der Drift, “SNG: A New Biomass-Based Energy Carrier,” Energy Research Centre of the Netherlands, Apr. 23, 2006, pp. 1-21.|-Van Der Meijden et al. “Production of bio-methane from woody biomass”, Energy Research Centre of the Netherlands, ECN-M-09-086, Jun. 2009, pp. 1-8.|-Wang et al., “The Life-Cycle Analysis of Petroleum Fuels and Biofuels with GREET”, Argonne National Laboratory, Dec. 2016 (Access date: Jun. 2, 2020), in 32 pages. 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Technol., 2020, 54, 12810-12819.|-Zhou et al., “Life-cycle Greenhouse Gas Emissions of Biomethane and Hydrogen Pathways in the European Union”, https://theicct.org/publication/life-cycle-greenhouse-gas-emissions-of-biomethane-and-hydrogen-pathways-in-the-european-union/ Access Date: Nov. 7, 2022.|-International Search Report and Written Opinion dated Jun. 29, 2022 for PCT Application No. PCT/CA2022/050612, filed Apr. 21, 2022.|||(WO2022/221954)|International Search Report [Examiner]|-See also references of EP 4326671A4|| | GRANTED | (EP4326671)|PENDING|(US12359134)|GRANTED|(US11946001)|GRANTED|(US20250304862)|PENDING|(WO2022/221954)|LAPSED|(CA3214954)|PENDING | ALIVE | (EP4326671)|ALIVE|(US12359134)|ALIVE|(US11946001)|ALIVE|(US20250304862)|ALIVE|(WO2022/221954)|DEAD|(CA3214954)|ALIVE | (EP4326671)|LEGAL DETAILS FOR EP4326671|Actual or expected expiration date=2042-04-21|Legal state=ALIVE|Status=PENDING|Event publication date=2022-04-21|Event code=EP/APP|Event indicator=Pos|Event 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publication date=2026-04-09|Event code=CA/U11|Event indicator=Pos|Event group=Payment or non-payment notifications|FULL RENEWAL OR MAINTENANCE FEE PAID|ST27 STATUS EVENT CODE: A-1-1-U10-U11-U102 (AS PROVIDED BY THE NATIONAL OFFICE)|Event text: MAINTENANCE FEE PAYMENT PAID IN FULL|Effective date of the event=2026-04-09|Event publication date=2026-04-09|Event code=CA/W00|Event group=Administrative notifications|OTHER EVENT OCCURRED|ST27 STATUS EVENT CODE: A-1-1-W10-W00-W111 (AS PROVIDED BY THE NATIONAL OFFICE)|Event text: CORRESPONDENT DETERMINED COMPLIANT|Effective date of the event=2026-04-09 | (EP4326671)|Contracting States: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, LI, RO, NL, TR|(WO2022/221954)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2022/221954)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2022/221954)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2022/221954)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2022/221954)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, JM, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, ME, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4326671)|EP|(US12359134)|US|(US11946001)|US|(US20250304862)|US|(WO2022/221954)|CA; EP; US|(CA3214954)|CA | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=8TP/cX+h8x769YjT6gtrznmXtI+wKb3KNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000022872447&ekey=2336&xpn=EP4326671&kind=A4 | https://register.epo.org/application?number=EP22790640 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=brrKCj19DQsuw56Xk6cpNXfDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2022/221954)|CA | (WO2022/221954)|NAME=IOGEN CORPORATION 310 Hunt Club Road, Suite 101 Ottawa, Ontario K1V 1C1 , COUNTRY=CA | (EP4326671)|GB|||(WO2022/221954)|CA|(CA3214954)|CA | (EP4326671)|NAME=Keltie LLP No. 1 London Bridge , CITY=London SE1 9BA , COUNTRY=GB , REG=101927740|(US12359134)|NAME=Knobbe Martens Olson & Bear LLP|(US11946001)|NAME=Knobbe Martens Olson & Bear LLP|(WO2022/221954)|NAME=LAMSON 1256 Tompkins Street Ottawa, Ontario K2C 3B7 , POSTCODE=K2C 3B7 , COUNTRY=CA|(CA3214954)|NAME=LAMSON, WENDY , COUNTRY=CA | |(EP4326671)|CA|(US12359134)|CA|(US20230295523)|CA|(US11946001)|CA|(US20230374394)|CA|(US20250304862)|CA|(WO2022/221954)|CA|(CA3214954)|CA | (EP4326671)|NAME=FOODY, Patrick J.|(EP4326671)|NAME=FOODY, Patrick J., CITY=Ottawa, Ontario K1V 1C1, COUNTRY=CA|(US12359134)|NAME=Foody Patrick J., CITY=Ottawa, COUNTRY=CA|(US20230295523)|NAME=FOODY Patrick J., CITY=Ottawa, COUNTRY=CA|(US11946001)|NAME=Foody Patrick J., CITY=Ottawa, COUNTRY=CA|(US20230374394)|NAME=FOODY Patrick J., CITY=Ottawa, COUNTRY=CA|(US20250304862)|NAME=FOODY Patrick J., CITY=Ottawa, COUNTRY=CA|(WO2022/221954)|NAME=FOODY, Patrick J. 310 Hunt Club Road, Suite 101 Ottawa, Ontario K1V 1C1, POSTCODE=K1V 1C1, COUNTRY=CA|(CA3214954)|NAME=FOODY, PATRICK J. C/O IOGEN CORPORATION 310 Hunt Club Road, Suite 101, CITY=OTTAWA, POSTCODE=K1V 1C1, STATE=O1 , COUNTRY=CA | (WO2022/221954)|3|(US20250304862)|3|(US12359134)|3|(US11946001)|3|(CA3214954)|3 | 5 | 6 | (EP4326671)|WO2022/221954|(US12359134)|WO2022/221954|(US11946001)|WO2022/221954|(US20250304862)|WO2022/221954|(CA3214954)|WO2022/221954 | (US12359134)|Number of Claims: NCL=23|Number of Drawings: NDR=3|Number of Figures: NFG=3|Independent Claim Number: ICL=1,22,23|Number of Independent Claims: NICL=3|Exemplary Claim Number: ECL=1|Extended under 35 USC 154(b) the following days: EXTD=234|Primary examiner: McCaig Brian A|Art Unit.: ART =1772||(US20230295523)|Number of Claims: NCL=20|Number of Drawings: NDR=3|Number of Figures: NFG=3|Independent Claim Number: ICL=29|Number of Independent Claims: NICL=1|Exemplary Claim Number: ECL=29|Primary examiner: McCaig Brian A|Art Unit.: ART =1772||(US11946001)|Number of Claims: NCL=20|Number of Drawings: NDR=3|Number of Figures: NFG=3|Independent Claim Number: ICL=1|Number of Independent Claims: NICL=1|Exemplary Claim Number: ECL=1|Primary examiner: McCaig Brian A|Art Unit.: ART =1772||(US20230374394)|Number of Claims: NCL=20|Number of Drawings: NDR=3|Number of Figures: NFG=3|Independent Claim Number: ICL=29|Number of Independent Claims: NICL=1|Exemplary Claim Number: ECL=29|Primary examiner: McCaig Brian A|Art Unit.: ART =1772||(US20250304862)|Number of Claims: NCL=18|Number of Drawings: NDR=3|Number of Figures: NFG=3|Independent Claim Number: ICL=22,23|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=22||(WO2022/221954)|Number of Claims: NCL=28|Extended kind: EXTK=x||(CA3214954)|Number of Claims: NCL=28| | (US12359134)|Continuation of: WOCA2022/050612 FDD=2022-04-21 [2022WO-CA50612] PENDING|Provisional Appl: US63/201,301 FDD=2021-04-22 [2021US-63201301]|Previous publication: US20230295523 A1 2023-09-21 [US20230295523]|(US11946001)|Continuation of: WOCA2022/050612 FDD=2022-04-21 [2022WO-CA50612] PENDING|Provisional Appl: US63/201,301 FDD=2021-04-22 [2021US-63201301]|Previous publication: US20230374394 A1 2023-11-23 [US20230374394]|(US20250304862)|Continuation of: US18/325,532 FDD=2023-05-30 [2023US-18325532]|Continuation of: US12359134 |Continuation of: WOCA2022/050612 FDD=2022-04-21 [2022WO-CA50612] PENDING|Provisional Appl: US63/201,301 FDD=2021-04-22 [2021US-63201301] | (EP4326671)|ENGLISH (ENG) | (US20250304862)|Patent|(US12359134)|Patent|(EP4326671)|Patent|(US11946001)|Patent|(EP4326671)|Patent|(US20230374394)|Patent|(US20230295523)|Patent|(CA3214954)|Patent|(WO2022221954)|Patent | Titre: (EP4326671)|Process and system for producing fuel Résumé: (EP4326671)|A process and/or system for producing fuel using renewable hydrogen having a reduced carbon intensity. The renewable hydrogen is produced in a hydrogen production process comprising methane reforming, wherein at least a portion of the feedstock for the hydrogen production process comprises upgraded biogas sourced from a plurality of biogas plants. Each of the upgraded biogases is produced in a process that includes collecting biogas comprising methane and carbon dioxide, capturing at least 50% of the carbon dioxide originally present in the collected biogas and producing the upgraded biogas. Storage of the captured carbon dioxide reducing a carbon intensity of the fuel, without having to provide carbon capture and storage of carbon dioxide from hydrogen production. Autre: (US12359134)|The invention claimed is:|1. A method of producing product, the method comprising:| sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising:| a) collecting biogas comprising methane and carbon dioxide,| b) capturing carbon dioxide from the collected biogas and producing upgraded biogas, and| c) providing the captured carbon dioxide for storage;| providing the at least two upgraded biogases and fossil-based gas for methane reforming, the methane reforming producing syngas; and,| producing the product from a production process that uses at least part of the syngas produced from the methane reforming,| wherein the captured carbon dioxide provided in step (c) of each of the processes is stored and reduces lifecycle greenhouse gas (GHG) emissions associated with the product.|2. The method according to claim 1, wherein the product comprises fuel, wherein the syngas is purified to produce a stream enriched in hydrogen, and wherein the stream enriched in hydrogen is provided for hydrogenating crude oil derived liquid.|3. The method according to claim 1, wherein the product comprises fuel, wherein the syngas is purified to produce a stream enriched in hydrogen, wherein the stream enriched in hydrogen is provided for hydrogenating renewable feedstock, the renewable feedstock comprising renewable oil, renewable fat, or a combination thereof.|4. The method according to claim 1, wherein the product comprises fuel.|5. The method according to claim 4, wherein the fuel comprises gasoline, diesel, jet fuel, or any combination thereof.|6. The method according to claim 1, wherein the product comprises methanol.|7. The method according to claim 1, wherein the product comprises ammonia, fertilizer, or a combination thereof.|8. The method according to claim 1, wherein carbon dioxide captured from one of the processes is provided for storage at a separate location than carbon dioxide captured from another of the processes.|9. The method according to claim 1, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for geological sequestration.|10. The method according to claim 1, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for enhanced oil recovery.|11. The method according to claim 1, wherein step (c) of at least one of the processes comprises providing the captured carbon dioxide for sequestration in concrete.|12. The method according to claim 1, wherein step (c) of at least one of the processes comprises compressing the captured carbon dioxide and injecting the captured carbon dioxide into a carbon dioxide distribution system configured to transport the captured carbon dioxide to storage.|13. The method according to claim 1, wherein step (b) of at least one of the processes comprises capturing the carbon dioxide using carbon dioxide capture selected from cryogenic separation, membrane separation, and absorption with amine solvent.|14. The method according to claim 1, wherein step (b) of at least one of the processes comprises capturing at least 70% of the carbon dioxide originally present in the biogas.|15. The method according to claim 1, wherein the fossil-based gas comprises fossil-based natural gas.|16. The method according to claim 1, wherein the method does not include storing carbon dioxide produced from the methane reforming.|17. The method according to claim 1, wherein at least one of the at least two upgraded biogases is derived from organic waste.|18. The method according to claim 1, wherein at least one of the at least two upgraded biogases is derived from manure, the manure selected from swine manure and dairy manure.|19. The method according to claim 1, wherein at least one of the at least two upgraded biogases is derived from landfill gas.|20. The method according to claim 1, wherein the process in which at least one of the upgraded biogases is produced further comprises injecting the upgraded biogas into a natural gas distribution system, wherein providing the at least two upgraded biogas comprises withdrawing gas from the natural gas distribution system, the withdrawn gas is associated with environmental attributes of the injected upgraded biogas.|21. The method according to claim 1, wherein the methane reforming comprises steam methane reforming, and wherein at least part of the at least two upgraded biogases and fossil-based gas provided for methane reforming is feedstock for the methane reforming and another part of the at least two upgraded biogases and fossil-based gas is fed to a combustion zone for the steam methane reforming to produce heat for the steam methane reforming.|22. A method of producing product, the process comprising:| (i) sourcing at least two upgraded biogases, each of the at least two upgraded biogases produced in a process comprising:| a) collecting biogas comprising methane and carbon dioxide, and,| b) capturing carbon dioxide from the collected biogas and producing upgraded biogas,| wherein the at least two upgraded biogases and fossil-based gas are used in methane reforming, the methane reforming producing syngas, at least part of the syngas used to produce the product; and| ii) storing the captured carbon dioxide produced from each process, thereby preventing the captured carbon dioxide, or an equal quantity of carbon dioxide displaced by the captured carbon dioxide, from being released to the atmosphere, and reducing lifecycle greenhouse gas (GHG) emissions associated with the product.|23. A method of producing product, the method comprising:| providing a plurality of upgraded biogases, each upgraded biogas in the plurality produced in a respective process comprising:| a) collecting biogas comprising methane and carbon dioxide,| b) removing at least a portion of the carbon dioxide from the biogas and producing upgraded biogas;| feeding at least a portion of each upgraded biogas and fossil-based gas to methane reforming, the methane reforming producing syngas, at least part of the syngas used for producing the product; and| wherein at least some of the carbon dioxide removed in step (b) of each of the processes is provided for at least one carbon capture and storage process to reduce lifecycle greenhouse gas (GHG) emissions associated with the product. | 21 | Abstract | gpt-4o-mini | no | The article focuses on hydrogen production from biogas and mentions carbon capture but does not describe a system that integrates biomass energy production with carbon capture and storage as required for BECCS. | ||||||||||||||
| 24 | US63/062,034|US63/062,034P|US17/393,544|WOUS2021/071099 | US17/393,544|WOUS2021/071099|JP2023507608|CN202180068170|EP21759000|SG11202300715P|AU2021320985|KR10-2023-7004306|CA3187852 | US11872537|JP2023537482|CN116367909|EP4192602|SG11202300715P|AU2021320985|KR10-2023-0037038|AU2021320985|CA3187852|US20220040668|WO2022/032281 | 98625271 | US11872537 B2 2024-01-16 [US11872537]|US20220040668 A1 2022-02-10 [US20220040668]|WO2022/032281 A1 2022-02-10 [WO202232281]|JP2023537482 A 2023-09-01 [JP2023537482]|CN116367909 A 2023-06-30 [CN116367909]|EP4192602 A1 2023-06-14 [EP4192602]|SG11202300715P A 2023-03-31 [SG11202300715P]|AU2021320985 A8 2023-03-23 [AU2021320985]|AU2021320985 A1 2023-03-09 [AU2021320985]|KR10-2023-0037038 A 2023-03-15 [KR20230037038]|CA3187852 A1 2022-02-10 [CA3187852] | 2020-08-06|2021-08-04 | 2021-08-04|2021-08-04|2021-08-04|2021-08-04|2021-08-04|2021-08-04|2021-08-04|2021-08-04|2021-08-04 | 2024-01-16|2023-09-01|2023-06-30|2023-06-14|2023-03-31|2023-03-23|2023-03-15|2023-03-09|2022-02-10|2022-02-10|2022-02-10 | |(US11872537)|2024-01-16||||||| | (EP4192602)|2041-08-04|(US11872537)|2041-10-27|(WO2022/032281)|2024-02-06|(JP2023537482)|2025-07-30|(CN116367909)|2041-08-04|(SG11202300715P)|2041-08-04|(AU2021320985)|2024-11-21|(KR10-2023-0037038)|2041-08-04|(CA3187852)|2026-01-08 | (EP4192602)|Metal-organic frameworks for carbon dioxide capture | (EP4192602)|The present application relates to absorbents comprising tetraainine ligands grafted onto metal-organic frameworks and a method for using same for CO2 capture from fossil fuel combustion sources to reduce emissions. In particular, this application relates to capturing > 90% by volume, preferable > 99% by volume, CO2 emissions such that the emissions are negative, essentially removing CO2 from the combustion air. | EXXONMOBIL RESEARCH & ENGINEERING|EXXONMOBIL TECHNOLOGY & ENGINEERING | (EP4192602)|ExxonMobil Technology and Engineering Company ([US])|(US11872537)|EXXONMOBIL TECHNOLOGY AND ENGINEERING COMPANY ([US])|(US20220040668)|ExxonMobil Research and Engineering Company ([US])|(WO2022/032281)|EXXONMOBIL RESEARCH AND ENGINEERING COMPANY ([US])|(JP2023537482)|EXXONMOBIL TECHNOLOGY & ENGINEERING COMPANY|(CN116367909)|EXXONMOBIL TECHNOLOGY & ENGINEERING COMPANY ([US])|(SG11202300715P)|EXXONMOBIL TECHNOLOGY AND ENGINEERING COMPANY ([US])|(AU2021320985)|ExxonMobil Technology and Engineering Company|(AU2021320985)|ExxonMobil Research and Engineering Company|(KR10-2023-0037038)|EXXONMOBIL TECHNOLOGY AND ENGINEERING COMPANY ([US])|(CA3187852)|EXXONMOBIL TECHNOLOGY AND ENGINEERING COMPANY ([US]) | WESTON SIMON C | (EP4192602)|WESTON, Simon, C. | (EP4192602)|ExxonMobil Chemical Europe Inc.;IP Law Europe ([BE])|Reg. Nb: 101482725|(US11872537)|SHOOK, HARDY & BACON L.L.P.|(WO2022/032281)|NEGRON, Liza et al. ([US])|(JP2023537482)|YAMAO, Norihito et al.|Reg. Nb: 100145403|Shikimi Masayuki|Reg. Nb: 100221501|(CN116367909)|ZHANG RONGJUN;ZHONGZI LAW OFFICE|Reg. Nb: 11247|LIN BONAN;ZHONGZI LAW OFFICE|Reg. Nb: 11247|(SG11202300715P)|Amica Law LLC|Reg. Nb: 200601697N|(AU2021320985)|ALLENS PATENT & TRADE MARK ATTORNEYS ([AU])|(KR10-2023-0037038)|FIRSTLAW P.C.|(CA3187852)|BORDEN LADNER GERVAIS LLP ([CA]) | (US11872537)|Accordingly, what is needed in the art are polyamine metal-organic frameworks, in which the polyamines are grafted to the metal-organic framework by multiple M-N bonds per ligand, that exhibit step-shaped CO2 adsorption profiles, and enable effective capture of CO2 at low partial pressures (e.g., an approximately 40° C. step occurring at or below 15 mbar for CO2 capture from coal flue gas, or at or below 4 mbar at approximately 40° C. for CO2 capture from natural gas flue gas, or at or below 0.4 mbar (400 ppm) at ambient temperature commonly taken as 25° C. for carbon capture from air), at greater than 90% by volume capture of CO2, preferably greater than 99%, and are sufficiently stable to be used in steam based regeneration processes on an industrial scale.|As such, there is a need for adsorbents which are specific to CO2 and maximize CO2 capture.|Alkyl groups that are limited to hydrocarbon groups are termed "homoalkyl".|However, one often overlooked drawback of many of these adsorbents is the significant co-adsorption of H2O upon CO2 adsorption, contributing to parasitic energy costs upon regeneration as water is desorbed from the bed with CO2.|However, these sorbents suffer from a number of drawbacks, including low working capacities (˜2 wt %), corrosiveness, and thermal degradation upon regeneration of the amine solution.| | (US11872537)|1. A method for reducing carbon dioxide emissions, the method comprising: (a) contacting a flue gas from a source with a carbon dioxide adsorbing material to reversibly adsorb CO2 from the flue gas thereby generating an adsorption material enriched for CO2; (b) reducing the concentration of CO2 from the flue gas to less than 15,000 ppmv; and, (c) stripping a portion of the CO2 from the adsorption material enriched for CO2 using a regeneration process, wherein the carbon dioxide adsorbing material comprises a tetraamine functionalized metal organic framework.|14. A method for CO2 direct air capture, the method comprising: contacting air with a carbon dioxide adsorption material to reversibly adsorb CO2 from the air thereby generating an adsorption material enriched for CO2 and reducing CO2 concentrations to less than 400 ppmv, wherein the carbon dioxide adsorbing material comprises a tetraamine functionalized metal organic framework.| | (US11872537)|Another aspect of the present disclosure provides a method of synthesizing an adsorption material in which a plurality of polyamine ligands is grafted onto a metal-organic framework.|One aspect of the present disclosure provides an adsorption material comprising a metal-organic framework.|The present application relates to absorbents comprising tetraamine ligands grafted onto metal-organic frameworks and a method for using same for CO2 capture from fossil fuel combustion sources to reduce emissions. In particular, this application relates to capturing >90% by volume, preferable >99% by volume, CO2 emissions such that the emissions are negative, essentially removing CO2 from the combustion air.| | (EP4192602)|CARBON DIOXIDE(100,1)|CARBON DIOXIDE CAPTURE(100,1)|METALORGANIC FRAMEWORK(100,1)||(US11872537)|DIVALENT CATION(100,2)|CO2 ADSORPTION PROFILE(43,3)|TETRAAMINE ANALOGUE(33,1)|UNSUBSTITUTED HETEROALKYL(29,1)|CO2 ISOBAR(24,1)|UNSUBSTITUTED ALKYL(20,1)|UNSUBSTITUTED ARYL(20,1)|AMMONIUM CARBAMATE CHAIN(16,1)|HETEROALKYLENE GROUP(16,1)|HETEROARYL RING(16,1)|INERT STREAM(16,1)|SEQUESTERING CARBON DIOXIDE(16,1)|TETRAAMINE SOLUTION(16,1)|TOLUENE WASH(16,1)|ADSORBENT(12,1)|ARYLALKYL GROUP(12,1)|CYCLOHEXANE(12,1)|DICHLOROMETHANE(12,1)|HETEROARENE(12,1)|HETEROATOM(12,1)|INVESTIGATION(12,1)|POLYAMINE APPENDED FRAMEWORK(12,1)|SIMULATED AIR(12,1)||(US20220040668)|METALORGANIC FRAMEWORK(100,32)|CARBON DIOXIDE(100,18)|DIRECT AIR CAPTURE(100,4)|CARBON DIOXIDE CAPTURE(100,1)|CARBON DIOXIDE EMISSION(100,1)|CO2 DIRECT AIR CAPTURE(100,1)|REVERSIBLY ADSORB CO2(85,9)|H2O COADSORPTION(75,1)|POLYTOPIC ORGANIC LINKER(67,15)|TETRAAMINE(62,9)|TETRAAMINE LIGAND(59,2)|POLYAMINE LIGAND(58,36)|ADSORPTION(47,59)|REGENERATION(46,4)|CO2(42,75)|CO2 CAPTURE(42,10)|METAL ORGANIC FRAMEWORK FUNCTIONALIZATION(37,7)|PPMV(36,16)|ADSORBENT MATERIAL(35,3)|CO2 EMISSION(33,5)|CO2 ADSORPTION(31,5)|REDUCING CO2(30,2)|CORROSIVENESS(30,1)|SORBENT(30,1)|FOSSIL FUEL COMBUSTION SOURCE(28,2)|CARBON DIOXIDE ADSORBING MATERIAL(27,3)|HOMOALKYL(27,1)|CARBON DIOXIDE ADSORPTION(26,2)|HYDROCARBON GROUP(24,1)|METALORGANIC FRAMEWORK DIVALENT CATION(23,5)|FLUE GAS(22,31)|DICARBOXYLATE(22,6)|REGENERATION(22,1)|UNSUBSTITUTED HETEROALKYL(21,7)|ABSORBENT(21,4)|WORKING CAPACITY(21,3)|COMBUSTION SOURCE(21,2)|DOTPDC(20,4)|BED(20,1)|ARYL SUBSTITUTION(19,12)|DOBDC(19,3)|TETRAAMINE FUNCTIONALIZED ADSORPTION(19,2)|UNSUBSTITUTED HETEROARYLOXY(18,4)|PARASITIC ENERGY COST(18,1)|UNSUBSTITUTED ALKYL(17,9)|ADSORBENT(17,7)|METAL ORGANIC FRAMEWORK(17,7)|AMINE SOLUTION(17,4)|TETRAAAMINE MOF VARIANT(17,2)|ADSORPTION MATERIAL(16,28)|FOSSIL FUEL(15,6)|NONCOORDINATING SOLVENT(15,5)|UNACTIVATED ADSORBENT(15,3)|ALKYL SUBSTITUTION(14,10)|UNACTIVATED ADSORPTION MATERIAL(13,16)|CO2 ADSORPTION PROFILE(13,4)|CO2 ISOBAR(13,4)|UNSUBSTITUTED ALKOXY(13,4)|UNSUBSTITUTED ARYLOXY(13,4)|INERT STREAM(12,7)|COMBUSTION AIR(12,2)|METALORGANIC FRAMEWORK MG(12,2)|ATOMIC ISOTOPE UNNATURAL PROPORTION(12,1)|VACUUM SWING ADSORPTION(11,14)|ALKOXY SUBSTITUTION(11,4)|EVACUATE REFILL CYCLE(11,4)|ABATING CO2(11,3)|CO2 DESORPTION PROFILE(11,2)|CO2 ABSORBENT REGENERATION(11,1)|GRAFTING POLYAMINE LIGAND(11,1)|TETRAAMINE FUNCTIONALIZED MG(11,1)|TETRAAMINE FUNCTIONALIZED MATERIAL(9,5)|ANHYDROUS ORGANIC SOLVENT(9,4)|HALOGEN SUBSTITUTED METHYL(9,4)|ADDRESS CO2 CONTRIBUTION(9,2)|AIRPLANE EMISSION(9,2)|CRUDE BIOGAS(9,2)|DEPROTONATED CARBOXYLIC MOIETY(9,2)|DIAMINO BUTANE(9,2)|HALOGENATED PARAFFIN(9,2)|WET IMPREGNATION(9,2)|CO2 SIMULTANEOUS SOLIDIFICATION(9,1)|COOPERATIVE CO2 ADSORPTION(9,1)|DECREASING AMINE VOLATILIZATION(9,1)|GROWING WORLDWIDE CONSUMPTION(9,1)|METHANOL MOTHER LIQUOR(9,1)|POLYAMINE LIGAND PERCENT(9,1)|TETRAAMINE ANALOG(9,1)|ACIDIC FUNCTIONALITY(8,2)|DIAMINE APPENDED MOFS(8,2)|DIVALENT RADICAL(8,2)|ANIONIC COUNTERION(8,1)|CAPTURING CO2 EMISSION(8,1)|CATIONIC COUNTERION(8,1)|FUEL COMBUSTION HIGHLIGHT(8,1)|GLOBAL CO2 EMISSION(8,1)|HETEROARENE NUCLEUS(8,1)|SCINTILLATION VIAL(8,1)|SOLID ADSORBENT EXPLORATION(8,1)|COAL FLUE GAS(7,5)|HETEROARYL GROUP(7,4)|DIOXIDOBIPHENYL(7,3)|HETEROARYL RING(7,3)|MULTICOMPONENT GAS MIXTURE(6,9)|R12(6,9)|METAL SITE(6,7)|GERMANIUM(6,4)|HUMIDITY CONDITION(6,4)|SELENIUM(6,4)|ALKYLPROPYLENETETRAAMINE(6,2)|CYCLICAL HYDROCARBON RADICAL(6,2)|HUMID GAS STREAM(6,2)|NEGATIVE EMISSION(6,2)|SEQUESTERING CARBON DIOXIDE(6,2)|TRIETHYLENETETRAAMINE(6,2)|ARYL HETEROARYL(6,1)|CYCLO HEPTYL(6,1)|GENERAL CONSUMPTION(6,1)|HETEROALKYL RADICAL(6,1)|HETEROARYL NUCLEUS(6,1)|INTERNATIONAL GOVERNMENT PANEL(6,1)|METHANOL SOLVATED MG(6,1)|MULTIVALENT RADICAL(6,1)|PIPELINE QUALITY METHANE(6,1)|TETRAHYDRO PYRIDYL(6,1)|WORLD POPULATION(6,1)|PRESSURE SWING ADSORPTION(5,11)|AQUEOUS AMINE SOLUTION(5,3)|ARYL ADJACENT ATOM(5,3)|CYCLOHEXYL(5,3)|DOBPDC(5,3)|INERT ENVIRONMENT(5,3)|REMOVING CO2(5,3)|RESIDUAL GAS(5,3)|HOMOLOG(5,2)|ADSORBENT FINE TUNING(5,1)|CARBONYL RESIDUE(5,1)|CITED PUBLICATION(5,1)|CYCLOPROPYL METHYL(5,1)|LINOEYL CHAIN(5,1)|LOWERING CO2(5,1)|MAJOR CONTRIBUTOR(5,1)|MINIMAL REGENERATION ENERGY(5,1)|NITROGEN HETEROATOM(5,1)|PORE ARCHITECTURE(5,1)|POROUS SOLID ADSORBENT(5,1)|PPMV CO2(5,1)|SALT HYDRATE(5,1)|SOLVENT COORDINATION(5,1)|SYNTHESIS REPORT(5,1)|UNSUBSTITUTED HETEROCYCLOALKYL GROUP(5,1)|ADSORPTION MATERIAL EXHIBIT(4,4)|HYDROXYL(4,4)|BRANCHED CHAIN(4,2)|CHLOROBENZENE(4,2)|CYCLOHEXANE(4,2)|DICHLOROMETHANE(4,2)|EXCESS CO2(4,2)|PENTADIENYL(4,2)|SIMULATED SYSTEM AIR(4,2)|TETRAHYDROFURAN(4,2)|TRICHLOROETHYLENE(4,2)|ACTIVATED ABSORBENT(4,1)|AMMONIUM CARBAMATE CHAIN(4,1)|ANTECEDENT(4,1)|BASIC FUNCTIONALITY(4,1)|CHIRAL CENTER(4,1)|CYCLICAL VERSION(4,1)|EXCLUSION LIMIT(4,1)|GEOMETRICAL ISOMER GENERATION(4,1)|HETEROALKYL GROUP(4,1)|HETEROALKYLENE GROUP(4,1)|HETEROARENE GROUP(4,1)|HETEROCYCLOALKENYL(4,1)|IDENTICAL SUBSTITUENT(4,1)|INERT SOLVENT(4,1)|IODINE ATOM(4,1)|KEY STRATEGY(4,1)|METHYL PHENOXY(4,1)|NONAROMATIC RING(4,1)|NONRENEWABLE GAS(4,1)|OLEOYL CHAIN(4,1)|PYRIDYL METHYL(4,1)|REDUCING CO2 EMISSION(4,1)|SATURATED HYDROCARBON RADICAL(4,1)|SIX MEMBERED AZINE(4,1)|STRAIGHT CHAIN(4,1)|TARGETED CO2 CONCENTRATION REDUCTION(4,1)|TETRAAAMINE FUNCTIONALIZED MATERIAL(4,1)|TETRAAMINE SOLUTION(4,1)|TOLUENE WASH(4,1)|UNSUBSTITUTED BRANCH CHAIN ALKYL(4,1)|DOUBLE BOND(3,4)|HYDROCARBON RESERVOIR(3,3)|OXYGEN ATOM(3,3)|SULFUR ATOM(3,3)|ABSOLUTE STEREOCHEMISTRY(3,1)|ADSORPTION DESORPTION(3,1)|AGRICULTURE(3,1)|ALKANE(3,1)|ALKYLTHIO(3,1)|AMINE APPENDED SILICA(3,1)|ANTEDATE(3,1)|APPROXIMATING UNRECITED NUMBER(3,1)|ARYLALKYL GROUP(3,1)|ARYLTHIOXY(3,1)|ASSESSMENT(3,1)|AVAILABLE RESERVE(3,1)|BIOENERGY(3,1)|BUTADIENYL(3,1)|CAPTURE TEMPERATURE(3,1)|CH2OCH(3,1)|CHOLESTEROL(3,1)|CHROMENE(3,1)|CO2 BINDING SITE(3,1)|CO2 POST COMBUSTION CAPTURE(3,1)|CO2 REMOVAL(3,1)|CROTYL(3,1)|CRYOGENICS(3,1)|CYCLOPENTYL(3,1)|DEPLETION(3,1)|DIAZINYL(3,1)|DIHYDROGEN(3,1)|ETHYNYL(3,1)||(WO2022/032281)|METALORGANIC FRAMEWORK(100,30)|CARBON DIOXIDE(100,19)|DIRECT AIR CAPTURE(100,4)|CARBON DIOXIDE CAPTURE(100,1)|CARBON DIOXIDE EMISSION(100,1)|CO2 DIRECT AIR CAPTURE(100,1)|REVERSIBLY ADSORB CO2(94,9)|TETRAAININE LIGAND(86,1)|H2O COADSORPTION(84,1)|CO2 CAPTURE(81,13)|POLYTOPIC ORGANIC LINKER(74,15)|TETRAAMINE(72,8)|CO2(56,72)|WORLD POPULATION(56,1)|CO2 EMISSION(54,5)|ADSORPTION(52,59)|REGENERATION(52,4)|IDENTIFIED SHORTCOMING(47,1)|MAJOR CONTRIBUTOR(45,1)|PPMV(41,16)|METAL ORGANIC FRAMEWORK FUNCTIONALIZATION(41,7)|CO2 ADSORPTION PROFILE(41,5)|ADSORBENT MATERIAL(39,3)|CAPTURING CO2(39,2)|CO2 ADSORPTION(34,5)|REDUCING CO2(34,2)|CORROSIVENESS(34,1)|SORBENT(34,1)|REGENERATION(33,2)|FOSSIL FUEL COMBUSTION SOURCE(31,2)|AMINE SOLUTION(30,4)|CARBON DIOXIDE ADSORBING MATERIAL(30,3)|AGRICULTURE(30,1)|HOMOALKYL(30,1)|FLUE GAS(29,32)|CARBON DIOXIDE ADSORPTION(29,2)|STEAM REGENERATION(29,1)|ARABLE LAND(28,1)|FOSSIL FUEL(26,6)|METALORGANIC FRAMEWORK DIVALENT CATION(26,5)|HYDROCARBON GROUP(26,1)|UNSUBSTITUTED HETEROALKYL(24,7)|ABSORBENT(24,4)|CCS(24,3)|WORKING CAPACITY(24,3)|COMBUSTION SOURCE(24,2)|TETRAAMINE FUNCTIONALIZED MATERIAL(23,5)|DOBPDC(22,5)|DOTPDC(22,4)|HUMIDITY CONDITION(22,4)|AQUEOUS AMINE SOLUTION(22,3)|DOBDC(22,3)|AMBIENT TEMPERATURE(22,1)|BED(22,1)|ARYL SUBSTITUTION(21,12)|UNSUBSTITUTED ARYL(21,11)|TETRAAMINE FUNCTIONALIZED ADSORPTION(21,2)|COAL FLUE GAS(20,6)|UNSUBSTITUTED HETEROARYLOXY(20,4)|PARASITIC ENERGY COST(20,1)|UNSUBSTITUTED ALKYL(19,9)|ADSORBENT(19,6)|BECCS(19,2)|REV(19,1)|METAL ORGANIC FRAMEWORK(18,8)|LIGAND(18,2)|UNSUBSTITUTED ARLYOXY(17,4)|UNACTIVATED ADSORBENT(17,3)|COMBUSTION AIR(17,1)|UNACTIVATED ADSORPTION MATERIAL(15,16)|ALKYL SUBSTITUTION(15,10)|NONCOORDINATING SOLVENT(15,4)|UNSUBSTITUTED ALKOXY(15,4)|ALKYLAMINE FUNCTIONALIZED METALORGANIC FRAMEWORK(15,1)|ATOMIC ISOTOPE UNNATURAL PROPORTION(14,1)|TETRAAAMINE MOF VARIANT(14,1)|THERMOELECTRIC POWER PLANT(14,1)|INERT STREAM(13,7)|ABATING CO2(13,3)|VACUUM SWING ADSORPTION(12,14)|ALKOXY SUBSTITUTION(12,4)|EVACUATE REFILL CYCLE(12,4)|CO2 DESORPTION PROFILE(12,2)|CO2 ABSORBENT REGENERATION(12,1)|GRAFTING POLYAMINE LIGAND(12,1)|TETRAAMINE FUNCTIONALIZED MG(12,1)|ARABLE LAND LARGE AREA(11,1)|TECHNOLOGY READY MATERIAL(11,1)|ANHYDROUS ORGANIC SOLVENT(10,4)|HALOGEN SUBSTITUTED METHYL(10,4)|NATURAL GAS FLUE GAS(10,3)|ADDRESS CO2 CONTRIBUTION(10,2)|AIRPLANE EMISSION(10,2)|CO2 ISOBAR(10,2)|CRUDE BIOGAS(10,2)|DEPROTONATED CARBOXYLIC MOIETY(10,2)|DIAMINO BUTANE(10,2)|GLOBAL CLIMATE CHANGE(10,2)|HALOGENATED PARAFFIN(10,2)|WET IMPREGNATION(10,2)|CO2 SIMULTANEOUS SOLIDIFICATION(10,1)|COOPERATIVE CO2 ADSORPTION(10,1)|GROWING WORLDWIDE CONSUMPTION(10,1)|METALORGANIC FRAMEWORK MG(10,1)|METHANOL MOTHER LIQUOR(10,1)|POLYAMINE LIGAND PERCENT(10,1)|TETRAAMINE ANALOG(10,1)|ACIDIC FUNCTIONALITY(9,2)|DIAMINE APPENDED MOFS(9,2)|DIVALENT RADICAL(9,2)|PROPANE DIAMINE(9,2)|CARBON CAPTURE(8,9)|HETEROARYL GROUP(8,4)|HETEROARYL RING(8,3)|ANIONIC COUNTERION(8,1)|CAPTURING CO2 EMISSION(8,1)|CATIONIC COUNTERION(8,1)|FUEL COMBUSTION HIGHLIGHT(8,1)|GLOBAL CO2 EMISSION(8,1)|HETEROARENE NUCLEUS(8,1)|PARTIAL PRESSURE(8,1)|SCINTILLATION VIAL(8,1)|SOLID ADSORBENT EXPLORATION(8,1)|TETRAAMINE LIGAND(8,1)|MULTICOMPONENT GAS MIXTURE(7,9)|NATURAL GAS(7,9)|R12(7,9)|GERMANIUM(7,4)|SELENIUM(7,4)|CYCLICAL HYDROCARBON RADICAL(7,2)|HUMID GAS STREAM(7,2)|NEGATIVE EMISSION(7,2)|SEQUESTERING CARBON DIOXIDE(7,2)|TRIETHYLENETETRAAMINE(7,2)|ARYL HETEROARYL(7,1)|CYCLO HEPTYL(7,1)|GENERAL CONSUMPTION(7,1)|HETEROALKYL RADICAL(7,1)|HETEROARYL NUCLEUS(7,1)|INTERNATIONAL GOVERNMENT PANEL(7,1)|LARGE AREA(7,1)|METHANOL SOLVATED MG(7,1)|MULTIVALENT RADICAL(7,1)|PIPELINE QUALITY METHANE(7,1)|TETRAHYDRO PYRIDYL(7,1)|PRESSURE SWING ADSORPTION(6,11)|METAL SITE(6,7)|ARYL ADJACENT ATOM(6,3)|CYCLOHEXYL(6,3)|INERT ENVIRONMENT(6,3)|REMOVING CO2(6,3)|RESIDUAL GAS(6,3)|HOMOLOG(6,2)|ADSORBENT FINE TUNING(6,1)|ADSORPTION PROFILE(6,1)|CARBONYL RESIDUE(6,1)|CITED PUBLICATION(6,1)|CYCLOPROPYL METHYL(6,1)|LINOEYL CHAIN(6,1)|LOWERING CO2(6,1)|MINIMAL REGENERATION ENERGY(6,1)|NITROGEN HETEROATOM(6,1)|PORE ARCHITECTURE(6,1)|POROUS SOLID ADSORBENT(6,1)|PPMV CO2(6,1)|SALT HYDRATE(6,1)|SOLVENT COORDINATION(6,1)|SYNTHESIS REPORT(6,1)|UNSUBSTITUTED HETEROCYCLOALKYL GROUP(6,1)|ADSORPTION MATERIAL EXHIBIT(5,4)|HYDROXYL(5,4)|2NR R(5,2)|BRANCHED CHAIN(5,2)|CHLOROBENZENE(5,2)|CONR R(5,2)|CYCLOHEXANE(5,2)|DICARBOXYLATE(5,2)|DICHLOROMETHANE(5,2)|EXCESS CO2(5,2)|NRSO2R(5,2)|PENTADIENYL(5,2)|TETRAHYDROFURAN(5,2)|TRICHLOROETHYLENE(5,2)|ACTIVATED ABSORBENT(5,1)|ALKYLPROPYLENETETRAAMINE(5,1)|AMMONIUM CARBAMATE CHAIN(5,1)|ANTECEDENT(5,1)|BASIC FUNCTIONALITY(5,1)|CHIRAL CENTER(5,1)|CYCLICAL VERSION(5,1)|DIOXIDOBIPHENYL(5,1)|EXCLUSION LIMIT(5,1)|GEOMETRICAL ISOMER GENERATION(5,1)|HETEROALKYL GROUP(5,1)|HETEROALKYLENE GROUP(5,1)|HETEROARENE GROUP(5,1)|HETEROCYCLOALKENYL(5,1)|IDENTICAL SUBSTITUENT(5,1)|INERT SOLVENT(5,1)|IODINE ATOM(5,1)|KEY STRATEGY(5,1)|METHYL PHENOXY(5,1)|NONAROMATIC RING(5,1)|NONRENEWABLE GAS(5,1)|OLEOYL CHAIN(5,1)|PYRIDYL METHYL(5,1)|REDUCING CO2 EMISSION(5,1)|SATURATED HYDROCARBON RADICAL(5,1)|SIX MEMBERED AZINE(5,1)|STRAIGHT CHAIN(5,1)|TARGETED CO2 CONCENTRATION REDUCTION(5,1)|TETRAAAMINE FUNCTIONALIZED MATERIAL(5,1)|TETRAAMINE SOLUTION(5,1)|TOLUENE WASH(5,1)|UNSUBSTITUTED BRANCH CHAIN ALKYL(5,1)|CRR(4,3)|HYDROCARBON RESERVOIR(4,3)|OXYGEN ATOM(4,3)|SULFUR ATOM(4,3)|DOUBLE BOND(3,4)|ABSOLUTE STEREOCHEMISTRY(3,1)|ADSORPTION DESORPTION(3,1)|ALKANE(3,1)|ALKYLTHIO(3,1)|AMINE APPENDED SILICA(3,1)|ANTEDATE(3,1)|APPROXIMATING UNRECITED NUMBER(3,1)|AQUEOUS AMINE(3,1)|ARYLALKYL GROUP(3,1)|ARYLTHIOXY(3,1)|ASSESSMENT(3,1)|AVAILABLE RESERVE(3,1)|BIOENERGY(3,1)|BUTADIENYL(3,1)|CAPTURE TEMPERATURE(3,1)|CH2OCH(3,1)|CHOLESTEROL(3,1)|CHROMENE(3,1)|CO2 BINDING SITE(3,1)|CO2 POST COMBUSTION CAPTURE(3,1)|CO2 REMOVAL(3,1)|COMBUSTION AIR BACKGROUND(3,1)|CROTYL(3,1)|CRYOGENICS(3,1)||(JP2023537482)|METAL ORGANIC FRAMEWORK(100,27)|CARBON DIOXIDE(100,19)|METALORGANIC FRAMEWORK(100,15)|TETRAAMINE FUNCTIONAL GROUP(100,7)|DIRECT AIR CAPTURE(100,2)|TETRAAMINE LIGAND(100,2)|CARBON DIOXIDE CAPTURE(100,1)|CARBON DIOXIDE EMISSION(100,1)|DIRECT AIR CAPTURE CO2A(100,1)|CARBON DIOXIDE SORBENT(66,3)|CO2A POLYAMINE(60,1)|CARBON DIOXIDE SORPTION(54,2)|TETRAAMINE FUNCTIONALITY(52,10)|POLYVALENT ORGANIC LINKER(51,14)|COAL EXHAUST STREAM(51,1)|CO2CAPTURE VOLUME(49,1)|FOSSIL FUEL CO2TO(49,1)|POLYAMINE LIGAND(48,37)|COMBUSTION SOURCE CO2TO(47,1)|COAL EXHAUST GAS CO2RECOVERY(46,1)|CO2PRODUCING RICH SORBENT MATERIAL(44,1)|STABILIZER(41,1)|EXHAUST GAS2THE(40,1)|ABSORBENT(34,4)|TREATING SKIN(34,1)|REGENERATION(33,2)|CO2TYPICAL EXHAUST GAS(33,1)|HAIR CARE(32,1)|PROPANE(31,14)|ETHANE(31,9)|ADSORPTION(30,29)|VAPOR REGENERATION(30,1)|DICARBOXYLATE(28,8)|CO2THEREBY(28,2)|CO2RICH SORBENT MATERIAL(27,2)|BUTANE(26,6)|CO24MBAR(26,1)|FOSSIL FUEL(25,5)|TETRAAMINE(24,3)|REGENERATION(23,2)|COMBUSTION SOURCE(23,1)|TERPHENYL(22,4)|UNSUBSTITUTED HETEROALKYL(21,7)|ADSORBENT MATERIAL(20,8)|DOTPDC(20,4)|DOBDC(20,3)|COMBUSTION AIR(20,2)|AMBIENT TEMPERATURE(20,1)|ARYL SUBSTITUTION(19,12)|DOBPDC(19,6)|CO2CAPTURE(19,4)|AMINE SOLUTION(19,2)|REVERSIBLY ADSORBING CO2TO(19,2)|EXHAUST GAS(18,19)|POLYAMINE(18,8)|UNSUBSTITUTED HETEROARYLOXY(18,4)|METALORGANIC FRAMEWORK DIVALENT CATION(18,3)|UNSUBSTITUTED ALKYL(17,9)|LIGAND(16,2)|NONCOORDINATING SOLVENT(15,5)|SMALL WORKING CAPACITY(15,1)|ALKYL SUBSTITUTION(14,10)|NONACTIVATED SORBENT MATERIAL(13,16)|UNSUBSTITUTED ALKOXY(13,4)|UNSUBSTITUTED ARYLOXY(13,4)|REVERSIBLY ADSORBING CO2PRODUCING(13,1)|STEP SHAPE CO2ADSORPTION PROFILE(13,1)|CO2(12,5)|CO2AND TETRAAMINE FUNCTIONALITY(12,1)|TETRAAMINE MOF VARIANT(12,1)|VACUUM SWING ADSORPTION(11,15)|ALKOXY SUBSTITUTION(11,4)|CO2FROM RICH ADSORBENT(11,1)|DEPROTONATED CARBOXY MOIETY(11,1)|ATOM NONNATURAL PROPORTION(10,1)|CO2BOND SITE PASSIVATE(10,1)|CO2EXCESS CO2PROVIDED(10,1)|ORGANOMETALLIC FRAMEWORK DIVALENT CATION(10,1)|PROTONATED CARBOXYL MOIETY(10,1)|ANHYDROUS ORGANIC SOLVENT(9,4)|HALOGEN SUBSTITUTED METHYL(9,4)|INERT STREAM(9,4)|CO2DESORPTION PROFILE(9,2)|CRUDE BIOGAS(9,2)|HALOGENATED PARAFFIN(9,2)|WET IMPREGNATION(9,2)|COORDINATED CO2ADSORPTION(9,1)|UNACTIVATED SORBENT(9,1)|POWER PLANT(8,7)|CO2REGENERATING(8,3)|HETEROARYL RING(8,3)|CITED PUBLICATION(8,2)|ANIONIC COUNTERION(8,1)|CATIONIC COUNTERION(8,1)|FUEL COMBUSTION HIGHLIGHT(8,1)|ISOTOPIC VARIANT(8,1)|LIQUOR SOLVATED MG2THE(8,1)|PERMISSIBLE SUBSTITUENT(8,1)|Q1AND Q2EACH(8,1)|R9AND R10EACH(8,1)|SCINTILLATION VIAL(8,1)|NATURAL GAS EXHAUST GAS(7,4)|NATURAL GAS(6,9)|MULTICOMPONENT GAS MIXTURE(6,8)|METAL SITE(6,7)|CO2ISOBARS(6,4)|GERMANIUM(6,4)|SELENIUM(6,4)|VACUUM REFILL CYCLE(6,4)|ARYL ADJACENT ATOM(6,3)|CYCLOHEXYL(6,3)|ENRICHED SORBENT MATERIAL(6,3)|HUMIDITY CONDITION(6,3)|INERT ENVIRONMENT(6,3)|RECITED NUMERIC VALUE(6,3)|CYCLICAL HYDROCARBON RADICAL(6,2)|HUMID GAS STREAM(6,2)|MG GRAPHICAL REPRESENTATION(6,2)|TRIETHYLENETETRAAMINE(6,2)|ARYLHETEROARYL GROUP SUBSTITUENT(6,1)|ATOMIC ISOTOPE(6,1)|CO2ADSORBS EMISSION(6,1)|CO2ALTHOUGH SOLID ADSORBENT(6,1)|CYCLO HEPTYL(6,1)|DIAMINE BUTANE(6,1)|GLOBAL CLIMATE FLUCTUATION(6,1)|GLOBAL CO2IT(6,1)|HETEROALKYL RADICAL(6,1)|HYDROCARBON RESERVOIR CO2PROVIDED(6,1)|INTERGOVERNMENTAL PANEL(6,1)|INTERNATIONAL GOVERNMENT PANEL(6,1)|PIPELINE QUALITY METHANE(6,1)|POLYVALENT RADICAL(6,1)|SPECIES SUBSTITUENT(6,1)|TETRAAMINE ANALOG(6,1)|TETRAHYDRO PYRIDYL(6,1)|UNSUBSTITUTED BRANCHED ALKYL(6,1)|PRESSURE SWING ADSORPTION(5,11)|R12(5,5)|ACQUISITION TEMPERATURE CO2IT(5,1)|ARYL SUBSTITUENT(5,1)|CARBONYL RESIDUE(5,1)|CO2DEPLETED RESIDUAL GAS(5,1)|DIVALENT RADICAL(5,1)|EXCESS CO2RESEARCHERS(5,1)|METHANOL MOTHER(5,1)|MINIMAL REGENERATION ENERGY(5,1)|NITROGEN HETEROATOM(5,1)|POLYAMINE LIGAND LOADING RATIO(5,1)|POROUS SOLID SORBENT(5,1)|REDUCING AMINE VOLATILIZATION(5,1)|SALT HYDRATE(5,1)|SOLVENT COORDINATION(5,1)|SYNTHESIS REPORT(5,1)|UNSUBSTITUTED HETEROCYCLOALKYL GROUP(5,1)|HYDROXYL(4,4)|NITROGEN ATOM(4,4)|CRR(4,3)|MATERIAL CO2THE(4,3)|SCIENCE(4,3)|SULFUR ATOM(4,3)|TEMPERATURE ELEVATION(4,3)|2NR R(4,2)|AMINE AQUEOUS SOLUTION(4,2)|CHLOROBENZENE(4,2)|CONR R(4,2)|CYCLOHEXANE(4,2)|DICHLOROMETHANE(4,2)|GRAFT(4,2)|HETEROARYL NUCLEUS(4,2)|MG2SIMULATED AIR(4,2)|NRSO2R(4,2)|PENTADIENYL(4,2)|STRATEGY(4,2)|TETRAHYDROFURAN(4,2)|TRICHLOROETHYLENE(4,2)|AMMONIUM SALT(4,1)|ANTECEDENT(4,1)|BISAMINOPROPYL(4,1)|CARBON DIOXIDE SEQUESTRATION(4,1)|CHIRAL CENTER(4,1)|CO2ON(4,1)|COAL EXHAUST GAS CO2(4,1)|CONFIRMATION(4,1)|CYCLICAL VERSION(4,1)|DIOXIDOBIPHENYL(4,1)|EMISSIONS2EMISSIONS(4,1)|FOSSIL FUELED POWER PLANT(4,1)|GAS INACTIVITY(4,1)|HETEROALKYLENE GROUP(4,1)|HETEROARENE GROUP(4,1)|HETEROCYCLOALKENYL(4,1)|IDENTICAL SUBSTITUENT(4,1)|INCREASED WORLDWIDE CONSUMPTION(4,1)|INERT SOLVENT(4,1)|IODINE ATOM(4,1)|LINOYL CHAIN(4,1)|METHYL PHENOXY(4,1)|N2ALTERNATIVELY(4,1)|NEGATIVE CO2IS(4,1)|NEGATIVE EMISSION(4,1)|OLEOYL CHAIN(4,1)|ORGANIC AMINO SALT(4,1)|RICH SORBENT MATERIAL CO2CAN(4,1)|SATURATED HYDROCARBON RADICAL(4,1)|SOLID CO2THEREBY(4,1)|TETRAAMINE SOLUTION(4,1)|TOLUENE WASHING(4,1)|DOUBLE BOND(3,4)|ABSOLUTE STEREOCHEMISTRY(3,1)|ACCOUNTING(3,1)|ADSORBER(3,1)|ADSORPTION2TO(3,1)|AGRICULTURE(3,1)|AIR RECOVERY(3,1)|AIRCRAFT(3,1)|ALKYLTHIO(3,1)|AMINE ADDED SILICA(3,1)|AQUEOUS AMINE SOLUTION(3,1)|ARYLALKYL GROUP(3,1)|ARYLTHIOXY(3,1)|ASSESSMENT(3,1)|AZINE(3,1)|BIOENERGY(3,1)|BRANCHED CHAIN(3,1)|BUTADIENYL(3,1)|CARBON DIOXIDE ADSORPTION(3,1)|CHOLESTEROL(3,1)|CHROMENE(3,1)|CO2 N2COMBINE(3,1)|CO2ATTENTION(3,1)|CO2IF(3,1)|CO2METHODS(3,1)|CO2RECOVERY(3,1)|COPOLYMER(3,1)|CROTYL(3,1)|CYCLOPENTYL(3,1)|DECOMPOSITION(3,1)|DEPLETION(3,1)|DIAZINYL(3,1)|DIHYDROGEN PHOSPHATE(3,1)|ETHYNYL(3,1)||(CN116367909)|CARBON DIOXIDE(100,179)|METALORGANIC FRAMEWORK(100,23)|DIRECT AIR CAPTURE(100,4)|CARBON DIOXIDE CAPTURE(100,1)|CARBON DIOXIDE EMISSION(100,1)|TETRAMINE LIGANDSTETRAAMINE LIGAND(100,1)|POLYAMINE METALORGANIC FRAMEWORK(94,1)|TETRAMINE LIGAND(70,1)|MULTISITE ORGANIC LINKER(69,2)|LIGANDSTETRAAMINE LIGAND(63,1)|CARBON DIOXIDE ADSORBENT(61,3)|TETRAAMINE(60,7)|REGENERATION(45,5)|FOSSIL FUEL COMBUSTION SOURCE(44,2)|MULTIBIT ORGANIC LINKER(38,5)|SCALE STEAM(36,1)|COMBUSTION SOURCE(35,2)|METAL ORGANIC FRAMEWORK FUNCTIONALIZATION(34,6)|DIVALENT CATION(30,29)|ADSORPTION(29,15)|DICARBOXYLIC ACID ESTER(29,11)|ADSORBENT(28,26)|FLUE GAS(27,34)|ABSORBENT(26,2)|ADSORPTION CURVE(25,5)|FOSSIL FUEL(23,6)|CAPTURING CARBON(23,4)|BUTANE(21,5)|TERPHENYL(21,4)|TETRAAMINE FUNCTIONALIZED MATERIAL(21,4)|UNSUBSTITUTED HETEROALKYL(20,7)|AMBIENT TEMPERATURE(20,1)|BED(20,1)|BIPHENYL(19,5)|COMBUSTION AIR(19,2)|POLYAMINE(18,5)|ADSORBENT MATERIAL(17,36)|METAL ORGANIC FRAMEWORK(17,22)|ARYL SUBSTITUTION(17,10)|UNSUBSTITUTED HETEROARYLOXY(17,4)|PARASITIC ENERGY COST(17,1)|REGENERATION(17,1)|UNSUBSTITUTED ALKYL(16,9)|FLUE GAS STREAM(15,3)|LIGAND(15,2)|TETRAMINE MOF VARIANT(15,2)|CARBON DIOXIDE ADSORBING MATERIAL(15,1)|POLYAMINE METAL ORGANIC FRAMEWORK(15,1)|NONCOORDINATING SOLVENT(14,5)|UNACTIVATED ADSORBENT MATERIAL(13,16)|UNSUBSTITUTED ALKOXY(13,4)|UNSUBSTITUTED ARYLOXY(13,4)|TETRAMINE FUNCTIONALIZED SORBENT(13,1)|ALKYL SUBSTITUTION(12,9)|ATOMIC ISOTOPE UNNATURAL PROPORTION(12,1)|TETRAMINE FUNCTIONALIZED ADSORPTION(12,1)|ALKOXY SUBSTITUTION(11,4)|GRAFTING POLYAMINE LIGAND(11,1)|ADSORPTION LADDER(10,2)|POLYTOPIC ORGANIC LINKER(10,2)|ADSORPTION TIME(10,1)|ATMOSPHERIC PRESSURE(10,1)|POLYAMINE SKELETON(10,1)|POLYUNSATURATED AROMATIC SUBSTITUENT(10,1)|ARYL SUBSTITUENT(9,3)|CRUDE BIOGAS(9,2)|HALOGEN SUBSTITUTED METHYL(8,4)|NATURAL GAS FLUE GAS(8,3)|ACIDIC FUNCTIONALITY(8,2)|HETEROALKYLENE LINKER(8,1)|METHANOL MOTHER LIQUOR(8,1)|MULTIPOSITION ORGANIC LINKER(8,1)|PIPELINE GRADE METHANE(8,1)|POLYAMINE GRAFTING(8,1)|MULTICOMPONENT GAS MIXTURE(7,12)|HETEROARYL GROUP(7,4)|HETEROALKYL GROUP(7,3)|DESORPTION PROFILE(7,2)|EVACUATION REFILL CYCLE(7,2)|GLOBAL CONSUMPTION(7,2)|ADSORBENT MAXIMIZATION(7,1)|ADSORPTION FUNCTIONALIZATION(7,1)|ANIONIC COUNTERION(7,1)|BOOT HANDFORD(7,1)|CATIONIC COUNTERION(7,1)|FUEL COMBUSTION HIGHLIGHT(7,1)|HETEROARENE NUCLEUS(7,1)|ORGANICTHE LINKER(7,1)|PARTIAL PRESSURE(7,1)|SCINTILLATION VIAL(7,1)|TETRAHYDRO PYRIDINYL(7,1)|TETRAMINE ANALOG(7,1)|NATURAL GAS(6,10)|AQUEOUS AMINE SOLUTION(6,4)|CARBOXYLIC ACID MOIETY(6,4)|DOBPDC(6,4)|GERMANIUM(6,4)|HUMIDITY CONDITION(6,4)|MEDIUM CAPTURE(6,4)|SELENIUM(6,4)|ALKYL PROPYLENE TETRAMINE(6,2)|ALKYL SUBSTITUENT(6,2)|HETEROARYL RING(6,2)|HUMID GAS STREAM(6,2)|OLEOYL CHAIN(6,2)|POLYAMINE ANHYDROUS ORGANIC SOLVENT(6,2)|PUMP REFILL CYCLE(6,2)|REGENERATING ENERGY(6,2)|TRIETHYLENETETRAMINE(6,2)|CYCLO HEPTYL(6,1)|INTERNATIONAL GOVERNMENT PANEL(6,1)|METHANOL SOLVATED MG(6,1)|SIMULTANEOUS SOLIDIFICATION(6,1)|SUBSTITUTED HETEROARENE(6,1)|VACUUM SWING ADSORPTION(5,9)|METAL SITE(5,7)|ARGON(5,6)|ARYL ADJACENT ATOM(5,3)|BACKBONE(5,3)|COAL FLUE GAS(5,3)|CYCLOHEXYL(5,3)|DICARBOXYLATE(5,3)|FEEDSTOCK(5,3)|INERT ENVIRONMENT(5,3)|EXPLICITLY RECITED VALUE(5,2)|ACTIVATED ABSORBER(5,1)|CAPTURED SOLID SORBENT(5,1)|CARBONYL RESIDUE(5,1)|CHEMREV 6B(5,1)|CYCLOPROPYL METHYL(5,1)|DESORPTION CURVE(5,1)|EVER INCREASING RESERVE(5,1)|HETEROARYL CORE(5,1)|MG SOLVATION(5,1)|NITROGEN HETEROATOM(5,1)|POROUS SOLID ADSORBENT(5,1)|POSSIBLETHE RAW GAS(5,1)|REDUCING AMINE VOLATILIZATION(5,1)|RSC ADV(5,1)|SALT HYDRATE(5,1)|SOLVENT COORDINATION(5,1)|SYNTHESIS REPORT(5,1)|UNSUBSTITUTED BRANCHED CHAIN ALKYL(5,1)|WITHAFTER DRYING(5,1)|INERT GAS STREAM(4,7)|SCIENCE(4,5)|ADSORBENT MATERIAL EXHIBIT(4,4)|HYDROCARBON RESERVOIR(4,4)|AMANTA(4,2)|ARYLALKYL(4,2)|BIOENERGY(4,2)|CHEMSUSCHEM(4,2)|CHLOROBENZENE(4,2)|CONR R(4,2)|CYCLOHEXANE(4,2)|DIOXANYL(4,2)|DIVALENT GROUP(4,2)|HOMOLOG(4,2)|PARAFFIN(4,2)|PENTADIENYL(4,2)|SIMULATED SYSTEM AIR(4,2)|STEP ADSORPTION PROFILE(4,2)|STEROID(4,2)|SUBSTITUENT SUBSTITUTION(4,2)|TETRAHYDROFURAN(4,2)|THIOALKOXY(4,2)|TRICHLOROETHYLENE(4,2)|ADSORBENTSHAVING(4,1)|ADSORBING CARBON CAPTURE(4,1)|ADSORPTION DESORPTION CYCLE(4,1)|ALKYL DERIVATIVE(4,1)|AMMONIUM CARBAMATE CHAIN(4,1)|ANTECEDENT(4,1)|BASIC FUNCTIONALITY(4,1)|CHIRAL CENTER(4,1)|CRITICAL STRATEGY(4,1)|DISCLOSURE PROVIDESEMISSION REDUCTION(4,1)|DISCLOSURE PROVIDESSEED REMOVAL(4,1)|EXCLUSION LIMIT(4,1)|HETEROALKYLENE GROUP(4,1)|HETEROARALKYL GROUP(4,1)|HETEROCYCLOALKENYL(4,1)|HETEROCYCLOALKYL GROUP(4,1)|IDENTICAL SUBSTITUENT(4,1)|INERT SOLVENT(4,1)|INTERGOVERNMENT CLIMATE CHANGE COMMITTEE(4,1)|IODINE ATOM(4,1)|METHYL PHENOXY(4,1)|MG SYNTHESIS(4,1)|MULTI BIT ORGANIC LINKER(4,1)|NEGATIVE EMISSION(4,1)|NONAROMATIC RING(4,1)|PYRIDYL METHYL(4,1)|RADIOACTIVEISOTOPE(4,1)|SIX MEMBERED AZINE(4,1)|SOURCETHE(4,1)|STRAIGHT CHAIN(4,1)|TETRAMINE SOLUTION(4,1)|TRIVALENT GROUP(4,1)|UNRECITED VALUE(4,1)|CRR(3,3)|DIAMINE(3,3)|ISOBAR SHOWING(3,3)|OXYGEN ATOM(3,3)|SULFUR ATOM(3,3)|ABATEMENT(3,1)|ABSOLUTE STEREOCHEMISTRY(3,1)|AGRICULTURE(3,1)|ALKYLTHIO(3,1)|AMINE ADDED SILICA(3,1)|ANTEDATE(3,1)|ARYLTHIOXY(3,1)|ASSESSMENT(3,1)|ATMOSPHERIC CARBON DIOXIDE(3,1)|BACSIK(3,1)|BELLABKHOUT(3,1)|BENZOPYRAN(3,1)|BUTADIENYL(3,1)|CAPTURE TEMPERATURE(3,1)|CARBON DIOXIDE ADSORPTION(3,1)|CHOLESTEROL(3,1)|CHROMANE(3,1)|COADSORPTION(3,1)|CONTINUOUSLYIT(3,1)|CORROSIVENESS(3,1)|CROTYL(3,1)|CYCLOPENTYL(3,1)|DEPLETION(3,1)|DIAZINYL(3,1)|DIOXABELYL(3,1)|ETHYNYL(3,1)|FAST GROWING SOURCE(3,1)|FURUKAWA(3,1)|GEOMETRIC ISOMER(3,1)|GLOBAL ARTIFICIAL ENERGY SUPPLY(3,1)|GREENHOUSE GASSES(3,1)|HALOALKANES(3,1)|HALOGENATED ALKANES(3,1)|HETEROALKENYL(3,1)||(KR10-2023-0037038)|METALORGANIC FRAMEWORK(100,28)|CARBON DIOXIDE(100,18)|CO2(100,18)|DIRECT AIR CAPTURE(100,3)|CARBON DIOXIDE CAPTURE(100,1)|POLYAMINE METALORGANIC FRAMEWORK(100,1)|TETRAAMINE LIGAND(95,3)|ADSORPTION2O COADSORPTION(78,1)|FLUE GAS2THE(73,2)|POLYTOPIC ORGANIC LINKER(57,14)|CARBON DIOXIDE ADSORBENT(56,3)|POLYAMINE LIGAND(48,37)|BOOT HANDFORD(46,2)|CO2BASED(44,2)|CULTIVATION PAPER(43,1)|DICARBOXYLATE(42,12)|EXHIBIT ADSORPTION(42,1)|EMISSION VOLUME(41,1)|REGENERATION(40,3)|AMINE SOLUTION REGENERATION(40,1)|ABSORBENT(39,2)|ADSORBENT(38,17)|PPMV(34,17)|SOLUTION REGENERATION(31,1)|FOSSIL FUEL COMBUSTION SOURCE(29,1)|EMISSION REDUCTION(28,1)|WORLD POPULATION(28,1)|PROPANE(25,16)|BECCSS(24,1)|METALORGANIC BACKBONE DIVALENT CATION(23,4)|CO VOLUME(23,1)|COMBUSTION SOURCE(23,1)|TERPHENYL(22,4)|ADSORBENT MATERIAL REACTIVATING(22,1)|AGRICULTURAL INDUSTRY(22,1)|CORROSION(22,1)|MASON(22,1)|UNSUBSTITUTED HETEROALKYL(21,7)|DOTPDC(21,4)|RICH SORBENT MATERIAL(21,4)|WORKING CAPACITY(21,3)|TETRAAMINE FUNCTIONALIZED ADSORBENT(21,2)|BUTANE(20,7)|CONCOMITANT ENERGY COST(20,1)|METAL ORGANIC FRAMEWORK(19,9)|UNSUBSTITUTED ALKOXY(19,8)|PARACARBOXYLATE(19,2)|ARYL SUBSTITUTION(18,10)|POLYAMINE(18,8)|UNSUBSTITUTED HETEROARYLOXY(18,4)|RICH ADSORBENT MATERIAL2REMOVE(18,2)|TETRAAMINE MOF VARIANT(18,2)|CARBON DIOXIDE EMISSION(18,1)|UNSUBSTITUTED ALKYL(17,9)|UNSUBSTITUTED ARYL(17,9)|ADSORBENT MATERIAL(16,13)|ALKOXY SUBSTITUTION(16,8)|SORBENT DEACTIVATION(16,4)|LIGAND(16,2)|METALORGANIC FRAMEWORK DIVALENT CATION(16,2)|TETRAAMINE FUNCTIONALIZED MG2THE(16,1)|NONCOORDINATING SOLVENT(15,5)|ALKYL SUBSTITUTION(14,10)|FOSSIL FUEL(14,4)|THERMAL DECOMPOSITION(14,2)|DEACTIVATED SORBENT MATERIAL(13,14)|ATOMIC ISOTOPE UNNATURAL PROPORTION(12,1)|TETRAAMINE FUNCTIONALIZED MATERIAL(11,7)|ADSORPTION PROFILE(11,4)|MG2DOBPDC MOF(11,2)|CULTIVATION PAPER LARGE AREA(11,1)|DEPROTONATED CARBOXYL MOIETY(11,1)|DESORPTION PROFILE(10,3)|CO 2THE METALORGANIC FRAMEWORK(10,1)|POLYUNSATURATED AROMATIC SUBSTITUENT(10,1)|VACUUM SWING ADSORPTION(9,8)|ANHYDROUS ORGANIC SOLVENT(9,4)|CRUDE BIOGAS(9,2)|HALOGENATED PARAFFIN(9,2)|CARBON DIOXIDE ADSORBING MATERIAL(9,1)|FUEL COMBUSTION HIGHLIGHT(9,1)|METHANOL MOTHER LIQUOR(9,1)|MULTICOMPONENT GAS MIXTURE2OF(9,1)|R20SILVER SUBSTITUTED ARYL(9,1)|STEPPED CO2 ACTIVATED ADSORBENT(9,1)|COAL FLUE GAS(8,4)|HALOGEN SUBSTITUTED METHYL(8,4)|HETEROARYL RING(8,3)|DIVALENT RADICAL(8,2)|ANIONIC COUNTERION(8,1)|CATIONIC COUNTERION(8,1)|COOPERATING CO2 ADSORPTION(8,1)|HETEROARENE NUCLEUS(8,1)|PUBLICATION FOOTWEAR DATE(8,1)|SCINTILLATION VIAL(8,1)|SOLID ADSORBENT EXPLORATION(8,1)|GERMANIUM(7,4)|HETEROARYL GROUP(7,4)|ISOSTATIC PRESSURE(7,4)|SELENIUM(7,4)|ACIDIC FUNCTIONALITY(7,2)|ADDRESS CONTRIBUTION2TO(7,1)|AIRPLANE EMISSION(7,1)|AT2AND ISOLATION(7,1)|CAPTURING EMISSION(7,1)|CO2 ADSORBENT(7,1)|COPOLYMERIZING CO2(7,1)|CYCLO HEPTYL(7,1)|FAST GROWING FOSSIL FUEL(7,1)|FOSSIL FUEL NUCLEAR POWERPLANT(7,1)|HETEROALKYL RADICAL(7,1)|HETEROARYL NUCLEUS(7,1)|INTERGOVERNMENT PANEL(7,1)|INTERNATIONAL GOVERNMENT PANEL(7,1)|LARGE AREA(7,1)|PIPELINE QUALITY METHANE(7,1)|R14FOUR OCCURRENCE(7,1)|R14THREE OCCURRENCE(7,1)|SIMULTANEOUS SOLIDIFICATION(7,1)|STAIR ADSORPTION(7,1)|STAIRCASE CO2(7,1)|SUBSTITUTED HETEROARENE(7,1)|TETRAAMINE ANALOG(7,1)|TETRAHYDRO PYRIDYL(7,1)|UNSUBSTITUTED BRANCHED ALKYL(7,1)|INERT GAS STREAM(6,7)|METAL SITE(6,7)|R12(6,7)|ARYL ADJACENT ATOM(6,3)|CO 2IS(6,3)|CYCLOHEXYL(6,3)|HUMIDITY CONDITION(6,3)|INERT ENVIRONMENT(6,3)|CO2 CAPTURE(6,2)|CYCLICAL HYDROCARBON RADICAL(6,2)|DIOXIDOBIPHENYL(6,2)|EXHAUST RECHARGE CYCLE(6,2)|HUMID GAS STREAM(6,2)|METALORGANIC FRAMEWORK STRUCTURE(6,2)|SEQUESTERING CARBON DIOXIDE(6,2)|TRIETHYLENETETRAAMINE(6,2)|PRESSURE SWING ADSORPTION(5,5)|AIRCRAFT EMISSION(5,1)|ARYL SUBSTITUENT(5,1)|CARBONYL RESIDUE(5,1)|CITED PUBLICATION(5,1)|CYCLOPROPYL METHYL(5,1)|DIAMINE ADDED MOF(5,1)|EMISSION MINIMIZATION(5,1)|EVACUATE REFILL CYCLE(5,1)|GLOBAL CONSUMPTION(5,1)|INERT SORBENT(5,1)|LINOALE CHAIN(5,1)|MOBILE EXHAUST(5,1)|NITROGEN HETEROATOM(5,1)|POROUS SOLID ADSORBENT(5,1)|R10IS HYDROGEN(5,1)|REDUCING AMINE VOLATILIZATION(5,1)|SALT HYDRATE(5,1)|SOLVENT COORDINATION(5,1)|SYNTHESIS REPORT(5,1)|TRIFLUORO ETHYL(5,1)|UNSUBSTITUTED HETEROCYCLOALKYL GROUP(5,1)|CO2CO SHOWING(4,4)|HYDROXYL(4,4)|CRR(4,3)|SULFUR ATOM(4,3)|2NR R(4,2)|ALKYLPROPYLENETETRAAMINE STRUCTURE(4,2)|AQUEOUS AMINE SOLUTION(4,2)|BRANCHED CHAIN(4,2)|CHLOROBENZENE(4,2)|CO 2PAUL(4,2)|CYCLOHEXANE(4,2)|DICHLOROMETHANE(4,2)|GRAFT(4,2)|INACTIVATED SORBENT MATERIAL(4,2)|KAND X(4,2)|NRSO2R(4,2)|ORDINARY SENSE(4,2)|PENTADIENYL(4,2)|SIMULATED SYSTEM AIR(4,2)|TETRAHYDROFURAN(4,2)|THIOALKOXY(4,2)|TRICHLOROETHYLENE(4,2)|ALKYL DERIVATIVE(4,1)|CAPTURING CARBON(4,1)|CHIRAL CENTER(4,1)|CO2 DEPLETED RESIDUE GAS(4,1)|CYCLICAL VERSION(4,1)|ENTRAPPING AIR(4,1)|EXCLUSION LIMIT(4,1)|EXHAUST SYSTEM(4,1)|GAS MIXTURES2CO(4,1)|HETEROALKYLENE GROUP(4,1)|HETEROARENE GROUP(4,1)|HETEROCYCLOALKENYL(4,1)|IDENTICAL SUBSTITUENT(4,1)|INERT SOLVENT(4,1)|IODINE ATOM(4,1)|KEY STRATEGY(4,1)|METHYL PHENOXY(4,1)|NEGATIVE EMISSION(4,1)|NONAROMATIC RING(4,1)|NONRENEWABLE GAS(4,1)|OLEOYL CHAIN(4,1)|ORGANIC FRAMEWORK MG(4,1)|PRODUCING CO2WHEREIN(4,1)|PYRIDYL METHYL(4,1)|RETENTATE GAS(4,1)|SATURATED HYDROCARBON RADICAL(4,1)|STRAIGHT CHAIN(4,1)|TETRAAMINE SOLUTION(4,1)|TOLUENE WASH(4,1)|UNSTATED NUMERIC VALUE(4,1)|WATER COADSORPTION(4,1)|ABSOLUTE STEREOCHEMISTRY(3,1)|ACQUISITION(3,1)|ADSORPTION DESORPTION(3,1)|ALKANE(3,1)|ALKYLTHIO(3,1)|AMINE ADDED SILICA(3,1)|ANTEDATE(3,1)|ARYLALKYL GROUP(3,1)|ARYLTHIOXY(3,1)|ASSESSMENT(3,1)|ATMOSPHERIC CARBON DIOXIDE(3,1)|AVAILABLE SALE(3,1)|AZINE(3,1)|BASE FUNCTIONALITY(3,1)|BIOENERGY(3,1)|BUTADIENYL(3,1)|CARBON DIOXIDE ADSORPTION(3,1)|CHOLESTEROL(3,1)|CHROMENE(3,1)|CO 2AND(3,1)|CO 2TO(3,1)|CO2CH2CH2CH(3,1)|CO2PACHAURI(3,1)|COAL FUEL POWER PLANT(3,1)|COATED SUBSTRATE(3,1)|CONCENTRATION REDUCTION(3,1)|CONR R(3,1)|CROTYL(3,1)|CYCLOPENTYL(3,1)||(CA3187852)|CARBON DIOXIDE(100,18)|DIRECT AIR CAPTURE(100,4)|CARBON DIOXIDE EMISSION(100,1)|POLYAMINE METALORGANIC FRAMEWORK(100,1)|REVERSIBLY ADSORB CO2(95,6)|TETRAAMINE FUNCTIONALI ZED(86,1)|CO2 CAPTURE(80,9)|H2O COADSORPTION(78,1)|POLYTOPIC ORGANIC LINKER(69,15)|METALORGANIC FRAMEWORK(67,25)|TETRAAMINE LIGAND(63,1)|TETRAAMINE(57,7)|POLYAMINE LIGAND(56,32)|CO2 ADSORPTION(52,4)|REGENERATION(48,4)|DESORPTION PROFILE(47,1)|ADSORPTION(46,59)|FUNCTIONALIZED METAL ORGANIC FRAMEWORK(44,1)|CO2(43,72)|ACTIVATED ABSORBENT(41,1)|PPMV(38,16)|CO2 ADSORPTION PROFILE(38,5)|ADSORBENT MATERIAL(37,3)|CAPTURING CO2(37,2)|CORROSIVENESS(32,1)|SORBENT(32,1)|REDUCING CO2(31,2)|REGENERATION(31,2)|METAL ORGANIC FRAMEWORK FUNCTIONALIZATION(30,5)|DICARBOXYLATE(30,2)|CO2 EMISSION(29,4)|FOSSIL FUEL COMBUSTION SOURCE(29,1)|HORNOALKYL(29,1)|CARBON DIOXIDE ADSORBING MATERIAL(28,3)|FLUE GAS(27,33)|CARBON DIOXIDE ADSORPTION(27,2)|STEAM REGENERATION(27,1)|HYDROCARBON GROUP(25,1)|COMBUSTION SOURCE(23,1)|PARACARBOXYLATE(23,1)|TETNIARNINE(23,1)|UNSUBSTITUTED HETEROALKYL(22,7)|TETRAAMINE FUNCTIONALIZED MATERIAL(22,4)|DOTPDC(22,3)|WORKING CAPACITY(22,3)|ABSORBENT(21,2)|AMBIENT TEMPERATURE(21,1)|BED(21,1)|DOBDC(20,3)|TETRAAMINE FUNCTIONALIZED ADSORPTION(20,2)|ARYL SUBSTITUTION(19,12)|POLYAMINE(19,7)|COAL FLUE GAS(19,6)|DIOXIDO(19,1)|PARASITIC ENERGY COST(19,1)|ADSORBENT(18,7)|METALORGANIC FRAMEWORK DIVALENT CATION(18,3)|TETRAAAMINE MOF VARIANT(18,2)|UNSUBSTITUTED ALKYL(17,9)|UNSUBSTITUTED ARYL(17,9)|AMINE SOLUTION(17,4)|METAL ORGANIC FRAMEWORK(16,14)|UNSUBSTITUTED ARLYOXY(16,4)|UNACTIVATED ADSORBENT(16,3)|LIGAND(16,2)|ALKYLAMINEFUNCTIONALIZED METALORGANIC FRAMEWORK(16,1)|UNSUBSTI KITED HETEROARYLOXY(16,1)|NONCOORDINATING SOLVENT(15,5)|TERPHENYL(15,2)|ALKYL SUBSTITUTION(14,10)|FOSSIL FUEL(14,5)|CO2 ISOBAR(14,4)|UNSUBSTITUTED ALKOXY(14,4)|STEP SHAPED CO2 ADSORPTION(14,1)|UNACTIVATED ADSORPTION MATERIAL(13,15)|UNSUBSTITUTED HETEROARYLOXY(13,2)|ATOMIC ISOTOPE UNNATURAL PROPORTION(13,1)|COMBUSTION AIR(13,1)|INERT STREAM(12,7)|ABATING CO2(12,3)|VACUUM SWING ADSORPTION(11,14)|ALKOXY SUBSTITUTION(11,4)|CO2 ABSORBENT REGENERATION(11,1)|GRAFTING POLYAMINE LIGAND(11,1)|TETRAAMINE FUNCTIONALIZED MG(11,1)|EVACUATE REFILL CYCLE(10,3)|ADDRESS CO2 CONTRIBUTION(10,2)|AIRPLANE EMISSION(10,2)|CRUDE BIOGAS(10,2)|DEPROTONATED CARBOXYLIC MOIETY(10,2)|DIAMINO BUTANE(10,2)|HALOGENATED PARAFFIN(10,2)|WET IMPREGNATION(10,2)|ANHYDROUS ORGANIC SOLVENT(9,4)|HALOGEN SUBSTITUTED METHYL(9,4)|NATURAL GAS FLUE GAS(9,3)|ACIDIC FUNCTIONALITY(9,2)|COOPERATIVE CO2 ADSORPTION(9,1)|DECREASING AMINE VOLATILIZATION(9,1)|GROWING WORLDWIDE CONSUMPTION(9,1)|METALORGANIC FRAMEWORK MG(9,1)|METHANOL MOTHER LIQUOR(9,1)|TETRAAMINE ANALOG(9,1)|UNSUBSTITUTED BETEROCYCLOALKYL(9,1)|CARBON CAPTURE(8,9)|HETEROARYL RING(8,3)|DIVALENT RADICAL(8,2)|ANIONIC COUNTERION(8,1)|BOOT HANDFORD(8,1)|CAPTURING CO2 EMISSION(8,1)|CATIONIC COUNTERION(8,1)|FUEL COMBUSTION HIGHLIGHT(8,1)|GLOBAL CO2 EMISSION(8,1)|HETEROARENE NUCLEUS(8,1)|PARTIAL PRESSURE(8,1)|POLYARNINE LIGAND(8,1)|SCINTILLATION VIAL(8,1)|SOLID ADSORBENT EXPLORATION(8,1)|MULTICOMPONENT GAS MIXTURE(7,10)|GERMANIUM(7,4)|HETEROARYL GROUP(7,4)|HUMIDITY CONDITION(7,4)|SELENIUM(7,4)|ARYL HETEROARYL(7,1)|CHARGING ABSORBENT(7,1)|CYCLO HEPTYL(7,1)|DI OXIDOBIPHENY(7,1)|DIT UNINE(7,1)|GENERAL CONSUMPTION(7,1)|HETEROALKYL RADICAL(7,1)|HETEROARYL NUCLEUS(7,1)|INTERNATIONAL GOVERNMENT PANEL(7,1)|LINKED COVALENTIY(7,1)|METHANOL SOLVATED MG(7,1)|METHYLTBUTYL ETHER(7,1)|MITAMI NE(7,1)|MULTIVALENT RADICAL(7,1)|PIPELINE QUALITY METHANE(7,1)|POLY AMINE LIGAND(7,1)|SIMULTANEOUS SOLIDIFICATION(7,1)|WORLD POPULATION(7,1)|NATURAL GAS(6,9)|R12(6,7)|AQUEOUS AMINE SOLUTION(6,3)|ARYL ADJACENT ATOM(6,3)|CYCLOHEXYL(6,3)|DIYOBIS(6,3)|INERT ENVIRONMENT(6,3)|REMOVING CO2(6,3)|RESIDUAL GAS(6,3)|ALKYLPROPYLENETETRAAMINE(6,2)|CYCLICAL HYDROCARBON RADICAL(6,2)|HUMID GAS STREAM(6,2)|NEGATIVE EMISSION(6,2)|SEQUESTERING CARBON DIOXIDE(6,2)|TRIETHYLENETETRAAMINE(6,2)|PRESSURE SWING ADSORPTION(5,11)|METAL SITE(5,6)|SCIENCE(5,5)|2NR R(5,2)|BRANCHED CHAIN(5,2)|CHEMSUSCHEM(5,2)|CHLOROBENZENE(5,2)|CONR R(5,2)|CYCLOHEXANE(5,2)|DICHLOROMETHANE(5,2)|EXCESS CO2(5,2)|NRSO2R(5,2)|PENTADIENYL(5,2)|SIMULATED SYSTEM AIR(5,2)|TETRAHYDROFURAN(5,2)|TRICHLOROETHYLENE(5,2)|ADSORBENT FINE TUNING(5,1)|CARBONYL RESIDUE(5,1)|CHERNREV 6B(5,1)|CHOI EL AL(5,1)|CITED PUBLICATION(5,1)|DI CARBOXYLATE(5,1)|DIAMINE APPENDED MOFS(5,1)|KIM EI AL(5,1)|LINOEYL CHAIN(5,1)|MAJOR CONTRIBUTOR(5,1)|MINIMAL REGENERATION ENERGY(5,1)|NITROGEN HETEROATOM(5,1)|PC DOBPDC(5,1)|PORE ARCHITECTURE(5,1)|POROUS SOLID ADSORBENT(5,1)|PPMV CO2(5,1)|PROPANE DIAMINE(5,1)|QI AO(5,1)|SALT HYDRATE(5,1)|SOLVENT COORDINATION(5,1)|SYNTHESIS REPORT(5,1)|UNSUBSTITUTED HETEROCYCLOALKYL GROUP(5,1)|ADSORPTION MATERIAL EXHIBIT(4,4)|HYDROXYL(4,4)|CRR(4,3)|HYDROCARBON RESERVOIR(4,3)|OXYGEN ATOM(4,3)|SULFUR ATOM(4,3)|AMMONIUM CARBAMATE CHAIN(4,1)|ANTECEDENT(4,1)|BASIC FUNCTIONALITY(4,1)|CHIRAL CENTER(4,1)|CYCLICAL VERSION(4,1)|CYCLOPROPVLMETHYL(4,1)|EXCLUSION LIMIT(4,1)|GEOMETRICAL ISOMER GENERATION(4,1)|HETEROALKYL GROUP(4,1)|HETEROALKYLENE GROUP(4,1)|HETEROARENE GROUP(4,1)|HETEROCYCLOALKENYL(4,1)|HOMOLOG(4,1)|IDENTICAL SUBSTITUENT(4,1)|INERT SOLVENT(4,1)|IODINE ATOM(4,1)|KEY STRATEGY(4,1)|METALORGANIC FRAMEWORK STRUCTURE(4,1)|METHYL PHENOXY(4,1)|NONAROMATIC RING(4,1)|NONRENEWABLE GAS(4,1)|OLEOYL CHAIN(4,1)|PROPARIEDIAMINE(4,1)|PYRIDYL METHYL(4,1)|REDUCING CO2 EMISSION(4,1)|SATURATED HYDROCARBON RADICAL(4,1)|SHAPED CO2 DESORPTION PROFILE(4,1)|SIX MEMBERED AZINE(4,1)|STRAIGHT CHAIN(4,1)|TARGETED CO2 CONCENTRATION REDUCTION(4,1)|TETRAAAMINE FURICTIONALIZED MATERIAL(4,1)|TETRAAMINE SOLUTION(4,1)|TETRAHYDROPYRIDY(4,1)|TOLUENE WASH(4,1)|UM STREAM(4,1)|UNSUBSTITUTED BRANCH CHAIN ALKYL(4,1)|DOUBLE BOND(3,4)|ABSOLUTE STEREOCHEMISTRY(3,1)|ADSORPTION DESORPTION(3,1)|AGRICULTURE(3,1)|ALKANE(3,1)|ALKYLTHIO(3,1)|AMINE APPENDED SILICA(3,1)|ANTEDATE(3,1)|APPROXIMATING UNRECITED NUMBER(3,1)|ARYLALKYL(3,1)|ARYLTHIOXY(3,1)|ASSESSMENT(3,1)|ATYLALKYL GROUP(3,1)|AVAILABLE RESERVE(3,1)|BUTADIENYL(3,1)|CAPTURE TEMPERATURE(3,1)|CH2OCH(3,1)|CHOLESTEROL(3,1)|CHROMENE(3,1)|CI CIO(3,1)|CO2 POST COMBUSTION CAPTURE(3,1)|CO2 REMOVAL(3,1)|COADSORPTION(3,1)|CROTYL(3,1)|CRYOGENICS(3,1)|CYCLOPENTYL(3,1)|DEPLETION(3,1)|DIAZINYL(3,1)| | (US11872537)|The invention claimed is:|1. A method for reducing carbon dioxide emissions, the method comprising:| (a) contacting a flue gas from a source with a carbon dioxide adsorbing material to reversibly adsorb CO2 from the flue gas thereby generating an adsorption material enriched for CO2;| (b) reducing the concentration of CO2 from the flue gas to less than 15,000 ppmv; and,| (c) stripping a portion of the CO2 from the adsorption material enriched for CO2 using a regeneration process,| wherein the carbon dioxide adsorbing material comprises a tetraamine functionalized metal organic framework.|2. The method of claim 1, wherein the tetraamine functionalized metal organic framework comprises a plurality of divalent cations and a plurality of polytopic organic linkers.|3. The method of claim 2, wherein each divalent cation in the plurality of divalent cations is Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, Zn or a combination thereof.|4. The method of claim 3 wherein the divalent cation in the plurality of divalent cations is Mg.|5. The method of claim 2, wherein the plurality of polytopic organic linkers comprise 4,4′-dioxidobiphenyl-3,3′-dicarboxylate (dobpdc4−), 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate (dotpdc4−), 2,5-dioxidobenzene-1,4-dicarboxylate (dobdc4−), or 3,3′ dioxide-biphenyl-4,4′-dicarboxylate (para-carboxylate-dobpdc4−).|6. The method of claim 2, wherein the tetraamine functionalized metal organic framework comprises N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine); or N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine).|7. The method of claim 6, wherein the tetraamine functionalized metal organic framework comprises N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) or N,N-(butane-1,4-diyl)bis(propane-1,3-diamine).|8. The method of claim 1, wherein the source is a natural gas combined cycle (NGCC) power plant and CO2 in the flue gas is reduced to a concentration of less than 2,000 ppmv.|9. The method of claim 8, wherein CO2 in the flue gas is reduced to concentration of less than 400 ppmv.|10. The method of claim 1, wherein the concentration of CO2 from the flue gas is reduced to less than 10,000 ppmv.|11. The method of claim 1, wherein the concentration of CO2 from the flue gas is reduced to less than 4,000 ppmv.|12. The method of claim 1, wherein the regeneration process comprises a temperature swing adsorption method, a vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|13. The method of claim 1, wherein the regeneration process comprises applying steam to the adsorption material enriched for CO2 thereby reactivating the adsorption material.|14. A method for CO2 direct air capture, the method comprising:| contacting air with a carbon dioxide adsorption material to reversibly adsorb CO2 from the air thereby generating an adsorption material enriched for CO2 and reducing CO2 concentrations to less than 400 ppmv,| wherein the carbon dioxide adsorbing material comprises a tetraamine functionalized metal organic framework.|15. The method of claim 14, wherein the tetraamine functionalized metal organic framework comprises a plurality of polytopic organic linkers comprising 4,4′-dioxidobiphenyl-3,3′-dicarboxylate (dotpdc4−), 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate (dotpdc4−), 2,5-bioxidobenzene-1,4dicarboxylate (dobdc4−), or 3,3′ dioxide-biphenyl-4,4′-dicarboxylate (para-carboxylate-dobpdc4−) and the tetraamine functionalized metal organic framework further comprises N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine); or N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine) and wherein CO2 in the flue gas is reduced to concentration of less than 400 ppmv. | (US11872537)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63/062,034, filed on Aug. 6, 2020, the disclosure of which is incorporated herein by reference in its entirety.|(US11872537)|FIELD OF THE PRESENT DISCLOSURE|[0002] The present application relates to absorbents comprising tetraamine ligands grafted onto metal-organic frameworks and a method for using same for CO2 capture from fossil fuel combustion sources to reduce emissions. In particular, this application relates to capturing >90% by volume, preferable >99% by volume, CO2 emissions such that the emissions are negative, essentially removing CO2 from the combustion air|BACKGROUND|[0003] Carbon dioxide (CO2) generated from burning fossil fuels at thermoelectric power plants is likely a major contributor to global climate change. See, Pachauri and Meyer, Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, International Government Panel on Climate Change, Geneva, Switzerland, 2014. Accordingly, point-source post-combustion capture of CO2 from the flue gas streams of fossil fuel-fired power plants, in which the CO2 is separated from the other constituents of flue gas (primarily N2, O2, and H2O) before it is released into the atmosphere, and sequestration (CCS), has been proposed as a key strategy to minimize global CO2 emissions. See, Pachauri and Meyer, Ibid., Chu, 2009, Science 325, p. 1599, and Haszeldine, 2009, Science 325. p. 1647. Moreover, researchers in the field have predicted that point-source CCS may need to be supplemented with air capture techniques in which excess CO2 in the atmosphere is reduced in order to address CO2 contribution from mobile sources such as automobile and airplane emissions. See Lackner et al., 2012, PNAS 109(33), p. 13156.|[0004] Despite extensive exploration of solid adsorbents for CO2 capture, few studies have examined the performance of adsorbents in post-combustion capture processes specific to natural gas flue emissions. Natural gas is the fastest-growing fossil fuel source in terms of worldwide consumption. The growing worldwide consumption of natural gas is due to increasingly available reserves and its low greenhouse gas footprint relative to coal.|[0005] The conditions for carbon capture from natural gas are relatively similar to that of carbon capture from coal flue gases. However, there are differences. The flue gas streams are released at atmospheric pressure, are generated at high temperatures (>80° C.) but typically cooled to 40-60° C. to enable effective CO2 capture. While coal flue gas streams typically contain relatively high CO2 concentrations, the typical flue gas from a natural gas combined cycle (NGCC) power plant contains ˜4% by vol. CO2, or about 40,000 ppmv CO2, making capture challenging. An additional challenge is that flue gas from natural gas combined cycle (NGCC) power plants also contains other components such oxygen and water.|[0006] According to the Intergovernmental Panel on Climate Change (IPCC) the 1.5° C. and 2° C. scenarios show a future need for carbon dioxide removal (CDR) negative emissions technologies such as bioenergy with carbon capture and storage (BECCS) or direct air capture (DAC). DAC is has shown to be very expensive while BECCS requires large areas of arable land competing with agriculture at the same time as the world's population is increasing.|[0007] As such, there is a need for adsorbents which are specific to CO2 and maximize CO2 capture.|[0008] The most technology-ready materials for CCS applications are aqueous amine solutions due to their low costs, effective performance under humid conditions, and high selectivity for CO2 over N2. For instance, in some such instances, the exhaust from power plants is passed through a fluidized bed of aqueous amine solution. See, Boot-Handford et al., 2014, Energy Environ. Sci. 7, p. 130; Bhown and Freeman, 2011, Environ. Sci. Technol. 45, p. 8624; and Rochelle, 2009, Science 325, p. 1652. However, these sorbents suffer from a number of drawbacks, including low working capacities (˜2 wt %), corrosiveness, and thermal degradation upon regeneration of the amine solution. See Boot-Handford, 2014, Fennell, Energy Environ. Sci. 7, p. 130; and Fredriksen and Jens, 2013, Energy Procedia 37, p. 1770; and Gouedard et al., 2012, Int. J. Greenhouse Gas Control, 10, p. 244. In particular, at least on the high volume scale needed for industrial regeneration of CO2 absorbents, aqueous amines to date have been unsatisfactory because of such thermal degradation.|[0009] Porous solid adsorbents are also of interest for CO2 adsorbent applications because of their increased stability compared to aqueous amine solutions and potentially lower regeneration energies. See, Drage, 2012, J. Mater. Chem. 22, p. 2815. These favorable properties have led to their investigation as adsorbents for CCS. For selected reviews, see: Lee and Park, 2015, Ind. Eng. Chem. 23, p. 1; Samanta et al., 2012, Ind. Eng. Chem. Res. 51, p. 1438; and Choi et al., 2009, ChemSusChem 2, p. 796. Unfortunately, CO2 adsorption in most of these materials is impaired by the water present in flue gas, which passivates the CO2 binding sites and/or degrades the material. See, Woerner et al., 2016, J. Phys. Chem. C 120, p. 360; Kim et al., 2016, Energy Environ. Sci. 9, p. 1803; Mason et al., 2015, J. Am. Chem. Soc. 137, p. 4787; and Wang and LeVan, 2010, J. Chem. Eng. Data 55, p. 3189.|[0010] Amine-functionalized porous solids, such as amine-appended silicas, combine the best of both classes of materials while maintaining high CO2/N2 selectivities under humid conditions. See, Lee and Park., 2015, Ind. Eng. Chem. 23, p. 1; Samanta et al., 2012, Ind. Eng. Chem. Res. 51, p. 1438; Choi et al., 2009, ChemSusChem 2, p. 796; Kim et al., 2016, Energy Environ. Sci. 9, p. 1803; Mason et al., 2015, J. Am. Chem. Soc. 137, p. 4787; Unveren et al., 2017, Petroleum 3, p. 37; Didas et al., 2014, J. Phys. Chem. Lett. 5, p. 4194; Bacsik et al., 2011, Langmuir 27, p. 11118; Sayari and Belmabkhout, 2010, J. Am. Chem. Soc. 132, p. 6312; Serna-Guerrero et al., 2008, Ind. Eng. Chem. Res. 47, p. 9406. However, one often overlooked drawback of many of these adsorbents is the significant co-adsorption of H2O upon CO2 adsorption, contributing to parasitic energy costs upon regeneration as water is desorbed from the bed with CO2. See, Mason et al., 2015, J. Am. Chem. Soc. 137, p. 4787; Veneman et al., 2014, Energy Procedia 63, p. 2336; Xu et al., 2005, Ind. Eng. Chem. Res. 44, p. 8113; and Franchi et al., 2005, Ind. Eng. Chem. Res. 44, p. 8007.|[0011] Metal-organic frameworks are a class of porous solids consisting of metal nodes connected by polytopic organic linkers that allow for precise control over pore architecture and thus fine-tuning of an adsorbent's properties. See, Zhou et al., 2012, Chem. Rev. 112, p. 673; Furukawa et al., 2013, Science 341, p. 123044; and Eddaoudi et al., 2002, Science 295, p. 469. Many metal-organic frameworks have been evaluated for CCS. For selected reviews, see: Yu et al., 2017, Chem. Rev., (DOI: 10.1021/acs.chemrev.6b0062); Sabouni et al., 2014, Environ. Sci. Pollut. Res. 21, p. 5427; Sumida et al., 2012, Chem. Rev. 112, p. 724; Liu et al., 2012, Greenhouse Gasses Sci. Technol. 2, p. 239; Li et al., 2011, Coord. Chem. Rev. 255, p. 1791; and D'Alessandro et al., 2010, Angew. Chem. Int. Ed., 49, p. 6058.|[0012] In particular, amine-functionalized (Sumida et al., 2012, Chem. Rev. 112, p. 724; Lin et al., 2016, RSC Adv. 6, p. 32598; Qiao et al., 2016, Chem. Commun. 52, p. 974; Liao et al., 2016, Chem. Sci. 7, p. 6528; Fracaroli et al., 2014, J. Am. Chem. Soc. 136, p. 8863; Cao et al., 2013, J. Environ. Sci. 25, p. 2081; Montoro et al., 2012, J. Mater. Chem. 22, p. 10155; Liu et al., 2012, Chem. Soc. Rev. 41, p. 2308) metal-organic frameworks are promising for these applications due to their ability to capture CO2 in the presence of water while potentially minimizing water co-adsorption.|[0013] Accordingly, what is needed in the art are polyamine metal-organic frameworks, in which the polyamines are grafted to the metal-organic framework by multiple M-N bonds per ligand, that exhibit step-shaped CO2 adsorption profiles, and enable effective capture of CO2 at low partial pressures (e.g., an approximately 40° C. step occurring at or below 15 mbar for CO2 capture from coal flue gas, or at or below 4 mbar at approximately 40° C. for CO2 capture from natural gas flue gas, or at or below 0.4 mbar (400 ppm) at ambient temperature commonly taken as 25° C. for carbon capture from air), at greater than 90% by volume capture of CO2, preferably greater than 99%, and are sufficiently stable to be used in steam based regeneration processes on an industrial scale.|SUMMARY|[0014] The present disclosure addresses the above-identified shortcomings by providing tetraamine functionalized materials that have an unexpected improvement in capturing CO2 over the prior art. The resulting tetraamine-appended framework adsorbs CO2 cooperatively, resulting in step-shaped CO2 adsorption profiles. These materials maintain CO2 adsorption steps in the presence of water vapor, and unlike the diamine-appended MOFs, these tetraamine materials are stable to steam, making them highly promising for carbon capture from humid gas streams. In addition, these tetraamine functionalized Mg2(dobpdc) materials are capable of greater than 90% by vol., preferably greater than 99% by vol., CO2 capture. For example, tetraamine functionalized materials can achieve greater than 90% by vol., preferably greater than 99% by vol., CO2 capture from NGCCflue gas streams at a temperature range of 40° C.-60° C., preferably 50° C., resulting in lowering CO2 concentrations to less than about 4,000 ppmv. Generally, these tetraaamine functionalized materials can reduce CO2 concentrations to less than about 15,000 ppmv, preferably to less than 10,000 ppmv, preferably less than 4,000 ppmv, preferably to less than about 2,000 ppmv, more preferably to less than about 400 ppmv, even more preferably to less than about 200 ppmv. These tetraamine functionalized materials have proven to be stable and able to capture CO2 at higher temperatures allowing for targeted CO2 concentration reductions depending on the capture temperature. Thus depending on the exact reduction in CO2 in the emitted gas desired, all that is needed is to adjust the temperature of the process.|[0015] These tetraamine functionalized materials exhibit enhanced cooperative CO2 adsorption relative to diamine-appended materials.|[0016] One aspect of the present disclosure provides activated absorbents comprising polyamine ligands grafted onto a metal-organic framework and exhibiting step-shaped CO2 adsorption and desorption profiles. Such adsorbents have a wide range of technical applications, such as for CO2 capture. The disclosed metal-organic frameworks are composed of polytopic organic linkers coordinated with divalent cations such as Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn. In some embodiments the disclosed metal-organic frameworks include two or more different divalent cations (e.g., Mg and Ca). In some embodiments the disclosed metal-organic frameworks include three or more different divalent cations. In some embodiments the disclosed metal-organic frameworks a single type of divalent cation. Examples of the polytopic organic linkers include 4,4′-dioxidobiphenyl-3,3′-dicarboxylate; 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate; 2,5-dioxidobenzene-1,4-dicarboxylate; and 3,3-dioxidobiphenyl-4,4-dicarboxylate.|[0017] Another aspect of the present disclosure provides methods for charging the disclosed absorbents. The disclosed charging methods include grafting polyamine ligands onto a metal-organic framework in an organic solvent to form unactivated adsorbent, followed by subjecting the unactivated adsorbent to an inert stream of gas at a temperature of at least 165° C. or by washing the unactivated adsorbent with a noncoordinating solvent such as toluene at 60-80° C., thereby activating the absorbent.|[0018] One aspect of the present disclosure provides an adsorption material comprising a metal-organic framework. The metal-organic framework comprises (i) a plurality of divalent cations and (ii) a plurality of polytopic organic linkers. The adsorption material further comprises a plurality of polyamine ligands. In some non-limiting embodiments, the adsorption material has a polyamine ligand:metal-organic framework divalent cation loading ratio of 0.3 or less to 1 (e.g. 0.25 to 1, meaning one polyamine ligand per four metal sites), 0.4 or less to 1 (e.g., 0.35 to 1), 0.5 or less to 1 (e.g. 0.45 to 1), 0.6 or less to 1 (e.g. 0.50 to 1 meaning one polyamine ligand per two metal sites), (0.7 or less to 1 (e.g. 0.6 to 1), 0.7 or less to 1 (e.g. 0.65 to 1), (0.8 or less to 1 (e.g. 0.75 to 1 meaning three polyamine ligands per four metal sites), or (0.9 or less to 1 (e.g. 0.85 to 1). In some embodiments, the polyamine ligand:metal-organic framework divalent cation loading ratio is some other ratio not referenced above. Each respective polyamine ligand in the plurality of polyamine ligands comprises:|In this formula, X1 and X2 are respective first and second divalent cations in the plurality of divalent cations (e.g., Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn). Further, Y is:|and Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium. The values i, j, k, x, y, and z are each independently 0, 1, or 2, while m is 2, 3, or 4. Each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy.|[0021] Another aspect of the present disclosure provides a method for abating CO2 from a flue gas in which the flue gas is contacted with the tetraamine functionalized adsorption material of the present disclosure to reversibly adsorb CO2 from the flue gas, capturing >90% by volume, preferably >99% by volume, CO2 emissions such that the emissions are negative, resulting in direct CO2 capture from the air, thereby generating an adsorption material enriched for CO2 and then stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0022] Another aspect of the present disclosure provides a method for capturing CO2 from air, also known as direct air capture, in which air is contacted with the tetraamine functionalized adsorption material of the present disclosure to reversibly adsorb CO2 from air, capturing >50% by volume, preferable >75% by volume, CO2 emissions, or stated differently, reducing CO2 concentrations in air to less than about 200 ppmv, preferably to less than 100 ppmv, such that the emissions are negative, resulting in direct CO2 capture from the air, thereby generating an adsorption material enriched for CO2. It would be understood by a person of skill in the art that as the base concentration changes, the capture rate also changes. A major portion of the CO2 is then stripped from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0023] Another aspect of the present disclosure provides a method for removing CO2 from a biogas. The method comprises contacting the biogas with any adsorption material of the present disclosure to reversibly adsorb CO2 from the biogas thereby generating an adsorption material enriched for CO2 and a residual gas that is greater than 98 percent pure methane. In some such embodiments, the method further comprises stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0024] Another aspect of the present disclosure provides a method for removing CO2 from a hydrocarbon reservoir. The method comprises contacting the hydrocarbon reservoir with any adsorption material of the present disclosure to reversibly adsorb CO2 from the hydrocarbon reservoir thereby generating an adsorption material enriched for CO2. In some such embodiments, the method further comprises stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0025] Still another aspect of the present disclosure provides a method of sequestering carbon dioxide produced by a source. The method comprises exposing the carbon dioxide to an adsorption material of the present disclosure whereby the carbon dioxide is reversibly sequestered into the adsorption material. In some such embodiments, the method further comprises regenerating the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0026] Another aspect of the present disclosure provides a method of synthesizing an adsorption material in which a plurality of polyamine ligands is grafted onto a metal-organic framework. The metal-organic framework comprises a plurality of divalent cations and a plurality of polytopic organic linkers. The grafting comprises exposing an amount of the metal-organic framework to a solution comprising the polyamine ligand diluted with a solvent thereby forming an unactivated adsorption material. Each polyamine ligand has the formula:|and where Y is:|Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium, i, j, k, x, y, and z are each independently 0, 1, or 2, and m is 2, 3, or 4. Further, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy. In some embodiments, the unactivated adsorption material is subjected to an inert stream of gas at a temperature of at least 165° C., at least 190° C., at least 210° C., or between 190° C. and 250° C., thereby activating the adsorption material. In some embodiments, the unactivated adsorption material is washed with a weakly coordinating or non-coordinating solvent at a temperature of between 60° C. and 180° C. thereby activating the adsorption material. Representative and non-limiting examples of weakly coordinating or non-coordinating solvents can include toluene, chlorobenzene, paraffins, halogenated paraffins, and the like, as well as combinations thereof. In some embodiments, the unactivated adsorption material is placed under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material. In some embodiments, the unactivated adsorption material is subjected to one or more cycles of (i) an inert stream of gas at a temperature of at least 165° C. followed by (ii) placement under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material. In some embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles, in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle. In some embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles under elevated temperatures, such as greater than 60° C., in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle. In some embodiments, the adsorption material is characterized as activated when it has a polyamine ligand loading of 120 percent or less, where a loading of 100% corresponds to one polyamine ligand per two metal sites.|[0029] Referring back to the synthesis of the adsorption material, in some embodiments, the solvent is toluene. In some embodiments, the solvent is toluene, water, methanol, dichloromethane, tetrahydrofuran, cyclohexane, pentane, 2-butanone, trichloroethylene, methyl-t-butyl ether, heptane, diethyl ether, or a mixture thereof. In some embodiments, the inert stream of gas is nitrogen gas, argon gas, or a mixture thereof.|[0030] In some embodiments, the activated adsorption material has a polyamine ligand loading of 110 percent or less.|[0031] In some embodiments, each divalent cation in the plurality of divalent cations is Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn.|[0032] Another aspect of the present disclosure provides a method for removing CO2 from a multi-component gas mixture comprising CO2 and at least one of N2, H2O, and O2, the method comprising contacting the multi-component gas mixture with the adsorption material of the present invention reversibly adsorb CO2 from the multi-component gas mixture thereby generating an adsorption material enriched for CO2 and a residual gas that is depleted of CO2 (e.g., less than 10% v/v CO2 remaining in the multi-component gas mixture, less than 5% v/v CO2 remaining in the multi-component gas mixture, less than 2% v/v CO2 remaining in the multi-component gas mixture, less than 1000 ppm at 25° C. in the multi-component gas mixture, less than 500 ppm at 25° C. in the multi-component gas mixture, etc. upon depletion).|(US11872537)|BRIEF DESCRIPTION OF THE DRAWINGS|[0033] FIG. 1 illustrates a structure of the metal-organic framework Mg2(dobpdc) (dobpdc4−=4,4′-dioxidobiphenyl-3,3′-dicarboxylate) (panel A) and appending alkylpropylenetetraamines to the open Mg2+ sites of the framework (panel B) to yield adsorbents displaying step-shaped adsorption of CO2.|[0034] FIG. 2 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”) Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated air (400 ppm CO2) at temperatures below 60° C.|[0035] FIG. 3 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”) Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated NGCC flue gas (4% CO2) at temperatures below 110° C.|[0036] FIG. 4 illustrates the two-step adsorption profile for Mg2(dobpdc) tetraaamine MOF variants: N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine) (“3-4-3”); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine) (“3-2-3”); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine) (“2-3-2”); and N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine) (“2-2-2”).|(US11872537)|DETAILED DESCRIPTION OF THE INVENTION|I. Introduction|[0037] Herein, a procedure for grafting polyamines (specifically triamines, tetraamines and pentamines) to Mg2(dobpdc) and related metal-organic frameworks via multiple M-N bonds, thereby greatly decreasing amine volatilization, is provided. These polyamines are grafted to the framework and then heated at a critical temperature thereby enabling the formation of the desired adducts possessing multiple M-N bonds per polyamine. The resulting polyamine-appended frameworks adsorb CO2 cooperatively, likely via formation of ammonium carbamate chains, resulting in step-shaped CO2 adsorption profiles. In addition, these materials maintain CO2 adsorption steps in the presence of water vapor, and unlike the diamine-appended MOFs, these polyamine materials are stable to steam, making them highly promising for carbon capture from humid gas streams.|[0038] Before the invention is described in greater detail, it is to be understood that the invention is not limited to particular embodiments described herein as such embodiments may vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and the terminology is not intended to be limiting. The scope of the invention will be limited only by the appended claims. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range, is encompassed within the invention. The upper and lower limits of these smaller ranges may independently be included in the smaller ranges and are also encompassed within the invention, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the invention. Certain ranges are presented herein with numerical values being preceded by the term “about.” The term “about” is used herein to provide literal support for the exact number that it precedes, as well as a number that is near to or approximately the number that the term precedes. In determining whether a number is near to or approximately a specifically recited number, the near or approximating unrecited number may be a number, which, in the context in which it is presented, provides the substantial equivalent of the specifically recited number. All publications, patents, and patent applications cited in this specification are incorporated herein by reference to the same extent as if each individual publication, patent, or patent application were specifically and individually indicated to be incorporated by reference. Furthermore, each cited publication, patent, or patent application is incorporated herein by reference to disclose and describe the subject matter in connection with which the publications are cited. The citation of any publication is for its disclosure prior to the filing date and should not be construed as an admission that the invention described herein is not entitled to antedate such publication by virtue of prior invention. Further, the dates of publication provided might be different from the actual publication dates, which may need to be independently confirmed.|[0039] It is noted that the claims may be drafted to exclude any optional element. As such, this statement is intended to serve as antecedent basis for use of such exclusive terminology as “solely,” “only,” and the like in connection with the recitation of claim elements, or use of a “negative” limitation. As will be apparent to those of skill in the art upon reading this disclosure, each of the individual embodiments described and illustrated herein has discrete components and features which may be readily separated from or combined with the features of any of the other several embodiments without departing from the scope or spirit of the invention. Any recited method may be carried out in the order of events recited or in any other order that is logically possible. Although any methods and materials similar or equivalent to those described herein may also be used in the practice or testing of the invention, representative illustrative methods and materials are now described.|[0040] In describing the present invention, the following terms will be employed, and are defined as indicated below.|II. Definitions|[0041] Where substituent groups are specified by their conventional chemical formulae, written from left to right, the structures optionally also encompass the chemically identical substituents, which would result from writing the structure from right to left, e.g., —CH2O— is intended to also optionally recite —OCH2—.|[0042] The term “alkyl,” by itself or as part of another substituent, means, unless otherwise stated, a straight or branched chain, or cyclic hydrocarbon radical, or combination thereof, which may be fully saturated, mono- or polyunsaturated and can include di-, tri- and multivalent radicals, having the number of carbon atoms designated (i.e. C1-C10 means one to ten carbons). Examples of saturated hydrocarbon radicals include, but are not limited to, groups such as methyl, ethyl, n-propyl, isopropyl, n-butyl, t-butyl, isobutyl, sec-butyl, cyclohexyl, (cyclohexyl)methyl, cyclopropylmethyl, homologs and isomers of, for example, n-pentyl, n-hexyl, n-heptyl, n-octyl, and the like. An unsaturated alkyl group is one having one or more double bonds or triple bonds. Examples of unsaturated alkyl groups include, but are not limited to, vinyl, 2-propenyl, crotyl, 2-isopentenyl, 2-(butadienyl), 2,4-pentadienyl, 3-(1,4-pentadienyl), ethynyl, 1- and 3-propynyl, 3-butynyl, and the higher homologs and isomers. The term “alkyl,” unless otherwise noted, is also meant to optionally include those derivatives of alkyl defined in more detail below, such as “heteroalkyl.” Alkyl groups that are limited to hydrocarbon groups are termed “homoalkyl”. Exemplary alkyl groups include the monounsaturated C9-10, oleoyl chain or the diunsaturated C9-10, 12-13 linoeyl chain.|[0043] The term “alkylene” by itself or as part of another substituent means a divalent radical derived from an alkane, as exemplified, but not limited, by —CH2CH2CH2CH2—, and further includes those groups described below as “heteroalkylene.” Typically, an alkyl (or alkylene) group will have from 1 to 24 carbon atoms, with those groups having 10 or fewer carbon atoms being preferred in the present invention. A “lower alkyl” or “lower alkylene” is a shorter chain alkyl or alkylene group, generally having eight or fewer carbon atoms.|[0044] The terms “alkoxy,” “alkylamino” and “alkylthio” (or thioalkoxy) are used in their conventional sense, and refer to those alkyl groups attached to the remainder of the molecule via an oxygen atom, an amino group, or a sulfur atom, respectively.|[0045] The terms “aryloxy” and “heteroaryloxy” are used in their conventional sense, and refer to those aryl or heteroaryl groups attached to the remainder of the molecule via an oxygen atom.|[0046] The term “heteroalkyl,” by itself or in combination with another term, means, unless otherwise stated, a stable straight or branched chain, or cyclic hydrocarbon radical, or combinations thereof, consisting of the stated number of carbon atoms and at least one heteroatom selected from the group consisting of O, N, Si and S, and wherein the nitrogen and sulfur atoms may optionally be oxidized and the nitrogen heteroatom may optionally be quaternized. The heteroatom(s) O, N and S and Si may be placed at any interior position of the heteroalkyl group or at the position at which the alkyl group is attached to the remainder of the molecule. Examples include, but are not limited to, —CH2—CH2—O—CH3, —CH2—CH2—NH—CH3, —CH2—CH2—N(CH3)—CH3, —CH2—S—CH2—CH3, —CH2—CH2, —S(O)—CH3, —CH2—CH2—S(O)2—CH3, —CH═CH—O—CH3, —Si(CH3)3, —CH2—CH═N—OCH3, and —CH═CH—N(CH3)—CH3. Up to two heteroatoms may be consecutive, such as, for example, —CH2—NH—OCH3 and —CH2—O—Si(CH3)3. Similarly, the term “heteroalkylene” by itself or as part of another substituent means a divalent radical derived from heteroalkyl, as exemplified, but not limited by, —CH2—CH2—S—CH2—CH2— and —CH2—S—CH2—CH2—NH—CH2—. For heteroalkylene groups, heteroatoms can also occupy either or both of the chain termini (e.g., alkyleneoxy, alkylenedioxy, alkyleneamino, alkylenediamino, and the like). Still further, for alkylene and heteroalkylene linking groups, no orientation of the linking group is implied by the direction in which the formula of the linking group is written. For example, the formula —CO2R′— represents both —C(O)OR′ and —OC(O)R′.|[0047] The terms “cycloalkyl” and “heterocycloalkyl,” by themselves or in combination with other terms, represent, unless otherwise stated, cyclic versions of “alkyl” and “heteroalkyl”, respectively. Additionally, for heterocycloalkyl, a heteroatom can occupy the position at which the heterocycle is attached to the remainder of the molecule. Examples of cycloalkyl include, but are not limited to, cyclopentyl, cyclohexyl, 1-cyclohexenyl, 3-cyclohexenyl, cycloheptyl, and the like. Further exemplary cycloalkyl groups include steroids, e.g., cholesterol and its derivatives. Examples of heterocycloalkyl include, but are not limited to, 1-(1,2,5,6-tetrahydropyridyl), 1-piperidinyl, 2-piperidinyl, 3-piperidinyl, 4-morpholinyl, 3-morpholinyl, tetrahydrofuran-2-yl, tetrahydrofuran-3-yl, tetrahydrothien-2-yl, tetrahydrothien-3-yl, 1-piperazinyl, 2-piperazinyl, and the like.|[0048] The terms “halo” or “halogen,” by themselves or as part of another substituent, mean, unless otherwise stated, a fluorine, chlorine, bromine, or iodine atom. Additionally, terms such as “haloalkyl,” are meant to include monohaloalkyl and polyhaloalkyl. For example, the term “halo(C1-C4)alkyl” is mean to include, but not be limited to, trifluoromethyl, 2,2,2-trifluoroethyl, 4-chlorobutyl, 3-bromopropyl, and the like.|[0049] The term “aryl” means, unless otherwise stated, a polyunsaturated, aromatic, substituent that can be a single ring or multiple rings (preferably from 1 to 3 rings), which are fused together or linked covalently. The term “heteroaryl” refers to aryl substituent groups (or rings) that contain from one to four heteroatoms selected from N, O, S, Si and B, wherein the nitrogen and sulfur atoms are optionally oxidized, and the nitrogen atom(s) are optionally quaternized. An exemplary heteroaryl group is a six-membered azine, e.g., pyridinyl, diazinyl and triazinyl. A heteroaryl group can be attached to the remainder of the molecule through a heteroatom. Non-limiting examples of aryl and heteroaryl groups include phenyl, 1-naphthyl, 2-naphthyl, 4-biphenyl, 1-pyrrolyl, 2-pyrrolyl, 3-pyrrolyl, 3-pyrazolyl, 2-imidazolyl, 4-imidazolyl, pyrazinyl, 2-oxazolyl, 4-oxazolyl, 2-phenyl-4-oxazolyl, 5-oxazolyl, 3-isoxazolyl, 4-isoxazolyl, 5-isoxazolyl, 2-thiazolyl, 4-thiazolyl, 5-thiazolyl, 2-furyl, 3-furyl, 2-thienyl, 3-thienyl, 2-pyridyl, 3-pyridyl, 4-pyridyl, 2-pyrimidyl, 4-pyrimidyl, 5-benzothiazolyl, purinyl, 2-benzimidazolyl, 5-indolyl, 1-isoquinolyl, 5-isoquinolyl, 2-quinoxalinyl, 5-quinoxalinyl, 3-quinolyl, and 6-quinolyl. Substituents for each of the above noted aryl and heteroaryl ring systems are selected from the group of acceptable substituents described below.|[0050] For brevity, the term “aryl” when used in combination with other terms (e.g., aryloxy, arylthioxy, arylalkyl) includes aryl, heteroaryl and heteroarene rings as defined above. Thus, the term “arylalkyl” is meant to include those radicals in which an aryl group is attached to an alkyl group (e.g., benzyl, phenethyl, pyridylmethyl and the like) including those alkyl groups in which a carbon atom (e.g., a methylene group) has been replaced by, for example, an oxygen atom (e.g., phenoxymethyl, 2-pyridyloxymethyl, 3-(1-naphthyloxy)propyl, and the like).|[0051] Each of the above terms (e.g., “alkyl,” “heteroalkyl,” “aryl, and “heteroaryl”) are meant to optionally include both substituted and unsubstituted forms of the indicated species. Exemplary substituents for these species are provided below.|[0052] Substituents for the alkyl and heteroalkyl radicals (including those groups often referred to as alkylene, alkenyl, heteroalkylene, heteroalkenyl, alkynyl, cycloalkyl, heterocycloalkyl, cycloalkenyl, and heterocycloalkenyl) are generically referred to as “alkyl group substituents,” and they can be one or more of a variety of groups selected from, but not limited to: H, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, —OR′, ═O, ═NR′, ═N—OR′, —NR′R″, —SR′, halogen, —SiR′R″R″′, —OC(O)R′, —C(O)R′, —CO2R′, —CONR′R″, —OC(O)NR′R″, —NR″C(O)R′, —NR′—C(O)NR″R″′, —NR″C(O)2R′, —NR—C(NR′R″R′″)═NR″″, —NR—C(NR′R″)═NR, —S(O)R′, —S(O)2R′, —S(O)2NR′R″, —NRSO2R′, —CN and —NO2 in a number ranging from zero to (2m′+1), where m′ is the total number of carbon atoms in such radical. R′, R″, R′″ and R″″ each preferably independently refer to hydrogen, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, e.g., aryl substituted with 1-3 halogens, substituted or unsubstituted alkyl, alkoxy or thioalkoxy groups, or arylalkyl groups. When a compound of the invention includes more than one R group, for example, each of the R groups is independently selected as are each R′, R″, R′″ and R″″ groups when more than one of these groups is present. When R′ and R″ are attached to the same nitrogen atom, they can be combined with the nitrogen atom to form a 5-, 6-, or 7-membered ring. For example, —NR′R″ is meant to include, but not be limited to, 1-pyrrolidinyl and 4-morpholinyl. From the above discussion of substituents, one of skill in the art will understand that the term “alkyl” is meant to include groups including carbon atoms bound to groups other than hydrogen groups, such as haloalkyl (e.g., —CF3 and —CH2CF3) and acyl (e.g., —C(O)CH3, —C(O)CF3, —C(O)CH2OCH3, and the like). These terms encompass groups considered exemplary “alkyl group substituents,” which are components of exemplary “substituted alkyl” and “substituted heteroalkyl” moieties.|[0053] Similar to the substituents described for the alkyl radical, substituents for the aryl heteroaryl and heteroarene groups are generically referred to as “aryl group substituents.” The substituents are selected from, for example: groups attached to the heteroaryl or heteroarene nucleus through carbon or a heteroatom (e.g., P, N, O, S, Si, or B) including, without limitation, substituted or unsubstituted alkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, —OR′, ═O, ═NR′, ═N—OR′, —NR′R″, —SR′, -halogen, —SiR′R″R′″, —OC(O)R′, —C(O)R′, —CO2R′, —CONR′R″, —OC(O)NR′R″, —NR″C(O)R′, —NR′—C(O)NR″R′″, —NR″C(O)2R′, —NR—C(NR′R″R′″)═NR″″, —NR—C(NR′R″)═NR′″, —S(O)R′, —S(O)2R′, —S(O)2NR′R″, —NRSO2R′, —CN and —NO2, —R′, —N3, —CH(Ph)2, fluoro(C1-C4)alkoxy, and fluoro(C1-C4)alkyl, in a number ranging from zero to the total number of open valences on the aromatic ring system. Each of the above-named groups is attached to the heteroarene or heteroaryl nucleus directly or through a heteroatom (e.g., P, N, O, S, Si, or B); and where R′, R″, R′″ and R″″ are preferably independently selected from hydrogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl and substituted or unsubstituted heteroaryl. When a compound of the invention includes more than one R group, for example, each of the R groups is independently selected as are each R′, R″, R′″ and R″″ groups when more than one of these groups is present.|[0054] Two of the substituents on adjacent atoms of the aryl, heteroarene or heteroaryl ring may optionally be replaced with a substituent of the formula T-C(O)—(CRR′)q—U—, wherein T and U are independently —NR—, —O—, —CRR′— or a single bond, and q is an integer of from 0 to 3. Alternatively, two of the substituents on adjacent atoms of the aryl or heteroaryl ring may optionally be replaced with a substituent of the formula -A-(CH2)r—B—, wherein A and B are independently —CRR′—, —O—, —NR—, —S—, —S(O)—, —S(O)2—, —S(O)2NR′— or a single bond, and r is an integer of from 1 to 4. One of the single bonds of the new ring so formed may optionally be replaced with a double bond. Alternatively, two of the substituents on adjacent atoms of the aryl, heteroarene or heteroaryl ring may optionally be replaced with a substituent of the formula —(CRR′)s—X—(CR″R′″)d—, where s and d are independently integers of from 0 to 3, and X is —O—, —NR′—, —S—, —S(O)—, —S(O)2—, or —S(O)2NR′—. The substituents R, R′, R″ and R′″ are preferably independently selected from hydrogen or substituted or unsubstituted (C1-C6) alkyl. These terms encompass groups considered exemplary “aryl group substituents”, which are components of exemplary “substituted aryl” “substituted heteroarene” and “substituted heteroaryl” moieties.|[0055] As used herein, the term “acyl” describes a substituent containing a carbonyl residue, C(O)R. Exemplary species for R include H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, and substituted or unsubstituted heterocycloalkyl.|[0056] As used herein, the term “fused ring system” means at least two rings, wherein each ring has at least 2 atoms in common with another ring. “Fused ring systems may include aromatic as well as non-aromatic rings. Examples of “fused ring systems” are naphthalenes, indoles, quinolines, chromenes and the like.|[0057] As used herein, the term “heteroatom” includes oxygen (O), nitrogen (N), sulfur (S) and silicon (Si), boron (B) and phosphorous (P).|[0058] The symbol “R” is a general abbreviation that represents a substituent group that is selected from H, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, and substituted or unsubstituted heterocycloalkyl groups.|[0059] The compounds disclosed herein may also contain unnatural proportions of atomic isotopes at one or more of the atoms that constitute such compounds. For example, the compounds may be radiolabeled with radioactive isotopes, such as for example tritium (3H), iodine-125 (125I) or carbon-14 (14C). All isotopic variations of the compounds of the present invention, whether radioactive or not, are intended to be encompassed within the scope of the present invention.|[0060] The term “salt(s)” includes salts of the compounds prepared by the neutralization of acids or bases, depending on the particular ligands or substituents found on the compounds described herein. When compounds of the present invention contain relatively acidic functionalities, base addition salts can be obtained by contacting the neutral form of such compounds with a sufficient amount of the desired base, either neat or in a suitable inert solvent. Examples of base addition salts include sodium, potassium calcium, ammonium, organic amino, or magnesium salt, or a similar salt. Examples of acid addition salts include those derived from inorganic acids like hydrochloric, hydrobromic, nitric, carbonic, monohydrogencarbonic, phosphoric, monohydrogenphosphoric, dihydrogenphosphoric, sulfuric, monohydrogensulfuric, hydriodic, or phosphorous acids, and the like, as well as the salts derived from relatively nontoxic organic acids like acetic, propionic, isobutyric, butyric, maleic, malic, malonic, benzoic, succinic, suberic, fumaric, lactic, mandelic, phthalic, benzenesulfonic, p-tolylsulfonic, citric, tartaric, methanesulfonic, and the like. Certain specific compounds of the present invention contain both basic and acidic functionalities that allow the compounds to be converted into either base or acid addition salts. Hydrates of the salts are also included.|[0061] “—COOH” as this term is used refers to is meant to optionally include —C(O)O− and —C(O)O−X+, wherein X+ is a cationic counter-ion. Likewise, a substituent having the formula N(R)(R) is meant to optionally include —N+H(R)(R) and —N+H(R)(R)Y−, wherein Y− represents an anionic counter-ion. Exemplary polymers of the invention include a protonated carboxylic moiety (COOH). Exemplary polymers of the invention include a deprotonated carboxylic moiety (COO−). Various polymers of the invention include both a protonated carboxylic moiety and a deprotonated carboxylic moiety.|[0062] It is understood that, in any compound described herein having one or more chiral centers, if an absolute stereochemistry is not expressly indicated, then each center may independently be of R-configuration or S-configuration or a mixture thereof. Thus, the compounds provided herein may be enantiomerically pure or be stereoisomeric mixtures. In addition it is understood that, in any compound described herein having one or more double bond(s) generating geometrical isomers that can be defined as E or Z, each double bond may independently be E or Z a mixture thereof. Likewise, it is understood that, in any compound described, all tautomeric forms are also intended to be included.|[0063] Below are examples of specific embodiments of the present disclosure. The examples are offered for illustrative purposes only, and are not intended to limit the scope of the present invention in any way.|III. Compositions|[0064] One aspect of the present disclosure provides an adsorption material comprising a metal-organic framework. The metal-organic framework comprises (i) a plurality of divalent cations and (ii) a plurality of polytopic organic linkers. The adsorption material further comprises a plurality of polyamine ligands. In some embodiments, the adsorption material has a polyamine ligand:metal-organic framework divalent cation loading ratio of 0.3 or less to 1 (e.g. 0.25 to 1, meaning one polyamine ligand per four metal sites), 0.4 or less to 1 (e.g., 0.35 to 1), 0.5 or less to 1 (e.g. 0.45 to 1), 0.6 or less to 1 (e.g. 0.50 to 1 meaning one polyamine ligand per two metal sites), (0.7 or less to 1 (e.g. 0.6 to 1), 0.7 or less to 1 (e.g. 0.65 to 1), (0.8 or less to 1 (e.g. 0.75 to 1 meaning three polyamine ligands per four metal sites), or (0.9 or less to 1 (e.g. 0.85 to 1). In some embodiments, the polyamine ligand:metal-organic framework divalent cation loading ratio is some other ratio not referenced above. Each respective polyamine ligand in the plurality of polyamine ligands comprises:|In this formula, X1 and X2 are respective first and second divalent cations in the plurality of divalent cations (e.g., Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn). Further, Y is:|and Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium. The values i, j, k, x, y, and z are each independently 0, 1, or 2, while m is 2, 3, or 4. Each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, or substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy.|[0067] In some embodiments, at least twenty percent, in at least forty percent, in at least sixty percent, in at least eighty percent, or at least ninety-eight percent of the plurality of polyamine ligands are each (i) amine appended by a first amine of the respective polyamine ligand to a first divalent cation in the plurality of divalent cations and (ii) amine appended by a second amine of the respective polyamine ligand to a second divalent cation in the plurality of divalent cations of the metal-organic framework|[0068] In some embodiments, Y is:|and (a) i and j are each zero, (b) i is one and j is zero, (c) i is one and j is one, or (d) i is one and j is two.|[0070] An example of such embodiments where i is one and j is zero is:|In the case of N-(2-Aminoethyl)-1,3-propanediamine, Z1, Z2, Z3, Q1 and Q2 are each carbon, i is one, j is zero, and R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11 and R12 are each hydrogen.|[0072] Alternatively, in some embodiments, Y is:|and k and x are zero, and m is two or three. An example of such embodiments is:|In the case of triethylenetetraamine, Z1, Z2, Z4, Q1 and Q2 are each carbon, k is zero, x is zero, R1, R2, R3, R4, R5, R6, R7, R8, R9, and R10, are each hydrogen, each instance of the two instances of R13 and R14 is hydrogen, and m is two.|[0075] Alternatively, in some embodiments, Y is:|k and x are each one, and m is two, three or four.|An example of such embodiments is:|In the case of N,N′-bis(3-aminopropyl)-1,3-propanediamine, Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each carbon, k is one, x is one, R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R15, and R16 are each hydrogen, each instance of the three instances of R13 and R14 is hydrogen, and m is three. Another example of such embodiments is:|In the case of N,N′-bis(3-aminopropyl)-1,4-diaminobutane, Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each carbon, k is one, x is one, R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R15, and R16 are each hydrogen, each instance of the four instances of R13 and R14 is hydrogen, and m is four.|[0079] In some embodiments, Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon. In some embodiments, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, and R15 is independently H, halogen, substituted or unsubstituted n-alkyl or a substituted or unsubstituted branched-chain alkyl. In some such embodiments, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, and R15 is H.|[0080] In some embodiments, the polytopic organic linker is 4,4′-dioxidobiphenyl-3,3′-dicarboxylate (dobpdc4−), 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate (dotpdc4−), 2,5-dioxidobenzene-1,4-dicarboxylate (dobdc4−), or 3,3′ dioxide-biphenyl-4,4′-dicarboxylate (para-carboxylate-dobpdc4−).|[0081] In some embodiments, each polyamine ligand in the plurality of polyamine ligands is: triethylenetetraamine, N,N′-bis(3-aminopropyl)-1,3-propanediamine (referred to herein as “3-3-3”), N,N′-bis(3-aminopropyl)-1,4-diaminobutane (referred to herein as “3-4-3”).|[0082] By way of example, the polyamine ligands can be|[0083] |[0084] In some embodiments, the loading of the plurality of polyamine ligands to the metal-organic framework is between 5 percent and 500 percent, 20 percent and 250 percent, 25 percent and 200 percent, 80 percent and 120 percent, between 90 percent and 110 percent, between 95 percent and 105 percent, or between 98 percent and 102 percent.|[0085] In some embodiments, the adsorption material exhibits a step-shaped CO2 adsorption profile. In some embodiments, the adsorption material exhibits a step-shaped CO2 desorption profile. In some embodiments, the adsorption material exhibits a single step-shaped CO2 adsorption profile. In some embodiments, the adsorption material exhibits a single step-shaped CO2 desorption profile.|[0086] In some embodiments, the polytopic organic linker is an analog of (dobpdc4−), having the formula:|where R17, R18, R19, R20, R21, and R22, are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl.|[0088] In some embodiments, the polytopic organic linker is an analog of (dotpdc4−) having the formula:|where R17, R18, R19, R20, R21, R22, R23, R24, R25, and R26, are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl.|[0090] In some embodiments, the polytopic organic linker is an analog of (pc-dobpdc4−) having the formula:|where R17, R18, R19, R20, R21, and R22, are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl.|[0092] In some embodiments, the polytopic organic linker has the formula:|where R17, R18, R19, R21, R22, and R23 are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl, and R20 is selected from substituted or unsubstituted aryl, and substituted or unsubstituted heteroaryl.|IV. Synthetic Methods|[0094] Another aspect of the present disclosure provides a method of synthesizing an adsorption material in which a plurality of polyamine ligands is grafted onto a metal-organic framework. The metal-organic framework comprises a plurality of divalent cations and a plurality of polytopic organic linkers. The grafting comprises exposing an amount of the metal-organic framework to a solution comprising the polyamine ligand diluted with a solvent thereby forming an unactivated adsorption material.|[0095] In some embodiments, adsorption material is prepared by a method in which the metal-organic framework is optionally first heated (e.g. at 160° C. under vacuum condition or under flowing N2 or Ar for 12 hours), removing adsorbed water and coordinated water or other coordinating solvents. Then the metal-organic framework is dissolved in a solution comprising anhydrous organic solvent charged with the polyamine thereby forming unactivated adsorption material. In some embodiments, the solution is 20% (v/v) polyamine to anhydrous organic solvent. In some embodiments, the solution is between 10% (v/v) and 40% (v/v) polyamine to anhydrous organic solvent. In some embodiments the polyamine is dissolved into the anhydrous organic solvent on an equivalent (w/v) basis rather than a (v/v) basis. In some embodiments, the resulting product is dried for three hours or more under nitrogen protection.|[0096] In some embodiments, each polyamine ligand has the formula:|and where Y is:|Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium, i, j, k, x, y, and z are each independently 0, 1, or 2, and m is 2, 3, or 4. Further, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy.|[0099] In some embodiments, the unactivated adsorption material is subjected to an inert stream of gas at a temperature of at least 165° C. thereby activating the adsorption material.|[0100] In some alternative embodiments, the unactivated adsorption material is washed with a weakly coordinating or non-coordinating solvent at a temperature of between 60° C. and 80° C. at least 165° C. thereby activating the adsorption material. Representative and non-limiting examples of weakly coordinating or non-coordinating solvents can include toluene, chlorobenzene, paraffins, halogenated paraffins, and the like, as well as combinations thereof.|[0101] In some alternative embodiments, the unactivated adsorption material is placed under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material.|[0102] In some alternative embodiments, the unactivated adsorption material is subjected to one or more cycles of (i) an inert stream of gas at a temperature of at least 165° C. followed by (ii) placement under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material.|[0103] In some alternative embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles, in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle, thereby activating the adsorption material.|[0104] In some alternative embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles under elevated temperatures, such as greater than 60° C., in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle thereby activating the adsorption material.|[0105] In some embodiments, the adsorption material is characterized as activated when it has a polyamine ligand loading of 120 percent or less. In some embodiments, each divalent cation in the plurality of divalent cations is Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn.|[0106] In some embodiments, the solvent is anhydrous. In some embodiments, the solvent is toluene. In some embodiments, the solvent is toluene, methanol, dichloromethane, tetrahydrofuran, cyclohexane, pentane, 2-butanone, trichloroethylene, methyl-t-butyl ether, heptane, diethyl ether, or a mixture thereof. In some embodiments, the inert stream of gas is an argon or nitrogen gas, or a mixture thereof.|[0107] In the disclosed methods, the unactivated adsorption material from the wet impregnation method is then subjected to an inert environment at a temperature of at least 165° C. thereby activating the adsorption material. In some such embodiments, the activated adsorption material has a polyamine ligand loading of 120 percent or less. In some embodiments, the activated adsorption material has a polyamine ligand loading of 110 percent or less. In some embodiments, the unactivated adsorption material from the wet impregnation method is subjected to an inert environment at a temperature of at least 190° C., at least 210° C., or between 190° C. and 250° C.|[0108] In some embodiments, the unactivated adsorption material is subjected to the inert environment at the temperature of at least 165° C. for at least four hours, for at least six hours, for at least eight hours, or at least twelve hours, thereby activating the adsorption material.|V. Technical Applications|[0109] In one aspect of the present disclosure, there is provided a number of technical applications for the disclosed adsorption materials.|[0110] One such application is carbon capture from powerplant exhaust, such as coal flue gas. The increasing atmospheric levels of carbon dioxide (CO2), which are likely contributing to global climate change, warrant new strategies for reducing CO2 emissions from point sources such as power plants. In particular, coal-fueled power plants are responsible for 46% of global anthropogenic energy supply CO2 emissions. See, “CO2 Emissions From Fuel Combustion Highlights,” 2016 Edition, International Energy Agency, Paris, France, which is hereby incorporated by reference. Thus, there remains a continuing need for the development of new adsorbents for carbon capture from coal flue gas, a gas stream consisting of CO2 (15-16%), O2 (3-4%), H2O (5-7%), N2 (70-75%), and trace impurities (e.g. SO2, NOx) at ambient pressure and 40° C. See, Planas et al., 2013, “The Mechanism of Carbon Dioxide Adsorption in an Alkylamine-Functionalized Metal-Organic Framework,” J. Am. Chem. Soc. 135, pp. 7402-7405, which is hereby incorporated by reference. In particular, for a temperature swing adsorption process, an adsorbent should possess the following properties: (a) a high working capacity with a minimal temperature swing, in order to minimize regeneration energy costs; (b) high selectivity for CO2 over the other constituents of coal flue gas; (c) 90% capture of CO2 under flue gas conditions; (d) effective performance under humid conditions; and (d) long-term stability to adsorption/desorption cycling under humid conditions.|[0111] Another such application is carbon capture from a biogas such as crude biogas, natural gas, or landfill gas. Biogas, for instance the CO2/CH4 mixtures produced by the breakdown of organic matter, is a renewable fuel source with the potential to replace traditional fossil fuel sources. Removal of CO2 from crude biogas mixtures is one of the most challenging aspects of upgrading this promising fuel source to pipeline quality methane. Therefore, for example, the use of adsorbents to selectively remove CO2 from high pressure CO2/CH4 mixtures with a high working capacity and minimal regeneration energy has the potential to greatly reduce the cost of using biogas in place of natural gas for applications in the energy sector. Some embodiments of the present disclosure provide a method that comprises contacting a biogas, natural gas, landfill gas, or non-renewable gas comprising CO2 and CH4 with any adsorption material of the present disclosure to reversibly adsorb CO2 from the gas thereby generating an adsorption material enriched for CO2 and a residual gas that is greater than 80 percent pure methane, 90 percent pure methane, or 98 percent pure methane. In some such embodiments, the method further comprises stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0112] The disclosed compositions (adsorption materials) can be used to strip a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method or a vacuum swing adsorption method. Example temperature swing adsorption methods and vacuum swing adsorption methods are disclosed in International Publication Number WO2013/059527 A1, which is hereby incorporated by reference.|[0113] Another aspect of the present disclosure provides a method for abating CO2 from a flue gas, such as natural gas flue gas. In such embodiments, the flue gas is contacted with any adsorption material of the present disclosure to reversibly adsorb CO2 from the flue gas thereby generating an adsorption material enriched for CO2 and then stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0114] Another other aspect of the present disclosure provides air capture methods in which excess CO2 in the atmosphere is reduced in order to address CO2 contribution from mobile sources such as automobile and airplane emissions for abating CO2 from a flue gas, such as natural gas flue gas. In some such embodiments, atmospheric air is contacted with any adsorption material of the present disclosure to reversibly adsorb CO2 from the air thereby generating an adsorption material enriched for CO2 and then stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0115] Still another aspect of the present disclosure provides a method of sequestering carbon dioxide produced by a source. The method comprises exposing the carbon dioxide to an adsorption material of the present disclosure whereby the carbon dioxide is reversibly sequestered into the adsorption material. In some such embodiments, the method further comprises regenerating the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0116] Still another aspect of the present disclosure provides a method of sequestering carbon dioxide from a multi-component gas mixture. In some such embodiments the multi-component gas mixture comprises CO2 and at least one of N2, H2O, and O2. The method comprises exposing the multi-component gas mixture to an adsorption material of the present disclosure whereby a least fifty percent, at least sixty percent, or at least eighty percent of the carbon dioxide within the multi-component gas mixture is reversibly sequestered into the adsorption material. In some such embodiments, the method further comprises regenerating the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0117] Another aspect of the present disclosure provides a method of capturing CO2 emissions using a combination of the tetraamine functionalized materials disclosed herein with known CO2 capture technologies such as liquid absorbents in process configurations such as those disclosed in Feron, P. et al., “Towards Zero Emissions from Fossil Fuel Power Stations”, International Journal of Greenhouse Gas Control 87 (2019) 188-902, hereby incorporated by reference, and separation processes, such as cryogenics, which involve the separation and the simultaneous solidification of CO2 from a gaseous mixture. See U.S. Pat. No. 2,011,550 to Hasche.|VI. Examples|Synthesis of Tetraamine-Appended Mg2(dobpdc)|[0118] The following procedure was used for each tetraamine analogue, 3-4-3 and 3-3-3. A 20 mL scintillation vial was charged with a 20% v/v solution of amine in toluene. Separately, approximately 20 mg of methanol-solvated Mg2(dobpdc) was filtered from the methanol mother liquor and washed with toluene (3 x 10 mL). After the toluene washes and subsequent drying on the filter for 2 min under vacuum, Mg2(dobpdc) was added to the tetraamine solution and the vial was left at room temperature for 24 h (60° C. for 24 h in the case of 3-4-3). After soaking, the mixture was filtered and washed with toluene (3 x 10 mL). Tetraamine-appended Mg2(dobpdc) was recovered as an off-white powder after 2 minutes of drying on the filter. To achieve desired 1:2 tetraamine:metal ratio, the as-synthesized material was then heated at 225° C. (for 3-3-3) while under flowing N2 for 1 h.|[0119] FIG. 1 illustrates a structure of the metal-organic framework Mg2(dobpdc) (dobpdc4−=4,4′-dioxidobiphenyl-3,3′-dicarboxylate) (panel A) and appending alkylpropylenetetraamines to the open Mg2+ sites of the framework (panel B) to yield adsorbents displaying step-shaped adsorption of CO2.|[0120] FIG. 2 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”)-Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated air (400 ppm CO2) at temperatures below 60° C.|[0121] FIG. 3 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”)-Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated NGCC flue gas (4% CO2) at temperatures below 110° C.|[0122] FIG. 4 illustrates the two-step adsorption profile for Mg2(dobpdc) tetraaamine MOF variants: N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”) (single-step); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine) (“3-4-3”); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine) (“3-2-3”); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine) (“2-3-2”); and N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine) (“2-2-2”).|CONCLUSION|[0123] It is understood that the examples and embodiments described herein are for illustrative purposes only and that various modifications or changes in light thereof will be suggested to persons skilled in the art and are to be included within the spirit and purview of this application and scope of the appended claims. All publications, patents, and patent applications cited herein are hereby incorporated by reference in their entirety for all purposes. | (US11872537)|CROSS-REFERENCE TO RELATED APPLICATIONS|[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63/062,034, filed on Aug. 6, 2020, the disclosure of which is incorporated herein by reference in its entirety.|(US11872537)|FIELD OF THE PRESENT DISCLOSURE|[0002] The present application relates to absorbents comprising tetraamine ligands grafted onto metal-organic frameworks and a method for using same for CO2 capture from fossil fuel combustion sources to reduce emissions. In particular, this application relates to capturing >90% by volume, preferable >99% by volume, CO2 emissions such that the emissions are negative, essentially removing CO2 from the combustion air|BACKGROUND|[0003] Carbon dioxide (CO2) generated from burning fossil fuels at thermoelectric power plants is likely a major contributor to global climate change. See, Pachauri and Meyer, Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, International Government Panel on Climate Change, Geneva, Switzerland, 2014. Accordingly, point-source post-combustion capture of CO2 from the flue gas streams of fossil fuel-fired power plants, in which the CO2 is separated from the other constituents of flue gas (primarily N2, O2, and H2O) before it is released into the atmosphere, and sequestration (CCS), has been proposed as a key strategy to minimize global CO2 emissions. See, Pachauri and Meyer, Ibid., Chu, 2009, Science 325, p. 1599, and Haszeldine, 2009, Science 325. p. 1647. Moreover, researchers in the field have predicted that point-source CCS may need to be supplemented with air capture techniques in which excess CO2 in the atmosphere is reduced in order to address CO2 contribution from mobile sources such as automobile and airplane emissions. See Lackner et al., 2012, PNAS 109(33), p. 13156.|[0004] Despite extensive exploration of solid adsorbents for CO2 capture, few studies have examined the performance of adsorbents in post-combustion capture processes specific to natural gas flue emissions. Natural gas is the fastest-growing fossil fuel source in terms of worldwide consumption. The growing worldwide consumption of natural gas is due to increasingly available reserves and its low greenhouse gas footprint relative to coal.|[0005] The conditions for carbon capture from natural gas are relatively similar to that of carbon capture from coal flue gases. However, there are differences. The flue gas streams are released at atmospheric pressure, are generated at high temperatures (>80° C.) but typically cooled to 40-60° C. to enable effective CO2 capture. While coal flue gas streams typically contain relatively high CO2 concentrations, the typical flue gas from a natural gas combined cycle (NGCC) power plant contains ˜4% by vol. CO2, or about 40,000 ppmv CO2, making capture challenging. An additional challenge is that flue gas from natural gas combined cycle (NGCC) power plants also contains other components such oxygen and water.|[0006] According to the Intergovernmental Panel on Climate Change (IPCC) the 1.5° C. and 2° C. scenarios show a future need for carbon dioxide removal (CDR) negative emissions technologies such as bioenergy with carbon capture and storage (BECCS) or direct air capture (DAC). DAC is has shown to be very expensive while BECCS requires large areas of arable land competing with agriculture at the same time as the world's population is increasing.|[0007] As such, there is a need for adsorbents which are specific to CO2 and maximize CO2 capture.|[0008] The most technology-ready materials for CCS applications are aqueous amine solutions due to their low costs, effective performance under humid conditions, and high selectivity for CO2 over N2. For instance, in some such instances, the exhaust from power plants is passed through a fluidized bed of aqueous amine solution. See, Boot-Handford et al., 2014, Energy Environ. Sci. 7, p. 130; Bhown and Freeman, 2011, Environ. Sci. Technol. 45, p. 8624; and Rochelle, 2009, Science 325, p. 1652. However, these sorbents suffer from a number of drawbacks, including low working capacities (˜2 wt %), corrosiveness, and thermal degradation upon regeneration of the amine solution. See Boot-Handford, 2014, Fennell, Energy Environ. Sci. 7, p. 130; and Fredriksen and Jens, 2013, Energy Procedia 37, p. 1770; and Gouedard et al., 2012, Int. J. Greenhouse Gas Control, 10, p. 244. In particular, at least on the high volume scale needed for industrial regeneration of CO2 absorbents, aqueous amines to date have been unsatisfactory because of such thermal degradation.|[0009] Porous solid adsorbents are also of interest for CO2 adsorbent applications because of their increased stability compared to aqueous amine solutions and potentially lower regeneration energies. See, Drage, 2012, J. Mater. Chem. 22, p. 2815. These favorable properties have led to their investigation as adsorbents for CCS. For selected reviews, see: Lee and Park, 2015, Ind. Eng. Chem. 23, p. 1; Samanta et al., 2012, Ind. Eng. Chem. Res. 51, p. 1438; and Choi et al., 2009, ChemSusChem 2, p. 796. Unfortunately, CO2 adsorption in most of these materials is impaired by the water present in flue gas, which passivates the CO2 binding sites and/or degrades the material. See, Woerner et al., 2016, J. Phys. Chem. C 120, p. 360; Kim et al., 2016, Energy Environ. Sci. 9, p. 1803; Mason et al., 2015, J. Am. Chem. Soc. 137, p. 4787; and Wang and LeVan, 2010, J. Chem. Eng. Data 55, p. 3189.|[0010] Amine-functionalized porous solids, such as amine-appended silicas, combine the best of both classes of materials while maintaining high CO2/N2 selectivities under humid conditions. See, Lee and Park., 2015, Ind. Eng. Chem. 23, p. 1; Samanta et al., 2012, Ind. Eng. Chem. Res. 51, p. 1438; Choi et al., 2009, ChemSusChem 2, p. 796; Kim et al., 2016, Energy Environ. Sci. 9, p. 1803; Mason et al., 2015, J. Am. Chem. Soc. 137, p. 4787; Unveren et al., 2017, Petroleum 3, p. 37; Didas et al., 2014, J. Phys. Chem. Lett. 5, p. 4194; Bacsik et al., 2011, Langmuir 27, p. 11118; Sayari and Belmabkhout, 2010, J. Am. Chem. Soc. 132, p. 6312; Serna-Guerrero et al., 2008, Ind. Eng. Chem. Res. 47, p. 9406. However, one often overlooked drawback of many of these adsorbents is the significant co-adsorption of H2O upon CO2 adsorption, contributing to parasitic energy costs upon regeneration as water is desorbed from the bed with CO2. See, Mason et al., 2015, J. Am. Chem. Soc. 137, p. 4787; Veneman et al., 2014, Energy Procedia 63, p. 2336; Xu et al., 2005, Ind. Eng. Chem. Res. 44, p. 8113; and Franchi et al., 2005, Ind. Eng. Chem. Res. 44, p. 8007.|[0011] Metal-organic frameworks are a class of porous solids consisting of metal nodes connected by polytopic organic linkers that allow for precise control over pore architecture and thus fine-tuning of an adsorbent's properties. See, Zhou et al., 2012, Chem. Rev. 112, p. 673; Furukawa et al., 2013, Science 341, p. 123044; and Eddaoudi et al., 2002, Science 295, p. 469. Many metal-organic frameworks have been evaluated for CCS. For selected reviews, see: Yu et al., 2017, Chem. Rev., (DOI: 10.1021/acs.chemrev.6b0062); Sabouni et al., 2014, Environ. Sci. Pollut. Res. 21, p. 5427; Sumida et al., 2012, Chem. Rev. 112, p. 724; Liu et al., 2012, Greenhouse Gasses Sci. Technol. 2, p. 239; Li et al., 2011, Coord. Chem. Rev. 255, p. 1791; and D'Alessandro et al., 2010, Angew. Chem. Int. Ed., 49, p. 6058.|[0012] In particular, amine-functionalized (Sumida et al., 2012, Chem. Rev. 112, p. 724; Lin et al., 2016, RSC Adv. 6, p. 32598; Qiao et al., 2016, Chem. Commun. 52, p. 974; Liao et al., 2016, Chem. Sci. 7, p. 6528; Fracaroli et al., 2014, J. Am. Chem. Soc. 136, p. 8863; Cao et al., 2013, J. Environ. Sci. 25, p. 2081; Montoro et al., 2012, J. Mater. Chem. 22, p. 10155; Liu et al., 2012, Chem. Soc. Rev. 41, p. 2308) metal-organic frameworks are promising for these applications due to their ability to capture CO2 in the presence of water while potentially minimizing water co-adsorption.|[0013] Accordingly, what is needed in the art are polyamine metal-organic frameworks, in which the polyamines are grafted to the metal-organic framework by multiple M-N bonds per ligand, that exhibit step-shaped CO2 adsorption profiles, and enable effective capture of CO2 at low partial pressures (e.g., an approximately 40° C. step occurring at or below 15 mbar for CO2 capture from coal flue gas, or at or below 4 mbar at approximately 40° C. for CO2 capture from natural gas flue gas, or at or below 0.4 mbar (400 ppm) at ambient temperature commonly taken as 25° C. for carbon capture from air), at greater than 90% by volume capture of CO2, preferably greater than 99%, and are sufficiently stable to be used in steam based regeneration processes on an industrial scale.|SUMMARY|[0014] The present disclosure addresses the above-identified shortcomings by providing tetraamine functionalized materials that have an unexpected improvement in capturing CO2 over the prior art. The resulting tetraamine-appended framework adsorbs CO2 cooperatively, resulting in step-shaped CO2 adsorption profiles. These materials maintain CO2 adsorption steps in the presence of water vapor, and unlike the diamine-appended MOFs, these tetraamine materials are stable to steam, making them highly promising for carbon capture from humid gas streams. In addition, these tetraamine functionalized Mg2(dobpdc) materials are capable of greater than 90% by vol., preferably greater than 99% by vol., CO2 capture. For example, tetraamine functionalized materials can achieve greater than 90% by vol., preferably greater than 99% by vol., CO2 capture from NGCCflue gas streams at a temperature range of 40° C.-60° C., preferably 50° C., resulting in lowering CO2 concentrations to less than about 4,000 ppmv. Generally, these tetraaamine functionalized materials can reduce CO2 concentrations to less than about 15,000 ppmv, preferably to less than 10,000 ppmv, preferably less than 4,000 ppmv, preferably to less than about 2,000 ppmv, more preferably to less than about 400 ppmv, even more preferably to less than about 200 ppmv. These tetraamine functionalized materials have proven to be stable and able to capture CO2 at higher temperatures allowing for targeted CO2 concentration reductions depending on the capture temperature. Thus depending on the exact reduction in CO2 in the emitted gas desired, all that is needed is to adjust the temperature of the process.|[0015] These tetraamine functionalized materials exhibit enhanced cooperative CO2 adsorption relative to diamine-appended materials.|[0016] One aspect of the present disclosure provides activated absorbents comprising polyamine ligands grafted onto a metal-organic framework and exhibiting step-shaped CO2 adsorption and desorption profiles. Such adsorbents have a wide range of technical applications, such as for CO2 capture. The disclosed metal-organic frameworks are composed of polytopic organic linkers coordinated with divalent cations such as Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn. In some embodiments the disclosed metal-organic frameworks include two or more different divalent cations (e.g., Mg and Ca). In some embodiments the disclosed metal-organic frameworks include three or more different divalent cations. In some embodiments the disclosed metal-organic frameworks a single type of divalent cation. Examples of the polytopic organic linkers include 4,4′-dioxidobiphenyl-3,3′-dicarboxylate; 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate; 2,5-dioxidobenzene-1,4-dicarboxylate; and 3,3-dioxidobiphenyl-4,4-dicarboxylate.|[0017] Another aspect of the present disclosure provides methods for charging the disclosed absorbents. The disclosed charging methods include grafting polyamine ligands onto a metal-organic framework in an organic solvent to form unactivated adsorbent, followed by subjecting the unactivated adsorbent to an inert stream of gas at a temperature of at least 165° C. or by washing the unactivated adsorbent with a noncoordinating solvent such as toluene at 60-80° C., thereby activating the absorbent.|[0018] One aspect of the present disclosure provides an adsorption material comprising a metal-organic framework. The metal-organic framework comprises (i) a plurality of divalent cations and (ii) a plurality of polytopic organic linkers. The adsorption material further comprises a plurality of polyamine ligands. In some non-limiting embodiments, the adsorption material has a polyamine ligand:metal-organic framework divalent cation loading ratio of 0.3 or less to 1 (e.g. 0.25 to 1, meaning one polyamine ligand per four metal sites), 0.4 or less to 1 (e.g., 0.35 to 1), 0.5 or less to 1 (e.g. 0.45 to 1), 0.6 or less to 1 (e.g. 0.50 to 1 meaning one polyamine ligand per two metal sites), (0.7 or less to 1 (e.g. 0.6 to 1), 0.7 or less to 1 (e.g. 0.65 to 1), (0.8 or less to 1 (e.g. 0.75 to 1 meaning three polyamine ligands per four metal sites), or (0.9 or less to 1 (e.g. 0.85 to 1). In some embodiments, the polyamine ligand:metal-organic framework divalent cation loading ratio is some other ratio not referenced above. Each respective polyamine ligand in the plurality of polyamine ligands comprises:|In this formula, X1 and X2 are respective first and second divalent cations in the plurality of divalent cations (e.g., Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn). Further, Y is:|and Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium. The values i, j, k, x, y, and z are each independently 0, 1, or 2, while m is 2, 3, or 4. Each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy.|[0021] Another aspect of the present disclosure provides a method for abating CO2 from a flue gas in which the flue gas is contacted with the tetraamine functionalized adsorption material of the present disclosure to reversibly adsorb CO2 from the flue gas, capturing >90% by volume, preferably >99% by volume, CO2 emissions such that the emissions are negative, resulting in direct CO2 capture from the air, thereby generating an adsorption material enriched for CO2 and then stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0022] Another aspect of the present disclosure provides a method for capturing CO2 from air, also known as direct air capture, in which air is contacted with the tetraamine functionalized adsorption material of the present disclosure to reversibly adsorb CO2 from air, capturing >50% by volume, preferable >75% by volume, CO2 emissions, or stated differently, reducing CO2 concentrations in air to less than about 200 ppmv, preferably to less than 100 ppmv, such that the emissions are negative, resulting in direct CO2 capture from the air, thereby generating an adsorption material enriched for CO2. It would be understood by a person of skill in the art that as the base concentration changes, the capture rate also changes. A major portion of the CO2 is then stripped from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0023] Another aspect of the present disclosure provides a method for removing CO2 from a biogas. The method comprises contacting the biogas with any adsorption material of the present disclosure to reversibly adsorb CO2 from the biogas thereby generating an adsorption material enriched for CO2 and a residual gas that is greater than 98 percent pure methane. In some such embodiments, the method further comprises stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0024] Another aspect of the present disclosure provides a method for removing CO2 from a hydrocarbon reservoir. The method comprises contacting the hydrocarbon reservoir with any adsorption material of the present disclosure to reversibly adsorb CO2 from the hydrocarbon reservoir thereby generating an adsorption material enriched for CO2. In some such embodiments, the method further comprises stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0025] Still another aspect of the present disclosure provides a method of sequestering carbon dioxide produced by a source. The method comprises exposing the carbon dioxide to an adsorption material of the present disclosure whereby the carbon dioxide is reversibly sequestered into the adsorption material. In some such embodiments, the method further comprises regenerating the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0026] Another aspect of the present disclosure provides a method of synthesizing an adsorption material in which a plurality of polyamine ligands is grafted onto a metal-organic framework. The metal-organic framework comprises a plurality of divalent cations and a plurality of polytopic organic linkers. The grafting comprises exposing an amount of the metal-organic framework to a solution comprising the polyamine ligand diluted with a solvent thereby forming an unactivated adsorption material. Each polyamine ligand has the formula:|and where Y is:|Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium, i, j, k, x, y, and z are each independently 0, 1, or 2, and m is 2, 3, or 4. Further, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy. In some embodiments, the unactivated adsorption material is subjected to an inert stream of gas at a temperature of at least 165° C., at least 190° C., at least 210° C., or between 190° C. and 250° C., thereby activating the adsorption material. In some embodiments, the unactivated adsorption material is washed with a weakly coordinating or non-coordinating solvent at a temperature of between 60° C. and 180° C. thereby activating the adsorption material. Representative and non-limiting examples of weakly coordinating or non-coordinating solvents can include toluene, chlorobenzene, paraffins, halogenated paraffins, and the like, as well as combinations thereof. In some embodiments, the unactivated adsorption material is placed under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material. In some embodiments, the unactivated adsorption material is subjected to one or more cycles of (i) an inert stream of gas at a temperature of at least 165° C. followed by (ii) placement under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material. In some embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles, in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle. In some embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles under elevated temperatures, such as greater than 60° C., in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle. In some embodiments, the adsorption material is characterized as activated when it has a polyamine ligand loading of 120 percent or less, where a loading of 100% corresponds to one polyamine ligand per two metal sites.|[0029] Referring back to the synthesis of the adsorption material, in some embodiments, the solvent is toluene. In some embodiments, the solvent is toluene, water, methanol, dichloromethane, tetrahydrofuran, cyclohexane, pentane, 2-butanone, trichloroethylene, methyl-t-butyl ether, heptane, diethyl ether, or a mixture thereof. In some embodiments, the inert stream of gas is nitrogen gas, argon gas, or a mixture thereof.|[0030] In some embodiments, the activated adsorption material has a polyamine ligand loading of 110 percent or less.|[0031] In some embodiments, each divalent cation in the plurality of divalent cations is Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn.|[0032] Another aspect of the present disclosure provides a method for removing CO2 from a multi-component gas mixture comprising CO2 and at least one of N2, H2O, and O2, the method comprising contacting the multi-component gas mixture with the adsorption material of the present invention reversibly adsorb CO2 from the multi-component gas mixture thereby generating an adsorption material enriched for CO2 and a residual gas that is depleted of CO2 (e.g., less than 10% v/v CO2 remaining in the multi-component gas mixture, less than 5% v/v CO2 remaining in the multi-component gas mixture, less than 2% v/v CO2 remaining in the multi-component gas mixture, less than 1000 ppm at 25° C. in the multi-component gas mixture, less than 500 ppm at 25° C. in the multi-component gas mixture, etc. upon depletion).|(US11872537)|BRIEF DESCRIPTION OF THE DRAWINGS|[0033] FIG. 1 illustrates a structure of the metal-organic framework Mg2(dobpdc) (dobpdc4−=4,4′-dioxidobiphenyl-3,3′-dicarboxylate) (panel A) and appending alkylpropylenetetraamines to the open Mg2+ sites of the framework (panel B) to yield adsorbents displaying step-shaped adsorption of CO2.|[0034] FIG. 2 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”) Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated air (400 ppm CO2) at temperatures below 60° C.|[0035] FIG. 3 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”) Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated NGCC flue gas (4% CO2) at temperatures below 110° C.|[0036] FIG. 4 illustrates the two-step adsorption profile for Mg2(dobpdc) tetraaamine MOF variants: N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine) (“3-4-3”); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine) (“3-2-3”); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine) (“2-3-2”); and N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine) (“2-2-2”).|(US11872537)|DETAILED DESCRIPTION OF THE INVENTION|I. Introduction|[0037] Herein, a procedure for grafting polyamines (specifically triamines, tetraamines and pentamines) to Mg2(dobpdc) and related metal-organic frameworks via multiple M-N bonds, thereby greatly decreasing amine volatilization, is provided. These polyamines are grafted to the framework and then heated at a critical temperature thereby enabling the formation of the desired adducts possessing multiple M-N bonds per polyamine. The resulting polyamine-appended frameworks adsorb CO2 cooperatively, likely via formation of ammonium carbamate chains, resulting in step-shaped CO2 adsorption profiles. In addition, these materials maintain CO2 adsorption steps in the presence of water vapor, and unlike the diamine-appended MOFs, these polyamine materials are stable to steam, making them highly promising for carbon capture from humid gas streams.|[0038] Before the invention is described in greater detail, it is to be understood that the invention is not limited to particular embodiments described herein as such embodiments may vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and the terminology is not intended to be limiting. The scope of the invention will be limited only by the appended claims. Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this invention belongs. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range, is encompassed within the invention. The upper and lower limits of these smaller ranges may independently be included in the smaller ranges and are also encompassed within the invention, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the invention. Certain ranges are presented herein with numerical values being preceded by the term “about.” The term “about” is used herein to provide literal support for the exact number that it precedes, as well as a number that is near to or approximately the number that the term precedes. In determining whether a number is near to or approximately a specifically recited number, the near or approximating unrecited number may be a number, which, in the context in which it is presented, provides the substantial equivalent of the specifically recited number. All publications, patents, and patent applications cited in this specification are incorporated herein by reference to the same extent as if each individual publication, patent, or patent application were specifically and individually indicated to be incorporated by reference. Furthermore, each cited publication, patent, or patent application is incorporated herein by reference to disclose and describe the subject matter in connection with which the publications are cited. The citation of any publication is for its disclosure prior to the filing date and should not be construed as an admission that the invention described herein is not entitled to antedate such publication by virtue of prior invention. Further, the dates of publication provided might be different from the actual publication dates, which may need to be independently confirmed.|[0039] It is noted that the claims may be drafted to exclude any optional element. As such, this statement is intended to serve as antecedent basis for use of such exclusive terminology as “solely,” “only,” and the like in connection with the recitation of claim elements, or use of a “negative” limitation. As will be apparent to those of skill in the art upon reading this disclosure, each of the individual embodiments described and illustrated herein has discrete components and features which may be readily separated from or combined with the features of any of the other several embodiments without departing from the scope or spirit of the invention. Any recited method may be carried out in the order of events recited or in any other order that is logically possible. Although any methods and materials similar or equivalent to those described herein may also be used in the practice or testing of the invention, representative illustrative methods and materials are now described.|[0040] In describing the present invention, the following terms will be employed, and are defined as indicated below.|II. Definitions|[0041] Where substituent groups are specified by their conventional chemical formulae, written from left to right, the structures optionally also encompass the chemically identical substituents, which would result from writing the structure from right to left, e.g., —CH2O— is intended to also optionally recite —OCH2—.|[0042] The term “alkyl,” by itself or as part of another substituent, means, unless otherwise stated, a straight or branched chain, or cyclic hydrocarbon radical, or combination thereof, which may be fully saturated, mono- or polyunsaturated and can include di-, tri- and multivalent radicals, having the number of carbon atoms designated (i.e. C1-C10 means one to ten carbons). Examples of saturated hydrocarbon radicals include, but are not limited to, groups such as methyl, ethyl, n-propyl, isopropyl, n-butyl, t-butyl, isobutyl, sec-butyl, cyclohexyl, (cyclohexyl)methyl, cyclopropylmethyl, homologs and isomers of, for example, n-pentyl, n-hexyl, n-heptyl, n-octyl, and the like. An unsaturated alkyl group is one having one or more double bonds or triple bonds. Examples of unsaturated alkyl groups include, but are not limited to, vinyl, 2-propenyl, crotyl, 2-isopentenyl, 2-(butadienyl), 2,4-pentadienyl, 3-(1,4-pentadienyl), ethynyl, 1- and 3-propynyl, 3-butynyl, and the higher homologs and isomers. The term “alkyl,” unless otherwise noted, is also meant to optionally include those derivatives of alkyl defined in more detail below, such as “heteroalkyl.” Alkyl groups that are limited to hydrocarbon groups are termed “homoalkyl”. Exemplary alkyl groups include the monounsaturated C9-10, oleoyl chain or the diunsaturated C9-10, 12-13 linoeyl chain.|[0043] The term “alkylene” by itself or as part of another substituent means a divalent radical derived from an alkane, as exemplified, but not limited, by —CH2CH2CH2CH2—, and further includes those groups described below as “heteroalkylene.” Typically, an alkyl (or alkylene) group will have from 1 to 24 carbon atoms, with those groups having 10 or fewer carbon atoms being preferred in the present invention. A “lower alkyl” or “lower alkylene” is a shorter chain alkyl or alkylene group, generally having eight or fewer carbon atoms.|[0044] The terms “alkoxy,” “alkylamino” and “alkylthio” (or thioalkoxy) are used in their conventional sense, and refer to those alkyl groups attached to the remainder of the molecule via an oxygen atom, an amino group, or a sulfur atom, respectively.|[0045] The terms “aryloxy” and “heteroaryloxy” are used in their conventional sense, and refer to those aryl or heteroaryl groups attached to the remainder of the molecule via an oxygen atom.|[0046] The term “heteroalkyl,” by itself or in combination with another term, means, unless otherwise stated, a stable straight or branched chain, or cyclic hydrocarbon radical, or combinations thereof, consisting of the stated number of carbon atoms and at least one heteroatom selected from the group consisting of O, N, Si and S, and wherein the nitrogen and sulfur atoms may optionally be oxidized and the nitrogen heteroatom may optionally be quaternized. The heteroatom(s) O, N and S and Si may be placed at any interior position of the heteroalkyl group or at the position at which the alkyl group is attached to the remainder of the molecule. Examples include, but are not limited to, —CH2—CH2—O—CH3, —CH2—CH2—NH—CH3, —CH2—CH2—N(CH3)—CH3, —CH2—S—CH2—CH3, —CH2—CH2, —S(O)—CH3, —CH2—CH2—S(O)2—CH3, —CH═CH—O—CH3, —Si(CH3)3, —CH2—CH═N—OCH3, and —CH═CH—N(CH3)—CH3. Up to two heteroatoms may be consecutive, such as, for example, —CH2—NH—OCH3 and —CH2—O—Si(CH3)3. Similarly, the term “heteroalkylene” by itself or as part of another substituent means a divalent radical derived from heteroalkyl, as exemplified, but not limited by, —CH2—CH2—S—CH2—CH2— and —CH2—S—CH2—CH2—NH—CH2—. For heteroalkylene groups, heteroatoms can also occupy either or both of the chain termini (e.g., alkyleneoxy, alkylenedioxy, alkyleneamino, alkylenediamino, and the like). Still further, for alkylene and heteroalkylene linking groups, no orientation of the linking group is implied by the direction in which the formula of the linking group is written. For example, the formula —CO2R′— represents both —C(O)OR′ and —OC(O)R′.|[0047] The terms “cycloalkyl” and “heterocycloalkyl,” by themselves or in combination with other terms, represent, unless otherwise stated, cyclic versions of “alkyl” and “heteroalkyl”, respectively. Additionally, for heterocycloalkyl, a heteroatom can occupy the position at which the heterocycle is attached to the remainder of the molecule. Examples of cycloalkyl include, but are not limited to, cyclopentyl, cyclohexyl, 1-cyclohexenyl, 3-cyclohexenyl, cycloheptyl, and the like. Further exemplary cycloalkyl groups include steroids, e.g., cholesterol and its derivatives. Examples of heterocycloalkyl include, but are not limited to, 1-(1,2,5,6-tetrahydropyridyl), 1-piperidinyl, 2-piperidinyl, 3-piperidinyl, 4-morpholinyl, 3-morpholinyl, tetrahydrofuran-2-yl, tetrahydrofuran-3-yl, tetrahydrothien-2-yl, tetrahydrothien-3-yl, 1-piperazinyl, 2-piperazinyl, and the like.|[0048] The terms “halo” or “halogen,” by themselves or as part of another substituent, mean, unless otherwise stated, a fluorine, chlorine, bromine, or iodine atom. Additionally, terms such as “haloalkyl,” are meant to include monohaloalkyl and polyhaloalkyl. For example, the term “halo(C1-C4)alkyl” is mean to include, but not be limited to, trifluoromethyl, 2,2,2-trifluoroethyl, 4-chlorobutyl, 3-bromopropyl, and the like.|[0049] The term “aryl” means, unless otherwise stated, a polyunsaturated, aromatic, substituent that can be a single ring or multiple rings (preferably from 1 to 3 rings), which are fused together or linked covalently. The term “heteroaryl” refers to aryl substituent groups (or rings) that contain from one to four heteroatoms selected from N, O, S, Si and B, wherein the nitrogen and sulfur atoms are optionally oxidized, and the nitrogen atom(s) are optionally quaternized. An exemplary heteroaryl group is a six-membered azine, e.g., pyridinyl, diazinyl and triazinyl. A heteroaryl group can be attached to the remainder of the molecule through a heteroatom. Non-limiting examples of aryl and heteroaryl groups include phenyl, 1-naphthyl, 2-naphthyl, 4-biphenyl, 1-pyrrolyl, 2-pyrrolyl, 3-pyrrolyl, 3-pyrazolyl, 2-imidazolyl, 4-imidazolyl, pyrazinyl, 2-oxazolyl, 4-oxazolyl, 2-phenyl-4-oxazolyl, 5-oxazolyl, 3-isoxazolyl, 4-isoxazolyl, 5-isoxazolyl, 2-thiazolyl, 4-thiazolyl, 5-thiazolyl, 2-furyl, 3-furyl, 2-thienyl, 3-thienyl, 2-pyridyl, 3-pyridyl, 4-pyridyl, 2-pyrimidyl, 4-pyrimidyl, 5-benzothiazolyl, purinyl, 2-benzimidazolyl, 5-indolyl, 1-isoquinolyl, 5-isoquinolyl, 2-quinoxalinyl, 5-quinoxalinyl, 3-quinolyl, and 6-quinolyl. Substituents for each of the above noted aryl and heteroaryl ring systems are selected from the group of acceptable substituents described below.|[0050] For brevity, the term “aryl” when used in combination with other terms (e.g., aryloxy, arylthioxy, arylalkyl) includes aryl, heteroaryl and heteroarene rings as defined above. Thus, the term “arylalkyl” is meant to include those radicals in which an aryl group is attached to an alkyl group (e.g., benzyl, phenethyl, pyridylmethyl and the like) including those alkyl groups in which a carbon atom (e.g., a methylene group) has been replaced by, for example, an oxygen atom (e.g., phenoxymethyl, 2-pyridyloxymethyl, 3-(1-naphthyloxy)propyl, and the like).|[0051] Each of the above terms (e.g., “alkyl,” “heteroalkyl,” “aryl, and “heteroaryl”) are meant to optionally include both substituted and unsubstituted forms of the indicated species. Exemplary substituents for these species are provided below.|[0052] Substituents for the alkyl and heteroalkyl radicals (including those groups often referred to as alkylene, alkenyl, heteroalkylene, heteroalkenyl, alkynyl, cycloalkyl, heterocycloalkyl, cycloalkenyl, and heterocycloalkenyl) are generically referred to as “alkyl group substituents,” and they can be one or more of a variety of groups selected from, but not limited to: H, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, —OR′, ═O, ═NR′, ═N—OR′, —NR′R″, —SR′, halogen, —SiR′R″R″′, —OC(O)R′, —C(O)R′, —CO2R′, —CONR′R″, —OC(O)NR′R″, —NR″C(O)R′, —NR′—C(O)NR″R″′, —NR″C(O)2R′, —NR—C(NR′R″R′″)═NR″″, —NR—C(NR′R″)═NR, —S(O)R′, —S(O)2R′, —S(O)2NR′R″, —NRSO2R′, —CN and —NO2 in a number ranging from zero to (2m′+1), where m′ is the total number of carbon atoms in such radical. R′, R″, R′″ and R″″ each preferably independently refer to hydrogen, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, e.g., aryl substituted with 1-3 halogens, substituted or unsubstituted alkyl, alkoxy or thioalkoxy groups, or arylalkyl groups. When a compound of the invention includes more than one R group, for example, each of the R groups is independently selected as are each R′, R″, R′″ and R″″ groups when more than one of these groups is present. When R′ and R″ are attached to the same nitrogen atom, they can be combined with the nitrogen atom to form a 5-, 6-, or 7-membered ring. For example, —NR′R″ is meant to include, but not be limited to, 1-pyrrolidinyl and 4-morpholinyl. From the above discussion of substituents, one of skill in the art will understand that the term “alkyl” is meant to include groups including carbon atoms bound to groups other than hydrogen groups, such as haloalkyl (e.g., —CF3 and —CH2CF3) and acyl (e.g., —C(O)CH3, —C(O)CF3, —C(O)CH2OCH3, and the like). These terms encompass groups considered exemplary “alkyl group substituents,” which are components of exemplary “substituted alkyl” and “substituted heteroalkyl” moieties.|[0053] Similar to the substituents described for the alkyl radical, substituents for the aryl heteroaryl and heteroarene groups are generically referred to as “aryl group substituents.” The substituents are selected from, for example: groups attached to the heteroaryl or heteroarene nucleus through carbon or a heteroatom (e.g., P, N, O, S, Si, or B) including, without limitation, substituted or unsubstituted alkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, —OR′, ═O, ═NR′, ═N—OR′, —NR′R″, —SR′, -halogen, —SiR′R″R′″, —OC(O)R′, —C(O)R′, —CO2R′, —CONR′R″, —OC(O)NR′R″, —NR″C(O)R′, —NR′—C(O)NR″R′″, —NR″C(O)2R′, —NR—C(NR′R″R′″)═NR″″, —NR—C(NR′R″)═NR′″, —S(O)R′, —S(O)2R′, —S(O)2NR′R″, —NRSO2R′, —CN and —NO2, —R′, —N3, —CH(Ph)2, fluoro(C1-C4)alkoxy, and fluoro(C1-C4)alkyl, in a number ranging from zero to the total number of open valences on the aromatic ring system. Each of the above-named groups is attached to the heteroarene or heteroaryl nucleus directly or through a heteroatom (e.g., P, N, O, S, Si, or B); and where R′, R″, R′″ and R″″ are preferably independently selected from hydrogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl and substituted or unsubstituted heteroaryl. When a compound of the invention includes more than one R group, for example, each of the R groups is independently selected as are each R′, R″, R′″ and R″″ groups when more than one of these groups is present.|[0054] Two of the substituents on adjacent atoms of the aryl, heteroarene or heteroaryl ring may optionally be replaced with a substituent of the formula T-C(O)—(CRR′)q—U—, wherein T and U are independently —NR—, —O—, —CRR′— or a single bond, and q is an integer of from 0 to 3. Alternatively, two of the substituents on adjacent atoms of the aryl or heteroaryl ring may optionally be replaced with a substituent of the formula -A-(CH2)r—B—, wherein A and B are independently —CRR′—, —O—, —NR—, —S—, —S(O)—, —S(O)2—, —S(O)2NR′— or a single bond, and r is an integer of from 1 to 4. One of the single bonds of the new ring so formed may optionally be replaced with a double bond. Alternatively, two of the substituents on adjacent atoms of the aryl, heteroarene or heteroaryl ring may optionally be replaced with a substituent of the formula —(CRR′)s—X—(CR″R′″)d—, where s and d are independently integers of from 0 to 3, and X is —O—, —NR′—, —S—, —S(O)—, —S(O)2—, or —S(O)2NR′—. The substituents R, R′, R″ and R′″ are preferably independently selected from hydrogen or substituted or unsubstituted (C1-C6) alkyl. These terms encompass groups considered exemplary “aryl group substituents”, which are components of exemplary “substituted aryl” “substituted heteroarene” and “substituted heteroaryl” moieties.|[0055] As used herein, the term “acyl” describes a substituent containing a carbonyl residue, C(O)R. Exemplary species for R include H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, and substituted or unsubstituted heterocycloalkyl.|[0056] As used herein, the term “fused ring system” means at least two rings, wherein each ring has at least 2 atoms in common with another ring. “Fused ring systems may include aromatic as well as non-aromatic rings. Examples of “fused ring systems” are naphthalenes, indoles, quinolines, chromenes and the like.|[0057] As used herein, the term “heteroatom” includes oxygen (O), nitrogen (N), sulfur (S) and silicon (Si), boron (B) and phosphorous (P).|[0058] The symbol “R” is a general abbreviation that represents a substituent group that is selected from H, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, and substituted or unsubstituted heterocycloalkyl groups.|[0059] The compounds disclosed herein may also contain unnatural proportions of atomic isotopes at one or more of the atoms that constitute such compounds. For example, the compounds may be radiolabeled with radioactive isotopes, such as for example tritium (3H), iodine-125 (125I) or carbon-14 (14C). All isotopic variations of the compounds of the present invention, whether radioactive or not, are intended to be encompassed within the scope of the present invention.|[0060] The term “salt(s)” includes salts of the compounds prepared by the neutralization of acids or bases, depending on the particular ligands or substituents found on the compounds described herein. When compounds of the present invention contain relatively acidic functionalities, base addition salts can be obtained by contacting the neutral form of such compounds with a sufficient amount of the desired base, either neat or in a suitable inert solvent. Examples of base addition salts include sodium, potassium calcium, ammonium, organic amino, or magnesium salt, or a similar salt. Examples of acid addition salts include those derived from inorganic acids like hydrochloric, hydrobromic, nitric, carbonic, monohydrogencarbonic, phosphoric, monohydrogenphosphoric, dihydrogenphosphoric, sulfuric, monohydrogensulfuric, hydriodic, or phosphorous acids, and the like, as well as the salts derived from relatively nontoxic organic acids like acetic, propionic, isobutyric, butyric, maleic, malic, malonic, benzoic, succinic, suberic, fumaric, lactic, mandelic, phthalic, benzenesulfonic, p-tolylsulfonic, citric, tartaric, methanesulfonic, and the like. Certain specific compounds of the present invention contain both basic and acidic functionalities that allow the compounds to be converted into either base or acid addition salts. Hydrates of the salts are also included.|[0061] “—COOH” as this term is used refers to is meant to optionally include —C(O)O− and —C(O)O−X+, wherein X+ is a cationic counter-ion. Likewise, a substituent having the formula N(R)(R) is meant to optionally include —N+H(R)(R) and —N+H(R)(R)Y−, wherein Y− represents an anionic counter-ion. Exemplary polymers of the invention include a protonated carboxylic moiety (COOH). Exemplary polymers of the invention include a deprotonated carboxylic moiety (COO−). Various polymers of the invention include both a protonated carboxylic moiety and a deprotonated carboxylic moiety.|[0062] It is understood that, in any compound described herein having one or more chiral centers, if an absolute stereochemistry is not expressly indicated, then each center may independently be of R-configuration or S-configuration or a mixture thereof. Thus, the compounds provided herein may be enantiomerically pure or be stereoisomeric mixtures. In addition it is understood that, in any compound described herein having one or more double bond(s) generating geometrical isomers that can be defined as E or Z, each double bond may independently be E or Z a mixture thereof. Likewise, it is understood that, in any compound described, all tautomeric forms are also intended to be included.|[0063] Below are examples of specific embodiments of the present disclosure. The examples are offered for illustrative purposes only, and are not intended to limit the scope of the present invention in any way.|III. Compositions|[0064] One aspect of the present disclosure provides an adsorption material comprising a metal-organic framework. The metal-organic framework comprises (i) a plurality of divalent cations and (ii) a plurality of polytopic organic linkers. The adsorption material further comprises a plurality of polyamine ligands. In some embodiments, the adsorption material has a polyamine ligand:metal-organic framework divalent cation loading ratio of 0.3 or less to 1 (e.g. 0.25 to 1, meaning one polyamine ligand per four metal sites), 0.4 or less to 1 (e.g., 0.35 to 1), 0.5 or less to 1 (e.g. 0.45 to 1), 0.6 or less to 1 (e.g. 0.50 to 1 meaning one polyamine ligand per two metal sites), (0.7 or less to 1 (e.g. 0.6 to 1), 0.7 or less to 1 (e.g. 0.65 to 1), (0.8 or less to 1 (e.g. 0.75 to 1 meaning three polyamine ligands per four metal sites), or (0.9 or less to 1 (e.g. 0.85 to 1). In some embodiments, the polyamine ligand:metal-organic framework divalent cation loading ratio is some other ratio not referenced above. Each respective polyamine ligand in the plurality of polyamine ligands comprises:|In this formula, X1 and X2 are respective first and second divalent cations in the plurality of divalent cations (e.g., Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn). Further, Y is:|and Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium. The values i, j, k, x, y, and z are each independently 0, 1, or 2, while m is 2, 3, or 4. Each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, or substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy.|[0067] In some embodiments, at least twenty percent, in at least forty percent, in at least sixty percent, in at least eighty percent, or at least ninety-eight percent of the plurality of polyamine ligands are each (i) amine appended by a first amine of the respective polyamine ligand to a first divalent cation in the plurality of divalent cations and (ii) amine appended by a second amine of the respective polyamine ligand to a second divalent cation in the plurality of divalent cations of the metal-organic framework|[0068] In some embodiments, Y is:|and (a) i and j are each zero, (b) i is one and j is zero, (c) i is one and j is one, or (d) i is one and j is two.|[0070] An example of such embodiments where i is one and j is zero is:|In the case of N-(2-Aminoethyl)-1,3-propanediamine, Z1, Z2, Z3, Q1 and Q2 are each carbon, i is one, j is zero, and R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11 and R12 are each hydrogen.|[0072] Alternatively, in some embodiments, Y is:|and k and x are zero, and m is two or three. An example of such embodiments is:|In the case of triethylenetetraamine, Z1, Z2, Z4, Q1 and Q2 are each carbon, k is zero, x is zero, R1, R2, R3, R4, R5, R6, R7, R8, R9, and R10, are each hydrogen, each instance of the two instances of R13 and R14 is hydrogen, and m is two.|[0075] Alternatively, in some embodiments, Y is:|k and x are each one, and m is two, three or four.|An example of such embodiments is:|In the case of N,N′-bis(3-aminopropyl)-1,3-propanediamine, Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each carbon, k is one, x is one, R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R15, and R16 are each hydrogen, each instance of the three instances of R13 and R14 is hydrogen, and m is three. Another example of such embodiments is:|In the case of N,N′-bis(3-aminopropyl)-1,4-diaminobutane, Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each carbon, k is one, x is one, R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R15, and R16 are each hydrogen, each instance of the four instances of R13 and R14 is hydrogen, and m is four.|[0079] In some embodiments, Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon. In some embodiments, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, and R15 is independently H, halogen, substituted or unsubstituted n-alkyl or a substituted or unsubstituted branched-chain alkyl. In some such embodiments, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, and R15 is H.|[0080] In some embodiments, the polytopic organic linker is 4,4′-dioxidobiphenyl-3,3′-dicarboxylate (dobpdc4−), 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate (dotpdc4−), 2,5-dioxidobenzene-1,4-dicarboxylate (dobdc4−), or 3,3′ dioxide-biphenyl-4,4′-dicarboxylate (para-carboxylate-dobpdc4−).|[0081] In some embodiments, each polyamine ligand in the plurality of polyamine ligands is: triethylenetetraamine, N,N′-bis(3-aminopropyl)-1,3-propanediamine (referred to herein as “3-3-3”), N,N′-bis(3-aminopropyl)-1,4-diaminobutane (referred to herein as “3-4-3”).|[0082] By way of example, the polyamine ligands can be|[0083] |[0084] In some embodiments, the loading of the plurality of polyamine ligands to the metal-organic framework is between 5 percent and 500 percent, 20 percent and 250 percent, 25 percent and 200 percent, 80 percent and 120 percent, between 90 percent and 110 percent, between 95 percent and 105 percent, or between 98 percent and 102 percent.|[0085] In some embodiments, the adsorption material exhibits a step-shaped CO2 adsorption profile. In some embodiments, the adsorption material exhibits a step-shaped CO2 desorption profile. In some embodiments, the adsorption material exhibits a single step-shaped CO2 adsorption profile. In some embodiments, the adsorption material exhibits a single step-shaped CO2 desorption profile.|[0086] In some embodiments, the polytopic organic linker is an analog of (dobpdc4−), having the formula:|where R17, R18, R19, R20, R21, and R22, are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl.|[0088] In some embodiments, the polytopic organic linker is an analog of (dotpdc4−) having the formula:|where R17, R18, R19, R20, R21, R22, R23, R24, R25, and R26, are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl.|[0090] In some embodiments, the polytopic organic linker is an analog of (pc-dobpdc4−) having the formula:|where R17, R18, R19, R20, R21, and R22, are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl.|[0092] In some embodiments, the polytopic organic linker has the formula:|where R17, R18, R19, R21, R22, and R23 are each independently selected from H, halogen, hydroxyl, methyl, and halogen substituted methyl, and R20 is selected from substituted or unsubstituted aryl, and substituted or unsubstituted heteroaryl.|IV. Synthetic Methods|[0094] Another aspect of the present disclosure provides a method of synthesizing an adsorption material in which a plurality of polyamine ligands is grafted onto a metal-organic framework. The metal-organic framework comprises a plurality of divalent cations and a plurality of polytopic organic linkers. The grafting comprises exposing an amount of the metal-organic framework to a solution comprising the polyamine ligand diluted with a solvent thereby forming an unactivated adsorption material.|[0095] In some embodiments, adsorption material is prepared by a method in which the metal-organic framework is optionally first heated (e.g. at 160° C. under vacuum condition or under flowing N2 or Ar for 12 hours), removing adsorbed water and coordinated water or other coordinating solvents. Then the metal-organic framework is dissolved in a solution comprising anhydrous organic solvent charged with the polyamine thereby forming unactivated adsorption material. In some embodiments, the solution is 20% (v/v) polyamine to anhydrous organic solvent. In some embodiments, the solution is between 10% (v/v) and 40% (v/v) polyamine to anhydrous organic solvent. In some embodiments the polyamine is dissolved into the anhydrous organic solvent on an equivalent (w/v) basis rather than a (v/v) basis. In some embodiments, the resulting product is dried for three hours or more under nitrogen protection.|[0096] In some embodiments, each polyamine ligand has the formula:|and where Y is:|Z1, Z2, Z3, Z4, Z5, Q1 and Q2 are each independently carbon, silicon, germanium, sulfur, or selenium, i, j, k, x, y, and z are each independently 0, 1, or 2, and m is 2, 3, or 4. Further, each instance of each R1, R2, R3, R4, R5, R6, R7, R8, R9, R10, R11, R12, R13, R14, R15, and R16 is independently H, halogen, substituted or unsubstituted alkyl, substituted or unsubstituted heteroalkyl, substituted or unsubstituted aryl, substituted or unsubstituted heteroaryl, substituted or unsubstituted heterocycloalkyl, substituted or unsubstituted alkoxy, substituted or unsubstituted aryloxy, or substituted or unsubstituted heteroaryloxy.|[0099] In some embodiments, the unactivated adsorption material is subjected to an inert stream of gas at a temperature of at least 165° C. thereby activating the adsorption material.|[0100] In some alternative embodiments, the unactivated adsorption material is washed with a weakly coordinating or non-coordinating solvent at a temperature of between 60° C. and 80° C. at least 165° C. thereby activating the adsorption material. Representative and non-limiting examples of weakly coordinating or non-coordinating solvents can include toluene, chlorobenzene, paraffins, halogenated paraffins, and the like, as well as combinations thereof.|[0101] In some alternative embodiments, the unactivated adsorption material is placed under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material.|[0102] In some alternative embodiments, the unactivated adsorption material is subjected to one or more cycles of (i) an inert stream of gas at a temperature of at least 165° C. followed by (ii) placement under a vacuum at a temperature of greater than 60° C. thereby activating the adsorption material.|[0103] In some alternative embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles, in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle, thereby activating the adsorption material.|[0104] In some alternative embodiments, the unactivated adsorption material is subjected to a plurality of evacuate-refill cycles under elevated temperatures, such as greater than 60° C., in which an inert gas such as argon or nitrogen, or mixtures thereof is used in the refill cycle thereby activating the adsorption material.|[0105] In some embodiments, the adsorption material is characterized as activated when it has a polyamine ligand loading of 120 percent or less. In some embodiments, each divalent cation in the plurality of divalent cations is Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, or Zn.|[0106] In some embodiments, the solvent is anhydrous. In some embodiments, the solvent is toluene. In some embodiments, the solvent is toluene, methanol, dichloromethane, tetrahydrofuran, cyclohexane, pentane, 2-butanone, trichloroethylene, methyl-t-butyl ether, heptane, diethyl ether, or a mixture thereof. In some embodiments, the inert stream of gas is an argon or nitrogen gas, or a mixture thereof.|[0107] In the disclosed methods, the unactivated adsorption material from the wet impregnation method is then subjected to an inert environment at a temperature of at least 165° C. thereby activating the adsorption material. In some such embodiments, the activated adsorption material has a polyamine ligand loading of 120 percent or less. In some embodiments, the activated adsorption material has a polyamine ligand loading of 110 percent or less. In some embodiments, the unactivated adsorption material from the wet impregnation method is subjected to an inert environment at a temperature of at least 190° C., at least 210° C., or between 190° C. and 250° C.|[0108] In some embodiments, the unactivated adsorption material is subjected to the inert environment at the temperature of at least 165° C. for at least four hours, for at least six hours, for at least eight hours, or at least twelve hours, thereby activating the adsorption material.|V. Technical Applications|[0109] In one aspect of the present disclosure, there is provided a number of technical applications for the disclosed adsorption materials.|[0110] One such application is carbon capture from powerplant exhaust, such as coal flue gas. The increasing atmospheric levels of carbon dioxide (CO2), which are likely contributing to global climate change, warrant new strategies for reducing CO2 emissions from point sources such as power plants. In particular, coal-fueled power plants are responsible for 46% of global anthropogenic energy supply CO2 emissions. See, “CO2 Emissions From Fuel Combustion Highlights,” 2016 Edition, International Energy Agency, Paris, France, which is hereby incorporated by reference. Thus, there remains a continuing need for the development of new adsorbents for carbon capture from coal flue gas, a gas stream consisting of CO2 (15-16%), O2 (3-4%), H2O (5-7%), N2 (70-75%), and trace impurities (e.g. SO2, NOx) at ambient pressure and 40° C. See, Planas et al., 2013, “The Mechanism of Carbon Dioxide Adsorption in an Alkylamine-Functionalized Metal-Organic Framework,” J. Am. Chem. Soc. 135, pp. 7402-7405, which is hereby incorporated by reference. In particular, for a temperature swing adsorption process, an adsorbent should possess the following properties: (a) a high working capacity with a minimal temperature swing, in order to minimize regeneration energy costs; (b) high selectivity for CO2 over the other constituents of coal flue gas; (c) 90% capture of CO2 under flue gas conditions; (d) effective performance under humid conditions; and (d) long-term stability to adsorption/desorption cycling under humid conditions.|[0111] Another such application is carbon capture from a biogas such as crude biogas, natural gas, or landfill gas. Biogas, for instance the CO2/CH4 mixtures produced by the breakdown of organic matter, is a renewable fuel source with the potential to replace traditional fossil fuel sources. Removal of CO2 from crude biogas mixtures is one of the most challenging aspects of upgrading this promising fuel source to pipeline quality methane. Therefore, for example, the use of adsorbents to selectively remove CO2 from high pressure CO2/CH4 mixtures with a high working capacity and minimal regeneration energy has the potential to greatly reduce the cost of using biogas in place of natural gas for applications in the energy sector. Some embodiments of the present disclosure provide a method that comprises contacting a biogas, natural gas, landfill gas, or non-renewable gas comprising CO2 and CH4 with any adsorption material of the present disclosure to reversibly adsorb CO2 from the gas thereby generating an adsorption material enriched for CO2 and a residual gas that is greater than 80 percent pure methane, 90 percent pure methane, or 98 percent pure methane. In some such embodiments, the method further comprises stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0112] The disclosed compositions (adsorption materials) can be used to strip a major portion of the CO2 from the adsorption material enriched for CO2 using a temperature swing adsorption method or a vacuum swing adsorption method. Example temperature swing adsorption methods and vacuum swing adsorption methods are disclosed in International Publication Number WO2013/059527 A1, which is hereby incorporated by reference.|[0113] Another aspect of the present disclosure provides a method for abating CO2 from a flue gas, such as natural gas flue gas. In such embodiments, the flue gas is contacted with any adsorption material of the present disclosure to reversibly adsorb CO2 from the flue gas thereby generating an adsorption material enriched for CO2 and then stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0114] Another other aspect of the present disclosure provides air capture methods in which excess CO2 in the atmosphere is reduced in order to address CO2 contribution from mobile sources such as automobile and airplane emissions for abating CO2 from a flue gas, such as natural gas flue gas. In some such embodiments, atmospheric air is contacted with any adsorption material of the present disclosure to reversibly adsorb CO2 from the air thereby generating an adsorption material enriched for CO2 and then stripping a major portion of the CO2 from the adsorption material enriched for CO2 using a using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0115] Still another aspect of the present disclosure provides a method of sequestering carbon dioxide produced by a source. The method comprises exposing the carbon dioxide to an adsorption material of the present disclosure whereby the carbon dioxide is reversibly sequestered into the adsorption material. In some such embodiments, the method further comprises regenerating the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0116] Still another aspect of the present disclosure provides a method of sequestering carbon dioxide from a multi-component gas mixture. In some such embodiments the multi-component gas mixture comprises CO2 and at least one of N2, H2O, and O2. The method comprises exposing the multi-component gas mixture to an adsorption material of the present disclosure whereby a least fifty percent, at least sixty percent, or at least eighty percent of the carbon dioxide within the multi-component gas mixture is reversibly sequestered into the adsorption material. In some such embodiments, the method further comprises regenerating the adsorption material enriched for CO2 using a temperature swing adsorption method, vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|[0117] Another aspect of the present disclosure provides a method of capturing CO2 emissions using a combination of the tetraamine functionalized materials disclosed herein with known CO2 capture technologies such as liquid absorbents in process configurations such as those disclosed in Feron, P. et al., “Towards Zero Emissions from Fossil Fuel Power Stations”, International Journal of Greenhouse Gas Control 87 (2019) 188-902, hereby incorporated by reference, and separation processes, such as cryogenics, which involve the separation and the simultaneous solidification of CO2 from a gaseous mixture. See U.S. Pat. No. 2,011,550 to Hasche.|VI. Examples|Synthesis of Tetraamine-Appended Mg2(dobpdc)|[0118] The following procedure was used for each tetraamine analogue, 3-4-3 and 3-3-3. A 20 mL scintillation vial was charged with a 20% v/v solution of amine in toluene. Separately, approximately 20 mg of methanol-solvated Mg2(dobpdc) was filtered from the methanol mother liquor and washed with toluene (3 x 10 mL). After the toluene washes and subsequent drying on the filter for 2 min under vacuum, Mg2(dobpdc) was added to the tetraamine solution and the vial was left at room temperature for 24 h (60° C. for 24 h in the case of 3-4-3). After soaking, the mixture was filtered and washed with toluene (3 x 10 mL). Tetraamine-appended Mg2(dobpdc) was recovered as an off-white powder after 2 minutes of drying on the filter. To achieve desired 1:2 tetraamine:metal ratio, the as-synthesized material was then heated at 225° C. (for 3-3-3) while under flowing N2 for 1 h.|[0119] FIG. 1 illustrates a structure of the metal-organic framework Mg2(dobpdc) (dobpdc4−=4,4′-dioxidobiphenyl-3,3′-dicarboxylate) (panel A) and appending alkylpropylenetetraamines to the open Mg2+ sites of the framework (panel B) to yield adsorbents displaying step-shaped adsorption of CO2.|[0120] FIG. 2 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”)-Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated air (400 ppm CO2) at temperatures below 60° C.|[0121] FIG. 3 depicts the CO2 isobar showing how the N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”)-Mg2(dobpdc) MOF can capture ˜16 wt. % CO2 from simulated NGCC flue gas (4% CO2) at temperatures below 110° C.|[0122] FIG. 4 illustrates the two-step adsorption profile for Mg2(dobpdc) tetraaamine MOF variants: N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) (“3-3-3”) (single-step); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine) (“3-4-3”); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine) (“3-2-3”); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine) (“2-3-2”); and N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine) (“2-2-2”).|CONCLUSION|[0123] It is understood that the examples and embodiments described herein are for illustrative purposes only and that various modifications or changes in light thereof will be suggested to persons skilled in the art and are to be included within the spirit and purview of this application and scope of the appended claims. All publications, patents, and patent applications cited herein are hereby incorporated by reference in their entirety for all purposes. | Family Number|(98625271)|98625271|Advantages / Prev. Drawbacks|(WO202232281 A1)|DAC is has shown to be very expensive while BECCS requires large areas of arable land competing with agriculture at the same time as the world's population is increasing. [0007] As such, there is a need for adsorbents which are specific to CO2 and maximize CO2 capture. 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date=2025-09-08|Event code=CA/D15|Event group=Examination events|EXAMINATION REPORT COMPLETED|ST27 STATUS EVENT CODE: A-2-2-D10-D15-D126 (AS PROVIDED BY THE NATIONAL OFFICE)|Event text: EXAMINER'S REPORT|Effective date of the event=2025-09-08|Event publication date=2026-01-08|Event code=CA/B12|Event indicator=Neg|Event group=Event indicating Not In Force|APPLICATION DEEMED TO BE WITHDRAWN, ABANDONED OR LAPSED|ST27 STATUS EVENT CODE: N-2-6-B10-B12-B303 (AS PROVIDED BY THE NATIONAL OFFICE)|Event text: DEEMED ABANDONED - FAILURE TO RESPOND TO AN EXAMINER'S REQUISITION|Effective date of the event=2026-01-08 | (EP4192602)|Contracting States: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, LI, RO, NL, TR|(EP4192602)|Extension States: ME, BA|(EP4192602)|Validation States: MA, MD, TN, KH|(WO2022/032281)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2022/032281)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2022/032281)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2022/032281)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2022/032281)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, ME, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4192602)|EP|(US11872537)|US|(WO2022/032281)|CN; EP; KR; SG|(CN116367909)|CN|(SG11202300715P)|SG|(KR10-2023-0037038)|KR | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=VCVyqWEeIcAAZXHLlSSqg6Ca4vFyxJplNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000021672828&ekey=2346&xpn=EP4192602&kind=A1 | https://register.epo.org/application?number=EP21759000 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=9koaUmyZYH6seLHW8WjXjnfDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (US11872537)|US|(US20220040668)|US|(WO2022/032281)|US | (US11872537)|NAME=EXXONMOBIL TECHNOLOGY AND ENGINEERING COMPANY , CITY=Annandale , STATE=NJ , COUNTRY=US , ATYP=US Company|(US20220040668)|NAME=ExxonMobil Research and Engineering Company , CITY=Annandale , STATE=NJ , COUNTRY=US|(WO2022/032281)|NAME=EXXONMOBIL RESEARCH AND ENGINEERING COMPANY 1545 Route 22 East, P.O. Box 900 Annandale, NJ 08801-0900 , COUNTRY=US | (EP4192602)|BE||(WO2022/032281)|US||||(AU2021320985)|AU|(AU2021320985)|AU||(CA3187852)|CA | (EP4192602)|NAME=ExxonMobil Chemical Europe Inc.;IP Law Europe Hermeslaan 2 , CITY=1831 Machelen , COUNTRY=BE , REG=101482725|(US11872537)|NAME=SHOOK, HARDY & BACON L.L.P.|(WO2022/032281)|NAME=NEGRON, Liza et al. ExxonMobil Research and Engineering Company 1545 Route 22 East P.O. Box 900 Annandale, NJ 08801-0900 , POSTCODE=08801-0900 , COUNTRY=US|(JP2023537482)|NAME=YAMAO, Norihito et al. , REG=100145403NAME=Shikimi Masayuki , REG=100221501|(CN116367909)|NAME=ZHANG RONGJUN;ZHONGZI LAW OFFICE , REG=11247NAME=LIN BONAN;ZHONGZI LAW OFFICE , REG=11247|(SG11202300715P)|NAME=Amica Law LLC , REG=200601697N|(AU2021320985)|NAME=ALLENS PATENT & TRADE MARK ATTORNEYS Deutsche Bank Place Corner Hunter and Phillip Streets , CITY=SYDNEY , STATE=NSW , POSTCODE=2000 , COUNTRY=AU|(AU2021320985)|NAME=ALLENS PATENT & TRADE MARK ATTORNEYS Deutsche Bank Place Corner Hunter and Phillip Streets , CITY=SYDNEY , STATE=NSW , POSTCODE=2000 , COUNTRY=AU|(KR10-2023-0037038)|NAME=FIRSTLAW P.C.|(CA3187852)|NAME=BORDEN LADNER GERVAIS LLP , COUNTRY=CA | (EP4192602)|US|(US11872537)|US|(US20220040668)|US|(WO2022/032281)|US|||(SG11202300715P)|US||||(CA3187852)|US | (EP4192602)|NAME=WESTON, Simon, C., CITY=Annandale, NJ 08801, COUNTRY=US|(US11872537)|NAME=Weston Simon C., CITY=Annandale, STATE=NJ , COUNTRY=US|(US20220040668)|NAME=Weston Simon C., CITY=Annandale, STATE=NJ , COUNTRY=US|(WO2022/032281)|NAME=WESTON, Simon, C. 68 Sidney School Road Annandale, NJ 08801, POSTCODE=08801, COUNTRY=US|(JP2023537482)|NAME=Weston, Simon Sea|(CN116367909)|NAME=WESTON SIMON C|(SG11202300715P)|NAME=WESTON Simon C 68 SIDNEY SCHOOL ROAD ANNANDALE, NJ 08801, COUNTRY=US|(AU2021320985)|NAME=WESTON, Simon C.|(AU2021320985)|NAME=WESTON, Simon C.|(KR10-2023-0037038)|NAME=WESTON SIMON C.|(CA3187852)|NAME=WESTON, SIMON C., COUNTRY=US | (US11872537)|4|(WO2022/032281)|4|(JP2023537482)|4|(CN116367909)|4||(KR10-2023-0037038)|4|(CA3187852)|4 | 3 | 9 | (EP4192602)|WO2022/032281|(JP2023537482)|WO2022/032281|(CN116367909)|WO2022/032281|(SG11202300715P)|WO2022/032281|(AU2021320985)|WO2022/032281|(KR10-2023-0037038)|WO2022/032281|(CA3187852)|WO2022/032281 | (US11872537)|Number of Claims: NCL=15|Number of Drawings: NDR=4|Number of Figures: NFG=4|Independent Claim Number: ICL=1,14|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1|Extended under 35 USC 154(b) the following days: EXTD=84|Primary examiner: Pregler Sharon|Art Unit.: ART =1772||(US20220040668)|Number of Claims: NCL=15|Number of Drawings: NDR=4|Number of Figures: NFG=4|Independent Claim Number: ICL=1,14|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1|Primary examiner: Pregler Sharon|Art Unit.: ART =1772||(WO2022/032281)|Number of Claims: NCL=15|Extended kind: EXTK=x||(JP2023537482)|Number of Claims: NCL=15|Request for examination: REQEXA=true||(CN116367909)|Number of Claims: NCL=15|Gazette date: GAZDATE=2023-06-30|Gazette number: GAZNUM=39-2602|Substantial examination effective date: 20230718|Number of Pages: NPAGES=26||(SG11202300715P)|Number of Claims: NCL=15||(AU2021320985)|Number of Claims: NCL=15||(KR10-2023-0037038)|Number of Claims: NCL=15||(CA3187852)|Number of Claims: NCL=15| | (US11872537)|Provisional Appl: US63/062,034 FDD=2020-08-06 [2020US-63062034]|Previous publication: US20220040668 A1 2022-02-10 [US20220040668] | (EP4192602)|ENGLISH (ENG) | (US11872537)|Patent|(JP2023537482)|Patent|(CN116367909)|Patent|(EP4192602)|Patent|(SG11202300715P)|Patent|(AU2021320985)|Patent|(KR20230037038)|Patent|(AU2021320985)|Patent|(CA3187852)|Patent|(US20220040668)|Patent|(WO202232281)|Patent | Titre: (EP4192602)|Metal-organic frameworks for carbon dioxide capture Résumé: (EP4192602)|The present application relates to absorbents comprising tetraainine ligands grafted onto metal-organic frameworks and a method for using same for CO2 capture from fossil fuel combustion sources to reduce emissions. In particular, this application relates to capturing > 90% by volume, preferable > 99% by volume, CO2 emissions such that the emissions are negative, essentially removing CO2 from the combustion air. Autre: (US11872537)|The invention claimed is:|1. A method for reducing carbon dioxide emissions, the method comprising:| (a) contacting a flue gas from a source with a carbon dioxide adsorbing material to reversibly adsorb CO2 from the flue gas thereby generating an adsorption material enriched for CO2;| (b) reducing the concentration of CO2 from the flue gas to less than 15,000 ppmv; and,| (c) stripping a portion of the CO2 from the adsorption material enriched for CO2 using a regeneration process,| wherein the carbon dioxide adsorbing material comprises a tetraamine functionalized metal organic framework.|2. The method of claim 1, wherein the tetraamine functionalized metal organic framework comprises a plurality of divalent cations and a plurality of polytopic organic linkers.|3. The method of claim 2, wherein each divalent cation in the plurality of divalent cations is Mg, Ca, Mn, Cr, Fe, Co, Ni, Cu, Zn or a combination thereof.|4. The method of claim 3 wherein the divalent cation in the plurality of divalent cations is Mg.|5. The method of claim 2, wherein the plurality of polytopic organic linkers comprise 4,4′-dioxidobiphenyl-3,3′-dicarboxylate (dobpdc4−), 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate (dotpdc4−), 2,5-dioxidobenzene-1,4-dicarboxylate (dobdc4−), or 3,3′ dioxide-biphenyl-4,4′-dicarboxylate (para-carboxylate-dobpdc4−).|6. The method of claim 2, wherein the tetraamine functionalized metal organic framework comprises N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine); or N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine).|7. The method of claim 6, wherein the tetraamine functionalized metal organic framework comprises N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine) or N,N-(butane-1,4-diyl)bis(propane-1,3-diamine).|8. The method of claim 1, wherein the source is a natural gas combined cycle (NGCC) power plant and CO2 in the flue gas is reduced to a concentration of less than 2,000 ppmv.|9. The method of claim 8, wherein CO2 in the flue gas is reduced to concentration of less than 400 ppmv.|10. The method of claim 1, wherein the concentration of CO2 from the flue gas is reduced to less than 10,000 ppmv.|11. The method of claim 1, wherein the concentration of CO2 from the flue gas is reduced to less than 4,000 ppmv.|12. The method of claim 1, wherein the regeneration process comprises a temperature swing adsorption method, a vacuum swing adsorption method, a pressure swing adsorption method, a concentration swing adsorption method, or a combination thereof.|13. The method of claim 1, wherein the regeneration process comprises applying steam to the adsorption material enriched for CO2 thereby reactivating the adsorption material.|14. A method for CO2 direct air capture, the method comprising:| contacting air with a carbon dioxide adsorption material to reversibly adsorb CO2 from the air thereby generating an adsorption material enriched for CO2 and reducing CO2 concentrations to less than 400 ppmv,| wherein the carbon dioxide adsorbing material comprises a tetraamine functionalized metal organic framework.|15. The method of claim 14, wherein the tetraamine functionalized metal organic framework comprises a plurality of polytopic organic linkers comprising 4,4′-dioxidobiphenyl-3,3′-dicarboxylate (dotpdc4−), 4,4″-dioxido-[1,1′:4′,1″-terphenyl]-3,3″-dicarboxylate (dotpdc4−), 2,5-bioxidobenzene-1,4dicarboxylate (dobdc4−), or 3,3′ dioxide-biphenyl-4,4′-dicarboxylate (para-carboxylate-dobpdc4−) and the tetraamine functionalized metal organic framework further comprises N,N′-(propane-1,3-diyl)bis(propane-1,3-diamine); N,N′-(butane-1,4-diyl)bis(propane-1,3-diamine); N,N′-(ethane-1,2-diyl)bis(propane-1,3-diamine); N,N′-(propane-1,3-diyl)bis(ethane-1,2-diamine); or N,N′-(ethane-1,2-diyl)bis(ethane-1,2-diamine) and wherein CO2 in the flue gas is reduced to concentration of less than 400 ppmv. | 26 | Abstract | gpt-4o-mini | no | The article focuses on CO2 capture from fossil fuel combustion sources, which does not align with the topic of BECCS that specifically involves biomass. | ||||||||||||||
| 25 | US62/865,708P|US17/621,752|US63/043,038P|WOUS2020/039265 | WOUS2020/039265|EP20832919|US17/621,752|CN202080058319|AU2020307562 | EP3986597|US20220347650|EP3986597|CN114390943|AU2020307562|WO2020/263910 | 92128920 | WO2020/263910 A1 2020-12-30 [WO2020263910]|EP3986597 A4 2023-07-19 [EP3986597]|EP3986597 A1 2022-04-27 [EP3986597]|US20220347650 A1 2022-11-03 [US20220347650]|CN114390943 A 2022-04-22 [CN114390943]|AU2020307562 A1 2022-02-03 [AU2020307562] | 2019-06-24|2020-06-23|2020-06-24 | 2020-06-24|2020-06-24|2020-06-24|2020-06-24|2020-06-24 | 2023-07-19|2022-11-03|2022-04-27|2022-04-22|2022-02-03|2020-12-30 | (EP3986597)|2040-06-24|(US20220347650)|2040-06-24|(WO2020/263910)|2022-12-24|(CN114390943)|2040-06-24|(AU2020307562)|2026-01-22 | (EP3986597)|Systems and methods for enhanced weathering and calcining for c02 removal from air | (EP3986597)|A plurality of carbonation plots are positioned in communication with atmospheric carbon dioxide to facilitate sequestration thereof via ambient weathering. The carbonation plots include a composition rich in metal oxides, which are positioned within the environment, such as on non-arable land, and exposed to the environment to react with carbon dioxide in the air and form metal carbonates. After about one year of exposure, the composition is recollected and calcined to produce a carbon dioxide stream and replenish the metal oxides, which can be redistributed in the carbonation plots to sequester additional carbon dioxide. The systems and methods of the present disclosure enable capture and redistribution of carbon dioxide for industrial-scale uses for very abundant quarry minerals and enable large-scale low-cost carbon capture projects for municipalities or corporations. C02 removal from air via these methods and systems have a similar or lower cost than C02 removal using DAC with synthetic sorbents or solvents. | COLUMBIA UNIVERSITY|UNIVERSITY OF BRITISH COLUMBIA|UNIVERSITY OF PENNSYLVANIA | (EP3986597)|The Trustees of Columbia University in the City of New York|(EP3986597)|The Trustees of Columbia University in the City of New York ([US])|(US20220347650)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK ([US])|(WO2020/263910)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK ([US])|(CN114390943)|UNIV COLUMBIA ([US])|(AU2020307562)|The Trustees of Columbia University in the City of New York | KELEMEN PETER|WILCOX JENNIFER|MCQUEEN NOAH|DIPPLE GREG|RENFORTH PHIL | (EP3986597)|KELEMEN, Peter|WILCOX, Jennifer|MCQUEEN, Noah|DIPPLE, Greg|RENFORTH, Phil|(EP3986597)|KELEMEN, Peter|WILCOX, Jennifer|MCQUEEN, Noah|DIPPLE, Greg|RENFORTH, Phil | (EP3986597)|Barker Brettell LLP;100 Hagley Road ([GB])|Reg. Nb: 101716225|(WO2020/263910)|GANGEMI, Anthony, P. ([US])|(CN114390943)|DONG QING;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC|Reg. Nb: 31100|LE HONGYONG;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC|Reg. Nb: 31100|(AU2020307562)|Spruson & Ferguson ([AU]) | (US20220347650)|The main energy demand of the process is for calcination which depends on calcining temperature.|The methods and systems of the present disclosure are advantageous in that they offer a less expensive route than other current and proposed techniques to remove CO2 from air. The systems and methods of the present disclosure enable capture and redistribution of "net-zero" carbon dioxide for industrial-scale uses for very abundant quarry minerals and enable large-scale low-cost carbon capture projects for municipalities or corporations.|Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS) and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|The method for CO2 removal from air is also less costly than the projected, future minimum cost for CDR machines.|These solutions are frequently expensive, with optimistic minimum cost predictions of $100/ton CO2 produced, and occasionally employ designer materials that may be difficult to produce.| | (US20220347650)|1 . A system utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising: at least one carbonation plot including a composition including one or more metal oxides, the at least one carbonation plot positioned to expose the composition to ambient weathering; a feedstock source including a feedstock, wherein at least a portion of the one or more metal oxides is derived from the feedstock; a preprocessing system in communication with the feedstock source, the preprocessing system configured to reduce the feedstock to a desired particle size; a calciner configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature; and a composition recycling system to transport composition to the calciner and return calcined composition to the at least one carbonation plots, wherein the system is configured to maintain exposure of the composition to ambient weathering for a year.|8 . A method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising: providing a composition including one or more metal oxides; distributing the composition into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering; capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition; calcining the ambiently weathered composition to generate a calcined composition and a CO2 stream; and distributing the calcined composition into the plurality of carbonation plots.|20 . A method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising: providing a source of feedstock; processing the feedstock to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2; providing the processed feedstock to a network of carbonation plots configured to expose the processed feedstock to ambient weathering; stirring a contents of the carbonation plots; capturing atmospheric CO2 via the one or more metal oxides for about 1 year to produce an ambiently weathered composition; calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C. to generate a CO2 stream and regenerate metal oxides as a calcined composition; and distributing the calcined composition into the plurality of carbonation plots, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof, and the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof.| | (US20220347650)|Some embodiments of the present disclosure are directed to a method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including providing a composition including one or more metal oxides; distributing the composition into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering; capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition; calcining the ambiently weathered composition to generate a calcined composition and a CO2 stream; and distributing the calcined composition into the plurality of carbonation plots.|Some embodiments of the present disclosure are directed to a method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including providing a source of feedstock; processing the feedstock to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2; providing the processed feedstock to a network of carbonation plots configured to expose the processed feedstock to ambient weathering; stirring a contents of the carbonation plots; capturing atmospheric CO2 via the one or more metal oxides for about 1 year to produce an ambiently weathered composition; calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C. to generate a CO2 stream and regenerate metal oxides as a calcined composition; and distributing the calcined composition into the plurality of carbonation plots.|Some embodiments of the present disclosure are directed to a system utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including at least one carbonation plot including a composition including one or more metal oxides, the at least one carbonation plot positioned to expose the composition to ambient weathering; a feedstock source including a feedstock, wherein at least a portion of the one or more metal oxides is derived from the feedstock; a preprocessing system in communication with the feedstock source, the preprocessing system configured to reduce the feedstock to a desired particle size; a calciner configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature; and a composition recycling system to transport composition to the calciner and return calcined composition to the at least one carbonation plots.| | (US20220347650)|CO2(100,41)|AMBIENT WEATHERING(100,25)|CARBON DIOXIDE(100,20)|AIR(100,15)|ALKALINITY(100,14)|CALCINATION(100,11)|CO2 REMOVAL(100,8)|ENHANCED WEATHERING(100,2)|ABUNDANT QUARRY MINERAL(99,2)|CARBONATION RANDOM ACCESS(87,69)|FEEDSTOCK(80,46)|CAPTURING ATMOSPHERIC CO2(75,5)|FEEDSTOCK PROCESSING(69,10)|OCEAN CO2 UPTAKE(69,1)|CARBONATION PLOT(65,9)|TERRESTRIAL BIOSPHERE(64,1)|CO2 STREAM(63,15)|QUARRY MINERAL(59,2)|FUTURE CO2 EMISSION(50,1)|PREPROCESSING(49,12)|GLOBAL RELIANCE(45,1)|CO2 UPTAKE(42,1)|COMPOSITION RECYCLING(41,5)|CALCINER(38,24)|FEEDSTOCK SOURCE(37,10)|NATURAL ACCELERATION(37,1)|CARBONATION RANDOM ACCESS NETWORK(36,4)|CARBONATION RANDOM ACCESS CONTENT(36,3)|MUNICIPALITY(36,2)|CARBONATION(35,12)|OPTIMISTIC MINIMUM(34,1)|NONARABLE LAND(33,2)|CARBON CAPTURE PROJECT(31,2)|FEEDSTOCK CALCINATION(30,3)|SERPENTINITE(29,10)|WOLLASTONITE(29,9)|PORTFOLIO(29,1)|PERIDOTITE(28,9)|PYROXENE(28,9)|REDISTRIBUTION(27,1)|METAL OXIDE(26,46)|MAGNESITE(26,16)|BRUCITE(26,10)|OLIVINE(26,10)|DOLOMITE(26,9)|SYNTHETIC SORBENT(26,2)|CALCITE(25,9)|DUNITE(25,9)|CDR MACHINE(25,2)|BIOENERGY(25,1)|CALCINING TEMPERATURE(25,1)|PHYSIOLOGICAL CARBONATE(23,3)|CARBON DIOXIDE REDISTRIBUTION(23,1)|ATMOSPHERIC CO2(21,9)|FOREST(21,1)|BECCS(20,1)|FUTURE MINIMUM COST(20,1)|REGENERATE METAL OXIDE(19,4)|FOSSIL FUEL(19,1)|GLOBAL MAGNESITE RESERVE(18,3)|MAXIMIZE METAL OXIDE(18,3)|INDUSTRIAL SCALE(18,2)|ATMOSPHERIC CARBON DIOXIDE(18,1)|SODIUM CARBONATE(17,9)|MGO(15,25)|CARBON DIOXIDE STREAM(15,1)|CO2 MITIGATION DIVERSE PORTFOLIO(15,1)|OXY FIRED CALCINER(14,5)|MAGNESITE FEEDSTOCK(14,3)|DESIGNER MATERIAL(14,1)|ENERGY DEMAND(14,1)|LESS EXPENSIVE ROUTE(14,1)|SOLAR ELECTRICITY SCENARIO(13,2)|LEGALLY PRODUCIBLE MAGNESITE(13,1)|GRID ELECTRICITY(12,6)|MINERAL(12,4)|ELECTRICITY TRICITY(11,1)|RANDOM ACCESS(10,7)|GLOBAL RESERVE(10,3)|FUTURE OPTIMISTIC PREDICTION(10,1)|CARBON CAPTURE(9,3)|CO2 EMISSION(9,3)|REACTION RATE(9,3)|CARBONATION CO2 UPTAKE CAPACITY(9,1)|MINERAL DISSOLUTION KINETICS(9,1)|POSTPROCESSING(8,4)|CALCINATION PLANT(8,2)|GT CO2 YEAR(8,2)|OXY FIRED CALCINATION(8,2)|SEQUESTERING CO2(8,2)|AUTHORITATIVE ORGANIZATION(8,1)|FUTURE SOLAR ELECTRICITY(8,1)|GASOLINE RECOLLECTION EQUIPMENT(8,1)|GEOLOGICAL SEQUESTRATION(8,1)|MAGNESITE CALCINATION REACTION(8,1)|SURFICIAL WEATHERING(8,1)|AVERAGE PARTICLE SIZE(7,8)|NET ZERO(7,3)|CARBON MINERALIZATION(7,2)|ELECTRICITY ASSUMPTION(7,2)|FEEDSTOCK STREAM(7,2)|MAGNESITE SUPPLY(7,2)|MAKEUP 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MG(3,1)|ANALYSIS LOOK(3,1)|BETRANSFORMATION(3,1)|CALCINING CONDITION(3,1)|CAO DECREASE REACTION CAPACITY(3,1)|CARBONATE FORMATION(3,1)|CARBONATED PRODUCT(3,1)|CARBONATION COMBINATION(3,1)|CARBONATIONLAND(3,1)|CEILING TREATMENT(3,1)|CENTRAL CALCINATION(3,1)|CYCLE PROGRESS(3,1)|ENERGY INVESTMENT(3,1)|FUTURE MINIMUM(3,1)|GEOLOGIC TIMESCALE(3,1)|GEOLOGICAL TIMESCALE(3,1)|GRINDING ENERGY(3,1)|INDUSTRIAL SCALE INITIATIVE(3,1)|INSTRUMENTALITY(3,1)|ISOLATION TARGET(3,1)|MAGNESIUM ADSORBENT CAPACITY LOSS(3,1)|MAXIMIZE EXPOSURE(3,1)|MINERAL CHARGE(3,1)|PLANT EQUIPMENT(3,1)|PRETREATMENT CALCINATION(3,1)|RAW ORE(3,1)|RELEVANT EQUIPMENT(3,1)|REPORTED MINE EMISSION VALUE(3,1)|SCALING FACTOR(3,1)|SOLAR ENERGY CALCINER(3,1)|SUPPLEMENT SUPPLY(3,1)|WEATHERINGFOR(3,1)|PRODUCT STREAM(2,3)|AMORPHOUS SOLID MGO RESIDUE(2,1)||(AU2020307562)|CO2(100,43)|CARBON DIOXIDE(100,20)|AIR(100,15)|ALKALINITY(100,14)|CALCINATION(100,10)|ENHANCED WEATHERING(100,2)|CARBONATION PLOT(99,67)|AMBIENT WEATHERING(52,25)|FEEDSTOCK(42,46)|CAPTURING ATMOSPHERIC CO2(40,5)|CARBONATION PLOT NETWORK(40,4)|CARBONATION PLOT CONTENT(40,3)|FEEDSTOCK PROCESSING(36,10)|OCEAN CO2 UPTAKE(36,1)|TERRESTRIAL BIOSPHERE(34,1)|CO2 STREAM(33,15)|ABUNDANT QUARRY MINERAL(33,1)|PREPROCESSING(26,12)|FUTURE CO2 EMISSION(26,1)|CARBONATION(24,23)|GLOBAL RELIANCE(24,1)|CO2 UPTAKE(22,1)|COMPOSITION RECYCLING(21,5)|CALCINER(20,24)|FEEDSTOCK SOURCE(19,10)|NATURAL ACCELERATION(19,1)|OPTIMISTIC MINIMUM(18,1)|NONARABLE LAND(17,2)|SERPENTINITE(15,10)|PERIDOTITE(15,9)|PYROXENE(15,9)|WOLLASTONITE(15,9)|FEEDSTOCK CALCINATION(15,3)|PORTFOLIO(15,1)|MAGNESITE(14,16)|SYNTHETIC SORBENT(14,2)|METAL OXIDE(13,47)|BRUCITE(13,10)|OLIVINE(13,10)|CALCITE(13,9)|DOLOMITE(13,9)|DUNITE(13,9)|BIOENERGY(13,1)|CARBON DIOXIDE REDISTRIBUTION(12,1)|MUNICIPALITY(12,1)|ATMOSPHERIC CO2(11,9)|PLOT(11,8)|BECCS(11,1)|FOREST(11,1)|REGENERATE METAL OXIDE(10,4)|CARBON CAPTURE PROJECT(10,1)|FOSSIL FUEL(10,1)|GLOBAL MAGNESITE RESERVE(9,3)|MAXIMIZE METAL OXIDE(9,3)|ATMOSPHERIC CARBON DIOXIDE(9,1)|MGO(8,23)|SODIUM CARBONATE(8,9)|CARBON DIOXIDE STREAM(8,1)|CDR(8,1)|CO2 MITIGATION DIVERSE PORTFOLIO(8,1)|OXY FIRED CALCINER(7,5)|MAGNESITE FEEDSTOCK(7,3)|SOLAR ELECTRICITY SCENARIO(7,2)|DESIGNER MATERIAL(7,1)|LEGALLY PRODUCIBLE MAGNESITE(7,1)|LESS EXPENSIVE ROUTE(7,1)|MINERAL(6,4)|CARBON CAPTURE(5,3)|GLOBAL RESERVE(5,3)|REACTION RATE(5,3)|FUTURE OPTIMISTIC PREDICTION(5,1)|GRID ELECTRICITY SOLAR ELECTRICITY(5,1)|PCT US(5,1)|POSTPROCESSING(4,4)|CO2 EMISSION(4,3)|FLUE GAS(4,3)|CALCINATION PLANT(4,2)|GALLON TCO(4,2)|OXY FIRED CALCINATION(4,2)|SEQUESTERING CO2(4,2)|AUTHORITATIVE ORGANIZATION(4,1)|CARBONATION CO2 UPTAKE CAPACITY(4,1)|CARBONATION PLOT ORIENTATION(4,1)|CAUSTIC MAGNESIA PARTICLE(4,1)|CLUSTERED CARBONATION(4,1)|FUTURE SOLAR ELECTRICITY(4,1)|GEOLOGICAL SEQUESTRATION(4,1)|MAGNESITE CALCINATION REACTION(4,1)|MINERAL DISSOLUTION KINETICS(4,1)|SURFICIAL WEATHERING(4,1)|AVERAGE PARTICLE SIZE(3,8)|CO2 REMOVAL(3,5)|KG CO2(3,5)|MTMGCO(3,5)|PREPROCESSOR(3,4)|OUTLET STREAM(3,3)|AQUEOUS CALCIUM LOOPING(3,2)|CARBON MINERALIZATION(3,2)|CDR MACHINE(3,2)|CO2 NET COST(3,2)|ELECTRICITY ASSUMPTION(3,2)|FEEDSTOCK STREAM(3,2)|MAGNESITE SUPPLY(3,2)|MAKEUP MINERAL(3,2)|MAXIMIZE EXPOSURE(3,2)|TON CO2(3,2)|AGRICULTURAL SOILS(3,1)|AMORPHOUS MG3SI(3,1)|CALCINATION RESIDUE(3,1)|CALCINED CARBONATE MINERAL(3,1)|CALCINING FEEDSTOCK(3,1)|CALCIUM CAUSTIC RECOVERY LOOP(3,1)|CALCIUM SORBENT(3,1)|CAO TON(3,1)|CARBONATION FACILITY(3,1)|CAUSTIC MGO(3,1)|CO2 DISSOLUTION(3,1)|CO2 TON(3,1)|DISTRIBUTING CAO(3,1)|ELECTRICITY EMISSION(3,1)|EXTRASYSTEMIC EFFLUENT STREAM(3,1)|GASOLINE RECOLLECTION EQUIPMENT(3,1)|GENERALIZED CALCINATION REACTION(3,1)|GENERALIZED NATURAL WEATHERING REACTION(3,1)|GLOBAL MAGNESITE PRODUCTION(3,1)|GRIND FEEDSTOCK(3,1)|JOINT CARBONATION(3,1)|KJ MOLL(3,1)|KOH SORBENT(3,1)|MAGNESIUM ADSORBENT(3,1)|MG PERIODIC REPLACEMENT(3,1)|MGCO3 FEEDSTOCK(3,1)|MGO CALCINATION(3,1)|MGO REACTIVITY(3,1)|MGO REUSE(3,1)|MINERAL BRUCITE(3,1)|MINERAL CARBONATION REACTION(3,1)|MINERAL RECOLLECTION(3,1)|MINING CONVEYER(3,1)|MINING EMISSION(3,1)|NONCONTIGUOUS PLOT(3,1)|OPTIMIZATION STRATEGY(3,1)|PLANT ECONOMIC LIFETIME(3,1)|REGENERATE MGO(3,1)|REPLACEMENT MAGNESITE(3,1)|ROCK MINE TAILING(3,1)|SHUTDOWN EXPENSE(3,1)|SOLAR CALCINER(3,1)|SOLAR ELECTRICITY PROJECTED COST(3,1)|SOLAR ELECTRICITY YIELD(3,1)|SOLAR SCENARIO(3,1)|TARGET COMPOUND SEQUESTRATION(3,1)|UNREACTED MGO(3,1)|UTILITY SOLAR ELECTRICITY(3,1)|UTILITY SOLAR PLANT(3,1)|WORLDWIDE MAGNESITE PRODUCTION(3,1)|CAPITAL EXPENDITURE(2,6)|CACO3(2,5)|DESIRED PARTICLE SIZE(2,4)|GTCO(2,4)|CARBONATION PLOT NUMBER(2,3)|CO2 SEQUESTRATION(2,3)|ACCOUNTING(2,2)|AMERICAN PHYSICAL SOCIETY(2,2)|ARABLE LAND(2,2)|BYPRODUCT(2,2)|CAPTURE COST(2,2)|CONE CRUSHER(2,2)|DAC(2,2)|DEACTIVATION(2,2)|DIRECT AIR CAPTURE(2,2)|GREENHOUSE(2,2)|GTMGCO(2,2)|MG CONVERSION(2,2)|PRECALCINATION(2,2)|SEA(2,2)|SINTERING(2,2)|AQUEOUS BRUCITE REACTION(2,1)|AVOIDING STARTUP(2,1)|CALCINATION CYCLE(2,1)|CALCINATION LOAD(2,1)|CALCINATION TEMPERATURE(2,1)|CALCINING CONDITION(2,1)|CALCINING REACTION(2,1)|CARBONATION PRODUCT(2,1)|CENTRAL CALCINATION EQUIPMENT(2,1)|COLLECT CO2(2,1)|COSTING(2,1)|DECARBONATION HEAT(2,1)|DEPOSIT LIME(2,1)|ELECTRIC CONVEYER(2,1)|ELECTRIC FIRED CALCINER(2,1)|ELECTRICITY STIRRING EQUIPMENT(2,1)|ENERGY INVESTMENT(2,1)|ENERGY RESOURCE SCENARIO(2,1)|FUTURE COST PROJECTION(2,1)|GEOLOGIC TIMESCALE(2,1)|GEOLOGICAL TIMESCALE(2,1)|GI CO2(2,1)|GRINDING ENERGY(2,1)|GT CO2(2,1)|GT MGCO3(2,1)|INDUSTRIAL SCALE INITIATIVE(2,1)|INSTRUMENTALITY(2,1)|LAND PRICE AVAILABILITY(2,1)|MAGNESITE GLOBAL PRODUCTION(2,1)|MAJOR CONTRIBUTION(2,1)|MAXIMUM CARBONATION CAPACITY(2,1)|MG LOSS(2,1)|MGCO3 LOSS(2,1)|MGO LAST(2,1)|MINERAL ACQUISITION(2,1)|MINERAL CHARGE(2,1)|MOL CO2(2,1)|OCEANIC PH(2,1)|PLANET REGION(2,1)|PLANT LIFETIME(2,1)|PREPREPROCESSING(2,1)|PREPROCESSING CALCINATION(2,1)|RENEWED FORMATION(2,1)|SEQUESTERING ATMOSPHERIC CO2(2,1)|SIZING EQUIPMENT(2,1)|SOLID MGO RESIDUE(2,1)|SPHERICAL GRAIN(2,1)|SUPPLYING MAKEUP(2,1)|TILLAGE EQUIPMENT(2,1)|WATER REACTIVITY(2,1)|MECO(1,3)|AQUEOUS POTASSIUM HYDROXIDE(1,1)| | (US20220347650)|What is claimed is:|1. A system utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising:| at least one carbonation plot including a composition including one or more metal oxides, the at least one carbonation plot positioned to expose the composition to ambient weathering;| a feedstock source including a feedstock, wherein at least a portion of the one or more metal oxides is derived from the feedstock;| a preprocessing system in communication with the feedstock source, the preprocessing system configured to reduce the feedstock to a desired particle size;| a calciner configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature; and| a composition recycling system to transport composition to the calciner and return calcined composition to the at least one carbonation plots,| wherein the system is configured to maintain exposure of the composition to ambient weathering for a year.|2. The system according to claim 1, wherein the system includes greater than about 5 carbonation plots.|3. The system according to claim 2, wherein the system includes greater than about 3,500 carbonation plots.|4. The system according to claim 1, wherein the at least one carbonation plot includes greater than about 20,000 tons of metal oxides available for ambient weathering.|5. The system according to claim 1, wherein the average particle size of the composition is about 20 μm.|6. The system according to claim 1, wherein the composition is included in the carbonation plot as a layer, wherein the layer has a thickness of about 0.1 m.|7. The system according to claim 1, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof.|8. A method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising:| providing a composition including one or more metal oxides;| distributing the composition into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering;| capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition;| calcining the ambiently weathered composition to generate a calcined composition and a CO2 stream; and| distributing the calcined composition into the plurality of carbonation plots.|9. The method according to claim 8, further comprising stirring the composition within the plurality of carbonation plots.|10. The method according to claim 8, wherein capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition includes:| recollecting the composition as the ambiently weathered composition after about 1 year of exposure to the atmosphere.|11. The method according to claim 8, wherein the composition is at least in part composed of processed feedstock, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof.|12. The method according to claim 11, wherein providing a composition includes:| grinding the feedstock to an average particle size of about 20 μm.|13. The method according to claim 12, wherein providing a composition includes:| calcining the feedstock to produce an additional CO2 stream and a calcined feedstock including the one or more metal oxides.|14. The method according to claim 8, wherein calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes:| calcining the ambiently weathered composition for a duration between about 30 minutes and about 2 hours.|15. The method according to claim 8, wherein calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes:| calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C.|16. The method according to claim 8, wherein the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof.|17. The method according to claim 8, wherein the plurality of carbonation plots includes greater than about 5 carbonation plots.|18. The method according to claim 8, wherein the plurality of carbonation plots includes greater than about 20,000 tons of metal oxides available for ambient weathering.|19. The method according to claim 8, wherein the composition is distributed in the plurality of carbonation plots as a layer, wherein the layer has a thickness of about 0.1 m.|20. A method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising:| providing a source of feedstock;| processing the feedstock to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2;| providing the processed feedstock to a network of carbonation plots configured to expose the processed feedstock to ambient weathering;| stirring a contents of the carbonation plots;| capturing atmospheric CO2 via the one or more metal oxides for about 1 year to produce an ambiently weathered composition;| calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C. to generate a CO2 stream and regenerate metal oxides as a calcined composition; and| distributing the calcined composition into the plurality of carbonation plots,| wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof, and the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. | (US20220347650)|CROSS REFERENCE TO RELATED APPLICATION(S)|[0001] This application is a national stage patent application filing of International Application No. PCT/US2020/039265, filed Jun. 24, 2020, which claims the benefit of U.S. Provisional Application No. 62/865,708, filed Jun. 24, 2019, and 63/043,038, filed Jun. 23, 2020, which are incorporated by reference as if disclosed herein in their entireties.|(US20220347650)|BACKGROUND|[0002] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS) and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. Prior to the deployment of these technologies, it is important to develop an understanding of the cost and potential environmental impact.|[0003] The contribution of carbon dioxide to global warming is well-documented. Recently, carbon capture methods have been developed for point-of-release carbon capture, e.g., at the smokestack. Previous approaches involved CO2 capture from flue gas and other concentrated sources, in smokestacks or reactors, on time scales of minutes to days. Prior systems also often rely on faster reaction times and higher energy investments, e.g., application of high heat and/or pressure. These solutions are frequently expensive, with optimistic minimum cost predictions of $100/ton CO2 produced, and occasionally employ designer materials that may be difficult to produce.|[0004] As discussed above, the Intergovernmental Panel on Climate Change, and other authoritative organizations, have determined that CO2 removal from air (CDR) is necessary to hold global warming to less than 2° C. CDR is far more difficult than CO2 capture from flue gas. Current technology involves “direct air capture” machines (DAC) that remove CO2 from air at a cost of $600/ton CO2.|[0005] Enhanced weathering was first proposed by Walter Seifritz in 1990 and is based on the process of natural weathering. In natural weathering, alkalinity-containing minerals are carbonated on geologic timescales (millions of years). The generalized natural weathering reaction is described below:|MeO+CO2→MeCO3+Energy|where Me represents a divalent metal cation. Typical cations include magnesium (Mg′) and calcium (Ca2+), where suitable feedstocks include minerals, such as olivine and serpentine, as well as industrial byproducts, such as mine tailings and fly ash. Since the natural weathering reaction occurs on geological timescales, many researchers have explored various process conditions, pretreatment methods, extraction mechanisms and optimization strategies to expedite the process kinetics as a form of CO2 sequestration.|[0006] In addition to natural weathering, calcination is a process by which carbonates are heated to decompose into metal oxides and CO2. The generalized calcination reaction is shown below:|MeCO3+Energy→MeO+CO2 |Similar systems proposing CO2 removal using carbonation reactions have been discussed in previous literature. The American Physical Society, in a 2011 study, evaluated a system where CO2 is absorbed by sodium hydroxide (NaOH) and subsequently reacted with calcium hydroxide (Ca(OH)2) to produce solid calcium carbonate (CaCO3). The CaCO3 is then calcined in an oxy-fired calciner to release the CO2. Other proposed solutions include a continuous looping process including an aqueous potassium hydroxide (KOH) sorbent coupled with a calcium caustic recovery loop. The KOH sorbent reacts with CO2 in the air to produce potassium carbonate (K2CO3). The K2CO3 then reacts with Ca(OH)2, produced from CaCO3, to reproduce the KOH and CaCO3. These types of aqueous calcium looping systems have been primarily evaluated using calcium-based sorbents in aqueous conditions (in the form of Ca(OH)2). Additionally, proposed ocean liming processes deposit lime (produced from calcined carbonate minerals) into the ocean to react with carbonic acid currently in the ocean. This process increases oceanic pH and leads to the dissolution of more CO2 into the ocean water, reducing the atmospheric concentration of CO2. Additional systems utilizing mineral carbonation reactions have looked at various forms of carbon mineralization as a method to capture CO2 from more concentrated point sources, such as power plants.|SUMMARY|[0007] Some embodiments of the present disclosure are directed to a system utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including at least one carbonation plot including a composition including one or more metal oxides, the at least one carbonation plot positioned to expose the composition to ambient weathering; a feedstock source including a feedstock, wherein at least a portion of the one or more metal oxides is derived from the feedstock; a preprocessing system in communication with the feedstock source, the preprocessing system configured to reduce the feedstock to a desired particle size; a calciner configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature; and a composition recycling system to transport composition to the calciner and return calcined composition to the at least one carbonation plots.|[0008] In some embodiments, the system is configured to maintain exposure of the composition to ambient weathering for a year. In some embodiments, the system includes greater than about 5 carbonation plots. In some embodiments, the system includes greater than about 3,500 carbonation plots. In some embodiments, the at least one carbonation plot includes greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the average particle size of the composition is about 20 μm. In some embodiments, the composition is included in the carbonation plot as a layer, wherein the layer has a thickness of about 0.1 m. In some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof.|[0009] Some embodiments of the present disclosure are directed to a method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including providing a composition including one or more metal oxides; distributing the composition into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering; capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition; calcining the ambiently weathered composition to generate a calcined composition and a CO2 stream; and distributing the calcined composition into the plurality of carbonation plots. In some embodiments, the method includes stirring the composition within the plurality of carbonation plots.|[0010] In some embodiments, the composition is at least in part composed of processed feedstock, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. In some embodiments, the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. In some embodiments, the plurality of carbonation plots includes greater than about 5 carbonation plots. In some embodiments, the plurality of carbonation plots includes greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the composition is distributed in the plurality of carbonation plots as a layer, wherein the layer has a thickness of about 0.1 m.|[0011] In some embodiments, capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition includes recollecting the composition as the ambiently weathered composition after about 1 year of exposure to the atmosphere.|[0012] In some embodiments, providing a composition includes grinding the feedstock to an average particle size of about 20 μm. In some embodiments, providing a composition includes calcining the feedstock to produce an additional CO2 stream and a calcined feedstock including the one or more metal oxides.|[0013] In some embodiments, calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes calcining the ambiently weathered composition for a duration between about 30 minutes and about 2 hours. In some embodiments, calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C.|[0014] Some embodiments of the present disclosure are directed to a method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including providing a source of feedstock; processing the feedstock to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2; providing the processed feedstock to a network of carbonation plots configured to expose the processed feedstock to ambient weathering; stirring a contents of the carbonation plots; capturing atmospheric CO2 via the one or more metal oxides for about 1 year to produce an ambiently weathered composition; calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C. to generate a CO2 stream and regenerate metal oxides as a calcined composition; and distributing the calcined composition into the plurality of carbonation plots. In some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof, and the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof.|(US20220347650)|BRIEF DESCRIPTION OF THE DRAWINGS|[0015] The drawings show embodiments of the disclosed subject matter for the purpose of illustrating the invention. However, it should be understood that the present application is not limited to the precise arrangements and instrumentalities shown in the drawings, wherein:|[0016] FIG. 1 is a schematic representation of a system utilizing alkalinity to sequester carbon dioxide according to some embodiments of the present disclosure;|[0017] FIG. 2 is a schematic representation of a system utilizing alkalinity to sequester carbon dioxide according to some embodiments of the present disclosure;|[0018] FIG. 3 is a chart of a method for utilizing alkalinity to sequester carbon dioxide from the atmosphere according to some embodiments of the present disclosure; and|[0019] FIG. 4 is a chart of a method for utilizing alkalinity to sequester carbon dioxide from the atmosphere according to some embodiments of the present disclosure.|(US20220347650)|DESCRIPTION|[0020] Referring now to FIG. 1, aspects of the disclosed subject matter include a system 100 utilizing alkalinity to sequester a target compound, e.g., carbon dioxide (CO2). In some embodiments, system 100 sequesters the target compound directly from the atmosphere. In some embodiments, system 100 sequesters the target compound directly from the atmosphere via reaction of the target compound with a composition in the system. In some embodiments, the reaction is a carbonation reaction.|[0021] In some embodiments, system 100 sequesters CO2 directly from the atmosphere. In these embodiments, sequestering of CO2 by system 100 contributes to an overall reduction in atmospheric CO2 concentration. In some embodiments, system 100 sequesters CO2 from one or more extra-systemic effluent streams, e.g., evolved from industrial processes outside of or independent from system 100. In some embodiments, energy for operating components of system 100 can be provided via any suitable source, grid electricity, solar electricity, combustion of one or more fuels, e.g., to power an oxy-fired system component, etc., or combinations thereof.|[0022] In some embodiments, system 100 includes at least one carbonation plot 102. In some embodiments, system 100 includes a plurality of carbonation plots 102. “Carbonation plot,” as used herein, includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots 102 include a composition that sequesters a target compound, e.g., CO2. In some embodiments, the carbonation plots 102 are positioned and configured to expose the composition to ambient weathering. In some embodiments, the environment in which the ambient weathering occurs, e.g., the location and orientation of carbonation plots 102, is configured to maximize the temperature at the surface of the composition. As used herein, the term “ambient weathering” is used to refer to the sequestration of a target compound, e.g., CO2, directly from the atmosphere at substantially ambient temperature and substantially atmospheric pressure. In some embodiments, carbonation plots 102 are positioned in the environment, e.g., on grasslands, deserts, mountainsides, etc. In some embodiments, carbonation plots 102 are clustered into a group. In these embodiments, and as will be discussed in greater detail below, the clustered carbonation plots 102 enable centralized implementation of other system components for more efficient operation of the overall system. In some embodiments, carbonation plots 102 are clustered in a plurality of separate groups. In some embodiments, a plurality of carbonation plot groups are distributed throughout a region of the planet, e.g., non-arable land in the Western United States. In some embodiments, a plurality of carbonation plot groups are distributed throughout the planet. In some embodiments, system 100 includes a sufficient number of carbonation plots 102 to hold a sufficient amount of the composition to sequester a desired amount of target compound, e.g., CO2. In some embodiments, system 100 includes more than about 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 1,500, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, or 10,000 carbonation plots 102. In some embodiments, system 100 includes greater than about 5 carbonation plots. In some embodiments, system 100 includes greater than about 3,500 carbonation plots.|[0023] In some embodiments, the composition includes one or more metal oxides. In some embodiments, the one or more metal oxides include MgO, CaO, Na2O, or combinations thereof. The composition may also include filler material, e.g., materials that do not actively react with the target compound, reacted metal oxides, e.g., metal carbonates, silicates, etc., and other materials without departing from the scope of the invention. In some embodiments, carbonation plot 102 includes greater than about 1,000, 2,000, 3,000, 4,000, 5,000, 10,000, 15,000, 20,000, 25,000, 30,000, 35,000, 40,000, or 50,000 tons of metal oxides. In some embodiments, carbonation plot 102 includes greater than about 1,000, 2,000, 3,000, 4,000, 5,000, 10,000, 15,000, 20,000, 25,000, 30,000, 35,000, 40,000, or 50,000 tons of metal oxides available for ambient weathering. In some embodiments, carbonation plot 102 includes greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the composition is included in the carbonation plot as a layer. In some embodiments, the layer has a thickness of about 0.01 m, 0.02 m, 0.03 m, 0.04 m, 0.05 m, 0.06 m, 0.07 m, 0.08 m, 0.09 m, 0.1 m, 0.2 m, or 0.3 m. In some embodiments, the layer has a thickness of about 0.1 m. In some embodiments, system 100 is configured to maintain exposure of the composition to ambient weathering for about a month, 2, months, 3 months, 4 months, 5 months, 6 months, 7 months, 8 months, 9 months, 10 months, 11 months, a year, or about 1.5 years. In some embodiments, system 100 is configured to maintain exposure of the composition to ambient weathering for about a year.|[0024] In some embodiments, system 100 includes a feedstock source 104 including a feedstock, e.g., feedstock stream 104A. In some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. In some embodiments, at least a portion of the metal oxides in the composition of carbonation plots 102 is derived from the feedstock. In some embodiments, the feedstock itself is composed at least partially of metal oxides which can be applied to carbonation plots 102 for use in sequestering CO2, as will be discussed in greater detail below. In some embodiments, feedstock is processed to form metal oxides, which are then applied to carbonation plots 102 for use in sequestering CO2, as will also be discussed in greater detail below.|[0025] In an exemplary embodiment, system 100 uses about 500,000 tons magnesite (MgCO3) feedstock. Worldwide magnesite production is 27.3 MtMgCO3/yr, indicating that in these exemplary embodiments, system 100 would use 2% of the global magnesite production. Without wishing to be bound by theory, to sequester 1GtCO2 would include 2.5 Gt MgCO3, which comes out to be 100 times the global production of magnesite per year.|[0026] In some embodiments, system 100 includes one or more calciners 106. In some embodiments, system 100 includes a plurality of calciners 106. In some embodiments, calciners 106 include an oxy-fired calciner, an electric-fired calciner, a solar calciner, e.g., “carbon-free” calciner, etc., or combinations thereof. Calciners 106 are configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature. In some embodiments, calciners 106 hear the feedstock/composition for a duration between about 30 minutes and about 2 hours In some embodiments, the predetermined temperature is between about 500° C. and about 1200° C. Heat from calciners 106, applied to the feedstock and/or composition, replenishes metal oxides from metal carbonates, e.g., those formed via ambient weathering, which can then be returned to carbonation plots 102 to sequester additional CO2. A general calcination reaction of magnesite is provided below:|MeCO3+Energy→MeO+CO2 |[0027] In some embodiments, calciner 106 is configured to calcine ambiently weathered composition to regenerate metal oxides in the composition and evolve a CO2 product stream 108, as will be discussed in greater detail below. In some embodiments, CO2 product stream 108 includes CO2 evolved from the operation of calciner 106 itself, e.g., via combustion of one or more fuels.|[0028] In an exemplary embodiment, calciner 106 is an oxy-fired calciner that includes two additional pieces of equipment: an air separation unit (to ensure pure oxygen is fed to the system) and a condenser (to condense water from the gaseous stream leaving the calciner). This allows for the capture of CO2 produced from fuel combustion. The complete combustion reaction is illustrated below using methane.|CH4 (g)+2 O2 (g)→CO2 (g)+H2O (g)+Energy|[0029] Following the combustion reaction, the gas stream is fed into the condenser where the water is removed from the process stream. After condensing out the water, both the CO2 captured from the air and the CO2 produced from natural gas combustion can be compressed and stored. Without wishing to be bound by theory, in this condensing step, 0.5 t of water are produced for every tCO2 captured from the air. This water can be utilized in the process or sold as a byproduct.|[0030] In some embodiments, system 100 includes a preprocessing system 110 in communication with feedstock source 104 and feedstock stream 104A. In some embodiments, preprocessing system 110 includes one or more components configured to grind the feedstock to a desired average particle size. In some embodiments, the desired average particle size is about 10 μm, 20 μm, 30 μm, 40 μm, 50 μm, 75 μm, 100 μm, 200 μm, 300 μm, 400 μm, 500 μm, 750 μm, or 1 mm. In some embodiments, the average particle size of the composition is about 20 μm. In some embodiments, preprocessing system 110 includes one or more mills, e.g., a ball mill, crushers, e.g., a cone crusher for an initial feedstock size reduction, or combinations thereof. In general, the number of grinders (and subsequent grinding energy) depends on the desired particle size. By way of example, in a first grinding step, a cone crusher could reduce the particle size from an inlet of 100 mm down to 20 mm. From this stage, two ball-milling steps could reduce the size to 20 μm. In some embodiments, preprocessing system 110 includes an additional calciner for calcining feedstock.|[0031] In some embodiments, preprocessing system 110 includes a first outlet stream 110A including processed feedstock. In some embodiments, preprocessing system 110 includes a second outlet stream 110B including a CO2 product stream evolved from processing the feedstock, e.g., from the additional calciner. In some embodiments, the preprocessing system 110 utilizes calciner 106 discussed above to process feedstock, e.g., before applying the feedstock to carbonation plots 102 as part of the composition therein. In such embodiments, CO2 product stream 108 is used as second outlet stream 110B.|[0032] In some embodiments, system 100 includes a composition recycling system 112. In some embodiments, composition recycling system 112 is configured to transport composition, e.g., ambiently weather composition rich in carbonates, to calciner 106 and return calcined composition, e.g., recycled composition rich in metal oxides, to carbonation plots 102. In some embodiments, composition recycling system 112 includes one or more conveyors. In some embodiments, the one or more conveyors are electric. In some exemplary embodiments, with looping, ultramafic rocks will be increasingly divided into materials such as MgCO3, minor CaCO3, and SiO2 after each weathering step, and the calcining residue will become richer and richer in MgO and CaO, and thus more reactive and useful as feedstock for the next cycle.|[0033] In some embodiments, system 100 includes a postprocessing system 114. In some embodiments, postprocessing system 114 collects CO2 product streams, e.g., stream 108 and 110B, for subsequent utilization and/or storage in product stream 114A. In some embodiments, postprocessing system 114 includes any suitable combination of system components to achieve the desired disposition of CO2 produced by system 100. In some embodiments, postprocessing system 114 facilitates compression, transportation, geological sequestration, and/or utilization of produced CO2. In some embodiments, produced CO2 is stored underground. In some embodiments, produced CO2 is used to make “net zero” carbon products, e.g., CO2 in greenhouses and beverages, CO2-added concrete, air-to-fuels, etc.|[0034] Referring now to FIG. 2, an exemplary embodiment of system 100 is shown with 10 carbonation plots 202, which are filled with a composition including feedstock provided from a feedstock source 204. The operation of this exemplary system can be generally divided into various parts including mineral acquisition, physical preprocessing, calcination, on-site transportation, carbonation, mineral recollection, etc. In this exemplary system, an initial magnesite feedstock stream 204A is fed into a preprocessor 206 where the mineral is ground and heated, e.g., via one or more crushers/mills and one or more calciners, to produce a metal oxide stream 206A (including MgO) and a CO2 product stream 206B. Alternatively, to produce MgO for weathering, one could calcine serpentinite, driving off H2O and minor CO2, to create reactive material composed of MgO and amorphous Mg3Si2O7. After a few weathering and calcining cycles, this would become MgO and SiO2. Metal oxide stream 206A is then distributed to carbonation plots 202 as the composition for sequestering atmospheric CO2 via carbonation reactions, i.e., ambient weathering.|[0035] In this embodiment, conveyors 212C act as the connection between carbonation plots 202 and a calcination plant 208. Conveyors 212C will transport the carbonation product from plots 202 back into the calcination plant once the year has elapsed, as well as spread calcined mineral provided therefrom.|[0036] In this embodiment, 10 conveyors are used. As discussed above, metal oxide stream 206A is transported to carbonation plots 202 where it is deposited and allowed to carbonate over a given timescale, e.g., over the course of a year. At least a portion of the ambiently weathered composition in carbonation plots 202 is then recollected, primarily in the form of magnesium carbonate, and transported to calciner 208. In some embodiments, the material is re-fed to preprocessor 206 with additional magnesite feedstock 204A to make up for environmental losses. In some embodiments, the material is re-ground in preprocessor 206. In the preprocessor 206 and calciner 208, the material is once again heated to regenerate MgO, e.g., as metal oxide stream 208A. In an exemplary embodiment, a CO2 stream 208B is generated from ambiently weathered composition in addition to that previously generated at 206B in processing the feedstock. In some embodiments, the process continues cyclically. In some embodiments, the process continues semi-continuously. In some embodiments, the process continues continuously. Overall, in this embodiment, MgCO3 feedstock is calcined to produce caustic MgO and high-purity CO2. The MgO is spread over land to react with atmospheric CO2 to reform magnesite and other Mg-carbonate minerals over the course of a year. After renewed formation of Mg-carbonate minerals, it is collected and calcined again, producing a nearly pure stream of CO2 together with an amorphous, solid MgO residue. The resulting MgO can be exposed to weathering again, and so on.|[0037] When analyzing the effectiveness of system 100, such as the embodiment shown in FIG. 2, the produced MgO is assumed to have the same aqueous reactivity as mineral brucite (Mg(OH)2). The rate of formation of magnesium carbonate via reaction of aqueous brucite is on the order of 3 x 10−8 moles m−1s−1 when mineral dissolution kinetics are rate limiting. Thus, for example, grains of brucite with a diameter of 10 to 100 microns (1.7 x 10−1° to 1.7 x 10−7 moles, 1.25 x 10−9 to 1.25 x 10−7 m2, assuming spherical grains), are predicted to be completely transformed to magnesite in less than a year. In practice, larger porous grains with a higher surface area to volume ratio than spheres would also be transformed in a year.|[0038] Existing data suggest that under conditions of near 100% relative humidity, conversion of MgO to Mg(OH)2 can occur on the order of hours, indicating over the course of a year hydration reaction is not rate limiting. This conversion is further dependent on the specific surface area and relative humidity of the system (or water vapor partial pressure) with higher partial pressures resulting in faster conversion. Since conversion of MgO to Mg(OH)2 in the presence of water is much faster than the rate of carbonation of Mg(OH)2, it was assumed the carbonation step is rate limiting. Thus, the rate of carbonation can be assumed as the effective rate for the system of FIG. 2.|[0039] The major process assumptions and parameters for the upper and lower bounds of the analysis are outlined in Table 1. Based on these considerations, it was assumed that 20 μm particles of caustic magnesia achieve 90% carbonation within a year. The number of carbonation plots in the analysis is optimized to keep the calciner continuously operational, avoiding startup and shutdown expenses. The upper and lower bounds correspond to the effect of each parameter on overall process cost, not necessarily the magnitude of each parameter value.|TABLE 1 Assumptions and parameters used for the upperand lower bounds in the process model ValueParameter/AssumptionLower BoundUpper Bound CalcinationCalcination Temperature [° C.]6001200Calcination Time [hr]20.5Time Between Calcination Loads [hr]0.25Heat of Decarbonation [kJ mol−1]118Kiln Efficiency [%]90Calcination Efficiency [%]90CarbonationCO2 Uptake Capacity [mol CO21molMgO−1]MgO Layer Thickness [m]0.1Particle Size [μm]20Environmental Losses [% cycle−1]510Carbonation Efficiency [%]90Stirring Equipment [Acres Unit125Equipment−1]Number of Plots350410512Energy Costs and EmissionsNatural Gas [$ GJ−1]3.5Natural Gas [kg CO2 GJ−1]59Gasoline [$ gallon−1]2.60Gasoline [kg CO2 gallon−1]8.89Grid Electricity [$ GJ−1]16.7Grid Electricity [kg CO2 GJ−1]150Solar Electricity [$ GJ−1]16.7Future Solar Electricity [$ GJ−1]8Solar Electricity [kg CO2 GJ−1]6.9Raw Material (Mining) Emissions [kg10CO2 tMineral−1]Economic ParametersCapacity Factor [%]90Plant Economic Lifetime [yr]20Discount Rate [%]411Capital Recovery Factor [%]7.412.6 |[0040] Three scenarios were explored in this analysis, related to the type, cost and emissions of electricity used. The first scenario used grid electricity, assuming electricity is taken directly from the commercial grid. The second scenario used solar electricity, assuming electricity is obtained via utility solar plants at current market price. The third scenario used a projected cost of solar electricity, assuming a decrease in utility solar electricity cost by 2030 as projected by the DOE.|[0041] The scale of operation used 50,000 tons of magnesite-including raw mineral per carbonation plot. Here the emissions value associated with mining magnesite was 10 kgCO2 tMgCO3−1, while typical range from 1.3-12.5 kgCO2 tmineral−1. The chosen value is on the higher side of reported values for mining emissions, and the process is not sensitive to these emissions due to repeated reuse of MgO from the feedstock. For this analysis, it was assumed the feedstock is available at the desired particle size of 20 μm or that this particle size is achieved in a first preprocessing/calcination step. Weathering in this process takes place on land at ambient conditions. MgO is spread on land in layers 0.1 m thick and stirred daily. Values for the capital costs of this equipment are approximated as large-scale agricultural tillage equipment.|[0042] When estimating magnesite use in this system, there are two main considerations: the initial supply of magnesite to each carbonation facility and the makeup supply of magnesite each subsequent year of facility operation. For the initial supply of magnesite, there are two cases: the lower bound utilizing 3,504 carbonation plots with 5% environmental losses and the upper bound utilizing 10,512 carbonation plots with 10% environmental losses. For both cases, the initial plots are each populated with 50,000 tMgCO3. The upper bound uses 525 MtMgCO3 to capture 180 MtCO2, or 6.2% of global reserves (estimated to be 8.5 billion tons of known, economically and legally producible magnesite). Additionally, with 10% environmental losses, the upper bound process would use 53 MtMgCO3 in replacement magnesite each year or 0.6% of global reserves.|[0043] For the lower bound, the initial mineral charge is 175 MtMgCO3 or 2% of global magnesite reserves to capture 64 MtCO2. For makeup minerals, the upper bound assumed 5% environmental losses, corresponding to an additional 8.7 MtMgCO3 per year or 0.1% of global reserves. Removing 1 GtCO2 from air per year would initially charge 2.9 GtMgCO3 or roughly 29% of global magnesite reserves. The makeup supply would use between 0.15-0.29 GtMgCO3 per year, or roughly 1.7-3.4% of global magnesite reserves.|[0044] The system analyzed here has between 3,504 (lower bound) and 10,512 (upper bound) carbonation plots, each with 21,500 tMgO from the original 50,000 tMgCO3 feedstock. The number of carbonation plots are optimized for continuous calciner operation. Since the upper bound and lower bound have 30 minute and 2 hour calcination cycles, respectively, more plots are processed per year in the upper bound scenario. By populating each plot with MgO at different times during the year, they can be recollected and calcined at varying times throughout the year. Additionally, it was assumed that 90 to 95% of the MgO will be recollected as MgCO3 or unreacted MgO and between 5% and 10% of this material will be lost to the environment. Losses of MgCO3 were calculated to be 0.03 to 0.05% per year and MgO will near 3 to 4% per year|[0045] The magnesite feedstock was calcined at temperatures ranging from 500-1200° C. For this analysis, two sets of calcination conditions are used: 600° C. for 2 hours (lower bound) and 1200° C. for 0.5 hours (upper bound). Calcining at 600° C. for 2 hours yields a higher specific surface area (93.07 m2 g−1 for a 2-5 mm feed pre-calcination) which will aid in subsequent carbonation reactions. The calcination conditions of 1200° C. for 0.5 hours result in a decreased surface area (10.9 m2 g−1 for a 2-5 mm feed pre-calcination). For this process, the calciner is continuously operational with a capacity factor of 90% to account for routine maintenance.|[0046] An oxy-fired calciner was used, which included an air separation unit and a condenser. Combustion energy and CO2 outputs were estimated for oxidation of pure methane. Following combined combustion and calcination, the gas stream was fed into the condenser where water was removed. Since oxy-fired calcination is used, the resulting flue gas stream has high concentrations of CO2 and water vapor, indicating a high purity stream of CO2 will be produced following condensation of water vapor. CO2 removed from Mg-carbonates, and CO2 produced from combustion, can be compressed and permanently stored or sold. Additionally, the condensation step produces 0.3 tons of water for every tCO2 captured from air.|[0047] To move calcined MgO to the plot of land used for weathering, an electric conveyor was used. Transportation operating costs are related to electricity used by the conveyor system which was determined using motor power details for commercially available mining conveyors (373 kW (500 HP) with a capacity of 454 t hr−1).|[0048] For recollection and delivery to conveyors, the associated pieces of equipment are assumed to be commercially available front-loading tractors. By staggering plot maturation times, central calcination equipment can be used continuously for multiple carbonation plots throughout the year. This also allows for more CO2 capture without increasing the operational scale, i.e., equipment sizing or throughput.|[0049] Without wishing to be bound by theory, after undergoing repeated calcination, sintering may have a significant effect on MgO reactivity. Studies evaluating capacity losses for magnesium-based adsorbents suggest that after 10 cycles CO2 uptake capacity diminishes by 5-7%. This would correspond to a capacity loss between 2 and 17% over the plant lifetime, depending on amount of makeup material and number of cycles undergone by material lost to the environment. This analysis assumes 5-10% losses in each cycle, accounting for both environmental losses and possible sintering effects so the initial MgO lasts for 10 to 20 cycles.|[0050] The largest contributions to the capital costs of the system were raw material costs at 81-86% of capital costs, the oxy-fired calciner at 9-10% of capital costs, and the air separation unit and condenser at 2-7% of the capital costs. The costing method and scaling factor used for each piece of equipment are presented in Table 2.|TABLE 2 Estimated capital expenditures (CAPEX)for the MgO looping process. Cost [M$]CAPEXLower BoundUpper Bound Raw Mineral8760110376Air Separation Unit and7852260CondenseraOxy-Fired Calcinera93012202Land1291796Transportation (Conveyor1291050System)aStirring Equipment2884Recollection Equipment2267Total CAPEX [M$]$10,783$127,835CAPEX Annualized [M$ year−1]$794$16,053CO2 Capture from Air [GtCO20.0640.198year−1]Total CO2 Capture [GtCO20.120.34year−1]CAPEX [$ tCO2−1 Captured]$12$89CAPEX [$ tCO2−1 Produced]$7$47 aAssumed a scale-up factor|[0051] Each capital cost value is scaled to the individual process conditions. Here, the upper bound is processing 0.18 Gt CO2 year−1 using 10,512 carbonation plots and the lower bound is processing 0.06 Gt CO2 year−1 using 3,504 carbonation plots. Since the upper bound is processing about 3 times more CO2 than the lower bound, the capital cost per ton CO2 is significantly less for the lower bound compared to the upper bound.|[0052] Table 3 shows the energy use and energy type for each unit operation. The main energy demand of the process is for calcination which depends on calcining temperature. Therefore, the energy use per ton CO2 vary between the lower and upper bounds.|TABLE 3 Energy Use for the CO2 sequestration process Energy Use LowerUpperEnergyUnit OperationBoundBoundType Air Separation Unit and Condenser300300Electricity[MJ tCO2−1]Oxy-Fired Calciner [MJ tCO2−1]58887966Natural GasTransportation [MJ tCO2−1]89ElectricityStirring Equipment [Gallons tCO2−1]0.290.31GasolineRecollection Equipment [Gallons0.00510.0054GasolinetCO2−1] |[0053] Table 4 details the operating costs for the CO2 sequestration system. There are no variations in the cost between grid and solar electricity scenarios as the cost of electricity is identical. Variations between these energy resource scenarios arise when considering CO2 emissions.|TABLE 4 Operating expenditures (OPEX) for the MgO looping process Cost [M$] OPEXLower BoundUpper Bound Maintenance3233,835 Labor971,151 Makeup minerals953 Gasoline50151 Natural Gas1,3105,036 Electricity327929 Total OPEX [M$]$2,117$11,154 Total OPEX [$ tCO2−1]$33$62 Captured] Total OPEX [$ tCO2−1]$17$32 Produced] |[0054] The largest contribution to operating costs is the natural gas for powering the calciner, making up 45-62% of operating costs for all scenarios. This indicates process operating costs can be sensitive to the price of natural gas. Additionally, electricity makes up 8-16©© of operating costs. Other major contributions to operation costs are maintenance (15-34%) and labor (5-10%), which are directly correlated to capital costs.|[0055] The cost of CO2 combines the capital and operating costs presented in the previous sections to develop a process cost per tCO2. These costs are shown in Table 5.|TABLE 5 Summary of CO2 capture costs for the MgO looping process GridSolarSolar Elec-ElectricityElectricity tricity($0.06 kWh−1)($0.03 kWh−1) Capture cost [$ tCO2−1]46-15146-15143-148Net Removal Cost [$ tCO2−1]48-15946-15244-149Produced Cost [$ tCO2−1]29-79 29-79 25-77 |[0056] While the cost of capture for the solar electricity scenario is the same as for the grid electricity scenario, the cost of CO2 net removed is ˜4% less for the solar scenario compared to the grid scenario. This is caused by the reduction in CO2 emissions associated with solar electricity versus grid electricity. Additionally, when accounting for projected cost reduction of solar electricity, the CO2 net removed process cost is reduced by ˜7% compared to grid electricity.|[0057] For the exemplary process presented here, the cost of CO2 net removed ranges from $46-159 tCO2−1 using current costs of grid and solar electricity, while the cost of CO2 produced ranges from $29-79 tCO2−1. Using future cost projections for solar electricity yields $43-149 tCO2−1 net removed and $25-77 tCO2−1 produced. Currently, DAC technologies have been demonstrated on the industrial and pilot scales with costs of CO2 net removed reported at $500-600 tCO2−1. Aside from industrial-scale initiatives, literature values for DAC technologies using joint carbonation and calcination processes have been described. In their analysis, the American Physical Society (APS) developed a cost estimate of $610-780 tCO2−1 net removed for the aqueous calcium looping system using sodium hydroxide. By varying the packing materials used in the process and optimizing the process around this new material, a similar process at $510-568 tCO2−1 net removed was developed.|[0058] Referring now to FIG. 3, some embodiments of the present disclosure are directed to a method 300 for utilizing alkalinity to sequester carbon dioxide from the atmosphere. At 302, a composition including one or more metal oxides is provided. As discussed above, the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. As discussed above, the composition is at least in part composed of processed feedstock, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. In some embodiments, providing 302 a composition includes grinding the feedstock to an average particle size of about 20 μm. In some embodiments, providing 302 a composition includes calcining the feedstock to produce an additional CO2 stream and a calcined feedstock including the one or more metal oxides.|[0059] [58] At 304, the composition is distributed into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering. In some embodiments, the composition is distributed 304 to greater than about 5 carbonation plots. In some embodiments, the carbonation plots include greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the composition is distributed in the carbonation plots as a layer. In some embodiments, the layer has a thickness of about 0.01 m, 0.02 m, 0.03 m, 0.04 m, 0.05 m, 0.06 m, 0.07 m, 0.08 m, 0.09, 0.1 m, 0.2 m, or 0.3 m. At 306, atmospheric CO2 is captured via the one or more metal oxides to produce an ambiently weathered composition. In some embodiments, the ambiently weathered composition is recollected after a certain duration of exposure. In some embodiments, the duration of exposure is about a month, 2, months, 3 months, 4 months, 5 months, 6 months, 7 months, 8 months, 9 months, 10 months, 11 months, a year, or about 1.5 years. At 308, the ambiently weathered composition is calcined to generate a calcined composition and a CO2 stream. In some embodiments, the ambiently weathered composition is calcined for a duration between about 30 minutes and about 2 hours. In some embodiments, the ambiently weathered composition is calcined at a temperature between about 500° C. and about 1200° C. At 310, the calcined composition is distributed into the plurality of carbonation plots.|[0060] In some embodiments of method 300, the composition within the plurality of carbonation plots is stirred to maximize exposure of the composition to the atmosphere. In some embodiments, the composition is stirred once a week, month, quarter, 6 months, year, etc. Any suitable system or mechanism, e.g., commercially-available farming equipment, can be used to stir the composition. Without wishing to be bound by theory, after undergoing repeated calcination, the pores in the particles of the composition begin to clog causing metal oxides to deactivate. Studies have demonstrated that the reaction capacity of CaO diminishes by greater than half the original capacity after 45 cycles. In some embodiments, a grinding process is used to periodically produce new metal oxides. Since the presence of magnesium in the original silicate structure appears to decrease this deactivation, 35 cycles at maximum carbonation capacity can be used to determine the amount of CO2 captured per ‘batch’ of MgO from the initial pre-preprocessing step. In some cases, the number of cycles for the natural weathering system will not be limited by the deactivation, but rather by the environmental losses of MgO. In some embodiments, in the case of 10% environmental losses, the MgO is assumed to last 10 cycles on average and the periodic replacement of MgO can be built in to the operating costs.|[0061] Referring now to FIG. 4, some embodiments of the present disclosure are directed to a method 400 for utilizing alkalinity to sequester carbon dioxide from the atmosphere. At 402, a source of feedstock is provided. As discussed above, in some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. At 404, the feedstock is processed to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2. As discussed above, in some embodiments, the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. As discussed above, in some embodiments, processing 404 includes one or more grinding steps, one or more calcination steps, or combinations thereof. At 406, the processed feedstock is provided to a network of carbonation plots configured to expose the processed feedstock to ambient weathering. As discussed above, in some embodiments, the network of carbonation plots includes more than about 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1,000, 1,500, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, or 10,000 plots. At 408, a contents of the carbonation plots is stirred to maximize exposure of the metal oxides in the carbonation plots to atmospheric CO2. At 410, atmospheric CO2 is captured via the one or more metal oxides to produce an ambiently weathered composition, e.g., for about 1 year. At 412, the ambiently weathered composition is calcined to generate a CO2 stream and regenerate metal oxides as a calcined composition, e.g., at a temperature between about 500° C. and about 1200° C. At 414, the calcined composition is distributed into the plurality of carbonation plots.|[0062] The methods and systems of the present disclosure are advantageous in that they offer a less expensive route than other current and proposed techniques to remove CO2 from air. The systems and methods of the present disclosure enable capture and redistribution of “net-zero” carbon dioxide for industrial-scale uses for very abundant quarry minerals and enable large-scale low-cost carbon capture projects for municipalities or corporations. CO2 captured using this method can be sold as a commodity (for carbonated beverages, enhanced oil recovery, greenhouses, etc.) or used to make (nearly) “net zero” carbon products (CO2-added concrete, air-to-fuels, etc.).|[0063] CO2 removal from air via the methods and systems of the present disclosure have a similar or lower cost than CO2 removal using DAC with synthetic sorbents or solvents. The process is relatively simple and robust and is feasible at a reasonable cost using existing technology. Additionally, the proposed process integrates CO2 capture from the oxy-fired calcination unit so the cost of produced CO2, both removed from air and captured from combustion, is competitive with other sources. When compared to ideas about enhanced, surficial weathering of rocks—mine tailings, ground rock material broadcast on agricultural soils or on beaches, distributing CaO and MgO for “ocean liming”—the disclosure outlined here reduces the area footprint substantially, since one ton of CaO and MgO can be used to capture many tons of CO2, year after year.|[0064] The method for CO2 removal from air is also less costly than the projected, future minimum cost for CDR machines. Using low carbon energy sources, e.g., PV at a cost of $0.03/kWh, and capturing CO2 emissions from the process, this process potentially removes CO2 at less than $100/ton, whereas optimistic predictions of the future cost of CO2 production using CDR machines yield a minimum cost of $100/ton. The cost of arable land was used to develop this analysis due to the availability of land prices. Since arable land is in higher demand due to its ability to grow crops, it is possible that the cost analysis presented here even overestimates the land cost.|[0065] Although the disclosed subject matter has been described and illustrated with respect to embodiments thereof, it should be understood by those skilled in the art that features of the disclosed embodiments can be combined, rearranged, etc., to produce additional embodiments within the scope of the invention, and that various other changes, omissions, and additions may be made therein and thereto, without parting from the spirit and scope of the present invention. | (US20220347650)|CROSS REFERENCE TO RELATED APPLICATION(S)|[0001] This application is a national stage patent application filing of International Application No. PCT/US2020/039265, filed Jun. 24, 2020, which claims the benefit of U.S. Provisional Application No. 62/865,708, filed Jun. 24, 2019, and 63/043,038, filed Jun. 23, 2020, which are incorporated by reference as if disclosed herein in their entireties.|(US20220347650)|BACKGROUND|[0002] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS) and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies. Prior to the deployment of these technologies, it is important to develop an understanding of the cost and potential environmental impact.|[0003] The contribution of carbon dioxide to global warming is well-documented. Recently, carbon capture methods have been developed for point-of-release carbon capture, e.g., at the smokestack. Previous approaches involved CO2 capture from flue gas and other concentrated sources, in smokestacks or reactors, on time scales of minutes to days. Prior systems also often rely on faster reaction times and higher energy investments, e.g., application of high heat and/or pressure. These solutions are frequently expensive, with optimistic minimum cost predictions of $100/ton CO2 produced, and occasionally employ designer materials that may be difficult to produce.|[0004] As discussed above, the Intergovernmental Panel on Climate Change, and other authoritative organizations, have determined that CO2 removal from air (CDR) is necessary to hold global warming to less than 2° C. CDR is far more difficult than CO2 capture from flue gas. Current technology involves “direct air capture” machines (DAC) that remove CO2 from air at a cost of $600/ton CO2.|[0005] Enhanced weathering was first proposed by Walter Seifritz in 1990 and is based on the process of natural weathering. In natural weathering, alkalinity-containing minerals are carbonated on geologic timescales (millions of years). The generalized natural weathering reaction is described below:|MeO+CO2→MeCO3+Energy|where Me represents a divalent metal cation. Typical cations include magnesium (Mg′) and calcium (Ca2+), where suitable feedstocks include minerals, such as olivine and serpentine, as well as industrial byproducts, such as mine tailings and fly ash. Since the natural weathering reaction occurs on geological timescales, many researchers have explored various process conditions, pretreatment methods, extraction mechanisms and optimization strategies to expedite the process kinetics as a form of CO2 sequestration.|[0006] In addition to natural weathering, calcination is a process by which carbonates are heated to decompose into metal oxides and CO2. The generalized calcination reaction is shown below:|MeCO3+Energy→MeO+CO2 |Similar systems proposing CO2 removal using carbonation reactions have been discussed in previous literature. The American Physical Society, in a 2011 study, evaluated a system where CO2 is absorbed by sodium hydroxide (NaOH) and subsequently reacted with calcium hydroxide (Ca(OH)2) to produce solid calcium carbonate (CaCO3). The CaCO3 is then calcined in an oxy-fired calciner to release the CO2. Other proposed solutions include a continuous looping process including an aqueous potassium hydroxide (KOH) sorbent coupled with a calcium caustic recovery loop. The KOH sorbent reacts with CO2 in the air to produce potassium carbonate (K2CO3). The K2CO3 then reacts with Ca(OH)2, produced from CaCO3, to reproduce the KOH and CaCO3. These types of aqueous calcium looping systems have been primarily evaluated using calcium-based sorbents in aqueous conditions (in the form of Ca(OH)2). Additionally, proposed ocean liming processes deposit lime (produced from calcined carbonate minerals) into the ocean to react with carbonic acid currently in the ocean. This process increases oceanic pH and leads to the dissolution of more CO2 into the ocean water, reducing the atmospheric concentration of CO2. Additional systems utilizing mineral carbonation reactions have looked at various forms of carbon mineralization as a method to capture CO2 from more concentrated point sources, such as power plants.|SUMMARY|[0007] Some embodiments of the present disclosure are directed to a system utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including at least one carbonation plot including a composition including one or more metal oxides, the at least one carbonation plot positioned to expose the composition to ambient weathering; a feedstock source including a feedstock, wherein at least a portion of the one or more metal oxides is derived from the feedstock; a preprocessing system in communication with the feedstock source, the preprocessing system configured to reduce the feedstock to a desired particle size; a calciner configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature; and a composition recycling system to transport composition to the calciner and return calcined composition to the at least one carbonation plots.|[0008] In some embodiments, the system is configured to maintain exposure of the composition to ambient weathering for a year. In some embodiments, the system includes greater than about 5 carbonation plots. In some embodiments, the system includes greater than about 3,500 carbonation plots. In some embodiments, the at least one carbonation plot includes greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the average particle size of the composition is about 20 μm. In some embodiments, the composition is included in the carbonation plot as a layer, wherein the layer has a thickness of about 0.1 m. In some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof.|[0009] Some embodiments of the present disclosure are directed to a method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including providing a composition including one or more metal oxides; distributing the composition into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering; capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition; calcining the ambiently weathered composition to generate a calcined composition and a CO2 stream; and distributing the calcined composition into the plurality of carbonation plots. In some embodiments, the method includes stirring the composition within the plurality of carbonation plots.|[0010] In some embodiments, the composition is at least in part composed of processed feedstock, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. In some embodiments, the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. In some embodiments, the plurality of carbonation plots includes greater than about 5 carbonation plots. In some embodiments, the plurality of carbonation plots includes greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the composition is distributed in the plurality of carbonation plots as a layer, wherein the layer has a thickness of about 0.1 m.|[0011] In some embodiments, capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition includes recollecting the composition as the ambiently weathered composition after about 1 year of exposure to the atmosphere.|[0012] In some embodiments, providing a composition includes grinding the feedstock to an average particle size of about 20 μm. In some embodiments, providing a composition includes calcining the feedstock to produce an additional CO2 stream and a calcined feedstock including the one or more metal oxides.|[0013] In some embodiments, calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes calcining the ambiently weathered composition for a duration between about 30 minutes and about 2 hours. In some embodiments, calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C.|[0014] Some embodiments of the present disclosure are directed to a method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere including providing a source of feedstock; processing the feedstock to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2; providing the processed feedstock to a network of carbonation plots configured to expose the processed feedstock to ambient weathering; stirring a contents of the carbonation plots; capturing atmospheric CO2 via the one or more metal oxides for about 1 year to produce an ambiently weathered composition; calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C. to generate a CO2 stream and regenerate metal oxides as a calcined composition; and distributing the calcined composition into the plurality of carbonation plots. In some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof, and the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof.|(US20220347650)|BRIEF DESCRIPTION OF THE DRAWINGS|[0015] The drawings show embodiments of the disclosed subject matter for the purpose of illustrating the invention. However, it should be understood that the present application is not limited to the precise arrangements and instrumentalities shown in the drawings, wherein:|[0016] FIG. 1 is a schematic representation of a system utilizing alkalinity to sequester carbon dioxide according to some embodiments of the present disclosure;|[0017] FIG. 2 is a schematic representation of a system utilizing alkalinity to sequester carbon dioxide according to some embodiments of the present disclosure;|[0018] FIG. 3 is a chart of a method for utilizing alkalinity to sequester carbon dioxide from the atmosphere according to some embodiments of the present disclosure; and|[0019] FIG. 4 is a chart of a method for utilizing alkalinity to sequester carbon dioxide from the atmosphere according to some embodiments of the present disclosure.|(US20220347650)|DESCRIPTION|[0020] Referring now to FIG. 1, aspects of the disclosed subject matter include a system 100 utilizing alkalinity to sequester a target compound, e.g., carbon dioxide (CO2). In some embodiments, system 100 sequesters the target compound directly from the atmosphere. In some embodiments, system 100 sequesters the target compound directly from the atmosphere via reaction of the target compound with a composition in the system. In some embodiments, the reaction is a carbonation reaction.|[0021] In some embodiments, system 100 sequesters CO2 directly from the atmosphere. In these embodiments, sequestering of CO2 by system 100 contributes to an overall reduction in atmospheric CO2 concentration. In some embodiments, system 100 sequesters CO2 from one or more extra-systemic effluent streams, e.g., evolved from industrial processes outside of or independent from system 100. In some embodiments, energy for operating components of system 100 can be provided via any suitable source, grid electricity, solar electricity, combustion of one or more fuels, e.g., to power an oxy-fired system component, etc., or combinations thereof.|[0022] In some embodiments, system 100 includes at least one carbonation plot 102. In some embodiments, system 100 includes a plurality of carbonation plots 102. “Carbonation plot,” as used herein, includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots 102 include a composition that sequesters a target compound, e.g., CO2. In some embodiments, the carbonation plots 102 are positioned and configured to expose the composition to ambient weathering. In some embodiments, the environment in which the ambient weathering occurs, e.g., the location and orientation of carbonation plots 102, is configured to maximize the temperature at the surface of the composition. As used herein, the term “ambient weathering” is used to refer to the sequestration of a target compound, e.g., CO2, directly from the atmosphere at substantially ambient temperature and substantially atmospheric pressure. In some embodiments, carbonation plots 102 are positioned in the environment, e.g., on grasslands, deserts, mountainsides, etc. In some embodiments, carbonation plots 102 are clustered into a group. In these embodiments, and as will be discussed in greater detail below, the clustered carbonation plots 102 enable centralized implementation of other system components for more efficient operation of the overall system. In some embodiments, carbonation plots 102 are clustered in a plurality of separate groups. In some embodiments, a plurality of carbonation plot groups are distributed throughout a region of the planet, e.g., non-arable land in the Western United States. In some embodiments, a plurality of carbonation plot groups are distributed throughout the planet. In some embodiments, system 100 includes a sufficient number of carbonation plots 102 to hold a sufficient amount of the composition to sequester a desired amount of target compound, e.g., CO2. In some embodiments, system 100 includes more than about 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 1,500, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, or 10,000 carbonation plots 102. In some embodiments, system 100 includes greater than about 5 carbonation plots. In some embodiments, system 100 includes greater than about 3,500 carbonation plots.|[0023] In some embodiments, the composition includes one or more metal oxides. In some embodiments, the one or more metal oxides include MgO, CaO, Na2O, or combinations thereof. The composition may also include filler material, e.g., materials that do not actively react with the target compound, reacted metal oxides, e.g., metal carbonates, silicates, etc., and other materials without departing from the scope of the invention. In some embodiments, carbonation plot 102 includes greater than about 1,000, 2,000, 3,000, 4,000, 5,000, 10,000, 15,000, 20,000, 25,000, 30,000, 35,000, 40,000, or 50,000 tons of metal oxides. In some embodiments, carbonation plot 102 includes greater than about 1,000, 2,000, 3,000, 4,000, 5,000, 10,000, 15,000, 20,000, 25,000, 30,000, 35,000, 40,000, or 50,000 tons of metal oxides available for ambient weathering. In some embodiments, carbonation plot 102 includes greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the composition is included in the carbonation plot as a layer. In some embodiments, the layer has a thickness of about 0.01 m, 0.02 m, 0.03 m, 0.04 m, 0.05 m, 0.06 m, 0.07 m, 0.08 m, 0.09 m, 0.1 m, 0.2 m, or 0.3 m. In some embodiments, the layer has a thickness of about 0.1 m. In some embodiments, system 100 is configured to maintain exposure of the composition to ambient weathering for about a month, 2, months, 3 months, 4 months, 5 months, 6 months, 7 months, 8 months, 9 months, 10 months, 11 months, a year, or about 1.5 years. In some embodiments, system 100 is configured to maintain exposure of the composition to ambient weathering for about a year.|[0024] In some embodiments, system 100 includes a feedstock source 104 including a feedstock, e.g., feedstock stream 104A. In some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. In some embodiments, at least a portion of the metal oxides in the composition of carbonation plots 102 is derived from the feedstock. In some embodiments, the feedstock itself is composed at least partially of metal oxides which can be applied to carbonation plots 102 for use in sequestering CO2, as will be discussed in greater detail below. In some embodiments, feedstock is processed to form metal oxides, which are then applied to carbonation plots 102 for use in sequestering CO2, as will also be discussed in greater detail below.|[0025] In an exemplary embodiment, system 100 uses about 500,000 tons magnesite (MgCO3) feedstock. Worldwide magnesite production is 27.3 MtMgCO3/yr, indicating that in these exemplary embodiments, system 100 would use 2% of the global magnesite production. Without wishing to be bound by theory, to sequester 1GtCO2 would include 2.5 Gt MgCO3, which comes out to be 100 times the global production of magnesite per year.|[0026] In some embodiments, system 100 includes one or more calciners 106. In some embodiments, system 100 includes a plurality of calciners 106. In some embodiments, calciners 106 include an oxy-fired calciner, an electric-fired calciner, a solar calciner, e.g., “carbon-free” calciner, etc., or combinations thereof. Calciners 106 are configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature. In some embodiments, calciners 106 hear the feedstock/composition for a duration between about 30 minutes and about 2 hours In some embodiments, the predetermined temperature is between about 500° C. and about 1200° C. Heat from calciners 106, applied to the feedstock and/or composition, replenishes metal oxides from metal carbonates, e.g., those formed via ambient weathering, which can then be returned to carbonation plots 102 to sequester additional CO2. A general calcination reaction of magnesite is provided below:|MeCO3+Energy→MeO+CO2 |[0027] In some embodiments, calciner 106 is configured to calcine ambiently weathered composition to regenerate metal oxides in the composition and evolve a CO2 product stream 108, as will be discussed in greater detail below. In some embodiments, CO2 product stream 108 includes CO2 evolved from the operation of calciner 106 itself, e.g., via combustion of one or more fuels.|[0028] In an exemplary embodiment, calciner 106 is an oxy-fired calciner that includes two additional pieces of equipment: an air separation unit (to ensure pure oxygen is fed to the system) and a condenser (to condense water from the gaseous stream leaving the calciner). This allows for the capture of CO2 produced from fuel combustion. The complete combustion reaction is illustrated below using methane.|CH4 (g)+2 O2 (g)→CO2 (g)+H2O (g)+Energy|[0029] Following the combustion reaction, the gas stream is fed into the condenser where the water is removed from the process stream. After condensing out the water, both the CO2 captured from the air and the CO2 produced from natural gas combustion can be compressed and stored. Without wishing to be bound by theory, in this condensing step, 0.5 t of water are produced for every tCO2 captured from the air. This water can be utilized in the process or sold as a byproduct.|[0030] In some embodiments, system 100 includes a preprocessing system 110 in communication with feedstock source 104 and feedstock stream 104A. In some embodiments, preprocessing system 110 includes one or more components configured to grind the feedstock to a desired average particle size. In some embodiments, the desired average particle size is about 10 μm, 20 μm, 30 μm, 40 μm, 50 μm, 75 μm, 100 μm, 200 μm, 300 μm, 400 μm, 500 μm, 750 μm, or 1 mm. In some embodiments, the average particle size of the composition is about 20 μm. In some embodiments, preprocessing system 110 includes one or more mills, e.g., a ball mill, crushers, e.g., a cone crusher for an initial feedstock size reduction, or combinations thereof. In general, the number of grinders (and subsequent grinding energy) depends on the desired particle size. By way of example, in a first grinding step, a cone crusher could reduce the particle size from an inlet of 100 mm down to 20 mm. From this stage, two ball-milling steps could reduce the size to 20 μm. In some embodiments, preprocessing system 110 includes an additional calciner for calcining feedstock.|[0031] In some embodiments, preprocessing system 110 includes a first outlet stream 110A including processed feedstock. In some embodiments, preprocessing system 110 includes a second outlet stream 110B including a CO2 product stream evolved from processing the feedstock, e.g., from the additional calciner. In some embodiments, the preprocessing system 110 utilizes calciner 106 discussed above to process feedstock, e.g., before applying the feedstock to carbonation plots 102 as part of the composition therein. In such embodiments, CO2 product stream 108 is used as second outlet stream 110B.|[0032] In some embodiments, system 100 includes a composition recycling system 112. In some embodiments, composition recycling system 112 is configured to transport composition, e.g., ambiently weather composition rich in carbonates, to calciner 106 and return calcined composition, e.g., recycled composition rich in metal oxides, to carbonation plots 102. In some embodiments, composition recycling system 112 includes one or more conveyors. In some embodiments, the one or more conveyors are electric. In some exemplary embodiments, with looping, ultramafic rocks will be increasingly divided into materials such as MgCO3, minor CaCO3, and SiO2 after each weathering step, and the calcining residue will become richer and richer in MgO and CaO, and thus more reactive and useful as feedstock for the next cycle.|[0033] In some embodiments, system 100 includes a postprocessing system 114. In some embodiments, postprocessing system 114 collects CO2 product streams, e.g., stream 108 and 110B, for subsequent utilization and/or storage in product stream 114A. In some embodiments, postprocessing system 114 includes any suitable combination of system components to achieve the desired disposition of CO2 produced by system 100. In some embodiments, postprocessing system 114 facilitates compression, transportation, geological sequestration, and/or utilization of produced CO2. In some embodiments, produced CO2 is stored underground. In some embodiments, produced CO2 is used to make “net zero” carbon products, e.g., CO2 in greenhouses and beverages, CO2-added concrete, air-to-fuels, etc.|[0034] Referring now to FIG. 2, an exemplary embodiment of system 100 is shown with 10 carbonation plots 202, which are filled with a composition including feedstock provided from a feedstock source 204. The operation of this exemplary system can be generally divided into various parts including mineral acquisition, physical preprocessing, calcination, on-site transportation, carbonation, mineral recollection, etc. In this exemplary system, an initial magnesite feedstock stream 204A is fed into a preprocessor 206 where the mineral is ground and heated, e.g., via one or more crushers/mills and one or more calciners, to produce a metal oxide stream 206A (including MgO) and a CO2 product stream 206B. Alternatively, to produce MgO for weathering, one could calcine serpentinite, driving off H2O and minor CO2, to create reactive material composed of MgO and amorphous Mg3Si2O7. After a few weathering and calcining cycles, this would become MgO and SiO2. Metal oxide stream 206A is then distributed to carbonation plots 202 as the composition for sequestering atmospheric CO2 via carbonation reactions, i.e., ambient weathering.|[0035] In this embodiment, conveyors 212C act as the connection between carbonation plots 202 and a calcination plant 208. Conveyors 212C will transport the carbonation product from plots 202 back into the calcination plant once the year has elapsed, as well as spread calcined mineral provided therefrom.|[0036] In this embodiment, 10 conveyors are used. As discussed above, metal oxide stream 206A is transported to carbonation plots 202 where it is deposited and allowed to carbonate over a given timescale, e.g., over the course of a year. At least a portion of the ambiently weathered composition in carbonation plots 202 is then recollected, primarily in the form of magnesium carbonate, and transported to calciner 208. In some embodiments, the material is re-fed to preprocessor 206 with additional magnesite feedstock 204A to make up for environmental losses. In some embodiments, the material is re-ground in preprocessor 206. In the preprocessor 206 and calciner 208, the material is once again heated to regenerate MgO, e.g., as metal oxide stream 208A. In an exemplary embodiment, a CO2 stream 208B is generated from ambiently weathered composition in addition to that previously generated at 206B in processing the feedstock. In some embodiments, the process continues cyclically. In some embodiments, the process continues semi-continuously. In some embodiments, the process continues continuously. Overall, in this embodiment, MgCO3 feedstock is calcined to produce caustic MgO and high-purity CO2. The MgO is spread over land to react with atmospheric CO2 to reform magnesite and other Mg-carbonate minerals over the course of a year. After renewed formation of Mg-carbonate minerals, it is collected and calcined again, producing a nearly pure stream of CO2 together with an amorphous, solid MgO residue. The resulting MgO can be exposed to weathering again, and so on.|[0037] When analyzing the effectiveness of system 100, such as the embodiment shown in FIG. 2, the produced MgO is assumed to have the same aqueous reactivity as mineral brucite (Mg(OH)2). The rate of formation of magnesium carbonate via reaction of aqueous brucite is on the order of 3 x 10−8 moles m−1s−1 when mineral dissolution kinetics are rate limiting. Thus, for example, grains of brucite with a diameter of 10 to 100 microns (1.7 x 10−1° to 1.7 x 10−7 moles, 1.25 x 10−9 to 1.25 x 10−7 m2, assuming spherical grains), are predicted to be completely transformed to magnesite in less than a year. In practice, larger porous grains with a higher surface area to volume ratio than spheres would also be transformed in a year.|[0038] Existing data suggest that under conditions of near 100% relative humidity, conversion of MgO to Mg(OH)2 can occur on the order of hours, indicating over the course of a year hydration reaction is not rate limiting. This conversion is further dependent on the specific surface area and relative humidity of the system (or water vapor partial pressure) with higher partial pressures resulting in faster conversion. Since conversion of MgO to Mg(OH)2 in the presence of water is much faster than the rate of carbonation of Mg(OH)2, it was assumed the carbonation step is rate limiting. Thus, the rate of carbonation can be assumed as the effective rate for the system of FIG. 2.|[0039] The major process assumptions and parameters for the upper and lower bounds of the analysis are outlined in Table 1. Based on these considerations, it was assumed that 20 μm particles of caustic magnesia achieve 90% carbonation within a year. The number of carbonation plots in the analysis is optimized to keep the calciner continuously operational, avoiding startup and shutdown expenses. The upper and lower bounds correspond to the effect of each parameter on overall process cost, not necessarily the magnitude of each parameter value.|TABLE 1 Assumptions and parameters used for the upperand lower bounds in the process model ValueParameter/AssumptionLower BoundUpper Bound CalcinationCalcination Temperature [° C.]6001200Calcination Time [hr]20.5Time Between Calcination Loads [hr]0.25Heat of Decarbonation [kJ mol−1]118Kiln Efficiency [%]90Calcination Efficiency [%]90CarbonationCO2 Uptake Capacity [mol CO21molMgO−1]MgO Layer Thickness [m]0.1Particle Size [μm]20Environmental Losses [% cycle−1]510Carbonation Efficiency [%]90Stirring Equipment [Acres Unit125Equipment−1]Number of Plots350410512Energy Costs and EmissionsNatural Gas [$ GJ−1]3.5Natural Gas [kg CO2 GJ−1]59Gasoline [$ gallon−1]2.60Gasoline [kg CO2 gallon−1]8.89Grid Electricity [$ GJ−1]16.7Grid Electricity [kg CO2 GJ−1]150Solar Electricity [$ GJ−1]16.7Future Solar Electricity [$ GJ−1]8Solar Electricity [kg CO2 GJ−1]6.9Raw Material (Mining) Emissions [kg10CO2 tMineral−1]Economic ParametersCapacity Factor [%]90Plant Economic Lifetime [yr]20Discount Rate [%]411Capital Recovery Factor [%]7.412.6 |[0040] Three scenarios were explored in this analysis, related to the type, cost and emissions of electricity used. The first scenario used grid electricity, assuming electricity is taken directly from the commercial grid. The second scenario used solar electricity, assuming electricity is obtained via utility solar plants at current market price. The third scenario used a projected cost of solar electricity, assuming a decrease in utility solar electricity cost by 2030 as projected by the DOE.|[0041] The scale of operation used 50,000 tons of magnesite-including raw mineral per carbonation plot. Here the emissions value associated with mining magnesite was 10 kgCO2 tMgCO3−1, while typical range from 1.3-12.5 kgCO2 tmineral−1. The chosen value is on the higher side of reported values for mining emissions, and the process is not sensitive to these emissions due to repeated reuse of MgO from the feedstock. For this analysis, it was assumed the feedstock is available at the desired particle size of 20 μm or that this particle size is achieved in a first preprocessing/calcination step. Weathering in this process takes place on land at ambient conditions. MgO is spread on land in layers 0.1 m thick and stirred daily. Values for the capital costs of this equipment are approximated as large-scale agricultural tillage equipment.|[0042] When estimating magnesite use in this system, there are two main considerations: the initial supply of magnesite to each carbonation facility and the makeup supply of magnesite each subsequent year of facility operation. For the initial supply of magnesite, there are two cases: the lower bound utilizing 3,504 carbonation plots with 5% environmental losses and the upper bound utilizing 10,512 carbonation plots with 10% environmental losses. For both cases, the initial plots are each populated with 50,000 tMgCO3. The upper bound uses 525 MtMgCO3 to capture 180 MtCO2, or 6.2% of global reserves (estimated to be 8.5 billion tons of known, economically and legally producible magnesite). Additionally, with 10% environmental losses, the upper bound process would use 53 MtMgCO3 in replacement magnesite each year or 0.6% of global reserves.|[0043] For the lower bound, the initial mineral charge is 175 MtMgCO3 or 2% of global magnesite reserves to capture 64 MtCO2. For makeup minerals, the upper bound assumed 5% environmental losses, corresponding to an additional 8.7 MtMgCO3 per year or 0.1% of global reserves. Removing 1 GtCO2 from air per year would initially charge 2.9 GtMgCO3 or roughly 29% of global magnesite reserves. The makeup supply would use between 0.15-0.29 GtMgCO3 per year, or roughly 1.7-3.4% of global magnesite reserves.|[0044] The system analyzed here has between 3,504 (lower bound) and 10,512 (upper bound) carbonation plots, each with 21,500 tMgO from the original 50,000 tMgCO3 feedstock. The number of carbonation plots are optimized for continuous calciner operation. Since the upper bound and lower bound have 30 minute and 2 hour calcination cycles, respectively, more plots are processed per year in the upper bound scenario. By populating each plot with MgO at different times during the year, they can be recollected and calcined at varying times throughout the year. Additionally, it was assumed that 90 to 95% of the MgO will be recollected as MgCO3 or unreacted MgO and between 5% and 10% of this material will be lost to the environment. Losses of MgCO3 were calculated to be 0.03 to 0.05% per year and MgO will near 3 to 4% per year|[0045] The magnesite feedstock was calcined at temperatures ranging from 500-1200° C. For this analysis, two sets of calcination conditions are used: 600° C. for 2 hours (lower bound) and 1200° C. for 0.5 hours (upper bound). Calcining at 600° C. for 2 hours yields a higher specific surface area (93.07 m2 g−1 for a 2-5 mm feed pre-calcination) which will aid in subsequent carbonation reactions. The calcination conditions of 1200° C. for 0.5 hours result in a decreased surface area (10.9 m2 g−1 for a 2-5 mm feed pre-calcination). For this process, the calciner is continuously operational with a capacity factor of 90% to account for routine maintenance.|[0046] An oxy-fired calciner was used, which included an air separation unit and a condenser. Combustion energy and CO2 outputs were estimated for oxidation of pure methane. Following combined combustion and calcination, the gas stream was fed into the condenser where water was removed. Since oxy-fired calcination is used, the resulting flue gas stream has high concentrations of CO2 and water vapor, indicating a high purity stream of CO2 will be produced following condensation of water vapor. CO2 removed from Mg-carbonates, and CO2 produced from combustion, can be compressed and permanently stored or sold. Additionally, the condensation step produces 0.3 tons of water for every tCO2 captured from air.|[0047] To move calcined MgO to the plot of land used for weathering, an electric conveyor was used. Transportation operating costs are related to electricity used by the conveyor system which was determined using motor power details for commercially available mining conveyors (373 kW (500 HP) with a capacity of 454 t hr−1).|[0048] For recollection and delivery to conveyors, the associated pieces of equipment are assumed to be commercially available front-loading tractors. By staggering plot maturation times, central calcination equipment can be used continuously for multiple carbonation plots throughout the year. This also allows for more CO2 capture without increasing the operational scale, i.e., equipment sizing or throughput.|[0049] Without wishing to be bound by theory, after undergoing repeated calcination, sintering may have a significant effect on MgO reactivity. Studies evaluating capacity losses for magnesium-based adsorbents suggest that after 10 cycles CO2 uptake capacity diminishes by 5-7%. This would correspond to a capacity loss between 2 and 17% over the plant lifetime, depending on amount of makeup material and number of cycles undergone by material lost to the environment. This analysis assumes 5-10% losses in each cycle, accounting for both environmental losses and possible sintering effects so the initial MgO lasts for 10 to 20 cycles.|[0050] The largest contributions to the capital costs of the system were raw material costs at 81-86% of capital costs, the oxy-fired calciner at 9-10% of capital costs, and the air separation unit and condenser at 2-7% of the capital costs. The costing method and scaling factor used for each piece of equipment are presented in Table 2.|TABLE 2 Estimated capital expenditures (CAPEX)for the MgO looping process. Cost [M$]CAPEXLower BoundUpper Bound Raw Mineral8760110376Air Separation Unit and7852260CondenseraOxy-Fired Calcinera93012202Land1291796Transportation (Conveyor1291050System)aStirring Equipment2884Recollection Equipment2267Total CAPEX [M$]$10,783$127,835CAPEX Annualized [M$ year−1]$794$16,053CO2 Capture from Air [GtCO20.0640.198year−1]Total CO2 Capture [GtCO20.120.34year−1]CAPEX [$ tCO2−1 Captured]$12$89CAPEX [$ tCO2−1 Produced]$7$47 aAssumed a scale-up factor|[0051] Each capital cost value is scaled to the individual process conditions. Here, the upper bound is processing 0.18 Gt CO2 year−1 using 10,512 carbonation plots and the lower bound is processing 0.06 Gt CO2 year−1 using 3,504 carbonation plots. Since the upper bound is processing about 3 times more CO2 than the lower bound, the capital cost per ton CO2 is significantly less for the lower bound compared to the upper bound.|[0052] Table 3 shows the energy use and energy type for each unit operation. The main energy demand of the process is for calcination which depends on calcining temperature. Therefore, the energy use per ton CO2 vary between the lower and upper bounds.|TABLE 3 Energy Use for the CO2 sequestration process Energy Use LowerUpperEnergyUnit OperationBoundBoundType Air Separation Unit and Condenser300300Electricity[MJ tCO2−1]Oxy-Fired Calciner [MJ tCO2−1]58887966Natural GasTransportation [MJ tCO2−1]89ElectricityStirring Equipment [Gallons tCO2−1]0.290.31GasolineRecollection Equipment [Gallons0.00510.0054GasolinetCO2−1] |[0053] Table 4 details the operating costs for the CO2 sequestration system. There are no variations in the cost between grid and solar electricity scenarios as the cost of electricity is identical. Variations between these energy resource scenarios arise when considering CO2 emissions.|TABLE 4 Operating expenditures (OPEX) for the MgO looping process Cost [M$] OPEXLower BoundUpper Bound Maintenance3233,835 Labor971,151 Makeup minerals953 Gasoline50151 Natural Gas1,3105,036 Electricity327929 Total OPEX [M$]$2,117$11,154 Total OPEX [$ tCO2−1]$33$62 Captured] Total OPEX [$ tCO2−1]$17$32 Produced] |[0054] The largest contribution to operating costs is the natural gas for powering the calciner, making up 45-62% of operating costs for all scenarios. This indicates process operating costs can be sensitive to the price of natural gas. Additionally, electricity makes up 8-16©© of operating costs. Other major contributions to operation costs are maintenance (15-34%) and labor (5-10%), which are directly correlated to capital costs.|[0055] The cost of CO2 combines the capital and operating costs presented in the previous sections to develop a process cost per tCO2. These costs are shown in Table 5.|TABLE 5 Summary of CO2 capture costs for the MgO looping process GridSolarSolar Elec-ElectricityElectricity tricity($0.06 kWh−1)($0.03 kWh−1) Capture cost [$ tCO2−1]46-15146-15143-148Net Removal Cost [$ tCO2−1]48-15946-15244-149Produced Cost [$ tCO2−1]29-79 29-79 25-77 |[0056] While the cost of capture for the solar electricity scenario is the same as for the grid electricity scenario, the cost of CO2 net removed is ˜4% less for the solar scenario compared to the grid scenario. This is caused by the reduction in CO2 emissions associated with solar electricity versus grid electricity. Additionally, when accounting for projected cost reduction of solar electricity, the CO2 net removed process cost is reduced by ˜7% compared to grid electricity.|[0057] For the exemplary process presented here, the cost of CO2 net removed ranges from $46-159 tCO2−1 using current costs of grid and solar electricity, while the cost of CO2 produced ranges from $29-79 tCO2−1. Using future cost projections for solar electricity yields $43-149 tCO2−1 net removed and $25-77 tCO2−1 produced. Currently, DAC technologies have been demonstrated on the industrial and pilot scales with costs of CO2 net removed reported at $500-600 tCO2−1. Aside from industrial-scale initiatives, literature values for DAC technologies using joint carbonation and calcination processes have been described. In their analysis, the American Physical Society (APS) developed a cost estimate of $610-780 tCO2−1 net removed for the aqueous calcium looping system using sodium hydroxide. By varying the packing materials used in the process and optimizing the process around this new material, a similar process at $510-568 tCO2−1 net removed was developed.|[0058] Referring now to FIG. 3, some embodiments of the present disclosure are directed to a method 300 for utilizing alkalinity to sequester carbon dioxide from the atmosphere. At 302, a composition including one or more metal oxides is provided. As discussed above, the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. As discussed above, the composition is at least in part composed of processed feedstock, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. In some embodiments, providing 302 a composition includes grinding the feedstock to an average particle size of about 20 μm. In some embodiments, providing 302 a composition includes calcining the feedstock to produce an additional CO2 stream and a calcined feedstock including the one or more metal oxides.|[0059] [58] At 304, the composition is distributed into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering. In some embodiments, the composition is distributed 304 to greater than about 5 carbonation plots. In some embodiments, the carbonation plots include greater than about 20,000 tons of metal oxides available for ambient weathering. In some embodiments, the composition is distributed in the carbonation plots as a layer. In some embodiments, the layer has a thickness of about 0.01 m, 0.02 m, 0.03 m, 0.04 m, 0.05 m, 0.06 m, 0.07 m, 0.08 m, 0.09, 0.1 m, 0.2 m, or 0.3 m. At 306, atmospheric CO2 is captured via the one or more metal oxides to produce an ambiently weathered composition. In some embodiments, the ambiently weathered composition is recollected after a certain duration of exposure. In some embodiments, the duration of exposure is about a month, 2, months, 3 months, 4 months, 5 months, 6 months, 7 months, 8 months, 9 months, 10 months, 11 months, a year, or about 1.5 years. At 308, the ambiently weathered composition is calcined to generate a calcined composition and a CO2 stream. In some embodiments, the ambiently weathered composition is calcined for a duration between about 30 minutes and about 2 hours. In some embodiments, the ambiently weathered composition is calcined at a temperature between about 500° C. and about 1200° C. At 310, the calcined composition is distributed into the plurality of carbonation plots.|[0060] In some embodiments of method 300, the composition within the plurality of carbonation plots is stirred to maximize exposure of the composition to the atmosphere. In some embodiments, the composition is stirred once a week, month, quarter, 6 months, year, etc. Any suitable system or mechanism, e.g., commercially-available farming equipment, can be used to stir the composition. Without wishing to be bound by theory, after undergoing repeated calcination, the pores in the particles of the composition begin to clog causing metal oxides to deactivate. Studies have demonstrated that the reaction capacity of CaO diminishes by greater than half the original capacity after 45 cycles. In some embodiments, a grinding process is used to periodically produce new metal oxides. Since the presence of magnesium in the original silicate structure appears to decrease this deactivation, 35 cycles at maximum carbonation capacity can be used to determine the amount of CO2 captured per ‘batch’ of MgO from the initial pre-preprocessing step. In some cases, the number of cycles for the natural weathering system will not be limited by the deactivation, but rather by the environmental losses of MgO. In some embodiments, in the case of 10% environmental losses, the MgO is assumed to last 10 cycles on average and the periodic replacement of MgO can be built in to the operating costs.|[0061] Referring now to FIG. 4, some embodiments of the present disclosure are directed to a method 400 for utilizing alkalinity to sequester carbon dioxide from the atmosphere. At 402, a source of feedstock is provided. As discussed above, in some embodiments, the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof. At 404, the feedstock is processed to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2. As discussed above, in some embodiments, the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. As discussed above, in some embodiments, processing 404 includes one or more grinding steps, one or more calcination steps, or combinations thereof. At 406, the processed feedstock is provided to a network of carbonation plots configured to expose the processed feedstock to ambient weathering. As discussed above, in some embodiments, the network of carbonation plots includes more than about 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1,000, 1,500, 2,000, 2,500, 3,000, 3,500, 4,000, 4,500, 5,000, or 10,000 plots. At 408, a contents of the carbonation plots is stirred to maximize exposure of the metal oxides in the carbonation plots to atmospheric CO2. At 410, atmospheric CO2 is captured via the one or more metal oxides to produce an ambiently weathered composition, e.g., for about 1 year. At 412, the ambiently weathered composition is calcined to generate a CO2 stream and regenerate metal oxides as a calcined composition, e.g., at a temperature between about 500° C. and about 1200° C. At 414, the calcined composition is distributed into the plurality of carbonation plots.|[0062] The methods and systems of the present disclosure are advantageous in that they offer a less expensive route than other current and proposed techniques to remove CO2 from air. The systems and methods of the present disclosure enable capture and redistribution of “net-zero” carbon dioxide for industrial-scale uses for very abundant quarry minerals and enable large-scale low-cost carbon capture projects for municipalities or corporations. CO2 captured using this method can be sold as a commodity (for carbonated beverages, enhanced oil recovery, greenhouses, etc.) or used to make (nearly) “net zero” carbon products (CO2-added concrete, air-to-fuels, etc.).|[0063] CO2 removal from air via the methods and systems of the present disclosure have a similar or lower cost than CO2 removal using DAC with synthetic sorbents or solvents. The process is relatively simple and robust and is feasible at a reasonable cost using existing technology. Additionally, the proposed process integrates CO2 capture from the oxy-fired calcination unit so the cost of produced CO2, both removed from air and captured from combustion, is competitive with other sources. When compared to ideas about enhanced, surficial weathering of rocks—mine tailings, ground rock material broadcast on agricultural soils or on beaches, distributing CaO and MgO for “ocean liming”—the disclosure outlined here reduces the area footprint substantially, since one ton of CaO and MgO can be used to capture many tons of CO2, year after year.|[0064] The method for CO2 removal from air is also less costly than the projected, future minimum cost for CDR machines. Using low carbon energy sources, e.g., PV at a cost of $0.03/kWh, and capturing CO2 emissions from the process, this process potentially removes CO2 at less than $100/ton, whereas optimistic predictions of the future cost of CO2 production using CDR machines yield a minimum cost of $100/ton. The cost of arable land was used to develop this analysis due to the availability of land prices. Since arable land is in higher demand due to its ability to grow crops, it is possible that the cost analysis presented here even overestimates the land cost.|[0065] Although the disclosed subject matter has been described and illustrated with respect to embodiments thereof, it should be understood by those skilled in the art that features of the disclosed embodiments can be combined, rearranged, etc., to produce additional embodiments within the scope of the invention, and that various other changes, omissions, and additions may be made therein and thereto, without parting from the spirit and scope of the present invention. | Family Number|(92128920)|92128920|Advantages / Prev. Drawbacks|(WO2020263910 A1)| (...) and future C02 emissions from the atmosphere, some of which include the acceleration of natural processes such as the C02 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS) and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(AU2020307562 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS) and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(US20220347650 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS) and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.| | Chemical engineering|Environmental technology | B01D-053/62|B01D-053/81|B01D-053/96|B01D-2251/304|B01D-2251/402|B01D-2251/404|B01D-2251/602|B01D-2253/1124|B01D-2257/504|B01D-2258/06|B01J-020/04/1|B01J-020/10|B01J-020/28/004|B01J-020/28/016|B01J-020/30/21|B01J-020/30/78|B01J-020/34/83|Y02C-020/40 | B01D-053/62|B01D-053/81|B01D-053/96|B01D-2251/304|B01D-2251/402|B01D-2251/404|B01D-2251/602|B01D-2253/1124|B01D-2257/504|B01D-2258/06|B01J-020/04/1|B01J-020/10|B01J-020/28/004|B01J-020/28/016|B01J-020/30/21|B01J-020/30/78|B01J-020/34/83|Y02C-020/40 | B01D-053/34|B01D-053/62|B01D-053/77|B01D-053/81|B01D-053/96|B01J-020/04|B01J-020/10|B01J-020/28|B01J-020/30|B01J-020/34 | B01D-053/34|B01D-053/62|B01D-053/77|B01D-053/81|B01D-053/96|B01J-020/04|B01J-020/10|B01J-020/28|B01J-020/30|B01J-020/34 | WO2023212567|JP2024512355|WO2025262426;WO2025262426|WO2024211540|CN116550447|US20230192543|WO202602422|EP4670824|GB2642057|WO2024211540|US12521676|US11938446|US20240069580|EP4551316;EP4551316;EP4551316|WO202411170|DE102022133893|EP4452884|WO2023122540|EP4423498;EP4423498;EP4423498|WO202372879|US11938445|US11964233|US12083475|IT202200016347|US11980172|JP2024512355|DE102021127692|US12533623 | WO2023212567 107091398 WHO=Examiner SELF=N CAT=X|JP2024512355 101683925 WHO=Examiner SELF=Y CAT=X|WO2025262426 111031938 WHO=Examiner SELF=N CAT=I CAT=X CAT=Y|WO2024211540 111695406 WHO=Examiner SELF=N CAT=A|CN116550447 106027091 WHO=Examiner SELF=N CAT=A|US20230192543 105329529 WHO=Examiner SELF=N CAT=103|WO202602422 117255527 WHO=Applicant SELF=N|EP4670824 117255527 WHO=Applicant SELF=N|GB2642057 111031938 WHO=Examiner SELF=N|WO2024211540 111695406 WHO=Applicant SELF=N|US12521676 107508821 WHO=Applicant SELF=N|US11938446 104364067 WHO=Applicant SELF=N|US20240069580 108609889 WHO=Examiner SELF=N|EP4551316 108462320 WHO=Applicant SELF=N|WO202411170 108035748 WHO=Applicant SELF=N|DE102022133893 110267759 WHO=Applicant SELF=N|EP4452884 105329529 WHO=Applicant SELF=N|WO2023122540 105329529 WHO=Applicant SELF=N|EP4423498 104701796 WHO=Applicant SELF=N|WO202372879 104701796 WHO=Applicant SELF=N|US11938445 104027867 WHO=Examiner SELF=N|US11964233 104027867 WHO=Applicant SELF=N|US12083475 104027867 WHO=Applicant SELF=N|IT202200016347 108462320 WHO=Applicant SELF=N|US11980172 97079576 WHO=Applicant SELF=N|JP2024512355 101683925 WHO=Applicant SELF=Y|DE102021127692 104701796 WHO=Applicant SELF=N|US12533623 97699359 WHO=Applicant SELF=N | US20140154162|US20140154162|US8413420|US8413420|CN109790044|US20160031757|US20160031757|CN103582611|US20090202410|WO200861305|CN101378826|US20040213705|US20040213705|RU2151012 | US20140154162 4131565 WHO=Examiner SELF=N CAT=Y|US20140154162 4131565 WHO=Examiner SELF=N CAT=Y|US8413420 44909293 WHO=Examiner SELF=N CAT=Y|US8413420 44909293 WHO=Examiner SELF=N CAT=Y|CN109790044 78658234 WHO=Examiner SELF=N CAT=A|US20160031757 72132109 WHO=Examiner SELF=N CAT=A|US20160031757 72132109 WHO=Examiner SELF=N CAT=A|CN103582611 15065813 WHO=Examiner SELF=N CAT=A|US20090202410 4163858 WHO=Examiner SELF=N CAT=A|WO200861305 6473502 WHO=Examiner SELF=N CAT=A|CN101378826 6476359 WHO=Examiner SELF=N CAT=A|US20040213705 1759232 WHO=Examiner SELF=N CAT=A|US20040213705 1759232 WHO=Examiner SELF=N CAT=A|RU2151012 36093105 WHO=Examiner SELF=N | 周安宁,黄定国: "洁净煤技术", 31 July 2010, 中国矿业大学出版社, pages: 288 (Cat. A)|黎锡流,曾利容: "甘蔗糖厂综合利用", 31 October 1998, 中国轻工业出版社, pages: 42 - 43 (Cat. A) | XP055779004; US20140154162; US20040213705; US20160031757|US20140154162; US20040213705; US20160031757; XP055779004; US8413420; XP026736686|RU2151012|WO200861305; CN101378826; US20090202410; US8413420; CN103582611; CN109790044; XP055779004| | (EP3986597)|Search Report references [Examiner]|-HARTMANN JENS ET AL: "Enhanced chemical weathering as a geoengineering strategy to reduce atmospheric carbon dioxide, supply nutrients, and mitigate ocean acidification", REVIEWS OF GEOPHYSICS, vol. 51, no. 2, 23 May 2013 (2013-05-23), pages 113 - 149, XP055779004, ISSN: 8755-1209, Retrieved from the Internet <URL:https://api.wiley.com/onlinelibrary/tdm/v1/articles/10.1002%2Frog.20004> DOI: 10.1002/rog.20004|-HANGX S J T ET AL: "Coastal spreading of olivine to control atmospheric CO"2 concentrations: A critical analysis of viability", INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, ELSEVIER, AMSTERDAM, NL, vol. 3, no. 6, 1 December 2009 (2009-12-01), pages 757 - 767, XP026736686, ISSN: 1750-5836, [retrieved on 20090803], DOI: 10.1016/J.IJGGC.2009.07.001|-See also references of WO 2020263910A1|||(WO2020/263910)|International Search Report [Examiner]|-JENS HARTMANN A. JOSHUA WEST PHIL RENFORTH PETER KÖHLER CHRISTINA L. DE LA ROCHA DIETER A. WOLF‐GLADROW HANS H. DÜRR JÜRGEN: "Enhanced chemical weathering as a geoengineering strategy to reduce atmospheric carbon dioxide, supply nutrients, and mitigate ocean acidification", REVIEWS OF GEOPHYSICS, vol. 51, no. 2, 15 February 2013 (2013-02-15), pages 113 - 149, XP055779004, ISSN: 8755-1209, DOI: 10.1002/rog.20004|-See also references of EP 3986597A4||(CN114390943)|Search Report references [Examiner]|-HARTMANN, J ET AL: "Enhanced chemical weathering as a geoengineering strategy to reduce atmospheric carbon dioxide, supply nutrients, and mitigate ocean acidification", REVIEWS OF GEOPHYSICS, vol. 51, no. 2, pages 113 - 149, XP055779004, DOI: 10.1002/rog.20004|| | PENDING | (EP3986597)|PENDING|(US20220347650)|PENDING|(WO2020/263910)|LAPSED|(CN114390943)|PENDING|(AU2020307562)|LAPSED | ALIVE | (EP3986597)|ALIVE|(US20220347650)|ALIVE|(WO2020/263910)|DEAD|(CN114390943)|ALIVE|(AU2020307562)|DEAD | (EP3986597)|LEGAL DETAILS FOR EP3986597|Actual or expected expiration date=2040-06-24|Legal 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group=Examination events|Published application|Publication country=CN|Publication number=CN114390943|Publication stage code=A|Publication date=2022-04-22|Standardized publication number=CN114390943|Event publication date=2022-04-22|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2022-05-10|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|(AU2020307562)|LEGAL DETAILS FOR AU2020307562|Actual or expected expiration date=2026-01-22|Legal state=DEAD|Status=LAPSED|Event publication date=2020-06-24|Event code=AU/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=AU AU2020307562|Application date=2020-06-24|Standardized application number=2020AU-0307562|Event publication date=2022-02-03|Event code=AU/A1|Event indicator=Pos|Event group=Examination events|Open to public inspection|Publication country=AU|Publication number=AU2020307562|Publication stage code=A1|Publication date=2022-02-03|Standardized publication number=AU2020307562|Event publication date=2026-01-22|Event code=AU/MK4|Event indicator=Neg|Event group=Event indicating Not In Force|Application lapsed section 142(2)(d) - no continuation fee paid for the application | (EP3986597)|Contracting States: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, LI, RO, NL, TR|(WO2020/263910)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2020/263910)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2020/263910)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2020/263910)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2020/263910)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IR, IS, AL, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, ME, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP3986597)|EP|(US20220347650)|US|(WO2020/263910)|CN; EP; US|(CN114390943)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=B9hVsxmBAQgQB8D+doR/s3mXtI+wKb3KNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000020744983&ekey=2121&xpn=EP3986597&kind=A4 | https://register.epo.org/application?number=EP20832919 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=zPRNAYoICSvdGqGyRhNS9XfDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2020/263910)|US | (WO2020/263910)|NAME=THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK 412 Low Memorial Library 535 West 116th Street New York, NY 10027 , COUNTRY=US | (EP3986597)|GB|(WO2020/263910)|US||(AU2020307562)|AU | (EP3986597)|NAME=Barker Brettell LLP;100 Hagley Road Edgbaston , CITY=Birmingham B16 8QQ , COUNTRY=GB , REG=101716225|(WO2020/263910)|NAME=GANGEMI, Anthony, P. Murtha Cullina LLP One Century Tower 9th Floor New Haven, CT 06510 , POSTCODE=06510 , COUNTRY=US|(CN114390943)|NAME=DONG QING;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC , REG=31100NAME=LE HONGYONG;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC , REG=31100|(AU2020307562)|NAME=Spruson & Ferguson GPO Box 3898 , CITY=Sydney , STATE=NSW , POSTCODE=2001 , COUNTRY=AU | |(EP3986597)|US; US; US; CA; GB|(US20220347650)|US; US; US; CA; GB|(WO2020/263910)|US; US; US; CA; GB|| | (EP3986597)|NAME=KELEMEN, Peter|NAME=WILCOX, Jennifer|NAME=MCQUEEN, Noah|NAME=DIPPLE, Greg|NAME=RENFORTH, Phil|(EP3986597)|NAME=KELEMEN, Peter 2 Clinton Avenue, CITY=Nyack, NY 10960, COUNTRY=US |NAME=WILCOX, Jennifer 600 W. Main Street, CITY=Northborough, MA 01532, COUNTRY=US |NAME=MCQUEEN, Noah 9007 W. 106th Street, CITY=Oveerland Park, KS 66212, COUNTRY=US |NAME=DIPPLE, Greg 2020-2207 Main Mall, CITY=Vancouver, British Columbia, V6T1Z4, COUNTRY=CA |NAME=RENFORTH, Phil 4 Newpark Mews, CITY=Livington EH549GX, COUNTRY=GB|(US20220347650)|NAME=KELEMEN Peter, CITY=Nyack, STATE=NY , COUNTRY=US |NAME=WILCOX Jennifer, CITY=Northborough, STATE=MA , COUNTRY=US |NAME=McQUEEN Noah, CITY=Overland Park, STATE=KS , COUNTRY=US |NAME=DIPPLE Greg, CITY=Vancouver, COUNTRY=CA |NAME=RENFORTH Phil, CITY=Livingston, COUNTRY=GB|(WO2020/263910)|NAME=KELEMEN, Peter 2 Clinton Avenue Nyack, NY 10960, POSTCODE=10960, COUNTRY=US |NAME=WILCOX, Jennifer 600 W. Main Street Northborough, MA 01532, POSTCODE=01532, COUNTRY=US |NAME=MCQUEEN, Noah 9007 W. 106th Street Oveerland Park, KS 66212, POSTCODE=66212, COUNTRY=US |NAME=DIPPLE, Greg 2020-2207 Main Mall Vancouver, British Columbia, V6T1Z4, POSTCODE=V6T1Z4, COUNTRY=CA |NAME=RENFORTH, Phil 4 Newpark Mews Livington EH549GX, POSTCODE=EH549GX, COUNTRY=GB|(CN114390943)|NAME=KLEMEN PETER|NAME=WILCOX JENNIFER|NAME=MAIKKUN NIRMAL|NAME=DIEP GAVIN|NAME=REFFERS PAUL|(AU2020307562)|NAME=KELEMEN, Peter|NAME=WILCOX, Jennifer|NAME=MCQUEEN, Noah|NAME=DIPPLE, Greg|NAME=RENFORTH, Phil | (WO2020/263910)|4|(US20220347650)|4|(CN114390943)|4|(AU2020307562)|4 | 4 | 5 | (EP3986597)|WO2020/263910|(US20220347650)|WO2020/263910|(CN114390943)|WO2020/263910|(AU2020307562)|WO2020/263910 | (US20220347650)|Number of Claims: NCL=20|Number of Drawings: NDR=4|Number of Figures: NFG=4|Independent Claim Number: ICL=1,8,20|Number of Independent Claims: NICL=3|Exemplary Claim Number: ECL=1||(WO2020/263910)|Number of Claims: NCL=20|Extended kind: EXTK=x||(CN114390943)|Number of Claims: NCL=20|Gazette date: GAZDATE=2022-04-22|Gazette number: GAZNUM=38-1602|Substantial examination effective date: 20220510|Number of Pages: NPAGES=19||(AU2020307562)|Number of Claims: NCL=20| | (US20220347650)|Provisional Appl: US63/043,038 FDD=2020-06-23 [2020US-63043038]|Provisional Appl: US62/865,708 FDD=2019-06-24 [2019US-62865708] | (EP3986597)|ENGLISH (ENG) | (EP3986597)|Patent|(US20220347650)|Patent|(EP3986597)|Patent|(CN114390943)|Patent|(AU2020307562)|Patent|(WO2020263910)|Patent | Titre: (EP3986597)|Systems and methods for enhanced weathering and calcining for c02 removal from air Résumé: (EP3986597)|A plurality of carbonation plots are positioned in communication with atmospheric carbon dioxide to facilitate sequestration thereof via ambient weathering. The carbonation plots include a composition rich in metal oxides, which are positioned within the environment, such as on non-arable land, and exposed to the environment to react with carbon dioxide in the air and form metal carbonates. After about one year of exposure, the composition is recollected and calcined to produce a carbon dioxide stream and replenish the metal oxides, which can be redistributed in the carbonation plots to sequester additional carbon dioxide. The systems and methods of the present disclosure enable capture and redistribution of carbon dioxide for industrial-scale uses for very abundant quarry minerals and enable large-scale low-cost carbon capture projects for municipalities or corporations. C02 removal from air via these methods and systems have a similar or lower cost than C02 removal using DAC with synthetic sorbents or solvents. Autre: (US20220347650)|What is claimed is:|1. A system utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising:| at least one carbonation plot including a composition including one or more metal oxides, the at least one carbonation plot positioned to expose the composition to ambient weathering;| a feedstock source including a feedstock, wherein at least a portion of the one or more metal oxides is derived from the feedstock;| a preprocessing system in communication with the feedstock source, the preprocessing system configured to reduce the feedstock to a desired particle size;| a calciner configured to heat the feedstock, composition, or combinations thereof, to a predetermined temperature; and| a composition recycling system to transport composition to the calciner and return calcined composition to the at least one carbonation plots,| wherein the system is configured to maintain exposure of the composition to ambient weathering for a year.|2. The system according to claim 1, wherein the system includes greater than about 5 carbonation plots.|3. The system according to claim 2, wherein the system includes greater than about 3,500 carbonation plots.|4. The system according to claim 1, wherein the at least one carbonation plot includes greater than about 20,000 tons of metal oxides available for ambient weathering.|5. The system according to claim 1, wherein the average particle size of the composition is about 20 μm.|6. The system according to claim 1, wherein the composition is included in the carbonation plot as a layer, wherein the layer has a thickness of about 0.1 m.|7. The system according to claim 1, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof.|8. A method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising:| providing a composition including one or more metal oxides;| distributing the composition into a plurality of carbonation plots, the plots positioned to expose the composition to ambient weathering;| capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition;| calcining the ambiently weathered composition to generate a calcined composition and a CO2 stream; and| distributing the calcined composition into the plurality of carbonation plots.|9. The method according to claim 8, further comprising stirring the composition within the plurality of carbonation plots.|10. The method according to claim 8, wherein capturing atmospheric CO2 via the one or more metal oxides to produce an ambiently weathered composition includes:| recollecting the composition as the ambiently weathered composition after about 1 year of exposure to the atmosphere.|11. The method according to claim 8, wherein the composition is at least in part composed of processed feedstock, wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof.|12. The method according to claim 11, wherein providing a composition includes:| grinding the feedstock to an average particle size of about 20 μm.|13. The method according to claim 12, wherein providing a composition includes:| calcining the feedstock to produce an additional CO2 stream and a calcined feedstock including the one or more metal oxides.|14. The method according to claim 8, wherein calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes:| calcining the ambiently weathered composition for a duration between about 30 minutes and about 2 hours.|15. The method according to claim 8, wherein calcining the ambiently weathered composition to generate calcined composition and a CO2 stream includes:| calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C.|16. The method according to claim 8, wherein the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof.|17. The method according to claim 8, wherein the plurality of carbonation plots includes greater than about 5 carbonation plots.|18. The method according to claim 8, wherein the plurality of carbonation plots includes greater than about 20,000 tons of metal oxides available for ambient weathering.|19. The method according to claim 8, wherein the composition is distributed in the plurality of carbonation plots as a layer, wherein the layer has a thickness of about 0.1 m.|20. A method for utilizing alkalinity to sequester carbon dioxide (CO2) from the atmosphere comprising:| providing a source of feedstock;| processing the feedstock to maximize metal oxides in the feedstock and reaction rate of the feedstock with atmospheric CO2;| providing the processed feedstock to a network of carbonation plots configured to expose the processed feedstock to ambient weathering;| stirring a contents of the carbonation plots;| capturing atmospheric CO2 via the one or more metal oxides for about 1 year to produce an ambiently weathered composition;| calcining the ambiently weathered composition at a temperature between about 500° C. and about 1200° C. to generate a CO2 stream and regenerate metal oxides as a calcined composition; and| distributing the calcined composition into the plurality of carbonation plots,| wherein the feedstock includes magnesite, peridotite, serpentinite, olivine, serpentine, brucite, sodium carbonate, dunite, calcite, dolomite, wollastonite, pyroxenes, or combinations thereof, and the one or more metal oxides includes MgO, CaO, Na2O, or combinations thereof. | 27 | Abstract | gpt-4o-mini | no | The article focuses on CO₂ removal from the air through enhanced weathering and does not involve biomass energy production or carbon capture and storage related to biomass. | ||||||||||||||
| 26 | IT202000031562|IT102020000031562|WOIB2021/061832|US18/258,956|US18/779,205 | US18/779,205|CL2023001837|WOIB2021/061832|IN202317042419|AEP6001584/2023|CA3202902|CN202180087205|US18/258,956|EP21847532|AU2021404910|IT202000031562 | CA3202902|US20240375076|AEP6001584/2023|CN116964002|US12070720|IN202317042419|EP4267282|EP4267282|US20230390699|CL2023001837|EP4267282|CN116964002|AU2021404910|CA3202902|WO2022/137038|IT202000031562 | 100675112 | US20240375076 A1 2024-11-14 [US20240375076]|CL2023001837 A1 2023-11-24 [CL202301837]|WO2022/137038 A1 2022-06-30 [WO2022137038]|IN202317042419 A 2024-08-02 [IN202317042419]|AEP6001584/2023 A1 2024-10-29 [AE20236001584]|CA3202902 C 2025-05-13 [CA3202902]|CA3202902 A1 2022-06-30 [CA3202902]|CN116964002 B 2024-09-20 [CN116964002B]|CN116964002 A 2023-10-27 [CN116964002]|US12070720 B2 2024-08-27 [US12070720]|US20230390699 A1 2023-12-07 [US20230390699]|EP4267282 B1 2024-05-01 [EP4267282]|EP4267282 C0 2024-05-01 [EP4267282]|EP4267282 A1 2023-11-01 [EP4267282]|AU2021404910 A1 2023-07-06 [AU2021404910]|IT202000031562 A1 2022-06-22 [IT202000031562] | 2020-12-22|2021-12-16|2023-06-22|2024-07-22 | 2024-07-22|2023-06-20|2021-12-16|2023-06-24|2023-06-20|2021-12-16|2021-12-16|2021-12-16|2021-12-16|2021-12-16|2020-12-22 | 2025-05-13|2024-11-14|2024-10-29|2024-09-20|2024-08-27|2024-08-02|2024-05-01|2024-05-01|2023-12-07|2023-11-24|2023-11-01|2023-10-27|2023-07-06|2022-06-30|2022-06-30|2022-06-22 | (EP4267282)|2024-05-01|(US12070720)|2024-08-27|||(CN116964002B)|2024-09-20|(CA3202902)|2025-05-13||||| | (EP4267282)|2041-12-16|(US12070720)|2041-12-16|(US20240375076)|2041-12-16|(WO2022/137038)|2024-06-22|(CN116964002)|2041-12-16|(CA3202902)|2041-12-16|(AEP6001584/2023)|2041-12-16|(IN202317042419)|2041-12-16|(CL2023001837)|2043-06-20|(AU2021404910)|2041-12-16|(IT202000031562)|2040-12-22 | (EP4267282)|Plant and method for producing decarbonized oxide or hydroxide using carbonate and electric power | (EP4267282)|A plant and a method for producing decarbonized oxide or hydroxide using carbonate, water and electric power are described. The plant (100) comprises an electric calciner (10), a contactor (20), a pH correction apparatus (30) and a dosing device (40). The plant (100) is adapted to receive at the inlet electric power, carbonate and water, and to release at the outlet decarbonized oxide or hydroxide and a buffered ionic mixture rich in bicarbonates, which, once released into the sea, represents the permanent storage for CO2. The plant (100) uses the bicarbonates as permanent CO2 storage in the sea: this storage allows a CO2 storage at low costs and in modular plants. | LIME NETWORK SOCIAL EFFECT|LIMENET BENEFIT|LIMENET SOC BENEFIT|LIMENET SOCIETA BENEFIT | (EP4267282)|Limenet S.r.l. Societa' Benefit|(EP4267282)|Limenet S.r.l. Societa' Benefit ([IT])|(EP4267282)|Limenet S.r.l. Societa' Benefit ([IT])|(US12070720)|LIMENET S.R.L. SOCIETA' BENEFIT ([IT])|(US20230390699)|LIMENET S.R.L. SOCIETA' BENEFIT ([IT])|(US20240375076)|LIMENET S.R.L. SOCIETA' BENEFIT ([IT])|(WO2022/137038)|CAPPELLO, Giovanni|(CN116964002)|LIME NETWORK SOCIAL EFFECT, LLC ([IT])|(CN116964002)|LIME NETWORK SOCIAL EFFECT, LLC ([IT])|(CA3202902)|LIMENET S.R.L. SOCIETA' BENEFIT ([IT])|(CA3202902)|LIMENET S.R.L. BENEFIT ([IT])|(AEP6001584/2023)|LIMENET SRL SOCIETA' BENEFIT ([IT])|(IN202317042419)|LIMENET SRL SOCIETA BENEFIT|(CL2023001837)|LIMENET S.R.L. SOCIETA' BENEFIT|(AU2021404910)|LIMENET S.R.L. SOCIETA' BENEFIT|(IT202000031562)|Cappello, Giovanni | CAPPELLO GIOVANNI | (EP4267282)|CAPPELLO, Giovanni|(EP4267282)|CAPPELLO, Giovanni|(EP4267282)|CAPPELLO, Giovanni | (EP4267282)|Belloni, Giancarlo;Thinx S.r.l. ([IT])|Reg. Nb: 101882651|(US12070720)|Maier & Maier, PLLC|(WO2022/137038)|BELLONI, Giancarlo et al. ([IT])|(CN116964002)|LI JIE;BEIJING KANGXIN INTELLECTUAL PROPERTY LTD.|Reg. Nb: 11240|(CA3202902)|CPST INTELLECTUAL PROPERTY INC. ([CA])|Reg. Nb: 12179|(AEP6001584/2023)|ABU GHAZALEH INTELLECTUAL PROPERTY - DUBAI BRANCH|Reg. Nb: 557523|(AU2021404910)|Baxter Patent Attorneys Pty Ltd ([AU]) | (EP4267282)|As a skilled person can certainly understand, the process for producing decarbonized oxide or hydroxide according to the invention makes it possible to permanently store CO2 in the sea in the form of bicarbonates and on land in the form of carbonates at a cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|As can be immediately understood, there is a need to identify a technology that allows the production of oxides through the carbonate calcination process to be carried out with simple technologies and to solve the problem of storing CO2 in a distributed form throughout the territory at an acceptable cost. The task of the present invention is to make available a method and a plant that can enable the efficient generation of oxides by calcination of carbonates with permanent storage of CO2 at lower costs than known technologies.|As the skilled person can well conclude, the method and the plant according to the invention make it possible to produce decarbonized oxide or hydroxide: it is thus possible to overcome one of the most important technical/economic obstacles to the spread of the plants for the permanent storage of the CO2 and for the generation of negative emissions worldwide and with competitive costs.|In a per se known form, the reaction of Ca(OH)2 (where Ca can be substituted with Mg if present in the carbonate) with seawater is a complex reaction due to the presence of other chemical elements and therefore it results that for each mole of Ca(OH)2 it is possible to neutralise less than the 2 moles of CO2 envisaged by the stoichiometry of the equation Ca(OH)2 + 2CO2 + H2O Ca(HCO3)2(aq).|It is therefore impossible to decarbonize the lime industry if no permanent CO2 storage is available, even if the fuels used in the calcination process were completely renewable.|The catastrophic effects of such a situation on the climate are easy to see and difficult to avoid especially because developing nations believe that the renewable energy option is too sophisticated and costly, and are more oriented towards short-term economic development programmes than towards CO2 emission containment and environmental issues.| | (EP4267282)|1. Plant (100) for producing decarbonized oxide or hydroxide, comprising an electric calciner (10), a contactor (20), a pH correction apparatus (30) and a dosing device (40), wherein: - the electric calciner (10) is adapted to receive at the inlet a flow of carbonate (110), electric power (120) and to release at the outlet at least one flow of carbonic gas (140) at high temperature and at least one flow of oxide (130); - the flow of oxide (130) is adapted to provide a flow of buffering substance; - the contactor (20) is adapted to receive at the inlet the flow of carbonic gas (140) released by the electric calciner (10), a flow of carbonate (220), a flow of water (210); - the contactor (20) is adapted to make the carbonate (220) react with water (210) and the CO2 present in the carbonic gas (140) according to the following reactions CO 2 aq + H 2 O l ⇌ H 2 CO 3 aq ⇌ H aq + + HCO 3 aq − and CaCO3 + CO2 + H2O Ca(HCO3)2(aq) (where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet at least one flow of ionic mixture (230); - the contactor (20) is provided with means for releasing non-soluble gases (221); - the pH correction apparatus (30) is adapted to receive at the inlet at least one flow of buffering substance (440; 640) and the flow of ionic mixture (230), is adapted to make the ionic mixture (230) react with the buffering substance (440; 640) according to the following reactions CaO + H2O + 2CO2 Ca(HCO3)2(aq) or Ca(OH)2(aq)+2CO2 Ca(HCO3)2(aq) and to release at the outlet a flow of buffered ionic mixture (240); - the dosing device (40) is adapted to receive at the inlet a flow of buffering substance (130; 630) deriving from the electric calciner (10) and to release at the outlet a predetermined quantity of buffering substance (440; 640) to feed the pH correction apparatus (30) and possibly a quantity of buffering substance (450; 650) available for use.|9. Decarbonized calcination method comprising the steps of: - providing an electric calciner (10); - feeding the electric calciner (10) with electric power (120) and a flow of carbonate (110; 111) in order to obtain the calcination of the carbonate (110) according to the reaction CaCO3 CaO + CO2 (where Ca can be substituted with Mg if present in the carbonate); - releasing at the outlet of the electric calciner (10) a flow of carbonic gas (140) at high temperature and a flow of oxide (130); - conveying the flow of carbonic gas (140); - conveying the flow of oxide (130); - from the flow of oxide (130) obtaining a flow of buffering substance (440; 640); - providing a contactor (20); - feeding the contactor (20) with the flow of carbonic gas (140) produced by the electric calciner (10) and a predetermined flow of water (210) in order to obtain a flow of ionic mixture (230) through the reaction CO 2 aq + H 2 O l ⇌ H 2 CO 3 aq ⇌ H aq + + HCO 3 aq − ; - releasing the flow of ionic mixture (230) at the outlet of the contactor (20); - conveying the ionic mixture (230); - providing a dosing device (40); - feeding the flow of buffering substance (130, 630) to the dosing device (40); - releasing a predetermined flow of buffering substance (440; 640) at the outlet of the dosing device (40); - conveying the flow of buffering substance (440; 640); - providing a pH correction apparatus (30); - feeding the pH correction apparatus (30) with the flow of ionic mixture (230) and with the predetermined flow of buffering substance (440; 640) so that the reactions take place CaO + H2O + 2CO2 Ca(HCO3)2(aq) or Ca(OH)2(aq)+2CO2 Ca(HCO3)2(aq) ; - releasing the flow of buffered ionic mixture (240) at the outlet of the pH correction apparatus (30); - placing the flow of buffered ionic mixture (240) into the sea.| | (EP4267282)|A first aspect of the invention concerns a plant 100 for producing decarbonized oxide or hydroxide.|A second aspect of the invention concerns a method for decarbonized calcination.|The present invention relates to a method and a plant for producing decarbonized oxide or hydroxide using carbonate and electric power.| | (US12070720)|CARBONATE(100,83)|BUFFERING SUBSTANCE(100,76)|HYDROXIDE(100,58)|OXIDE(100,55)|PLANT(100,34)|CALCINATION(100,14)|ELECTRICAL POWER(100,12)|BUFFERING SUBSTANCE FLOW(61,45)|CALCINER OUTLET(47,4)|PH CORRECTION(43,40)|ELECTRIC CALCINER(41,47)|HYDROXIDE PRODUCTION(29,35)|CARBONATE CALCINATION(28,2)|DECARBONIZE LIME INDUSTRY(28,1)|DOSING(27,29)|DOSING OUTLET(26,4)|CARBONATE PREHEATING(25,12)|CO2 EMISSION CONTAINMENT(25,1)|CONTACTOR(24,52)|EQUATION CA STOICHIOMETRY(24,1)|CALCINER OUTLET FLOW(23,4)|GEOLOGICAL CCS(23,1)|ELECTRIC CALCINER OUTLET(22,3)|DOSING INLET(22,1)|GEOLOGICAL CCS COST(22,1)|HCO(18,31)|RELEASING NONSOLUBLE GAS(18,2)|CARBONATE FLOW(17,14)|PERMANENT CO2 STORAGE(17,2)|PH CORRECTION OUTLET(17,2)|HYDROXIDE FLOW(15,10)|CO2 PERMANENT STORAGE(15,5)|NEGATIVE EMISSION GENERATION(15,1)|TECHNICAL ECONOMIC OBSTACLE(14,1)|CO2(13,60)|PERMANENT STORAGE(13,7)|PREHEATED CARBONATE FLOW(13,4)|EQUATION CA(13,1)|MODULAR PLANT(13,1)|RENEWABLE ENERGY ALTERNATIVE(13,1)|CARBONIC GAS(12,48)|SEA(11,12)|BICARBONATE(11,9)|NEGATIVE CO2 EMISSION(11,5)|BIOENERGY(11,1)|COMPETITIVE COST(11,1)|STORE CO2(11,1)|TERRITORY(11,1)|ALKALINITY(10,7)|H2CO(9,7)|NEGATIVE EMISSION(9,3)|COMPLEX REACTION(9,1)|DEVELOPING NATION(9,1)|CO2(8,3)|CLIMATE(8,2)|HARDNESS MEASUREMENT(8,2)|BECCS(8,1)|OBTAINING FLOW(8,1)|DAC(7,1)|ECONOMIC DEVELOPMENT(7,1)|SEAWATER(6,11)|CACO(6,4)|ENVIRONMENTAL ISSUE(6,2)|CO2 SEQUESTRATION(5,5)|CAO(5,4)|CALCINING(5,3)|NEGATIVE CO2 EMISSION TON(5,3)|INLET ELECTRICAL POWER(5,1)|H2O(4,6)|CALCITE CONTACTOR(4,2)|CONTROL DOSING(4,2)|LIMESTONE CONTACTOR(4,2)|ECONOMY FUTURE DECARBONIZATION(4,1)|RESOURCE HUGE AVAILABILITY(4,1)|SHORT TERM ECONOMIC DEVELOPMENT(4,1)|PERSON(3,32)|ELECTRIC KWHE(3,3)|CALCINING ZONE(3,2)|CARBONATE ROCK(3,2)|EMISSION SHARE(3,2)|PH METER(3,2)|ANTHROPOGENIC CO2(3,1)|AUTHORITATIVE STUDY(3,1)|CALCITE SATURATION(3,1)|DEEP SALINE AQUIFER(3,1)|DISSOLUTION KINETICS(3,1)|DOLOMITE CAMG(3,1)|DOLOMITIC SEDIMENTARY ROCK(3,1)|MGCO3 CALCINATION(3,1)|NONLIMITING INTENT(3,1)|OCEAN LIMING(3,1)|ORE DECOMPOSITION(3,1)|PHYSICOCHEMICAL CRITERIA(3,1)|RESIDUAL CO2 DEGASSING(3,1)|RESIDUAL CO2 TREND(3,1)|BARA(2,11)|REACTION CA(2,4)|ACIDIC EFFLUENT(2,2)|CHEMICAL ELEMENT(2,2)|ENERGY CONTRIBUTION(2,2)|PH ADJUSTMENT(2,2)|ABSORBING CO2(2,1)|ADVANCED COUNTRY(2,1)|BUFFERING SUBSTANCE INSERTION(2,1)|CAPTURING CO2(2,1)|CARBONATE AVAILABILITY(2,1)|CARBONATE PRECIPITATION(2,1)|CO2 CAPTURE PROHIBITIVE COST(2,1)|CO2 EMISSION PERMANENT STORAGE(2,1)|CO2 HYDRATION(2,1)|CO2 TON YEAR(2,1)|COMBAT GLOBAL WARMING(2,1)|CONSUMPTION LAMP(2,1)|DEGASSING CO2(2,1)|DEPOSIT DISCOVERY(2,1)|DESALINIZATION TREATMENT(2,1)|DIRECT AIR CAPTURE(2,1)|EFFLUENT DISCHARGE(2,1)|ENTIRE COUNTRY INDUSTRIALIZATION(2,1)|EQUILIBRIUM CURVE(2,1)|EQUILIBRIUM GRAPH(2,1)|FOREIGN SUBSTANCE(2,1)|INEFFICIENT COAL(2,1)|INTERNATIONAL COMMUNITY EFFORT(2,1)|LIME INDUSTRY(2,1)|LIMESTONE MILL(2,1)|MARGINAL IMPACT(2,1)|MICROWAVE GENERATOR(2,1)|MINERAL CARBONATION(2,1)|NEGATIVE EMISSION TON(2,1)|SCIENTIFIC COMMUNITY EFFORT(2,1)|SEA FLOOR(2,1)|SEA PH(2,1)|SEQUESTERING CO2(2,1)|TECHNOLOGICAL EFFORT(2,1)|VAPOR TURBINE(2,1)|CONTROL UNIT(1,13)|SLURRY(1,4)|SALE(1,3)|ACIDITY(1,2)|CRUSHING(1,2)|IMPURITY(1,2)|INVESTMENT(1,2)|AKALINE EARTH METAL BICARBONATE(1,1)|AKALINITY(1,1)|ARAGONITE(1,1)|BASIC SUBSTANCE(1,1)|CA TOTAL CONTENT(1,1)|CALCINING REACTION(1,1)|CALCIUM CARBONATE CACO3(1,1)|CALCIUM OXIDE CAO(1,1)|CARBONATE COST(1,1)|CARBONATE DECREASE(1,1)|CARBONATE PARTICLE(1,1)|CARBONATE PREHEATED FLOW(1,1)|CARBONIC ACID H2CO(1,1)|CHOICE TECHNOLOGY(1,1)|CIVIL WORK(1,1)|CO2 ATMOSPHERE(1,1)|CO2 COMING(1,1)|CO2 EXCESS(1,1)|CO2 STORAGE COST(1,1)|DIRECTIVE(1,1)|DRINKING WATER REMINERALISATION(1,1)|ELECTRIC CALCINATION(1,1)|ELECTRICAL CALCINER(1,1)|HYDROXIDE OH(1,1)|INITIATIVE(1,1)|LCOE LEVELIZED COST(1,1)|LIQUID BASICITY(1,1)|NONSOLUBLE GAS(1,1)|REACTION CO2(1,1)|REMINERALISING DRINKING WATER(1,1)|SEQUESTERING CARBON DIOXIDE(1,1)|SERVICE ACCOUNT(1,1)|TON COST(1,1)||(US20230390699)|CARBONATE(100,76)|HYDROXIDE(100,58)|OXIDE(100,43)|BUFFERING SUBSTANCE(100,40)|PLANT(100,31)|CALCINATION(100,13)|ELECTRICAL POWER(100,12)|ELECTRIC CALCINER(87,49)|PH CORRECTION(75,38)|BUFFERING SUBSTANCE FLOW(57,18)|DECARBONIZE LIME INDUSTRY(54,1)|CARBONATE CALCINATION(53,2)|CARBONATE PREHEATING(48,12)|CO2 EMISSION CONTAINMENT(47,1)|CONTACTOR(46,52)|GEOLOGICAL CCS(44,1)|GEOLOGICAL CCS COST(41,1)|BUILT CACO(39,1)|DOSING(37,24)|HCO(37,18)|DOSING OUTLET(34,2)|ELECTRIC CALCINER OUTLET(34,2)|HYDROXIDE PRODUCTION(33,25)|PERMANENT CO2 STORAGE(33,2)|PH CORRECTION OUTLET(32,2)|CO2 PERMANENT STORAGE(29,5)|TECHNICAL ECONOMIC OBSTACLE(29,1)|NEGATIVE EMISSION GENERATION(28,1)|CARBONATE FLOW(27,13)|PERMANENT STORAGE(25,7)|CO2(24,52)|CARBONIC GAS(24,49)|BUILT PLACING(24,1)|MODULAR PLANT(24,1)|RENEWABLE ENERGY ALTERNATIVE(24,1)|H2CO(23,3)|NONSOLUBLE GAS(23,3)|SEA(22,12)|COMPETITIVE COST(22,1)|STORE CO2(22,1)|TERRITORY(22,1)|BICARBONATE(21,8)|NEGATIVE CO2 EMISSION(21,5)|ALKALINITY(20,7)|BIOENERGY(20,1)|BUILT FEEDING(19,4)|CARBONATE PREHEATED FLOW(19,3)|CACO(19,1)|DEVELOPING NATION(18,1)|NEGATIVE EMISSION(17,3)|COMPLEX REACTION(17,1)|BECCS(16,1)|CO2(15,3)|PRE HEATING FLOW(15,3)|CLIMATE(15,2)|HARDNESS MEASUREMENT(15,2)|CARBONATE BUILT WATER(15,1)|SEAWATER(13,11)|DAC(13,1)|ECONOMIC DEVELOPMENT(13,1)|HYDROXIDE FLOW(12,4)|ENVIRONMENTAL ISSUE(12,2)|PREHEATED CARBONATE FLOW(12,2)|CAO(11,3)|CO2 SEQUESTRATION(10,5)|CALCINING(10,3)|BUILDING WATER(10,1)|INLET ELECTRICAL POWER(10,1)|BUILT RELEASE(9,16)|CALCITE CONTACTOR(8,2)|CONTROL DOSING(8,2)|LIMESTONE CONTACTOR(8,2)|ECONOMY FUTURE DECARBONIZATION(8,1)|RESOURCE HUGE AVAILABILITY(8,1)|SHORT TERM ECONOMIC DEVELOPMENT(8,1)|EMISSION SHARE(7,2)|PH METER(7,2)|BUILT NONLIMITING INTENT(7,1)|PERSON(6,32)|BUILT BICARBONATE HCO(6,1)|DEEP SALINE AQUIFER(6,1)|DOLOMITIC SEDIMENTARY ROCK(6,1)|RESIDUAL CO2 DEGASSING(6,1)|RESIDUAL CO2 TREND(6,1)|BARA(5,11)|BUILT CARBONATE(5,3)|CALCINING ZONE(5,2)|CARBONATE ROCK(5,2)|CHEMICAL ELEMENT(5,2)|ANTHROPOGENIC CO2(5,1)|AUTHORITATIVE STUDY(5,1)|BUILT VAPOR TURBINE(5,1)|CALCITE SATURATION(5,1)|DISSOLUTION KINETICS(5,1)|DOLOMITE CAMG(5,1)|MGCO3 CALCINATION(5,1)|OCEAN LIMING(5,1)|ORE DECOMPOSITION(5,1)|PHYSICOCHEMICAL CRITERIA(5,1)|BUILDING ENERGY BALANCE(4,6)|MASS BUILT ENERGY BALANCE(4,6)|ACIDIC EFFLUENT(4,2)|ENERGY CONTRIBUTION(4,2)|PH ADJUSTMENT(4,2)|ABSORBING CO2(4,1)|ADVANCED COUNTRY(4,1)|BUFFERING SUBSTANCE INSERTION(4,1)|BUILT DOLOMITE(4,1)|BUILT WORLD POLITICS(4,1)|CARBONATE AVAILABILITY(4,1)|CARBONATE PRECIPITATION(4,1)|CO2 BUILT TRACE(4,1)|CO2 CAPTURE PROHIBITIVE COST(4,1)|CO2 EMISSION PERMANENT STORAGE(4,1)|CO2 HYDRATION(4,1)|CO2 YEAR(4,1)|COMBAT GLOBAL WARMING(4,1)|CONSUMPTION LAMP(4,1)|DEGASSING CO2(4,1)|DEPOSIT DISCOVERY(4,1)|DESALINIZATION TREATMENT(4,1)|DIRECT AIR CAPTURE(4,1)|EFFLUENT DISCHARGE(4,1)|ENTIRE COUNTRY INDUSTRIALIZATION(4,1)|EQUILIBRIUM CURVE(4,1)|EQUILIBRIUM GRAPH(4,1)|FOREIGN SUBSTANCE(4,1)|INEFFICIENT COAL(4,1)|INTERNATIONAL COMMUNITY EFFORT(4,1)|LIME INDUSTRY(4,1)|LIMESTONE MILL(4,1)|MARGINAL IMPACT(4,1)|MICROWAVE GENERATOR(4,1)|MINERAL CARBONATION(4,1)|SCIENTIFIC COMMUNITY EFFORT(4,1)|SEA FLOOR(4,1)|SEA PH(4,1)|SEQUESTERING CO2(4,1)|TECHNOLOGICAL EFFORT(4,1)|SLURRY(3,4)|ACIDITY(3,2)|CRUSHING(3,2)|IMPURITY(3,2)|INVESTMENT(3,2)|AKALINE EARTH METAL BICARBONATE(3,1)|BUILT DEVELOPING COUNTRY(3,1)|BUILT GLOBAL WARMING(3,1)|CALCINING REACTION(3,1)|CALCIUM CARBONATE CACO3(3,1)|CARBONATE DECREASE(3,1)|CARBONATE PARTICLE(3,1)|CARBONIC ACID H2CO(3,1)|CHOICE TECHNOLOGY(3,1)|CIVIL WORK(3,1)|CO2 ATMOSPHERE(3,1)|CO2 COMING(3,1)|CO2 EXCESS(3,1)|DIRECTIVE(3,1)|DRINKING WATER REMINERALISATION(3,1)|ELECTRIC CALCINATION(3,1)|ELECTRICAL CALCINER(3,1)|HYDROXIDE OH(3,1)|INITIATIVE(3,1)|LCOE LEVELIZED COST(3,1)|LIQUID BASICITY(3,1)|REMINERALISING DRINKING WATER(3,1)|SEQUESTERING CARBON DIOXIDE(3,1)|SERVICE ACCOUNT(3,1)|TON COST(3,1)|CONTROL UNIT(2,13)|SALE(2,3)|AKALINITY(2,1)|ARAGONITE(2,1)|BASIC SUBSTANCE(2,1)|BUILT MG(2,1)|BUILT RENEWABLE ELECTRICAL POWER(2,1)|CA TOTAL CONTENT(2,1)|CALCIUM OXIDE CAO(2,1)|CARBONATE COST(2,1)||(US20240375076)|CARBONATE(100,83)|BUFFERING SUBSTANCE(100,76)|HYDROXIDE(100,58)|OXIDE(100,54)|PLANT(100,34)|CALCINATION(100,14)|ELECTRICAL POWER(100,12)|BUFFERING SUBSTANCE FLOW(61,45)|CALCINER OUTLET(54,6)|PH CORRECTION(43,40)|CALCINER(30,15)|CARBONATE CALCINATION(28,2)|DECARBONIZE LIME INDUSTRY(28,1)|HYDROXIDE PRODUCTION(27,33)|DOSING OUTLET(26,4)|DOSING(25,28)|CO2 EMISSION CONTAINMENT(25,1)|CALCINER OUTLET FLOW(23,4)|GEOLOGICAL CCS(23,1)|CONTACTOR(22,51)|CARBONATE PREHEATING(22,11)|DOSING INLET(22,1)|GEOLOGICAL CCS COST(22,1)|BIOMASS DERIVED FUEL(21,2)|GREEN HYDROGEN(21,2)|HCO(19,19)|RELEASING NONSOLUBLE GAS(18,2)|CARBONATE FLOW(17,14)|PERMANENT CO2 STORAGE(17,2)|PH CORRECTION OUTLET(17,2)|WASTE DERIVED FUEL(17,2)|HYDROXIDE FLOW(15,10)|CO2 PERMANENT STORAGE(15,5)|NEGATIVE EMISSION GENERATION(15,1)|ELECTRIC CALCINER(14,33)|TECHNICAL ECONOMIC OBSTACLE(14,1)|PERMANENT STORAGE(13,7)|PREHEATED CARBONATE FLOW(13,4)|MODULAR PLANT(13,1)|RENEWABLE ENERGY ALTERNATIVE(13,1)|CARBONIC GAS(12,48)|CACO(12,5)|SEA(11,12)|BICARBONATE(11,9)|NEGATIVE CO2 EMISSION(11,5)|BIOENERGY(11,1)|COMPETITIVE COST(11,1)|DERIVATION(11,1)|STORE CO2(11,1)|TERRITORY(11,1)|ALKALINITY(10,8)|NEGATIVE EMISSION(9,3)|COMPLEX REACTION(9,1)|DEVELOPING NATION(9,1)|CO2(8,42)|CO2(8,3)|CLIMATE(8,2)|HARDNESS MEASUREMENT(8,2)|BECCS(8,1)|OBTAINING FLOW(8,1)|DAC(7,1)|ECONOMIC DEVELOPMENT(7,1)|SEAWATER(6,11)|CAO(6,3)|ENVIRONMENTAL ISSUE(6,2)|CO2 SEQUESTRATION(5,5)|CALCINING(5,3)|NEGATIVE CO2 EMISSION TON(5,3)|INLET ELECTRICAL POWER(5,1)|CALCITE CONTACTOR(4,2)|CONTROL DOSING(4,2)|LIMESTONE CONTACTOR(4,2)|ECONOMY FUTURE DECARBONIZATION(4,1)|RESOURCE HUGE AVAILABILITY(4,1)|SHORT TERM ECONOMIC DEVELOPMENT(4,1)|PERSON(3,32)|ELECTRIC KWHE(3,3)|CALCINING ZONE(3,2)|CARBONATE ROCK(3,2)|EMISSION SHARE(3,2)|PH METER(3,2)|ANTHROPOGENIC CO2(3,1)|AUTHORITATIVE STUDY(3,1)|CALCITE SATURATION(3,1)|DEEP SALINE AQUIFER(3,1)|DISSOLUTION KINETICS(3,1)|DOLOMITE CAMG(3,1)|DOLOMITIC SEDIMENTARY ROCK(3,1)|MGCO3 CALCINATION(3,1)|NONLIMITING INTENT(3,1)|OCEAN LIMING(3,1)|ORE DECOMPOSITION(3,1)|PHYSICOCHEMICAL CRITERIA(3,1)|RESIDUAL CO2 DEGASSING(3,1)|RESIDUAL CO2 TREND(3,1)|BARA(2,11)|KJ MOL(2,8)|ACIDIC EFFLUENT(2,2)|CHEMICAL ELEMENT(2,2)|ENERGY CONTRIBUTION(2,2)|PH ADJUSTMENT(2,2)|ABSORBING CO2(2,1)|ADVANCED COUNTRY(2,1)|BUFFERING SUBSTANCE INSERTION(2,1)|CAPTURING CO2(2,1)|CARBONATE AVAILABILITY(2,1)|CARBONATE PRECIPITATION(2,1)|CO2 CAPTURE PROHIBITIVE COST(2,1)|CO2 EMISSION PERMANENT STORAGE(2,1)|CO2 HYDRATION(2,1)|CO2 TON YEAR(2,1)|COMBAT GLOBAL WARMING(2,1)|CONSUMPTION LAMP(2,1)|DEGASSING CO2(2,1)|DEPOSIT DISCOVERY(2,1)|DESALINIZATION TREATMENT(2,1)|DIRECT AIR CAPTURE(2,1)|EFFLUENT DISCHARGE(2,1)|ELECTRIC CALCINER OUTLET(2,1)|ENTIRE COUNTRY INDUSTRIALIZATION(2,1)|EQUILIBRIUM CURVE(2,1)|EQUILIBRIUM GRAPH(2,1)|FOREIGN SUBSTANCE(2,1)|INEFFICIENT COAL(2,1)|INTERNATIONAL COMMUNITY EFFORT(2,1)|LIME INDUSTRY(2,1)|LIMESTONE MILL(2,1)|MARGINAL IMPACT(2,1)|MICROWAVE GENERATOR(2,1)|MINERAL CARBONATION(2,1)|NEGATIVE EMISSION TON(2,1)|SCIENTIFIC COMMUNITY EFFORT(2,1)|SEA FLOOR(2,1)|SEA PH(2,1)|SEQUESTERING CO2(2,1)|TECHNOLOGICAL EFFORT(2,1)|VAPOR TURBINE(2,1)|CONTROL UNIT(1,13)|SLURRY(1,4)|SALE(1,3)|ACIDITY(1,2)|CRUSHING(1,2)|IMPURITY(1,2)|INVESTMENT(1,2)|ARAGONITE(1,1)|BASIC SUBSTANCE(1,1)|CA TOTAL CONTENT(1,1)|CALCINING REACTION(1,1)|CALCIUM CARBONATE CACO3(1,1)|CALCIUM OXIDE CAO(1,1)|CARBONATE COST(1,1)|CARBONATE DECREASE(1,1)|CARBONATE PARTICLE(1,1)|CARBONATE PREHEATED FLOW(1,1)|CARBONIC ACID H2CO(1,1)|CHOICE TECHNOLOGY(1,1)|CIVIL WORK(1,1)|CO2 ATMOSPHERE(1,1)|CO2 COMING(1,1)|CO2 EXCESS(1,1)|CO2 STORAGE COST(1,1)|CO2CAPTURE(1,1)|CONTACTOR AVERAGE PRESSURE(1,1)|CORAL(1,1)|DIRECTIVE(1,1)|DRINKING WATER REMINERALISATION(1,1)|ELECTRIC CALCINATION(1,1)|ELECTRICAL CALCINER(1,1)|HYDROXIDE OH(1,1)|INITIATIVE(1,1)|LCOE LEVELIZED COST(1,1)|LIQUID BASICITY(1,1)|NONSOLUBLE GAS(1,1)|REMINERALISING DRINKING WATER(1,1)|SEQUESTERING CARBON DIOXIDE(1,1)|SERVICE ACCOUNT(1,1)|TON COST(1,1)||(WO2022/137038)|CARBONATE(100,82)|HYDROXIDE(100,58)|OXIDE(100,44)|BUFFERING SUBSTANCE(100,40)|PLANT(100,31)|ELECTRICAL POWER(100,13)|HIDROXIDE(100,1)|ELECTRIC CALCINER(89,49)|PH CORRECTION(77,38)|BUFFERING SUBSTANCE FLOW(54,18)|CARBONATE PREHEATING(53,12)|DECARBONIZE LIME INDUSTRY(48,1)|CONTACTOR(47,52)|CARBONATE CALCINATION(47,2)|CO2 EMISSION CONTAINMENT(42,1)|HYDROXIDE PRODUCTION(40,25)|GEOLOGICAL CCS(40,1)|GEOLOGICAL CCS COST(37,1)|DOSING(34,24)|DOSING OUTLET(31,2)|ELECTRIC CALCINER OUTLET(30,2)|PERMANENT CO2 STORAGE(30,2)|CARBONATE FLOW(29,13)|PH CORRECTION OUTLET(29,2)|CALCINATION(28,7)|H2O CA(28,1)|CO2 PERMANENT STORAGE(26,5)|CARBONIC GAS(25,49)|NEGATIVE EMISSION GENERATION(25,1)|TECHNICAL ECONOMIC OBSTACLE(24,1)|PERMANENT STORAGE(23,7)|CARBONATE PREHEATED FLOW(23,3)|MODULAR PLANT(22,1)|RENEWABLE ENERGY ALTERNATIVE(22,1)|ALKALINITY(21,8)|SEA(20,12)|NONSOLUBLE GAS(20,3)|COMPETITIVE COST(20,1)|STORE CO2(20,1)|TERRITORY(20,1)|BICARBONATE(19,9)|NEGATIVE CO2 EMISSION(19,5)|METER(18,7)|PRE HEATING FLOW(18,3)|BIOENERGY(18,1)|CO2(16,46)|HARDNESS(16,5)|NEGATIVE EMISSION(16,3)|DEVELOPING NATION(16,1)|BECCS(15,1)|COMPLEX REACTION(15,1)|HYDROXIDE FLOW(14,4)|CO2(14,3)|CLIMATE(14,2)|HARDNESS MEASUREMENT(14,2)|CONTROL DOSING(12,2)|DAC(12,1)|ECONOMIC DEVELOPMENT(12,1)|SEAWATER(11,11)|ENVIRONMENTAL ISSUE(11,2)|PREHEATED CARBONATE FLOW(11,2)|CO2 SEQUESTRATION(9,5)|CALCINING(9,3)|INLET ELECTRICAL POWER(9,1)|NEUTRALIZE FLUID FLOW(9,1)|CALCITE CONTACTOR(7,2)|LIMESTONE CONTACTOR(7,2)|ECONOMY FUTURE DECARBONIZATION(7,1)|RESOURCE HUGE AVAILABILITY(7,1)|SHORT TERM ECONOMIC DEVELOPMENT(7,1)|EMISSION SHARE(6,2)|PH METER(6,2)|CO2 EMISSION FLEXING(6,1)|DEEP SALINE AQUIFER(6,1)|DOLOMITIC SEDIMENTARY ROCK(6,1)|RESIDUAL CO2 DEGASSING(6,1)|RESIDUAL CO2 TREND(6,1)|PERSON(5,32)|ELECTRIC KWHE(5,3)|CALCINING ZONE(5,2)|CARBONATE ROCK(5,2)|ANTHROPOGENIC CO2(5,1)|AUTHORITATIVE STUDY(5,1)|CALCITE SATURATION(5,1)|DISSOLUTION KINETICS(5,1)|DOLOMITE CAMG(5,1)|MGCO3 CALCINATION(5,1)|NONLIMITING INTENT(5,1)|OCEAN LIMING(5,1)|ORE DECOMPOSITION(5,1)|PHYSICOCHEMICAL CRITERIA(5,1)|BARA(4,11)|ACIDIC EFFLUENT(4,2)|CHEMICAL ELEMENT(4,2)|ENERGY CONTRIBUTION(4,2)|PH ADJUSTMENT(4,2)|ADVANCED COUNTRY(4,1)|BUFFERING SUBSTANCE INSERTION(4,1)|CARBONATE PRECIPITATION(4,1)|CO2 CAPTURE PROHIBITIVE COST(4,1)|CO2 HYDRATION(4,1)|COMBAT GLOBAL WARMING(4,1)|DEPOSIT DISCOVERY(4,1)|DIRECT AIR CAPTURE(4,1)|ENTIRE COUNTRY INDUSTRIALIZATION(4,1)|INEFFICIENT COAL(4,1)|LIMESTONE MILL(4,1)|MINERAL CARBONATION(4,1)|SCIENTIFIC COMMUNITY EFFORT(4,1)|SEQUESTERING CO2(4,1)|TECHNOLOGICAL EFFORT(4,1)|VAPOR TURBINE(4,1)|CONTROL UNIT(3,13)|SLURRY(3,4)|ACIDITY(3,2)|CRUSHING(3,2)|IMPURITY(3,2)|INVESTMENT(3,2)|ABSORBING CO2(3,1)|CALCINING REACTION(3,1)|CALCIUM CARBONATE CACO3(3,1)|CARBONATE AVAILABILITY(3,1)|CARBONATE DECREASE(3,1)|CARBONATE PARTICLE(3,1)|CARBONIC ACID H2CO(3,1)|CHOICE TECHNOLOGY(3,1)|CIVIL WORK(3,1)|CO2 ATMOSPHERE(3,1)|CO2 COMING(3,1)|CO2 EXCESS(3,1)|CO2 YEAR(3,1)|CONSUMPTION LAMP(3,1)|DEGASSING CO2(3,1)|DESALINIZATION TREATMENT(3,1)|DIRECTIVE(3,1)|DRINKING WATER REMINERALISATION(3,1)|EFFLUENT DISCHARGE(3,1)|ELECTRIC CALCINATION(3,1)|ELECTRICAL CALCINER(3,1)|EQUILIBRIUM CURVE(3,1)|EQUILIBRIUM GRAPH(3,1)|FOREIGN SUBSTANCE(3,1)|HYDROXIDE OH(3,1)|INITIATIVE(3,1)|INTERNATIONAL COMMUNITY EFFORT(3,1)|LCOE LEVELIZED COST(3,1)|LIME INDUSTRY(3,1)|LIQUID BASICITY(3,1)|MARGINAL IMPACT(3,1)|MICROWAVE GENERATOR(3,1)|REMINERALISING DRINKING WATER(3,1)|SEA FLOOR(3,1)|SEA PH(3,1)|SEQUESTERING CARBON DIOXIDE(3,1)|SERVICE ACCOUNT(3,1)|TON COST(3,1)|SALE(2,3)|ARAGONITE(2,1)|BASIC SUBSTANCE(2,1)|CA TOTAL CONTENT(2,1)|CALCIUM OXIDE CAO(2,1)|CARBONATE COST(2,1)|CO2 STORAGE COST(2,1)|CONTACTOR AVERAGE PRESSURE(2,1)|CONTINGENT(2,1)|CORAL(2,1)|CORRELATION(2,1)|DEVELOPING COUNTRY(2,1)|DOWNDRAFT(2,1)|ELECTRICAL POWER KWH(2,1)|EQUILIBRIUM CONDITION(2,1)|FLUIDIZED BED(2,1)|FORECAST(2,1)|FOSSIL SOURCE(2,1)|FULL STATE(2,1)||(CN116964002)|CARBONATE(100,79)|HYDROXIDE(100,54)|BUFFER SUBSTANCE(100,40)|OXIDE(100,39)|FACILITY(100,12)|ELECTRICITY(100,10)|ELECTRIC CALCINER(99,45)|FACILITY WORLDWIDE PROMOTION(77,1)|PH CORRECTION(76,33)|BUFFERED ION STREAM(70,6)|CONTACTOR(61,51)|BUFFERED ION(61,13)|CARBONATE PREHEATING(57,12)|WORLDWIDE PROMOTION(54,1)|FEED PH CORRECTION(50,1)|PERMANENT SEQUESTRATION(49,4)|DECARBONATED LIME PRODUCT(46,1)|CARBONATE CALCINATION(43,1)|CALCINER OUTLET(42,2)|CARBONACEOUS GAS(41,8)|HYDROXIDE PRODUCTION(40,25)|PH CORRECTION OUTLET(37,2)|MODULAR FACILITY(33,1)|CARBONATE STREAM(30,2)|INSOLUBLE GAS RELEASE(30,2)|CALCINATION(27,8)|ELECTRICAL POWER(27,3)|DECARBONIZATION(27,2)|PREHEATED CARBONATE STREAM(26,3)|COMPETITIVE COST(26,1)|TECHNICAL ECONOMIC BARRIER(26,1)|REACTIONCAO(25,2)|NEGATIVE EMANATION PRODUCTION(25,1)|CARBONATE FLOW(24,8)|ALKALINITY(23,8)|TECHNICAL OPTION(23,1)|SEA(21,11)|PERMANENT SEQUESTRATION LIMITED AVAILABILITY(21,1)|COMPLEX REACTION(20,1)|HYDRATION(19,2)|CLIMATE(18,2)|DEVELOPING WORLD(18,1)|PREHEATED CARBONATE FLOW(18,1)|HARDNESS(17,7)|METERING DEVICE(16,27)|STEAM(16,5)|SEAWATER(15,10)|ECONOMIC DEVELOPMENT(15,1)|HYDROXIDE FLOW(14,3)|CAO(12,4)|CALCITE CONTACTOR(9,2)|HYDROXIDE CA TON(9,2)|LIMESTONE CONTACTOR(9,2)|SHORT TERM ECONOMIC DEVELOPMENT(9,1)|CONTACTOR DIMENSION(8,2)|DECARBONIZE LIME INDUSTRY(8,1)|FUTURE ECONOMIC DECARBONIZATION(8,1)|HEAT SINK(8,1)|INTERNATIONAL POLITICAL EFFORT(8,1)|PERSON(7,26)|ACIDIC EFFLUENT(7,2)|CARBONATE DISSOLUTION(7,2)|PH METER(7,2)|CALCINING DECARBONIZATION(7,1)|LIMITED AVAILABILITY(7,1)|MASS RATIO(7,1)|OLD INEFFICIENT COAL(7,1)|CALCINING ZONE(6,2)|CARBONATE ROCK(6,2)|EMISSION FRACTION(6,2)|AUTHORITATIVE STUDY(6,1)|BATA GENIA(6,1)|CALCITE SATURATION(6,1)|DISSOLUTION KINETICS(6,1)|DOLOMITE SEDIMENTARY ROCK(6,1)|EMISSIONS CONTROL(6,1)|GEOLOGICAL CCS COST(6,1)|ORE DECOMPOSITION(6,1)|CHEMICAL ELEMENT(5,3)|RECEPTION TEST(5,3)|ENERGY CONTRIBUTION(5,2)|NEGATIVE EMISSION(5,2)|RENEWABLE ENERGY SOURCE(5,2)|BICARBONATE HCO(5,1)|DEPOSIT DISCOVERY(5,1)|FOSSIL RESOURCE(5,1)|GLOBAL WARMING AVOIDANCE(5,1)|HYDROXIDE CARBONATION(5,1)|LIMESTONE MILL(5,1)|MARINE LIME(5,1)|MINERAL CARBONATION(5,1)|PARIS AGREEMENT(5,1)|CARBONATE COST(4,2)|INVESTMENT(4,2)|PH ADJUSTMENT(4,2)|SCIENTIFIC COMMUNITY(4,2)|CALCIUM CARBONATE CACO(4,1)|CARBONATE AVAILABILITY(4,1)|EFFLUENT EMISSION(4,1)|EQUILIBRIUM GRAPH(4,1)|FOREIGN SUBSTANCE(4,1)|MICROWAVE GENERATOR(4,1)|NORWAY WINDY AREA(4,1)|PH PARAMETER(4,1)|RESIDUAL TREND(4,1)|TRANSPORTATION FUEL(4,1)|CONTROL UNIT(3,13)|ABSOLUTE PRESSURE(3,12)|CONTACT TIME(3,7)|SLURRY(3,4)|BRINE LAYER DEPTH(3,1)|CALCINING REACTION(3,1)|CARBONATE ABSENCE(3,1)|CARBONATE DECREASE(3,1)|CARBONATE PARTICLE(3,1)|CARBONATE SALT(3,1)|COMPOUND CALCIUM(3,1)|DIRECTIVE(3,1)|DRINKING WATER REMINERALISATION(3,1)|ELECTROCALCINATION(3,1)|EXPLOITATION(3,1)|FINAL DEGASSING(3,1)|GLOBAL PROTECTION(3,1)|HYDROXIDE PRODUCTION OUTLET(3,1)|HYDROXIDE STREAM(3,1)|INDUSTRIALIZATION(3,1)|INDUSTRIALIZED COUNTRY(3,1)|INSOLUBLE GAS(3,1)|LCOE WIND ENERGY(3,1)|LIQUID BASICITY(3,1)|NEGATIVE TON(3,1)|NONLIMITING(3,1)|POTABLE WATER REMINERALIZATION(3,1)|PRODUCING DECARBONATED OXIDE(3,1)|REVERSE OSMOSIS FACILITY(3,1)|SEQUESTERING CARBON DIOXIDE(3,1)|TARGET INDUSTRY(3,1)|TON COST(3,1)|ACIDITY(2,1)|APPROVAL(2,1)|ARAGONITE(2,1)|BIOENERGY(2,1)|BIOMASS(2,1)|CA TOTAL CONTENT(2,1)|CALCINATION PRODUCT(2,1)|CALCIUM OXIDE CAO(2,1)|CALCIUM OXIDE HYDRATION PRODUCT(2,1)|CARBON STREAM(2,1)|CIVIL ENGINEERING(2,1)|CORRELATION(2,1)|DEVELOPING COUNTRY(2,1)|DOWNDRAFT(2,1)|EMERGING COUNTRY(2,1)|EQUILIBRIUM CONDITION(2,1)|GLOBAL ENERGY DEMAND(2,1)|HELP(2,1)|HYDROXIDE REDUCTION(2,1)|HYDROXYL(2,1)|IMPURITY(2,1)|INDIRECT CONTACT(2,1)|INTERNATIONAL INSTITUTION(2,1)|INTERNATIONAL SOCIETY(2,1)|LESSER EXTENT(2,1)|LEVELING ENERGY COST(2,1)|MAGNESITE(2,1)|MAGNESIUM OXIDE MGO(2,1)||(CN116964002)|CARBONATE(100,69)|HYDROXIDE(100,54)|BUFFER SUBSTANCE(100,40)|OXIDE(100,39)|PLANT(100,16)|FACILITY(100,12)|CALCINATION(100,7)|ELECTRICITY(100,7)|DECARBONIZATION(100,2)|ELECTRIC CALCINER(99,46)|PH CORRECTION(83,34)|BUFFERED ION STREAM(70,6)|BUFFERED ION(68,13)|CARBONATE PREHEATING(57,12)|CONTACTOR(55,44)|CARBONACEOUS GAS(50,10)|GLOBAL SCALEIS(49,1)|HCO(45,8)|CARBONATE CALCINATION(43,1)|PERMANENT SEAL AVAILABILITY(43,1)|CALCINER OUTLET(42,2)|CALCINING CARBONATE(42,1)|HYDROXIDE PRODUCTION(40,25)|REACTION CACO(39,1)|PH CORRECTION OUTLET(37,2)|MODULAR FACILITY(33,1)|SEQUESTRATION(32,9)|CARBONATE STREAM(30,2)|ELECTRICAL POWER(27,3)|PREHEATED CARBONATE STREAM(26,3)|LIME PRODUCT(26,1)|TECHNICAL ECONOMIC BARRIER(26,1)|COMPETITIVE COST(25,1)|PRODUCING NEGATIVE EMISSION(25,1)|CARBONATE FLOW(24,8)|CAPTURE COST(24,1)|ALKALINITY(23,8)|INSOLUBLE GAS(23,2)|PERMANENT SEAL(23,2)|TECHNICAL OPTION(22,1)|SEA(21,11)|COMPLEX REACTION(20,1)|BICARBONATE(18,8)|CLIMATE(18,2)|CAO(18,1)|ENVIRONMENTAL ISSUE(18,1)|PREHEATED CARBONATE FLOW(18,1)|HARDNESS(17,7)|METERING DEVICE(16,27)|STEAM(16,5)|DEVELOPING COUNTRY(16,2)|SEAWATER(15,9)|ECONOMIC DEVELOPMENT(15,1)|CACO(14,5)|HYDROXIDE FLOW(14,3)|CALCITE CONTACTOR(9,2)|HYDROXIDE CA TON(9,2)|LIMESTONE CONTACTOR(9,2)|SHORT TERM ECONOMIC DEVELOPMENT(9,1)|CONTACTOR DIMENSION(8,2)|DECARBONIZE LIME INDUSTRY(8,1)|EMISSION PERMANENT SEQUESTRATION(8,1)|FUTURE ECONOMIC DECARBONIZATION(8,1)|INTERNATIONAL POLITICAL EFFORT(8,1)|WATERTHE PH DEGASSING(8,1)|ACIDIC EFFLUENT(7,2)|CALCINING ZONE(7,2)|CARBONATE ROCK(7,2)|CO2 TON(7,2)|EMISSION FRACTION(7,2)|PH METER(7,2)|CALCINING DECARBONIZATION(7,1)|OLD INEFFICIENT COAL(7,1)|AUTHORITATIVE STUDY(6,1)|BATA GENIA(6,1)|CALCITE SATURATION(6,1)|DISSOLUTION KINETICS(6,1)|DOLOMITE SEDIMENTARY ROCK(6,1)|EMISSIONS CONTROL(6,1)|GEOLOGICAL CCS(6,1)|ORE DECOMPOSITION(6,1)|PERMANENTLY SEALED CONTACTOR(6,1)|PERSON(5,19)|CHEMICAL ELEMENT(5,3)|NEUTRALIZING(5,3)|ENERGY CONTRIBUTION(5,2)|RENEWABLE ENERGY SOURCE(5,2)|CARBONATE DISSOLUTION(5,1)|DEPOSIT DISCOVERY(5,1)|FOSSIL RESOURCE(5,1)|GLOBAL WARMING AVOIDANCE(5,1)|HYDROXIDE CARBONATION(5,1)|LIMESTONE MILL(5,1)|MINERAL CARBONATION(5,1)|PARIS AGREEMENT(5,1)|SEAWATER CARBONATE(5,1)|SLURRY(4,5)|CARBONATE COST(4,2)|INVESTMENT(4,2)|PH ADJUSTMENT(4,2)|SCIENTIFIC COMMUNITY(4,2)|CALCIUM CARBONATE CACO(4,1)|CARBONATE AVAILABILITY(4,1)|CARBONATE PRECIPITATION(4,1)|EFFLUENT EMISSION(4,1)|FOREIGN SUBSTANCE(4,1)|MICROWAVE GENERATOR(4,1)|NORWAY WINDY AREA(4,1)|PH PARAMETER(4,1)|SEA LIME(4,1)|TRANSPORTATION FUEL(4,1)|CONTROL UNIT(3,13)|ACCEPTANCE TEST(3,3)|CALCINING REACTION(3,1)|CARBONATE DECREASE(3,1)|CARBONATE PARTICLE(3,1)|CARBONATE SALT(3,1)|COMPOUND CALCIUM(3,1)|COMPRESSIONTHE FORCE(3,1)|CONVERTING CARBONATE(3,1)|DEEP SALINE LAYER(3,1)|DRINKING WATER REMINERALISATION(3,1)|EMISSION MEASUREMENT(3,1)|EXPLOITATION(3,1)|HYDROXIDE PRODUCTION OUTLET(3,1)|HYDROXIDE STREAM(3,1)|INDUSTRIALIZATION(3,1)|INDUSTRIALIZED COUNTRY(3,1)|ION SUBSTITUTION(3,1)|LCOE WIND ENERGY(3,1)|LIQUID BASICITY(3,1)|NEGATIVE EMISSION(3,1)|POTABLE WATER REMINERALIZATION(3,1)|PRODUCING DECARBONATED OXIDE(3,1)|REVERSE OSMOSIS FACILITY(3,1)|SEQUESTERING CARBON DIOXIDE(3,1)|SEQUESTRATION COST(3,1)|TARGET INDUSTRY(3,1)|TECHNIQUEPERSONNEL(3,1)|TON COST(3,1)|TREND GRAPH(3,1)|WATER CONTACTOR(3,1)|ACIDITY(2,1)|APPROVAL(2,1)|ARAGONITE(2,1)|BIOENERGY(2,1)|BIOMASS(2,1)|CALCINATION PRODUCT(2,1)|CALCIUM OXIDE CAO(2,1)|CARBON STREAM(2,1)|CARBONATE REMAINS(2,1)|CIVIL ENGINEERING(2,1)|CONTACTOR AVERAGE PRESSURE(2,1)|CORRELATION(2,1)|DOWNDRAFT(2,1)|EMERGING COUNTRY(2,1)|EQUILIBRIUM CONDITION(2,1)|FIXATION(2,1)|GLOBAL ENERGY DEMAND(2,1)|HELP(2,1)|HYDRATION PRODUCT(2,1)|HYDROXYL(2,1)|IMPURITY(2,1)|INDIRECT CONTACT(2,1)|INTERNATIONAL INSTITUTION(2,1)|INTERNATIONAL SOCIETY(2,1)|LANDMOST(2,1)|LESSER EXTENT(2,1)|LEVELING ENERGY COST(2,1)||(IN202317042419)|CARBONATE(100,81)|HYDROXIDE(100,57)|OXIDE(100,43)|BUFFERING SUBSTANCE(100,40)|PLANT(100,30)|ELECTRICAL POWER(100,12)|CALCINATION(100,7)|HIDROXIDE(100,1)|ELECTRIC CALCINER(87,49)|PH CORRECTION(75,38)|BUFFERING SUBSTANCE FLOW(57,18)|DECARBONIZE LIME INDUSTRY(54,1)|CARBONATE CALCINATION(53,2)|CARBONATE PREHEATING(48,12)|CO2 EMISSION CONTAINMENT(47,1)|CONTACTOR(46,52)|GEOLOGICAL CCS(44,1)|GEOLOGICAL CCS COST(41,1)|DOSING(37,24)|DOSING OUTLET(34,2)|ELECTRIC CALCINER OUTLET(34,2)|RELEASING NONSOLUBLE GAS(34,2)|HYDROXIDE PRODUCTION(33,25)|PERMANENT CO2 STORAGE(33,2)|PH CORRECTION OUTLET(32,2)|CO2 PERMANENT STORAGE(29,5)|NEGATIVE EMISSION GENERATION(28,1)|CARBONATE FLOW(27,13)|TECHNICAL ECONOMIC OBSTACLE(26,1)|PERMANENT STORAGE(25,7)|CARBONIC GAS(24,49)|MODULAR PLANT(24,1)|RENEWABLE ENERGY ALTERNATIVE(24,1)|SEA(22,12)|COMPETITIVE COST(22,1)|STORE CO2(22,1)|TERRITORY(22,1)|BICARBONATE(21,9)|NEGATIVE CO2 EMISSION(21,5)|ALKALINITY(20,8)|BIOENERGY(20,1)|CARBONATE PREHEATED FLOW(19,3)|DEVELOPING NATION(18,1)|H2O CA(18,1)|CO2(17,43)|NEGATIVE EMISSION(17,3)|COMPLEX REACTION(17,1)|BECCS(16,1)|CO2(15,3)|PRE HEATING FLOW(15,3)|CLIMATE(15,2)|HARDNESS MEASUREMENT(15,2)|SEAWATER(13,11)|DAC(13,1)|ECONOMIC DEVELOPMENT(13,1)|ENVIRONMENTAL ISSUE(12,2)|PREHEATED CARBONATE FLOW(12,2)|HYDROXIDE FLOW(11,4)|CO2 SEQUESTRATION(10,5)|CALCINING(10,3)|NEGATIVE CO2 EMISSION TON(10,3)|INLET ELECTRICAL POWER(10,1)|CALCITE CONTACTOR(8,2)|CONTROL DOSING(8,2)|LIMESTONE CONTACTOR(8,2)|ECONOMY FUTURE DECARBONIZATION(8,1)|RESOURCE HUGE AVAILABILITY(8,1)|SHORT TERM ECONOMIC DEVELOPMENT(8,1)|EMISSION SHARE(7,2)|PH METER(7,2)|PERSON(6,32)|DEEP SALINE AQUIFER(6,1)|DOLOMITIC SEDIMENTARY ROCK(6,1)|RESIDUAL CO2 DEGASSING(6,1)|RESIDUAL CO2 TREND(6,1)|BARA(5,11)|EURO TON(5,5)|ELECTRIC KWHE(5,3)|CALCINING ZONE(5,2)|CARBONATE ROCK(5,2)|CHEMICAL ELEMENT(5,2)|ANTHROPOGENIC CO2(5,1)|AUTHORITATIVE STUDY(5,1)|CALCITE SATURATION(5,1)|DISSOLUTION KINETICS(5,1)|DOLOMITE CAMG(5,1)|MGCO3 CALCINATION(5,1)|NONLIMITING INTENT(5,1)|OCEAN LIMING(5,1)|ORE DECOMPOSITION(5,1)|PHYSICOCHEMICAL CRITERIA(5,1)|ACIDIC EFFLUENT(4,2)|ENERGY CONTRIBUTION(4,2)|PH ADJUSTMENT(4,2)|ABSORBING CO2(4,1)|ADVANCED COUNTRY(4,1)|BUFFERING SUBSTANCE INSERTION(4,1)|CAPTURING CO2(4,1)|CARBONATE AVAILABILITY(4,1)|CARBONATE PRECIPITATION(4,1)|CO2 CAPTURE PROHIBITIVE COST(4,1)|CO2 EMISSION PERMANENT STORAGE(4,1)|CO2 HYDRATION(4,1)|CO2 TON YEAR(4,1)|COMBAT GLOBAL WARMING(4,1)|CONSUMPTION LAMP(4,1)|DEGASSING CO2(4,1)|DEPOSIT DISCOVERY(4,1)|DESALINIZATION TREATMENT(4,1)|DIRECT AIR CAPTURE(4,1)|EFFLUENT DISCHARGE(4,1)|ENTIRE COUNTRY INDUSTRIALIZATION(4,1)|EQUILIBRIUM CURVE(4,1)|EQUILIBRIUM GRAPH(4,1)|FOREIGN SUBSTANCE(4,1)|INEFFICIENT COAL(4,1)|INTERNATIONAL COMMUNITY EFFORT(4,1)|LIME INDUSTRY(4,1)|LIMESTONE MILL(4,1)|MARGINAL IMPACT(4,1)|MICROWAVE GENERATOR(4,1)|MINERAL CARBONATION(4,1)|NEGATIVE EMISSION TON(4,1)|SCIENTIFIC COMMUNITY EFFORT(4,1)|SEA FLOOR(4,1)|SEA PH(4,1)|SEQUESTERING CO2(4,1)|TECHNOLOGICAL EFFORT(4,1)|VAPOR TURBINE(4,1)|SLURRY(3,4)|ACIDITY(3,2)|CRUSHING(3,2)|IMPURITY(3,2)|INVESTMENT(3,2)|CALCINING REACTION(3,1)|CALCIUM CARBONATE CACO3(3,1)|CARBONATE DECREASE(3,1)|CARBONATE PARTICLE(3,1)|CARBONIC ACID H2CO(3,1)|CHOICE TECHNOLOGY(3,1)|CIVIL WORK(3,1)|CO2 ATMOSPHERE(3,1)|CO2 COMING(3,1)|CO2 EXCESS(3,1)|DIRECTIVE(3,1)|DRINKING WATER REMINERALISATION(3,1)|ELECTRIC CALCINATION(3,1)|ELECTRICAL CALCINER(3,1)|HYDROXIDE OH(3,1)|INITIATIVE(3,1)|LCOE LEVELIZED COST(3,1)|LIQUID BASICITY(3,1)|NONSOLUBLE GAS(3,1)|REMINERALISING DRINKING WATER(3,1)|SEQUESTERING CARBON DIOXIDE(3,1)|SERVICE ACCOUNT(3,1)|TON COST(3,1)|CONTROL UNIT(2,13)|SALE(2,3)|ARAGONITE(2,1)|BASIC SUBSTANCE(2,1)|CA TOTAL CONTENT(2,1)|CALCIUM OXIDE CAO(2,1)|CARBONATE COST(2,1)|CO2 STORAGE COST(2,1)|CONTACTOR AVERAGE PRESSURE(2,1)|CORAL(2,1)|CORRELATION(2,1)|DEVELOPING COUNTRY(2,1)|DOWNDRAFT(2,1)|ELECTRICAL POWER KWH(2,1)||(AU2021404910)|CARBONATE(100,3)|OXIDE(100,3)|ELECTRICAL POWER(100,1)|HIDROXIDE(100,1)|SPREADING CALCINER(100,1)|PH CORRECTION(68,1)|DOSING(50,1)|CONTACTOR(46,1)|SPREADING POWER(39,1)|PERMANENT STORAGE(30,1)| | (EP4267282)|1. Plant (100) for producing decarbonized oxide or hydroxide, comprising an electric calciner (10), a contactor (20), a pH correction apparatus (30) and a dosing device (40), wherein:| - the electric calciner (10) is adapted to receive at the inlet a flow of carbonate (110), electric power (120) and to release at the outlet at least one flow of carbonic gas (140) at high temperature and at least one flow of oxide (130);| - the flow of oxide (130) is adapted to provide a flow of buffering substance;| - the contactor (20) is adapted to receive at the inlet the flow of carbonic gas (140) released by the electric calciner (10), a flow of carbonate (220), a flow of water (210);| - the contactor (20) is adapted to make the carbonate (220) react with water (210) and the CO2 present in the carbonic gas (140) according to the following reactions | and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet at least one flow of ionic mixture (230);| - the contactor (20) is provided with means for releasing non-soluble gases (221);| - the pH correction apparatus (30) is adapted to receive at the inlet at least one flow of buffering substance (440; 640) and the flow of ionic mixture (230), is adapted to make the ionic mixture (230) react with the buffering substance (440; 640) according to the following reactions| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|and to release at the outlet a flow of buffered ionic mixture (240);| - the dosing device (40) is adapted to receive at the inlet a flow of buffering substance (130; 630) deriving from the electric calciner (10) and to release at the outlet a predetermined quantity of buffering substance (440; 640) to feed the pH correction apparatus (30) and possibly a quantity of buffering substance (450; 650) available for use.|2. Plant (100) according to claim 1 wherein the buffering substance is the oxide (130; 440) originated by the electric calciner (10) and wherein the pH correction apparatus (30) is adapted to make the ionic mixture (230) react with the oxide (440) according to the reaction| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|3. Plant (100) according to claim 1, comprising a hydroxide production unit (60) installed between the electric calciner (10) and the pH correction apparatus (30) wherein:| - the hydroxide production unit (60) is suitable to receive at the inlet at least one flow (130; 440) of oxide originated by the electric calciner (10), a predetermined flow of water (610),| - the hydroxide production unit (60) is adapted to make the oxide (130; 440) react with water (610) according to the reaction| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet a flow of hydroxide (630; 640) and possibly, a flow of vapour (620); and| - wherein the buffering substance is hydroxide (630; 640) produced by the hydroxide production unit (60).|4. Plant (100) according to claim 1, 2 or 3, comprising a control unit (50) and a meter of the chemical parameters of water (51) wherein:| - the meter of the chemical parameters of water (51) is adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture (230) or of the buffered ionic mixture (240) and to provide the measurement to the control unit (50);| - the control unit (50) is adapted to control the dosing device (40) so that it feeds the pH correction apparatus (30) with the quantity of buffering substance (440; 640) that is suitable for obtaining a buffered ionic mixture (240) with a desired pH.|5. Plant (100) according to any preceding claim wherein the contactor (20) has a volume that allows a minimum contact time of the water (210) with the carbonate (220) and the carbonic gas (140; 151) of 1000 s.|6. Plant (100) according to any preceding claim wherein the quantity of carbonate (220) introduced into the contactor (20) is zero and the contactor (20) has a volume that allows a contact time of the water with the carbonic gas (140; 151) greater than 10 s, preferably comprised between 60 s and 300 s.|7. Plant (100) according to one or more of claims 3 to 6 further comprising a conduit adapted to feed the flow of vapour (620) released by the hydroxide production unit (60) to the electric calciner (10).|8. Plant (100) according to any preceding claim further comprising a carbonate preheating unit (15), wherein the carbonate preheating unit (15) is adapted to receive at the inlet the flow of carbonic gas (140) at high temperature released by the electric calciner (10), a flow of carbonate (110) and to release at the outlet a flow of carbonic gas (151) and a preheated flow of carbonate (111).|9. Decarbonized calcination method comprising the steps of:| - providing an electric calciner (10);| - feeding the electric calciner (10) with electric power (120) and a flow of carbonate (110; 111) in order to obtain the calcination of the carbonate (110) according to the reaction| CaCO3 → CaO + CO2|(where Ca can be substituted with Mg if present in the carbonate);| - releasing at the outlet of the electric calciner (10) a flow of carbonic gas (140) at high temperature and a flow of oxide (130);| - conveying the flow of carbonic gas (140);| - conveying the flow of oxide (130);| - from the flow of oxide (130) obtaining a flow of buffering substance (440; 640);| - providing a contactor (20);| - feeding the contactor (20) with the flow of carbonic gas (140) produced by the electric calciner (10) and a predetermined flow of water (210) in order to obtain a flow of ionic mixture (230) through the reaction |;| - releasing the flow of ionic mixture (230) at the outlet of the contactor (20);| - conveying the ionic mixture (230);| - providing a dosing device (40);| - feeding the flow of buffering substance (130, 630) to the dosing device (40);| - releasing a predetermined flow of buffering substance (440; 640) at the outlet of the dosing device (40);| - conveying the flow of buffering substance (440; 640);| - providing a pH correction apparatus (30);| - feeding the pH correction apparatus (30) with the flow of ionic mixture (230) and with the predetermined flow of buffering substance (440; 640) so that the reactions take place| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq);| - releasing the flow of buffered ionic mixture (240) at the outlet of the pH correction apparatus (30);| - placing the flow of buffered ionic mixture (240) into the sea.|10. Method according to the preceding claim, further comprising the step of feeding the contactor (20) with a predetermined flow of carbonate (220) so that the reaction can take place| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|11. Method according to claim 9 or 10, wherein the flow of buffering substance (440; 640) fed to the pH correction apparatus (30) is a flow of oxide (440).|12. Method according to claim 9 or 10, further comprising the steps of:| - providing a hydroxide production unit (60);| - feeding the hydroxide production unit (60) with a flow of oxide (130; 440) and a predetermined flow of water (610) so that the reaction can take place| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate);| - releasing at least one flow of hydroxide (630) and one flow of vapour (620) at the outlet of the hydroxide production unit (60);|and wherein the flow of buffering substance (440; 640) fed to the pH correction apparatus (30) is a flow of hydroxide (640).|13. Method according to one or more of claims 9 to 12, further comprising the steps of:| - providing a control unit (50) and a meter of the chemical parameters of water (51) adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture (230) or of the buffered ionic mixture (240);| - providing the pH and/or alkalinity and/or hardness measurement from the pH meter (51) to the control unit (50);| - controlling the dosing device (40) by means of the control unit (50) so that it feeds the pH correction apparatus (30) with the correct quantity of buffering substance (440; 640) in order to obtain a buffered ionic mixture (240) with a desired pH.|14. Method according to claim 12 or 13, further comprising the steps of:| - conveying the flow of vapour (620); and| - feeding the flow of vapour (620) to the electric calciner (10).|15. Method according to one or more of claims 9 to 14, further comprising the steps of:| - providing a carbonate preheating unit (15);| - feeding the carbonate preheating unit (15) with the flow of carbonic gas (140) at high temperature released by the electric calciner (10) and a flow of carbonate (110);| - releasing a flow of preheated carbonate (111) from the carbonate preheating unit (15); and| - feeding the electric calciner (10) with the preheated flow of carbonate (111). | (EP4267282)|[0001] The present invention relates to a method and a plant for producing decarbonized oxide or hydroxide using carbonate and electric power.|[0002] The effects of so-called "greenhouse gases" on the climate have long been known, especially the correlation between the concentration in the atmosphere of CO2 (carbon dioxide) and global warming.|[0003] The efforts of the scientific community and world politics in recent years have been concentrated on trying to counteract the increase in greenhouse gas emissions into the atmosphere, in order to avoid the phenomenon of global warming, i.e. the rise in the average temperature at a global level.|[0004] In a per se known way, many initiatives aimed at containing CO2 emissions into the atmosphere have been promoted at an international level: the Kyoto Protocol in 1997 and the Paris Agreement in 2015, among others, are worth mentioning.|[0005] The forms identified by the scientific community to avoid global warming are many and substantially concern the decrease in the use of fossil fuels such as coal, oil and natural gas favouring the development of renewable energies such as hydraulic, wind, solar, biomass energy and of zero-emission fuels such as hydrogen or ammonia.|[0006] Furthermore, many efforts of the international community are focused on improving the efficiency of energy use, like in the case of lighting with low consumption lamps, on the transport with new generations of high-efficiency engines and, in the field of power generation, on replacing old, inefficient coal- or oil-fired power stations with new combined-cycle plants with gas turbine and vapour turbine having energy yields approaching 60%.|[0007] Despite the technological efforts being made in the most advanced nations, the forecasts of well-known international institutions on the energy needs at global level over the next few years indicate a sharp increase in the demand of electric power, thermal energy for industry and of fuels for transportation.|[0008] Consequently, these forecasts indicate a steady increase in the use of fossil sources such as oil, coal and natural gas, especially by emerging, newly industrialised and developing countries. This consumption is in fact favoured by the huge availability of these resources and by the discovery of new deposits and techniques for the extraction thereof, factors which altogether make these energy sources economically favourable.|[0009] Using the data envisaged by these authoritative studies, a decrease in CO2 emissions is just globally not expected in order to combat global warming, but a substantial increase in the emissions is instead expected over the next 50 years, mainly due to the increase in world population and the new industrialisation of entire countries.|[0010] The catastrophic effects of such a situation on the climate are easy to see and difficult to avoid especially because developing nations believe that the renewable energy option is too sophisticated and costly, and are more oriented towards short-term economic development programmes than towards CO2 emission containment and environmental issues.|[0011] One of the industries that will be targeted by the future decarbonization of the economy is represented by the lime industry.|[0012] The calcination process that transforms the carbonates (limestones and dolomites) into oxides produces large quantities of CO2 mainly coming from the decomposition of the ore at high temperature and secondarily from the fuels used.|[0013] It is therefore impossible to decarbonize the lime industry if no permanent CO2 storage is available, even if the fuels used in the calcination process were completely renewable. Different technologies have been proposed in order to be able to produce oxides with CO2 capture, but with all the proposed technologies there remains the problem of the permanent storage of the CO2 emissions produced in the process.|[0014] In US5965103, the carbon dioxide produced in the calcination of limestone is made to react with the calcium hydroxide obtained from the hydration of calcium oxide to produce a calcium carbonate slurry.|[0015] In a per se known way, CO2 capture and storage technologies are commonly referred to as CCS (Carbon Capture and Storage or also Carbon Capture and Sequestration).|[0016] The main CCS technologies proposed and known are:| CO2 sequestration in deep saline aquifers, a method recognised and promoted by the European Union through a specific directive dated 2009;| CO2 sequestration directly in the ocean floor, in liquid form;| the sequestration of CO2 in calcium carbonates or calcium silicates, either directly or with the use of peptoids, known as Mineral Carbonation;| the sequestration of CO2 in oil wells where it is injected to increase the oil production of the well itself with a technology called EOR (enhanced oil recovery);| the sequestration of CO2 in the form of alkaline earth metal bicarbonates such as calcium and magnesium bicarbonate.|[0017] Although various technological alternatives are available, one of the most important issues still to be solved is the prohibitive cost of CO2 capture and the limited availability of permanent storages of the CO2 produced to offer decarbonized lime-based products on the market.|[0018] As can be immediately understood, there is a need to identify a technology that allows the production of oxides through the carbonate calcination process to be carried out with simple technologies and to solve the problem of storing CO2 in a distributed form throughout the territory at an acceptable cost.|[0019] The task of the present invention is to make available a method and a plant that can enable the efficient generation of oxides by calcination of carbonates with permanent storage of CO2 at lower costs than known technologies.|[0020] This object and these tasks are achieved by means of a plant according to claim 1 and by means of a method according to claim 9.|[0021] In order to better understand the invention and appreciate its advantages, some exemplary and non-limiting embodiments thereof are described below, with reference to the attached drawings, in which:| Figure 1 is a schematic view of a plant for producing decarbonized oxide according to the invention;| Figure 2 is a schematic view of another possible embodiment of the plant for producing decarbonized oxide according to the invention;| Figure 3A is a schematic view of a possible embodiment of the plant for producing decarbonized hydroxide according to the invention;| Figure 3B is a schematic view of another possible embodiment of the plant for producing decarbonized oxide according to the invention;| Figure 4 is a schematic view of another possible embodiment of the plant for producing decarbonized hydroxide according to the invention;| Figure 5 is a graph of the equilibrium of 2270 kg calcite and 1000 kg CO2 in seawater as a function of the pH and of the quantity of water;| Figure 6 is the graph of the trend of the residual CO2 quantity after a dwell time of 100000 s in the contactor with 2270 kg CaCO3 with 10 micron size and 1500 m3 of water as a function of the pressure in bara;| Figure 7 is a mass and energy balance of a possible embodiment of the plant for producing decarbonized hydroxide according to the invention;| Figure 8 is a mass and energy balance of a possible embodiment of the plant for storing CO2 coming from an external source according to the invention.| Figure 9 is a mass and energy balance of a possible embodiment of the plant for producing decarbonized hydroxide according to the invention.|[0022] In the description, reference will also be made to "carbonic gas", meaning thereby a gas mixture containing mainly CO2, and possibly other substances including N2, O2, H2O, Ar, whereas when reference is intended to be made to the chemical element CO2 (carbon dioxide) alone, CO2 will be used in the description.|[0023] In the description, reference will also be made to "non-soluble" gases, meaning thereby all gases that are not very soluble in water, including H2, CO, CH4, N2, Ar.|[0024] In the description reference will also be made to "water", meaning thereby water in the liquid phase with the chemical and temperature characteristics necessary for use in the process according to the invention, whereas when reference is intended to be made to the chemical element H2O alone, H2O will be used in the description.|[0025] In the description, reference will also be made to the "vapour", meaning thereby water in vapour form with the temperature and pressure characteristics necessary for use in the process according to the invention.|[0026] In the description, reference will also be made to the "sea", meaning thereby the sea itself but also the ocean, a lake, a river or any salt or fresh water body.|[0027] The description will also refer to "carbonate" meaning any calcareous or dolomitic sedimentary rock such as calcite, aragonite, dolomite, siderite, magnesite, marble, but also any other carbonate material such as shells or corals.|[0028] In the description reference will also be made to the "electric calciner" (or electric furnace) meaning any electrical apparatus under controlled atmosphere, per se known, capable of calcining the carbonate according to the reactions:| CaCO3 → CaO + CO2 (+183 kJ/mol)|or| MgCO3 → MgO + CO2 (+118 kj/mol).|[0029] The calcination process, per se known, takes place at temperatures preferably comprised between 600°C and 1200°C and is an endothermic process. The controlled-atmosphere electric calciner does not allow direct contact of the calcining zone with the ambient air, while it does allow flushing the calcining zone possibly with water vapour.|[0030] In the description, reference will also be made to the "oxide", meaning thereby the product of the calcination formed mainly by calcium oxide CaO or magnesium oxide MgO and to a lesser extent by other materials present in the carbonate rock with which the calciner is fed.|[0031] In the description, reference will also be made to the "hydroxide", meaning thereby the product of the hydration of calcium oxide Ca(OH)2 or of magnesium oxide Mg(OH)2 with the following chemical reactions:| CaO + H2O → Ca(OH)2 (-64.8 kJ/mol)| MgO + H2O → Mg(OH)2 (-37.0 kj/mol)|[0032] In the description reference will be made to the "bicarbonates" meaning thereby the chemical compounds Ca(HCO3)2(aq) and/or Mg(HCO3)2(aq)|[0033] In the description, reference will be made to the "impurities", meaning thereby foreign substances present in the carbonate which do not take part in the chemical reactions in the reactor according to the invention.|[0034] In the description, reference will be made to the "contactor", meaning thereby a reactor in which CO2, water and possibly carbonate are reacted according to the following reactions | and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate rock. This reactor is known as "limestone contactor" or "calcite contactor" and is normally used for remineralising drinking water from reverse osmosis plants and can be with fixed bed (updraft or downdraft), fluidised bed, either pressurised or atmospheric.|[0035] In the description, reference will be made to the "ionic mixture", meaning thereby a mixture where the carbonate, if any, has dissolved and Ca2+ or Mg2+ are in ionic form. "Ionic mixture" also refers to the mixture of water and CO2 alone.|[0036] In the description, reference will be made to the "buffered ionic mixture", meaning thereby an ionic mixture in which the pH has been corrected to the desired value by the addition of an oxide or a hydroxide.|[0037] In the description, reference will be made to "Ωcal", meaning thereby the calcite saturation state in seawater.|[0038] In the description, reference will be made to "pH", meaning thereby the measurement scale indicating the acidity or the basicity of a liquid which is defined by the following formula: |[0039] In the description, reference will be made to the "alkalinity", meaning thereby the quantity of hydroxides OH-, carbonates CO32- and bicarbonates HCO32- present in seawater.|[0040] In the description reference will be made to the "hardness", meaning thereby a value expressing the total content of Ca2+ and Mg2+ ions present in seawater.|[0041] In the description, reference will also be made to the "buffering substance", meaning thereby both the oxide and the hydroxide.|[0042] In the description, reference will also be made to the "atmosphere", meaning thereby any place in contact with atmospheric air.|[0043] In the description, reference will be made to "bara", meaning thereby the unit of absolute pressure in the CGS system (centimetre-gram-second). 1 bara corresponds to 105 Pa in the International System.|[0044] In the description, reference will also be made to "high temperature" meaning thereby a temperature greater than 600°C.|[0045] In the description, reference will also be made to "ambient temperature", meaning thereby a temperature lower than 50°C.|[0046] In the description, reference will also be made to the "preheating temperature", meaning thereby a temperature comprised between 50°C and 600°C.|[0047] In the description, reference will also be made to the "average pressure of the contactor", meaning thereby the weighted average pressure to which the carbonate is subjected during the dwell time in the contactor.|[0048] In the description, reference will also be made to the concept of "decarbonized", meaning thereby a product or service that does not entail CO2 emissions into the atmosphere, i.e. where the CO2 produced by the production process has been stored permanently.|[0049] In the attached figures, the reference 100 indicates as a whole the plant according to the invention.|[0050] A first aspect of the invention concerns a plant 100 for producing decarbonized oxide or hydroxide. With reference to Figures 1 to 4, the plant 100 comprises an electrical calciner 10, a contactor 20, a pH correction apparatus 30 and a dosing device 40, wherein:| the electric calciner 10 is adapted to receive at the inlet a flow of carbonate 110, electric power 120 and to release at the outlet at least one flow of carbonic gas 140 at high temperature and at least one flow of oxide 130;| the flow of oxide 130 is adapted to provide a flow of buffering substance;| the contactor 20 is adapted to receive at the inlet the flow of carbonic gas 140 released by the electric calciner 10, a flow of carbonate 220, a flow of water 210;| the contactor 20 is adapted to make the carbonate 220 react with water 210 and the CO2 present in the carbonic gas 140 according to the following reactions and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet at least one flow of ionic mixture 230;| the contactor 20 is provided with means for releasing non-soluble gases 221;| the pH correction apparatus 30 is adapted to receive at the inlet at least one flow of buffering substance 440; 640 and the flow of ionic mixture 230, is adapted to make the ionic mixture 230 react with the buffering substance 440; 640 according to the following reactions| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|and to release at the outlet a flow of buffered ionic mixture 240;| the dosing device 40 is adapted to receive at the inlet a flow of buffering substance 130; 630 deriving from the electric calciner 10 and to release at the outlet a predetermined quantity of buffering substance 440; 640 to feed the pH correction apparatus 30 and possibly a quantity of buffering substance 450; 650 available for use.|[0051] In some embodiments of the plant 100 according to the invention (see, for example, Figures 1 and 2), the buffering substance is the oxide 130; 440 originated from the electric calciner 10 and the pH correction apparatus 30 is adapted to make the ionic mixture 230 react with the oxide 440 according to the reaction| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|[0052] In some embodiments of the invention (see, for example, Figures 3A, 3B and 4), the plant 100 further comprises a hydroxide production unit 60 installed between the electric calciner 10 and the pH correction apparatus 30, wherein:| the hydroxide production unit 60 is adapted to receive at the inlet at least one flow 130; 440 of oxide originated from the electric calciner 10, a predetermined flow of water 610, and| the hydroxide production unit 60 is adapted to make the oxide 130; 440 react with water 610 according to the reaction| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet a flow of hydroxide 630; 640 and possibly, a flow of vapour 620.|[0053] The hydroxide production unit 60 may be installed between the electric calciner 10 and the dosing device 40 (see Figures 3A and 4) or between the dosing device 40 and the pH correction apparatus 30 (see Figure 3B).|[0054] In such embodiments of the plant 100, the buffering substance fed to the pH correction apparatus 30 may be the hydroxide 630; 640 produced by the hydroxide production unit 60.|[0055] In accordance with an embodiment of the plant 100 according to the invention and with reference to Figures 2, 3A and 4, the plant 100 further comprises a control unit 50 and a meter of the chemical parameters of water 51 adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture 230 or of the buffered ionic mixture 240. The meter of the chemical parameters of water 51 is further adapted to provide the measurement to the control unit 50, and the control unit 50 is adapted to control the dosing device 40 so that it feeds the pH correction apparatus 30 with the quantity of buffering substance 440; 640 that is suitable for obtaining a buffered ionic mixture 240 with a desired pH.|[0056] In accordance with some embodiments of the plant 100 (see, for example, Figure 4), the plant 100 further comprises a conduit adapted to feed the flow of vapour 620 released by the hydroxide production unit 60 to the electric calciner 10.|[0057] In accordance with some embodiments of the plant 100 (see, for example, Figure 4), the plant 100 further comprises a carbonate preheating unit 15, wherein the carbonate preheating unit 15 is adapted to receive at the inlet the flow of carbonic gas 140 at high temperature released by the electric calciner 10, a flow of carbonate 110 and to release at the outlet a flow of carbonic gas 151 and a flow of carbonate 111.|[0058] In a per se known form, the carbonate preheating unit 15 is a heat exchanger which may be a direct-contact unit in which the flow of carbonic gas comes into direct contact with the carbonate, or it may be an indirect-contact unit in which the carbonate and the carbonic gas always remain separate while exchanging heat.|[0059] A skilled person will certainly be able to understand that the size of the contactor 20 depends on the flow rates of carbonic gas 140 or 151, of water 210 and possibly of carbonate 220 and on the kinetics of the chemical reactions that take place. The ratios between the flow rates of carbonic gas 140 or 151, water 210 and carbonate 220 are established with physico-chemical criteria that allow the reactions to be completed | and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate) avoiding the precipitation of carbonates in the pH correction apparatus 30 during the insertion of the buffering substance 440 or 640 due to too high Ωcal.|[0060] A skilled person will therefore agree that the required contact time between the water 210, the carbonic gas 140 or 151 and possibly the carbonate 220 is the main parameter that allows sizing the contactor 20: if for a contact time of 10 s, a flow rate of carbonic gas 140 or 151 of 1 kg/s, it were required 1 m3/s of water 210, this means that the size of the contactor 20 must be about 10 m3, whereas if the flow rate of carbonic gas 140 or 151 were 10 kg/s, it would be required 10 m3/s of water and the size of the contactor would be about 100 m3.|[0061] In accordance with an embodiment of the plant 100, the contactor 20 has a volume which allows a contact time of the water 210 with the carbonate 220 and the carbonic gas 140 or 151 of at least 1000 s and an average pressure of the contactor greater than 1.0 bara.|[0062] In accordance with an embodiment of the plant 100 (see for example Figures 3B and 9), the quantity of carbonate 220 introduced into the contactor 20 is zero and the contactor 20 has a volume which allows a minimum contact time of the water with the carbonic gas 140 or 151 of 10 s, preferably comprised between 60 s and 300 s, which allows for a partial pressure of CO2 greater than 0.1 bara, preferably comprised between 0.2 bara and 2 bara.|[0063] In a per se known form and in accordance with experimental results and the scientific literature, the time it takes for CO2 to completely hydrate in water to form carbonic acid H2CO3 according to the reaction: | has a characteristic time ranging from a few seconds to a few minutes.|[0064] It should be noted here that the carbonic gas fed to the contactor 20 can be either the carbonic gas (indicated with 140) coming directly from the electric calciner 10 or it can be the carbonic gas (indicated with 151) coming from the carbonate preheating unit 15.|[0065] It should be noted here that the carbonate fed to the electric calciner 10 can be both carbonate at room temperature (indicated with 110 in figs. 1, 2 and 3) and preheated carbonate (indicated with 111 in fig. 4).|[0066] It should be noted here that the buffering substance fed to the pH correction unit 30 may be the oxide (indicated with 440; fig. 1 and 2) or it can be the hydroxide (indicated with 640; fig. 3 and 4).|[0067] It should be noted here that the buffering substance fed to the dosing device 40 can be either the oxide (indicated with 130; fig. 1, 2 and 3B) released by the electric calciner 10 or the hydroxide (indicated with 630; fig. 3A and 4) released by the hydroxide production unit 60, and that the buffering substance released by the dosing device 40 can be both the oxide (indicated with 440 and 450) and the hydroxide (indicated with 640 and 650).|[0068] A second aspect of the invention concerns a method for decarbonized calcination. The method according to the invention comprises the steps of:| providing an electric calciner 10;| feeding the electric calciner 10 with electric power 120 and a flow of carbonate 110; 111 in order to obtain the calcination of the carbonate 110 according to the reaction| CaCO3 → CaO + CO2|(where Ca can be substituted with Mg if present in the carbonate);| releasing at the outlet of the electric calciner 10 a flow of carbonic gas 140 at high temperature and a flow of oxide 130;| conveying the flow of carbonic gas 140;| conveying the flow of oxide 130;| from the flow of oxide 130 obtaining a flow of buffering substance 440; 640;| providing a contactor 20;| feeding the contactor 20 with the flow of carbonic gas 140 produced by the electric calciner 10 and a predetermined flow of water 210 in order to obtain a flow of ionic mixture 230 through the reaction ;| releasing the flow of ionic mixture 230 at the outlet of the contactor 20;| conveying the ionic mixture 230;| providing a dosing device 40;| feeding the flow of buffering substance 130, 630 to the dosing device 40;| releasing a predetermined flow of buffering substance 440; 640 at the outlet of the dosing device 40;| conveying the flow of buffering substance 440; 640;| providing a pH correction apparatus 30;| feeding the pH correction apparatus 30 with the flow of ionic mixture 230 and with the predetermined flow of buffering substance 440; 640 so that the reactions take place| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq);| releasing the flow of buffered ionic mixture 240 at the outlet of the pH correction apparatus 30;| placing the flow of buffered ionic mixture 240 into the sea.|[0069] In accordance with some embodiments of the invention, the method further comprises the step of feeding to the contactor 20 a predetermined flow of carbonate 220 so that the reaction can take place| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|[0070] In accordance with some embodiments of the invention, the flow of buffering substance fed to the pH correction apparatus 30 is a flow of oxide 440.|[0071] In accordance with some embodiments of the invention, the method further comprises the steps of:| providing a hydroxide production unit 60;| feeding the hydroxide production unit 60 with a flow of oxide 130; 440 and a predetermined flow of water 610 so that the reaction can take place| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate); and| releasing at least one flow of hydroxide 630 and one flow of vapour 620 at the outlet of the hydroxide production unit 60.|[0072] In accordance with such embodiments of the method, the flow of buffering substance fed to the pH correction apparatus 30 may be a flow of hydroxide 640.|[0073] In accordance with such embodiments, the method may further comprise the steps of:| conveying the flow of vapour 620 at the outlet of the hydroxide production unit 60; and| feeding the flow of vapour 620 to the electric calciner 10.|[0074] In accordance with some embodiments of the invention, the method further comprises the steps of:| providing a control unit 50 and a meter of the chemical parameters of water 51 adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture 230 or of the buffered ionic mixture 240;| providing the pH and/or alkalinity and/or hardness measurement from the pH meter 51 to the control unit 50;| controlling the dosing device 40 by means of the control unit 50 so that it feeds the pH correction apparatus 30 with the correct quantity of buffering substance 440; 640 in order to obtain a buffered ionic mixture 240 with a desired pH.|[0075] In accordance with some embodiments, the method may further comprise the steps of:| providing a carbonate preheating unit 15;| feeding the carbonate preheating unit 15 with the flow of carbonic gas 140 at high temperature released by the electric calciner 10 and a flow of carbonate 110;| releasing a flow of preheated carbonate 111 from the carbonate preheating unit 15; and| feeding the electric calciner 10 with the preheated flow of carbonate 111.|[0076] Referring to Figures 1, 2, 3 and 4, a skilled person will be able to see that the electric calciner 10 is fed with carbonate 110 or 111 and electric power 120 and releases the oxide 130 and the carbonic gas 140. The electric calciner 10 is fed by electric power to generate the heat required for calcination. Electric power can be used in electric resistances, microwave generators or induction systems.|[0077] In a per se known form, the calcination of the carbonate 110 takes place according to the reaction| CaC03 → CaO + CO2|where Ca can be substituted with Mg if present in the carbonate 110, at temperatures comprised between about 600° (MgCO3) and 1200°C (CaCO3) and at intermediate values depending on the chemical composition of the carbonate, which can also be a dolomite CaMg(CO3)2, and of the chemical composition of the atmosphere in the calciner.|[0078] In a per se known form, the calcination reaction is an endothermic reaction requiring 118 kJ/mol of heat in the case of MgCO3 calcination and 183 kJ/mol in the case of CaCO3.|[0079] A skilled person can understand that the CO2 produced by an electric calcination under controlled atmosphere generates a carbonic gas 140 formed by CO2 and traces of non-soluble gases that may have entered with the carbonate 110 or 111 inside the electric calciner 10 or gases intentionally fed to the electric calciner 10 to improve the process conditions, such as in the case of water vapour (Figure 4).|[0080] Referring to the embodiment of Figures 1, 2, 3 or 4, the plant 100 according to the invention comprises the contactor 20.|[0081] In a per se known form, the contactor 20 uses water 210 and carbonate 220 as a means for absorbing CO2 from the flow of carbonic gas 140 and forming the ionic mixture 230 according to the reaction:| CO2(g) + CaCO3(s) + H2O => Ca2+(aq) + 2HCO3-(aq) [1]|where Ca can be substituted with Mg if present in the carbonate 220.|[0082] In a per se known form, there exist different types of contactors (limestone contactors or calcite contactors), generally used for the remineralisation of drinking water downstream of desalination treatments.|[0083] In a per se known form, the permanent storage of CO2 in the form of bicarbonates in the sea using contactors has been proposed in several scientific articles and patents, among which it is worth mentioning the US patent 6,890,497 B2 entitled "Method for extracting and sequestering carbon dioxide" and the Italian patent application IT202000000037 entitled "Plant and method for sequestering CO2 with a growing pressure reactor conduit".|[0084] In a per se known form, the contactors used for the remineralisation of water or whose use has been proposed for the permanent storage of CO2 in the form of bicarbonates must keep the water that is in contact with the carbonate sufficiently undersaturated, with an Ωcal preferably comprised between 0.01 and 0.6, to allow a dissolution kinetics of the carbonate that is sufficiently rapid and acceptable for an industrial plant. For this reason, the commercial contactors use an excess of CO2 in the water, a pH generally comprised between 5 and 6, and a final degassing of the CO2 to bring the pH of the water back to values above 7.|[0085] In a per se known form, the CO2 storage technologies by means of bicarbonates in the sea include, as mentioned above, the discharge of an acid effluent (pH comprised between 6 and 7), with still a significant quantity of CO2 not reacted with the carbonate according to the reaction [1]. This fact turns out to be environmentally harmful if the effluent discharge takes place in the depths of the sea where there is no possibility of degassing CO2 or it is very inefficient (CO2 storage efficiencies of about 50%) where the discharge takes place on the surface with degassing of the residual CO2.|[0086] A skilled person will understand that by neutralizing this acidity present in the acid mixture 230 with a buffering substance 440 or 640, an effluent with the same natural pH as seawater could be discharged into the sea and all the residual CO2 could be stored in the form of bicarbonates according to the reaction| Ca(OH)2 + 2CO2 + H2O → Ca2+ + (HCO3)2|where the Ca2+ ion can be substituted with the Mg2+ ion, eliminating the environmental issues due to the discharge of acid effluents and achieving a CO2 storage efficiency of about 100%.|[0087] In a per se known form, the reaction of Ca(OH)2 (where Ca can be substituted with Mg if present in the carbonate) with seawater is a complex reaction due to the presence of other chemical elements and therefore it results that for each mole of Ca(OH)2 it is possible to neutralise less than the 2 moles of CO2 envisaged by the stoichiometry of the equation| Ca(OH)2 + 2CO2 + H2O → Ca(HCO3)2(aq).|[0088] Referring to the embodiment of Figures 1, 2, 3 or 4, the plant 100 according to the invention comprises the pH correction apparatus 30 in which the ionic mixture 230 is mixed with a predetermined quantity of buffering substance 440 or 640 that is sufficient to obtain the desired pH of the buffered mixture 240.|[0089] A skilled person can easily understand that the composition of the ionic mixture 230 released by the contactor 20 may contain impurities which should conveniently be filtered from the mixture 230 by means of special filters (not shown in the figure) placed between the mixer 20 and the pH correction apparatus 30 or downstream of the pH correction apparatus 30.|[0090] Referring to the embodiment of Figures 2 and 4, the apparatus 100 according to the invention is provided with a meter of the chemical parameters of water 51 adapted to measure the pH and/or the alkalinity and/or the hardness of the water and with a control unit 50 for managing the dosing device 40 which allows feeding the pH correction apparatus 30 with the correct quantity of oxide 440 or hydroxide 640. In the case of hydroxide 640, the dosing device 40 may be a dosing pump as the hydroxide 640 may be fed to the pH correction apparatus 30 in the form of a suspension (slurry) or an ionic solution.|[0091] In a per se known form, the dissolution of the carbonate 220 in the contactor 20 depends on the quantity of water and on the pH according to the equilibrium curve presented in Figure 5 which refers to the complete dissolution of 2270 kg of CaCO3 in seawater in the presence of 1000 kg of CO2.|[0092] A skilled person will certainly be able to calculate, with the information available in the literature, the dissolution rate of the carbonate as a function of the quantity of water and the pH and the sizes of the contactor 20.|[0093] In a per se known form and as already mentioned above, the dissolution rate of the carbonate decreases asymptotically to zero as the equilibrium conditions are approached and therefore, in order to keep the sizes of the contactor 20 within commercially acceptable limits, it is necessary to maintain process conditions away from the equilibrium by using in the contactor 20 a water pH preferably comprised between 5 and 6.5 with water quantities from 1000 m3/tonCO2 to 4000 m3/tonCO2.|[0094] A skilled person can certainly understand that the ionic mixture 230 released by the contactor 20, if not subjected to CO2 degassing with a loss of storage efficiency, generally has a pH comprised between 6 and 6.5, lower than the pH of the sea which is about pH 8.|[0095] A skilled person will certainly be able to understand that, in order to avoid acidifying the sea by releasing an acid ionic mixture 230, it is necessary to buffer the pH with a basic substance such as the oxide 440 or the hydroxide 640.|[0096] A skilled person will certainly be able to understand that it would also be possible to use other substances to buffer the ionic solution 230, such as NaOH or KOH, but that their cost would make them not economically convenient.|[0097] A skilled person will certainly be able to verify that the contact times between the water 210 and the carbonate 220 inside the contactor 20 required for a complete dissolution of the carbonate depend on the sizes of the carbonate 220 itself and on the ratio between the quantities of CO2 present in the carbonic gas 140 and the quantity of water 210.|[0098] A skilled person will certainly be able to verify that by using a ratio of mass flow of water 210 to CO2 present in the carbonic gas 140 of less than 2000:1, and a carbonate particle 220 greater than 6 microns, the minimum contact time between water 210 and carbonate 220 inside the contactor 20 that are necessary to have a residual quantity of CO2 in the mixture 230 lower than 80% are higher than 50000s.|[0099] A skilled person will easily be able to verify that with the same mass ratio between the water 210 and the CO2 present in the carbonic gas 140 and by decreasing the quantity of carbonate 220 used in the contactor 20 according to the invention, the necessary contact time between the water 210, the CO2 and the carbonate 220, progressively decreases until reaching a few seconds that are necessary only for the hydration of the CO2 in the particular case in which the carbonate 220 used is zero.|[0100] A skilled person will certainly be able to understand that the choice of the contact time between the water 210, the CO2 present in the carbonic gas 140 or 151 with the carbonate 220 or the choice of not using the carbonate 220 to buffer the CO2 present in the carbonic gas but only the buffering substance 440 or 640 are economic choices: in fact, by decreasing the quantity of carbonate 220 used with the same quantity of CO2 present in the carbonic gas 140 or 151 and of water 210, the sizes and the plant cost of the contactor 20 are reduced at the expense of a greater consumption of electric power necessary to produce greater quantities of oxide 130 necessary to buffer the CO2 present in the ionic mixture 230 or of smaller quantities of hydroxide 650 available for sale.|[0101] In a per se known form, the dissolution of the carbonate in water is favoured and directly proportional to pressure. A skilled person will certainly be able to understand that it is advisable that the average pressure of the contactor 20 be higher than the pressure of 1 bara.|[0102] Referring to Figure 7, a skilled person can certainly understand the simplified mass and energy balance of a particular plant 100 for producing decarbonized hydroxide in which:| the electric calciner 10 is fed by 2270 kg of carbonate (CaCO3) 110 and by 2000 kWhe of electric power 120 and releases at the outlet 1000 kg of carbonic gas (CO2) 140 and 1271 kg of oxide (CaO) 130;| the contactor is fed by 1000 m3 of water 210 (considered to have a density of 1 kg/dm3), by 1135 kg of carbonate (CaCO3) 220 and 1000 kg of carbonic gas (CO2) 140 and releases at the outlet, after a dwell time of 80,000 s at an average pressure of 150 bara, 1002135 kg of ionic mixture 230 in which 500 kg of CO2 and a pH of about 6.2 are still present;| the hydroxide production unit 60 is fed by 1271 kg of oxide 130 released by the electric calciner 10 and by a predetermined flow of water (not shown) and releases at the outlet 1680 kg of hydroxide (Ca(OH)2) 630;| the dosing device 40 receives at the inlet 1680 kg of hydroxide 630 released by the hydroxide production unit 60 and releases at the outlet 560 kg of hydroxide 640 to the pH adjustment apparatus 30 and 1100 kg of hydroxide 650 available for sale as decarbonized hydroxide;| the pH correction apparatus 30 receives at the inlet 1002130 kg of ionic mixture 230 released by the contactor 20 and 560 kg of hydroxide 640 released by the dosing device 40 and releases 1002690 kg of buffered ionic mixture 240 with pH of 8 exploiting the reaction| Ca(OH)2(aq)+2CO2→Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate. In the case of seawater, depending on its chemical composition, 1 mole of Ca(OH)2 neutralises 1.50-2.00 moles of CO2. In the case under examination, a ratio of 1.5 moles of CO2 per mole of Ca(OH)2 is taken into consideration.|[0103] As a skilled person can well understand from the above example, the hydroxide 650 available for other uses is a fully decarbonized hydroxide in case the electric power 120 powering the calciner and the electric power (not shown in the example) powering the extraction, the transport and the crushing of the carbonate and the pumping of the water were renewable; otherwise, the hydroxide 650 would be decarbonized except for the share of the emissions due to the energy contribution mentioned above.|[0104] As a skilled person can understand, the hydroxide 650, or the oxide 450, can be conveniently used to capture CO2 coming from industrial processes or power plants by means of the reactions| Ca(OH)2(aq) + 2CO2→Ca(HCO3)2(aq)|or, in a less efficient form,| Ca(OH)2 + CO2 → CaCO3 + H2O|(where Ca can be substituted with Mg if it were present in the carbonate).|[0105] A skilled person will certainly be able to understand that the hydroxide 650 or the oxide 450 produced in a plant according to the invention could be conveniently used for capturing CO2 directly from the atmospheric air once dispersed over large areas both in dry and in liquid or slurry form.|[0106] Referring to Figure 8, a skilled person can certainly understand the simplified mass and energy balance of a particular plant 100 for storing CO2 coming from a source outside the process 100 itself wherein:| the electric calciner 10 is fed by 2270 kg of carbonate (CaCO3) 110 and 2000 kWhe of electric power 120 and releases at the outlet 1000 kg of carbonic gas (CO2) 140 and 1271 kg of oxide (CaO) 130;| the contactor is fed by 1000 m3 of water 210 (considered to have a density of 1 kg/dm3), by 3405 kg of carbonate (CaCO3) 220 and by 1000 kg of carbonic gas (CO2) 140 and releases at the outlet, after a dwell time of 80,000 s at an average pressure of 150 bara, an ionic mixture 230 in which 500 kg of CO2 and a pH of about 6.2 are still present;| the hydroxide production unit 60 is fed by 1271 kg of oxide 130 released by the electric calciner 10, by a predetermined quantity of water (not shown) and releases at the outlet about 1680 kg of hydroxide (Ca(OH)2) 630;| the dosing device 40 receives at the inlet 1680 kg of hydroxide 630 released by the hydroxide production unit 60 and releases at the outlet 1680 kg of hydroxide 640 to the pH correction apparatus 30;| the pH correction apparatus 30 receives at the inlet 1006405 kg of ionic mixture 230 released by the contactor 20 and 1680 kg of hydroxide 640 released by the dosing device 40 and releases 1008085 kg of buffered ionic mixture 240 with pH of 8 exploiting the reaction| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate. In the case of seawater, due to its chemical composition, 1 mole of Ca(OH)2 neutralises 1.5-2.00 moles of CO2. In the case under examination, a ratio of 1.5 moles of CO2 per mole of Ca(OH)2 was taken into consideration.|[0107] As the skilled person can well calculate using market values, the cost of a ton of decarbonized oxide or hydroxide depends mainly on the cost of the carbonate and electric power, while the plant and labour costs have a marginal impact on the final result. In particular, about 2000 kWh of electric power and 2000 kg of carbonate are needed to produce 1 ton of decarbonized calcium hydroxide Ca(OH)2. If the cost of carbonate were 7.5 €/ton and the cost of renewable electric power were 30 €/MWh (this is the LCOE - Levelized Cost Of Energy of wind power), the variable cost of hydroxide would be 75 €/ton.|[0108] A skilled person could therefore calculate that the installation costs of the electric calciner, the contactor, the dosing device, the limestone mill, the civil works and the services account for about 5 €/ton of Ca(OH)2 while the personnel costs are negligible.|[0109] A skilled person will therefore be able to calculate that the final cost of a ton of Ca(OH)2 is 80€. Considering that with one ton of Ca(OH)2 used in a CO2 storage plant using a contactor as illustrated in Figure 8, 0.89 ton of CO2 in the form of calcium bicarbonates or 0.59 ton of CO2 in the form of calcium carbonates can be permanently stored, the cost of CO2 storage according to the invention would be about 89 €/ton and 135 €/ton respectively.|[0110] As a skilled person may certainly know, if a ton of hydroxide Ca(OH)2 were spread on the sea surface in a process known as "ocean liming", 0.9 tons of negative CO2 emissions would be generated: in that case, 1 ton of negative CO2 emissions would cost about €90.|[0111] As a skilled person may certainly know, if a ton of hydroxide Ca(OH)2 were spread on a solid surface such as on a wall or on the ground in contact with atmospheric air, this would absorb the atmospheric CO2 transforming into calcium carbonate CaCO3, generating 0.59 tons of negative emissions: in such a case, 1 ton of negative CO2 emissions would cost about 135 €.|[0112] In a per se known form, about 10 km2 of surface exposed to the air are required to capture 1000000 tons/year of CO2 from the atmosphere. This surface can be conveniently obtained in flat and desert areas where the hydroxide can be spread in the form of slurry in special tanks built in a similar way to salt pans or rice fields and allowed to dry forming a solid mainly formed by CaCO3 and possibly salts if the water used to form the slurry is seawater.|[0113] In the latter case, the desert surfaces covered with carbonate generated by carbonation of the hydroxide would be white and would generate an albedo effect reflecting part of the solar radiation and further contributing to contain the increase in the average temperature on earth.|[0114] As a skilled person can certainly understand, the process for producing decarbonized oxide or hydroxide according to the invention makes it possible to permanently store CO2 in the sea in the form of bicarbonates and on land in the form of carbonates at a cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|[0115] As a skilled person will certainly be able to understand, in some cases it may be advantageous to opt for a simplified plant 100 in which, at the expense of a higher energy cost for the calcination process, it is possible to eliminate the investment in an expensive large-sized contactor 20 by eliminating the step of dissolution of the carbonate 220 and by buffering all the CO2 present in the carbonic gas 140 or 151 by means of the oxide 440 or the hydroxide 640.|[0116] Referring to Figure 9, a skilled person can certainly understand the simplified mass and energy balance of a particular plant 100 for producing decarbonized hydroxide in which:| the electric calciner 10 is fed by 2270 kg of carbonate (CaCO3) 110 and by 2000 kWhe of electric power 120 and releases at the outlet 1000 kg of carbonic gas (CO2) 140 and 1271 kg of oxide (CaO) 130;| the contactor is fed by 1000 m3 of water 210 (considered to have a density of 1 kg/dm3), and by 1000 kg of carbonic gas (CO2) 140 and releases at the outlet, after a dwell time of 60 s at an average pressure of 1.5 bara, 1001000 kg of ionic mixture 230 in which 1000 kg of CO2 and a pH of about 5.2 are still present;| the hydroxide production unit 60 is fed by 1271 kg of oxide 130 released by the electric calciner 10 and by a predetermined flow of water (not shown) and releases at the outlet about 1680 kg of hydroxide (Ca(OH)2) 630;| the dosing device 40 receives at the inlet about 1680 kg of hydroxide 630 released by the hydroxide production unit 60 and releases at the outlet 1121 kg of hydroxide 640 to the pH adjustment apparatus 30 and about 560 kg of hydroxide 650 available for sale as decarbonized hydroxide;| the pH correction apparatus 30 receives at the inlet 1001000 kg of ionic mixture 230 released by the contactor 20 and 1121 kg of hydroxide 640 released by the dosing device 40 and releases 1002121 kg of buffered ionic mixture 240 with pH of 8 exploiting the reaction| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate. In the case of seawater, depending on its chemical composition, 1 mole of Ca(OH)2 neutralises 1.50-2.00 moles of CO2. In the case under examination, a ratio of 1.5 moles of CO2 per mole of Ca(OH)2 is taken into consideration.|[0117] As a skilled person will certainly be able to deduce from the above data, not using carbonate 220 in the contactor 20 leads to a reduction of hydroxide 650 available for market or for negative emissions and an increase in specific energy consumption that goes from about 2 MWh/ton to 4 MWh/ton of Ca(OH)2 but with the elimination of a large-sized contactor 20.|[0118] As a skilled person will certainly be able to understand, in places where the LCOE of renewable energy power is low, such as in particularly windy areas of Norway or Patagonia, it may be more convenient to use a less energy efficient system 100 but with a lower investment (CAPEX) in the contactor 20.|[0119] As a skilled person can well understand from the above example, the hydroxide 650 available for other uses is a fully decarbonized hydroxide in case the electric power 120 powering the calciner and the electric power (not shown in the example) powering the extraction, the transport and the crushing of the carbonate and the pumping of the water were renewable; otherwise, the hydroxide 650 would be decarbonized except for the share of the emissions due to the energy contribution mentioned above.|[0120] As a person will certainly be able to understand, the availability of carbonate, water and renewable electric power are not limiting factors to produce enough decarbonized oxide or hydroxide according to the invention to permanently store all the anthropogenic CO2 and to generate the negative CO2 emissions needed to comply with the 2015 Paris Agreements.|[0121] As the skilled person can well conclude, the method and the plant according to the invention make it possible to produce decarbonized oxide or hydroxide: it is thus possible to overcome one of the most important technical/economic obstacles to the spread of the plants for the permanent storage of the CO2 and for the generation of negative emissions worldwide and with competitive costs.|[0122] It is clear that the specific characteristics are described in relation to different embodiments of the plant and of the method with an illustrative and non-limiting intent. Obviously, further modifications and variations may be made to the plant and the method according to the present invention by a person skilled in the art, in order to meet contingent and specific requirements. The scope of protection of the invention is however defined by the following claims. | (EP4267282)|[0001] The present invention relates to a method and a plant for producing decarbonized oxide or hydroxide using carbonate and electric power.|[0002] The effects of so-called "greenhouse gases" on the climate have long been known, especially the correlation between the concentration in the atmosphere of CO2 (carbon dioxide) and global warming.|[0003] The efforts of the scientific community and world politics in recent years have been concentrated on trying to counteract the increase in greenhouse gas emissions into the atmosphere, in order to avoid the phenomenon of global warming, i.e. the rise in the average temperature at a global level.|[0004] In a per se known way, many initiatives aimed at containing CO2 emissions into the atmosphere have been promoted at an international level: the Kyoto Protocol in 1997 and the Paris Agreement in 2015, among others, are worth mentioning.|[0005] The forms identified by the scientific community to avoid global warming are many and substantially concern the decrease in the use of fossil fuels such as coal, oil and natural gas favouring the development of renewable energies such as hydraulic, wind, solar, biomass energy and of zero-emission fuels such as hydrogen or ammonia.|[0006] Furthermore, many efforts of the international community are focused on improving the efficiency of energy use, like in the case of lighting with low consumption lamps, on the transport with new generations of high-efficiency engines and, in the field of power generation, on replacing old, inefficient coal- or oil-fired power stations with new combined-cycle plants with gas turbine and vapour turbine having energy yields approaching 60%.|[0007] Despite the technological efforts being made in the most advanced nations, the forecasts of well-known international institutions on the energy needs at global level over the next few years indicate a sharp increase in the demand of electric power, thermal energy for industry and of fuels for transportation.|[0008] Consequently, these forecasts indicate a steady increase in the use of fossil sources such as oil, coal and natural gas, especially by emerging, newly industrialised and developing countries. This consumption is in fact favoured by the huge availability of these resources and by the discovery of new deposits and techniques for the extraction thereof, factors which altogether make these energy sources economically favourable.|[0009] Using the data envisaged by these authoritative studies, a decrease in CO2 emissions is just globally not expected in order to combat global warming, but a substantial increase in the emissions is instead expected over the next 50 years, mainly due to the increase in world population and the new industrialisation of entire countries.|[0010] The catastrophic effects of such a situation on the climate are easy to see and difficult to avoid especially because developing nations believe that the renewable energy option is too sophisticated and costly, and are more oriented towards short-term economic development programmes than towards CO2 emission containment and environmental issues.|[0011] One of the industries that will be targeted by the future decarbonization of the economy is represented by the lime industry.|[0012] The calcination process that transforms the carbonates (limestones and dolomites) into oxides produces large quantities of CO2 mainly coming from the decomposition of the ore at high temperature and secondarily from the fuels used.|[0013] It is therefore impossible to decarbonize the lime industry if no permanent CO2 storage is available, even if the fuels used in the calcination process were completely renewable. Different technologies have been proposed in order to be able to produce oxides with CO2 capture, but with all the proposed technologies there remains the problem of the permanent storage of the CO2 emissions produced in the process.|[0014] In US5965103, the carbon dioxide produced in the calcination of limestone is made to react with the calcium hydroxide obtained from the hydration of calcium oxide to produce a calcium carbonate slurry.|[0015] In a per se known way, CO2 capture and storage technologies are commonly referred to as CCS (Carbon Capture and Storage or also Carbon Capture and Sequestration).|[0016] The main CCS technologies proposed and known are:| CO2 sequestration in deep saline aquifers, a method recognised and promoted by the European Union through a specific directive dated 2009;| CO2 sequestration directly in the ocean floor, in liquid form;| the sequestration of CO2 in calcium carbonates or calcium silicates, either directly or with the use of peptoids, known as Mineral Carbonation;| the sequestration of CO2 in oil wells where it is injected to increase the oil production of the well itself with a technology called EOR (enhanced oil recovery);| the sequestration of CO2 in the form of alkaline earth metal bicarbonates such as calcium and magnesium bicarbonate.|[0017] Although various technological alternatives are available, one of the most important issues still to be solved is the prohibitive cost of CO2 capture and the limited availability of permanent storages of the CO2 produced to offer decarbonized lime-based products on the market.|[0018] As can be immediately understood, there is a need to identify a technology that allows the production of oxides through the carbonate calcination process to be carried out with simple technologies and to solve the problem of storing CO2 in a distributed form throughout the territory at an acceptable cost.|[0019] The task of the present invention is to make available a method and a plant that can enable the efficient generation of oxides by calcination of carbonates with permanent storage of CO2 at lower costs than known technologies.|[0020] This object and these tasks are achieved by means of a plant according to claim 1 and by means of a method according to claim 9.|[0021] In order to better understand the invention and appreciate its advantages, some exemplary and non-limiting embodiments thereof are described below, with reference to the attached drawings, in which:| Figure 1 is a schematic view of a plant for producing decarbonized oxide according to the invention;| Figure 2 is a schematic view of another possible embodiment of the plant for producing decarbonized oxide according to the invention;| Figure 3A is a schematic view of a possible embodiment of the plant for producing decarbonized hydroxide according to the invention;| Figure 3B is a schematic view of another possible embodiment of the plant for producing decarbonized oxide according to the invention;| Figure 4 is a schematic view of another possible embodiment of the plant for producing decarbonized hydroxide according to the invention;| Figure 5 is a graph of the equilibrium of 2270 kg calcite and 1000 kg CO2 in seawater as a function of the pH and of the quantity of water;| Figure 6 is the graph of the trend of the residual CO2 quantity after a dwell time of 100000 s in the contactor with 2270 kg CaCO3 with 10 micron size and 1500 m3 of water as a function of the pressure in bara;| Figure 7 is a mass and energy balance of a possible embodiment of the plant for producing decarbonized hydroxide according to the invention;| Figure 8 is a mass and energy balance of a possible embodiment of the plant for storing CO2 coming from an external source according to the invention.| Figure 9 is a mass and energy balance of a possible embodiment of the plant for producing decarbonized hydroxide according to the invention.|[0022] In the description, reference will also be made to "carbonic gas", meaning thereby a gas mixture containing mainly CO2, and possibly other substances including N2, O2, H2O, Ar, whereas when reference is intended to be made to the chemical element CO2 (carbon dioxide) alone, CO2 will be used in the description.|[0023] In the description, reference will also be made to "non-soluble" gases, meaning thereby all gases that are not very soluble in water, including H2, CO, CH4, N2, Ar.|[0024] In the description reference will also be made to "water", meaning thereby water in the liquid phase with the chemical and temperature characteristics necessary for use in the process according to the invention, whereas when reference is intended to be made to the chemical element H2O alone, H2O will be used in the description.|[0025] In the description, reference will also be made to the "vapour", meaning thereby water in vapour form with the temperature and pressure characteristics necessary for use in the process according to the invention.|[0026] In the description, reference will also be made to the "sea", meaning thereby the sea itself but also the ocean, a lake, a river or any salt or fresh water body.|[0027] The description will also refer to "carbonate" meaning any calcareous or dolomitic sedimentary rock such as calcite, aragonite, dolomite, siderite, magnesite, marble, but also any other carbonate material such as shells or corals.|[0028] In the description reference will also be made to the "electric calciner" (or electric furnace) meaning any electrical apparatus under controlled atmosphere, per se known, capable of calcining the carbonate according to the reactions:| CaCO3 → CaO + CO2 (+183 kJ/mol)|or| MgCO3 → MgO + CO2 (+118 kj/mol).|[0029] The calcination process, per se known, takes place at temperatures preferably comprised between 600°C and 1200°C and is an endothermic process. The controlled-atmosphere electric calciner does not allow direct contact of the calcining zone with the ambient air, while it does allow flushing the calcining zone possibly with water vapour.|[0030] In the description, reference will also be made to the "oxide", meaning thereby the product of the calcination formed mainly by calcium oxide CaO or magnesium oxide MgO and to a lesser extent by other materials present in the carbonate rock with which the calciner is fed.|[0031] In the description, reference will also be made to the "hydroxide", meaning thereby the product of the hydration of calcium oxide Ca(OH)2 or of magnesium oxide Mg(OH)2 with the following chemical reactions:| CaO + H2O → Ca(OH)2 (-64.8 kJ/mol)| MgO + H2O → Mg(OH)2 (-37.0 kj/mol)|[0032] In the description reference will be made to the "bicarbonates" meaning thereby the chemical compounds Ca(HCO3)2(aq) and/or Mg(HCO3)2(aq)|[0033] In the description, reference will be made to the "impurities", meaning thereby foreign substances present in the carbonate which do not take part in the chemical reactions in the reactor according to the invention.|[0034] In the description, reference will be made to the "contactor", meaning thereby a reactor in which CO2, water and possibly carbonate are reacted according to the following reactions | and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate rock. This reactor is known as "limestone contactor" or "calcite contactor" and is normally used for remineralising drinking water from reverse osmosis plants and can be with fixed bed (updraft or downdraft), fluidised bed, either pressurised or atmospheric.|[0035] In the description, reference will be made to the "ionic mixture", meaning thereby a mixture where the carbonate, if any, has dissolved and Ca2+ or Mg2+ are in ionic form. "Ionic mixture" also refers to the mixture of water and CO2 alone.|[0036] In the description, reference will be made to the "buffered ionic mixture", meaning thereby an ionic mixture in which the pH has been corrected to the desired value by the addition of an oxide or a hydroxide.|[0037] In the description, reference will be made to "Ωcal", meaning thereby the calcite saturation state in seawater.|[0038] In the description, reference will be made to "pH", meaning thereby the measurement scale indicating the acidity or the basicity of a liquid which is defined by the following formula: |[0039] In the description, reference will be made to the "alkalinity", meaning thereby the quantity of hydroxides OH-, carbonates CO32- and bicarbonates HCO32- present in seawater.|[0040] In the description reference will be made to the "hardness", meaning thereby a value expressing the total content of Ca2+ and Mg2+ ions present in seawater.|[0041] In the description, reference will also be made to the "buffering substance", meaning thereby both the oxide and the hydroxide.|[0042] In the description, reference will also be made to the "atmosphere", meaning thereby any place in contact with atmospheric air.|[0043] In the description, reference will be made to "bara", meaning thereby the unit of absolute pressure in the CGS system (centimetre-gram-second). 1 bara corresponds to 105 Pa in the International System.|[0044] In the description, reference will also be made to "high temperature" meaning thereby a temperature greater than 600°C.|[0045] In the description, reference will also be made to "ambient temperature", meaning thereby a temperature lower than 50°C.|[0046] In the description, reference will also be made to the "preheating temperature", meaning thereby a temperature comprised between 50°C and 600°C.|[0047] In the description, reference will also be made to the "average pressure of the contactor", meaning thereby the weighted average pressure to which the carbonate is subjected during the dwell time in the contactor.|[0048] In the description, reference will also be made to the concept of "decarbonized", meaning thereby a product or service that does not entail CO2 emissions into the atmosphere, i.e. where the CO2 produced by the production process has been stored permanently.|[0049] In the attached figures, the reference 100 indicates as a whole the plant according to the invention.|[0050] A first aspect of the invention concerns a plant 100 for producing decarbonized oxide or hydroxide. With reference to Figures 1 to 4, the plant 100 comprises an electrical calciner 10, a contactor 20, a pH correction apparatus 30 and a dosing device 40, wherein:| the electric calciner 10 is adapted to receive at the inlet a flow of carbonate 110, electric power 120 and to release at the outlet at least one flow of carbonic gas 140 at high temperature and at least one flow of oxide 130;| the flow of oxide 130 is adapted to provide a flow of buffering substance;| the contactor 20 is adapted to receive at the inlet the flow of carbonic gas 140 released by the electric calciner 10, a flow of carbonate 220, a flow of water 210;| the contactor 20 is adapted to make the carbonate 220 react with water 210 and the CO2 present in the carbonic gas 140 according to the following reactions and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet at least one flow of ionic mixture 230;| the contactor 20 is provided with means for releasing non-soluble gases 221;| the pH correction apparatus 30 is adapted to receive at the inlet at least one flow of buffering substance 440; 640 and the flow of ionic mixture 230, is adapted to make the ionic mixture 230 react with the buffering substance 440; 640 according to the following reactions| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|and to release at the outlet a flow of buffered ionic mixture 240;| the dosing device 40 is adapted to receive at the inlet a flow of buffering substance 130; 630 deriving from the electric calciner 10 and to release at the outlet a predetermined quantity of buffering substance 440; 640 to feed the pH correction apparatus 30 and possibly a quantity of buffering substance 450; 650 available for use.|[0051] In some embodiments of the plant 100 according to the invention (see, for example, Figures 1 and 2), the buffering substance is the oxide 130; 440 originated from the electric calciner 10 and the pH correction apparatus 30 is adapted to make the ionic mixture 230 react with the oxide 440 according to the reaction| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|[0052] In some embodiments of the invention (see, for example, Figures 3A, 3B and 4), the plant 100 further comprises a hydroxide production unit 60 installed between the electric calciner 10 and the pH correction apparatus 30, wherein:| the hydroxide production unit 60 is adapted to receive at the inlet at least one flow 130; 440 of oxide originated from the electric calciner 10, a predetermined flow of water 610, and| the hydroxide production unit 60 is adapted to make the oxide 130; 440 react with water 610 according to the reaction| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet a flow of hydroxide 630; 640 and possibly, a flow of vapour 620.|[0053] The hydroxide production unit 60 may be installed between the electric calciner 10 and the dosing device 40 (see Figures 3A and 4) or between the dosing device 40 and the pH correction apparatus 30 (see Figure 3B).|[0054] In such embodiments of the plant 100, the buffering substance fed to the pH correction apparatus 30 may be the hydroxide 630; 640 produced by the hydroxide production unit 60.|[0055] In accordance with an embodiment of the plant 100 according to the invention and with reference to Figures 2, 3A and 4, the plant 100 further comprises a control unit 50 and a meter of the chemical parameters of water 51 adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture 230 or of the buffered ionic mixture 240. The meter of the chemical parameters of water 51 is further adapted to provide the measurement to the control unit 50, and the control unit 50 is adapted to control the dosing device 40 so that it feeds the pH correction apparatus 30 with the quantity of buffering substance 440; 640 that is suitable for obtaining a buffered ionic mixture 240 with a desired pH.|[0056] In accordance with some embodiments of the plant 100 (see, for example, Figure 4), the plant 100 further comprises a conduit adapted to feed the flow of vapour 620 released by the hydroxide production unit 60 to the electric calciner 10.|[0057] In accordance with some embodiments of the plant 100 (see, for example, Figure 4), the plant 100 further comprises a carbonate preheating unit 15, wherein the carbonate preheating unit 15 is adapted to receive at the inlet the flow of carbonic gas 140 at high temperature released by the electric calciner 10, a flow of carbonate 110 and to release at the outlet a flow of carbonic gas 151 and a flow of carbonate 111.|[0058] In a per se known form, the carbonate preheating unit 15 is a heat exchanger which may be a direct-contact unit in which the flow of carbonic gas comes into direct contact with the carbonate, or it may be an indirect-contact unit in which the carbonate and the carbonic gas always remain separate while exchanging heat.|[0059] A skilled person will certainly be able to understand that the size of the contactor 20 depends on the flow rates of carbonic gas 140 or 151, of water 210 and possibly of carbonate 220 and on the kinetics of the chemical reactions that take place. The ratios between the flow rates of carbonic gas 140 or 151, water 210 and carbonate 220 are established with physico-chemical criteria that allow the reactions to be completed | and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate) avoiding the precipitation of carbonates in the pH correction apparatus 30 during the insertion of the buffering substance 440 or 640 due to too high Ωcal.|[0060] A skilled person will therefore agree that the required contact time between the water 210, the carbonic gas 140 or 151 and possibly the carbonate 220 is the main parameter that allows sizing the contactor 20: if for a contact time of 10 s, a flow rate of carbonic gas 140 or 151 of 1 kg/s, it were required 1 m3/s of water 210, this means that the size of the contactor 20 must be about 10 m3, whereas if the flow rate of carbonic gas 140 or 151 were 10 kg/s, it would be required 10 m3/s of water and the size of the contactor would be about 100 m3.|[0061] In accordance with an embodiment of the plant 100, the contactor 20 has a volume which allows a contact time of the water 210 with the carbonate 220 and the carbonic gas 140 or 151 of at least 1000 s and an average pressure of the contactor greater than 1.0 bara.|[0062] In accordance with an embodiment of the plant 100 (see for example Figures 3B and 9), the quantity of carbonate 220 introduced into the contactor 20 is zero and the contactor 20 has a volume which allows a minimum contact time of the water with the carbonic gas 140 or 151 of 10 s, preferably comprised between 60 s and 300 s, which allows for a partial pressure of CO2 greater than 0.1 bara, preferably comprised between 0.2 bara and 2 bara.|[0063] In a per se known form and in accordance with experimental results and the scientific literature, the time it takes for CO2 to completely hydrate in water to form carbonic acid H2CO3 according to the reaction: | has a characteristic time ranging from a few seconds to a few minutes.|[0064] It should be noted here that the carbonic gas fed to the contactor 20 can be either the carbonic gas (indicated with 140) coming directly from the electric calciner 10 or it can be the carbonic gas (indicated with 151) coming from the carbonate preheating unit 15.|[0065] It should be noted here that the carbonate fed to the electric calciner 10 can be both carbonate at room temperature (indicated with 110 in figs. 1, 2 and 3) and preheated carbonate (indicated with 111 in fig. 4).|[0066] It should be noted here that the buffering substance fed to the pH correction unit 30 may be the oxide (indicated with 440; fig. 1 and 2) or it can be the hydroxide (indicated with 640; fig. 3 and 4).|[0067] It should be noted here that the buffering substance fed to the dosing device 40 can be either the oxide (indicated with 130; fig. 1, 2 and 3B) released by the electric calciner 10 or the hydroxide (indicated with 630; fig. 3A and 4) released by the hydroxide production unit 60, and that the buffering substance released by the dosing device 40 can be both the oxide (indicated with 440 and 450) and the hydroxide (indicated with 640 and 650).|[0068] A second aspect of the invention concerns a method for decarbonized calcination. The method according to the invention comprises the steps of:| providing an electric calciner 10;| feeding the electric calciner 10 with electric power 120 and a flow of carbonate 110; 111 in order to obtain the calcination of the carbonate 110 according to the reaction| CaCO3 → CaO + CO2|(where Ca can be substituted with Mg if present in the carbonate);| releasing at the outlet of the electric calciner 10 a flow of carbonic gas 140 at high temperature and a flow of oxide 130;| conveying the flow of carbonic gas 140;| conveying the flow of oxide 130;| from the flow of oxide 130 obtaining a flow of buffering substance 440; 640;| providing a contactor 20;| feeding the contactor 20 with the flow of carbonic gas 140 produced by the electric calciner 10 and a predetermined flow of water 210 in order to obtain a flow of ionic mixture 230 through the reaction ;| releasing the flow of ionic mixture 230 at the outlet of the contactor 20;| conveying the ionic mixture 230;| providing a dosing device 40;| feeding the flow of buffering substance 130, 630 to the dosing device 40;| releasing a predetermined flow of buffering substance 440; 640 at the outlet of the dosing device 40;| conveying the flow of buffering substance 440; 640;| providing a pH correction apparatus 30;| feeding the pH correction apparatus 30 with the flow of ionic mixture 230 and with the predetermined flow of buffering substance 440; 640 so that the reactions take place| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq);| releasing the flow of buffered ionic mixture 240 at the outlet of the pH correction apparatus 30;| placing the flow of buffered ionic mixture 240 into the sea.|[0069] In accordance with some embodiments of the invention, the method further comprises the step of feeding to the contactor 20 a predetermined flow of carbonate 220 so that the reaction can take place| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|[0070] In accordance with some embodiments of the invention, the flow of buffering substance fed to the pH correction apparatus 30 is a flow of oxide 440.|[0071] In accordance with some embodiments of the invention, the method further comprises the steps of:| providing a hydroxide production unit 60;| feeding the hydroxide production unit 60 with a flow of oxide 130; 440 and a predetermined flow of water 610 so that the reaction can take place| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate); and| releasing at least one flow of hydroxide 630 and one flow of vapour 620 at the outlet of the hydroxide production unit 60.|[0072] In accordance with such embodiments of the method, the flow of buffering substance fed to the pH correction apparatus 30 may be a flow of hydroxide 640.|[0073] In accordance with such embodiments, the method may further comprise the steps of:| conveying the flow of vapour 620 at the outlet of the hydroxide production unit 60; and| feeding the flow of vapour 620 to the electric calciner 10.|[0074] In accordance with some embodiments of the invention, the method further comprises the steps of:| providing a control unit 50 and a meter of the chemical parameters of water 51 adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture 230 or of the buffered ionic mixture 240;| providing the pH and/or alkalinity and/or hardness measurement from the pH meter 51 to the control unit 50;| controlling the dosing device 40 by means of the control unit 50 so that it feeds the pH correction apparatus 30 with the correct quantity of buffering substance 440; 640 in order to obtain a buffered ionic mixture 240 with a desired pH.|[0075] In accordance with some embodiments, the method may further comprise the steps of:| providing a carbonate preheating unit 15;| feeding the carbonate preheating unit 15 with the flow of carbonic gas 140 at high temperature released by the electric calciner 10 and a flow of carbonate 110;| releasing a flow of preheated carbonate 111 from the carbonate preheating unit 15; and| feeding the electric calciner 10 with the preheated flow of carbonate 111.|[0076] Referring to Figures 1, 2, 3 and 4, a skilled person will be able to see that the electric calciner 10 is fed with carbonate 110 or 111 and electric power 120 and releases the oxide 130 and the carbonic gas 140. The electric calciner 10 is fed by electric power to generate the heat required for calcination. Electric power can be used in electric resistances, microwave generators or induction systems.|[0077] In a per se known form, the calcination of the carbonate 110 takes place according to the reaction| CaC03 → CaO + CO2|where Ca can be substituted with Mg if present in the carbonate 110, at temperatures comprised between about 600° (MgCO3) and 1200°C (CaCO3) and at intermediate values depending on the chemical composition of the carbonate, which can also be a dolomite CaMg(CO3)2, and of the chemical composition of the atmosphere in the calciner.|[0078] In a per se known form, the calcination reaction is an endothermic reaction requiring 118 kJ/mol of heat in the case of MgCO3 calcination and 183 kJ/mol in the case of CaCO3.|[0079] A skilled person can understand that the CO2 produced by an electric calcination under controlled atmosphere generates a carbonic gas 140 formed by CO2 and traces of non-soluble gases that may have entered with the carbonate 110 or 111 inside the electric calciner 10 or gases intentionally fed to the electric calciner 10 to improve the process conditions, such as in the case of water vapour (Figure 4).|[0080] Referring to the embodiment of Figures 1, 2, 3 or 4, the plant 100 according to the invention comprises the contactor 20.|[0081] In a per se known form, the contactor 20 uses water 210 and carbonate 220 as a means for absorbing CO2 from the flow of carbonic gas 140 and forming the ionic mixture 230 according to the reaction:| CO2(g) + CaCO3(s) + H2O => Ca2+(aq) + 2HCO3-(aq) [1]|where Ca can be substituted with Mg if present in the carbonate 220.|[0082] In a per se known form, there exist different types of contactors (limestone contactors or calcite contactors), generally used for the remineralisation of drinking water downstream of desalination treatments.|[0083] In a per se known form, the permanent storage of CO2 in the form of bicarbonates in the sea using contactors has been proposed in several scientific articles and patents, among which it is worth mentioning the US patent 6,890,497 B2 entitled "Method for extracting and sequestering carbon dioxide" and the Italian patent application IT202000000037 entitled "Plant and method for sequestering CO2 with a growing pressure reactor conduit".|[0084] In a per se known form, the contactors used for the remineralisation of water or whose use has been proposed for the permanent storage of CO2 in the form of bicarbonates must keep the water that is in contact with the carbonate sufficiently undersaturated, with an Ωcal preferably comprised between 0.01 and 0.6, to allow a dissolution kinetics of the carbonate that is sufficiently rapid and acceptable for an industrial plant. For this reason, the commercial contactors use an excess of CO2 in the water, a pH generally comprised between 5 and 6, and a final degassing of the CO2 to bring the pH of the water back to values above 7.|[0085] In a per se known form, the CO2 storage technologies by means of bicarbonates in the sea include, as mentioned above, the discharge of an acid effluent (pH comprised between 6 and 7), with still a significant quantity of CO2 not reacted with the carbonate according to the reaction [1]. This fact turns out to be environmentally harmful if the effluent discharge takes place in the depths of the sea where there is no possibility of degassing CO2 or it is very inefficient (CO2 storage efficiencies of about 50%) where the discharge takes place on the surface with degassing of the residual CO2.|[0086] A skilled person will understand that by neutralizing this acidity present in the acid mixture 230 with a buffering substance 440 or 640, an effluent with the same natural pH as seawater could be discharged into the sea and all the residual CO2 could be stored in the form of bicarbonates according to the reaction| Ca(OH)2 + 2CO2 + H2O → Ca2+ + (HCO3)2|where the Ca2+ ion can be substituted with the Mg2+ ion, eliminating the environmental issues due to the discharge of acid effluents and achieving a CO2 storage efficiency of about 100%.|[0087] In a per se known form, the reaction of Ca(OH)2 (where Ca can be substituted with Mg if present in the carbonate) with seawater is a complex reaction due to the presence of other chemical elements and therefore it results that for each mole of Ca(OH)2 it is possible to neutralise less than the 2 moles of CO2 envisaged by the stoichiometry of the equation| Ca(OH)2 + 2CO2 + H2O → Ca(HCO3)2(aq).|[0088] Referring to the embodiment of Figures 1, 2, 3 or 4, the plant 100 according to the invention comprises the pH correction apparatus 30 in which the ionic mixture 230 is mixed with a predetermined quantity of buffering substance 440 or 640 that is sufficient to obtain the desired pH of the buffered mixture 240.|[0089] A skilled person can easily understand that the composition of the ionic mixture 230 released by the contactor 20 may contain impurities which should conveniently be filtered from the mixture 230 by means of special filters (not shown in the figure) placed between the mixer 20 and the pH correction apparatus 30 or downstream of the pH correction apparatus 30.|[0090] Referring to the embodiment of Figures 2 and 4, the apparatus 100 according to the invention is provided with a meter of the chemical parameters of water 51 adapted to measure the pH and/or the alkalinity and/or the hardness of the water and with a control unit 50 for managing the dosing device 40 which allows feeding the pH correction apparatus 30 with the correct quantity of oxide 440 or hydroxide 640. In the case of hydroxide 640, the dosing device 40 may be a dosing pump as the hydroxide 640 may be fed to the pH correction apparatus 30 in the form of a suspension (slurry) or an ionic solution.|[0091] In a per se known form, the dissolution of the carbonate 220 in the contactor 20 depends on the quantity of water and on the pH according to the equilibrium curve presented in Figure 5 which refers to the complete dissolution of 2270 kg of CaCO3 in seawater in the presence of 1000 kg of CO2.|[0092] A skilled person will certainly be able to calculate, with the information available in the literature, the dissolution rate of the carbonate as a function of the quantity of water and the pH and the sizes of the contactor 20.|[0093] In a per se known form and as already mentioned above, the dissolution rate of the carbonate decreases asymptotically to zero as the equilibrium conditions are approached and therefore, in order to keep the sizes of the contactor 20 within commercially acceptable limits, it is necessary to maintain process conditions away from the equilibrium by using in the contactor 20 a water pH preferably comprised between 5 and 6.5 with water quantities from 1000 m3/tonCO2 to 4000 m3/tonCO2.|[0094] A skilled person can certainly understand that the ionic mixture 230 released by the contactor 20, if not subjected to CO2 degassing with a loss of storage efficiency, generally has a pH comprised between 6 and 6.5, lower than the pH of the sea which is about pH 8.|[0095] A skilled person will certainly be able to understand that, in order to avoid acidifying the sea by releasing an acid ionic mixture 230, it is necessary to buffer the pH with a basic substance such as the oxide 440 or the hydroxide 640.|[0096] A skilled person will certainly be able to understand that it would also be possible to use other substances to buffer the ionic solution 230, such as NaOH or KOH, but that their cost would make them not economically convenient.|[0097] A skilled person will certainly be able to verify that the contact times between the water 210 and the carbonate 220 inside the contactor 20 required for a complete dissolution of the carbonate depend on the sizes of the carbonate 220 itself and on the ratio between the quantities of CO2 present in the carbonic gas 140 and the quantity of water 210.|[0098] A skilled person will certainly be able to verify that by using a ratio of mass flow of water 210 to CO2 present in the carbonic gas 140 of less than 2000:1, and a carbonate particle 220 greater than 6 microns, the minimum contact time between water 210 and carbonate 220 inside the contactor 20 that are necessary to have a residual quantity of CO2 in the mixture 230 lower than 80% are higher than 50000s.|[0099] A skilled person will easily be able to verify that with the same mass ratio between the water 210 and the CO2 present in the carbonic gas 140 and by decreasing the quantity of carbonate 220 used in the contactor 20 according to the invention, the necessary contact time between the water 210, the CO2 and the carbonate 220, progressively decreases until reaching a few seconds that are necessary only for the hydration of the CO2 in the particular case in which the carbonate 220 used is zero.|[0100] A skilled person will certainly be able to understand that the choice of the contact time between the water 210, the CO2 present in the carbonic gas 140 or 151 with the carbonate 220 or the choice of not using the carbonate 220 to buffer the CO2 present in the carbonic gas but only the buffering substance 440 or 640 are economic choices: in fact, by decreasing the quantity of carbonate 220 used with the same quantity of CO2 present in the carbonic gas 140 or 151 and of water 210, the sizes and the plant cost of the contactor 20 are reduced at the expense of a greater consumption of electric power necessary to produce greater quantities of oxide 130 necessary to buffer the CO2 present in the ionic mixture 230 or of smaller quantities of hydroxide 650 available for sale.|[0101] In a per se known form, the dissolution of the carbonate in water is favoured and directly proportional to pressure. A skilled person will certainly be able to understand that it is advisable that the average pressure of the contactor 20 be higher than the pressure of 1 bara.|[0102] Referring to Figure 7, a skilled person can certainly understand the simplified mass and energy balance of a particular plant 100 for producing decarbonized hydroxide in which:| the electric calciner 10 is fed by 2270 kg of carbonate (CaCO3) 110 and by 2000 kWhe of electric power 120 and releases at the outlet 1000 kg of carbonic gas (CO2) 140 and 1271 kg of oxide (CaO) 130;| the contactor is fed by 1000 m3 of water 210 (considered to have a density of 1 kg/dm3), by 1135 kg of carbonate (CaCO3) 220 and 1000 kg of carbonic gas (CO2) 140 and releases at the outlet, after a dwell time of 80,000 s at an average pressure of 150 bara, 1002135 kg of ionic mixture 230 in which 500 kg of CO2 and a pH of about 6.2 are still present;| the hydroxide production unit 60 is fed by 1271 kg of oxide 130 released by the electric calciner 10 and by a predetermined flow of water (not shown) and releases at the outlet 1680 kg of hydroxide (Ca(OH)2) 630;| the dosing device 40 receives at the inlet 1680 kg of hydroxide 630 released by the hydroxide production unit 60 and releases at the outlet 560 kg of hydroxide 640 to the pH adjustment apparatus 30 and 1100 kg of hydroxide 650 available for sale as decarbonized hydroxide;| the pH correction apparatus 30 receives at the inlet 1002130 kg of ionic mixture 230 released by the contactor 20 and 560 kg of hydroxide 640 released by the dosing device 40 and releases 1002690 kg of buffered ionic mixture 240 with pH of 8 exploiting the reaction| Ca(OH)2(aq)+2CO2→Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate. In the case of seawater, depending on its chemical composition, 1 mole of Ca(OH)2 neutralises 1.50-2.00 moles of CO2. In the case under examination, a ratio of 1.5 moles of CO2 per mole of Ca(OH)2 is taken into consideration.|[0103] As a skilled person can well understand from the above example, the hydroxide 650 available for other uses is a fully decarbonized hydroxide in case the electric power 120 powering the calciner and the electric power (not shown in the example) powering the extraction, the transport and the crushing of the carbonate and the pumping of the water were renewable; otherwise, the hydroxide 650 would be decarbonized except for the share of the emissions due to the energy contribution mentioned above.|[0104] As a skilled person can understand, the hydroxide 650, or the oxide 450, can be conveniently used to capture CO2 coming from industrial processes or power plants by means of the reactions| Ca(OH)2(aq) + 2CO2→Ca(HCO3)2(aq)|or, in a less efficient form,| Ca(OH)2 + CO2 → CaCO3 + H2O|(where Ca can be substituted with Mg if it were present in the carbonate).|[0105] A skilled person will certainly be able to understand that the hydroxide 650 or the oxide 450 produced in a plant according to the invention could be conveniently used for capturing CO2 directly from the atmospheric air once dispersed over large areas both in dry and in liquid or slurry form.|[0106] Referring to Figure 8, a skilled person can certainly understand the simplified mass and energy balance of a particular plant 100 for storing CO2 coming from a source outside the process 100 itself wherein:| the electric calciner 10 is fed by 2270 kg of carbonate (CaCO3) 110 and 2000 kWhe of electric power 120 and releases at the outlet 1000 kg of carbonic gas (CO2) 140 and 1271 kg of oxide (CaO) 130;| the contactor is fed by 1000 m3 of water 210 (considered to have a density of 1 kg/dm3), by 3405 kg of carbonate (CaCO3) 220 and by 1000 kg of carbonic gas (CO2) 140 and releases at the outlet, after a dwell time of 80,000 s at an average pressure of 150 bara, an ionic mixture 230 in which 500 kg of CO2 and a pH of about 6.2 are still present;| the hydroxide production unit 60 is fed by 1271 kg of oxide 130 released by the electric calciner 10, by a predetermined quantity of water (not shown) and releases at the outlet about 1680 kg of hydroxide (Ca(OH)2) 630;| the dosing device 40 receives at the inlet 1680 kg of hydroxide 630 released by the hydroxide production unit 60 and releases at the outlet 1680 kg of hydroxide 640 to the pH correction apparatus 30;| the pH correction apparatus 30 receives at the inlet 1006405 kg of ionic mixture 230 released by the contactor 20 and 1680 kg of hydroxide 640 released by the dosing device 40 and releases 1008085 kg of buffered ionic mixture 240 with pH of 8 exploiting the reaction| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate. In the case of seawater, due to its chemical composition, 1 mole of Ca(OH)2 neutralises 1.5-2.00 moles of CO2. In the case under examination, a ratio of 1.5 moles of CO2 per mole of Ca(OH)2 was taken into consideration.|[0107] As the skilled person can well calculate using market values, the cost of a ton of decarbonized oxide or hydroxide depends mainly on the cost of the carbonate and electric power, while the plant and labour costs have a marginal impact on the final result. In particular, about 2000 kWh of electric power and 2000 kg of carbonate are needed to produce 1 ton of decarbonized calcium hydroxide Ca(OH)2. If the cost of carbonate were 7.5 €/ton and the cost of renewable electric power were 30 €/MWh (this is the LCOE - Levelized Cost Of Energy of wind power), the variable cost of hydroxide would be 75 €/ton.|[0108] A skilled person could therefore calculate that the installation costs of the electric calciner, the contactor, the dosing device, the limestone mill, the civil works and the services account for about 5 €/ton of Ca(OH)2 while the personnel costs are negligible.|[0109] A skilled person will therefore be able to calculate that the final cost of a ton of Ca(OH)2 is 80€. Considering that with one ton of Ca(OH)2 used in a CO2 storage plant using a contactor as illustrated in Figure 8, 0.89 ton of CO2 in the form of calcium bicarbonates or 0.59 ton of CO2 in the form of calcium carbonates can be permanently stored, the cost of CO2 storage according to the invention would be about 89 €/ton and 135 €/ton respectively.|[0110] As a skilled person may certainly know, if a ton of hydroxide Ca(OH)2 were spread on the sea surface in a process known as "ocean liming", 0.9 tons of negative CO2 emissions would be generated: in that case, 1 ton of negative CO2 emissions would cost about €90.|[0111] As a skilled person may certainly know, if a ton of hydroxide Ca(OH)2 were spread on a solid surface such as on a wall or on the ground in contact with atmospheric air, this would absorb the atmospheric CO2 transforming into calcium carbonate CaCO3, generating 0.59 tons of negative emissions: in such a case, 1 ton of negative CO2 emissions would cost about 135 €.|[0112] In a per se known form, about 10 km2 of surface exposed to the air are required to capture 1000000 tons/year of CO2 from the atmosphere. This surface can be conveniently obtained in flat and desert areas where the hydroxide can be spread in the form of slurry in special tanks built in a similar way to salt pans or rice fields and allowed to dry forming a solid mainly formed by CaCO3 and possibly salts if the water used to form the slurry is seawater.|[0113] In the latter case, the desert surfaces covered with carbonate generated by carbonation of the hydroxide would be white and would generate an albedo effect reflecting part of the solar radiation and further contributing to contain the increase in the average temperature on earth.|[0114] As a skilled person can certainly understand, the process for producing decarbonized oxide or hydroxide according to the invention makes it possible to permanently store CO2 in the sea in the form of bicarbonates and on land in the form of carbonates at a cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|[0115] As a skilled person will certainly be able to understand, in some cases it may be advantageous to opt for a simplified plant 100 in which, at the expense of a higher energy cost for the calcination process, it is possible to eliminate the investment in an expensive large-sized contactor 20 by eliminating the step of dissolution of the carbonate 220 and by buffering all the CO2 present in the carbonic gas 140 or 151 by means of the oxide 440 or the hydroxide 640.|[0116] Referring to Figure 9, a skilled person can certainly understand the simplified mass and energy balance of a particular plant 100 for producing decarbonized hydroxide in which:| the electric calciner 10 is fed by 2270 kg of carbonate (CaCO3) 110 and by 2000 kWhe of electric power 120 and releases at the outlet 1000 kg of carbonic gas (CO2) 140 and 1271 kg of oxide (CaO) 130;| the contactor is fed by 1000 m3 of water 210 (considered to have a density of 1 kg/dm3), and by 1000 kg of carbonic gas (CO2) 140 and releases at the outlet, after a dwell time of 60 s at an average pressure of 1.5 bara, 1001000 kg of ionic mixture 230 in which 1000 kg of CO2 and a pH of about 5.2 are still present;| the hydroxide production unit 60 is fed by 1271 kg of oxide 130 released by the electric calciner 10 and by a predetermined flow of water (not shown) and releases at the outlet about 1680 kg of hydroxide (Ca(OH)2) 630;| the dosing device 40 receives at the inlet about 1680 kg of hydroxide 630 released by the hydroxide production unit 60 and releases at the outlet 1121 kg of hydroxide 640 to the pH adjustment apparatus 30 and about 560 kg of hydroxide 650 available for sale as decarbonized hydroxide;| the pH correction apparatus 30 receives at the inlet 1001000 kg of ionic mixture 230 released by the contactor 20 and 1121 kg of hydroxide 640 released by the dosing device 40 and releases 1002121 kg of buffered ionic mixture 240 with pH of 8 exploiting the reaction| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|where Ca can be substituted with Mg if it were present in the carbonate. In the case of seawater, depending on its chemical composition, 1 mole of Ca(OH)2 neutralises 1.50-2.00 moles of CO2. In the case under examination, a ratio of 1.5 moles of CO2 per mole of Ca(OH)2 is taken into consideration.|[0117] As a skilled person will certainly be able to deduce from the above data, not using carbonate 220 in the contactor 20 leads to a reduction of hydroxide 650 available for market or for negative emissions and an increase in specific energy consumption that goes from about 2 MWh/ton to 4 MWh/ton of Ca(OH)2 but with the elimination of a large-sized contactor 20.|[0118] As a skilled person will certainly be able to understand, in places where the LCOE of renewable energy power is low, such as in particularly windy areas of Norway or Patagonia, it may be more convenient to use a less energy efficient system 100 but with a lower investment (CAPEX) in the contactor 20.|[0119] As a skilled person can well understand from the above example, the hydroxide 650 available for other uses is a fully decarbonized hydroxide in case the electric power 120 powering the calciner and the electric power (not shown in the example) powering the extraction, the transport and the crushing of the carbonate and the pumping of the water were renewable; otherwise, the hydroxide 650 would be decarbonized except for the share of the emissions due to the energy contribution mentioned above.|[0120] As a person will certainly be able to understand, the availability of carbonate, water and renewable electric power are not limiting factors to produce enough decarbonized oxide or hydroxide according to the invention to permanently store all the anthropogenic CO2 and to generate the negative CO2 emissions needed to comply with the 2015 Paris Agreements.|[0121] As the skilled person can well conclude, the method and the plant according to the invention make it possible to produce decarbonized oxide or hydroxide: it is thus possible to overcome one of the most important technical/economic obstacles to the spread of the plants for the permanent storage of the CO2 and for the generation of negative emissions worldwide and with competitive costs.|[0122] It is clear that the specific characteristics are described in relation to different embodiments of the plant and of the method with an illustrative and non-limiting intent. Obviously, further modifications and variations may be made to the plant and the method according to the present invention by a person skilled in the art, in order to meet contingent and specific requirements. The scope of protection of the invention is however defined by the following claims. | Family Number|(100675112)|100675112|Advantages / Prev. Drawbacks|(WO2022137038 A1)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|(CA3202902 A1)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|(EP4267282 B1)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|(US20230390699 A1)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC+CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|(US12070720 B2)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC+CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|(IN202317042419 A)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the market, such as DAC + CCS (Direct Air Capture and CCS) or BECCS (Bio Energy and CCS).|(US20240375076 A1)| (...) cost that is competitive with the cost of geological CCS, and above all to be able to generate negative CO2 emissions at a much lower cost than any technology currently available on the 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US6890497; IT202000000037||US5965103; KR20130023483; US20030160003; US20030127397; XP004179440; US20200361819; JP60206489; US6890497; IT202000000037 | |(US12070720)|Applicant references|-International Search Report issued on Apr. 22, 2022, in corresponding International Application No. PCT/IB2021/061832, 3 pages.|-Written Opinion issued on Apr. 22, 2022, in corresponding International Application No. PCT/IB2021/061832, 8 pages.|-Rau G H et al: “Enhanced carbonate dissolution: a means of sequestering waste CO2 as ocean bicarbonate”, Energy Conversion and Management, Elsevier Science Publishers, Oxford, GB, vol. 40, No. 17, Nov. 1, 1999 (Nov. 1, 1999), pp. 1803-1813, 11 pages.|||(WO2022/137038)|International Search Report [Examiner]|-RAU G H ET AL: "Enhanced carbonate dissolution: - a means of sequestering waste CO"2 as ocean bicarbonate", ENERGY CONVERSION AND MANAGEMENT, ELSEVIER SCIENCE PUBLISHERS, OXFORD, GB, vol. 40, no. 17, 1 November 1999 (1999-11-01), pages 1803 - 1813, XP004179440, ISSN: 0196-8904, DOI: 10.1016/S0196-8904(99)00071-0||||||||(IT202000031562)|Search Report references [Examiner]|-RAU G H ET AL: "Enhanced carbonate dissolution: - a means of sequestering waste CO"2 as ocean bicarbonate", ENERGY CONVERSION AND MANAGEMENT, ELSEVIER SCIENCE PUBLISHERS, OXFORD, GB, vol. 40, no. 17, 1 November 1999 (1999-11-01), pages 1803 - 1813, XP004179440, ISSN: 0196-8904, DOI: 10.1016/S0196-8904(99)00071-0| | GRANTED | (EP4267282)|GRANTED|(US12070720)|GRANTED|(US20240375076)|PENDING|(WO2022/137038)|LAPSED|(CN116964002)|GRANTED|(CA3202902)|GRANTED|(AEP6001584/2023)|PENDING|(IN202317042419)|PENDING|(CL2023001837)|PENDING|(AU2021404910)|PENDING|(IT202000031562)|PENDING | ALIVE | (EP4267282)|ALIVE|(US12070720)|ALIVE|(US20240375076)|ALIVE|(WO2022/137038)|DEAD|(CN116964002)|ALIVE|(CA3202902)|ALIVE|(AEP6001584/2023)|ALIVE|(IN202317042419)|ALIVE|(CL2023001837)|ALIVE|(AU2021404910)|ALIVE|(IT202000031562)|ALIVE | (EP4267282)|LEGAL DETAILS FOR EP4267282|Actual or 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events|Application details|Application country=US US18258956|Application date=2021-12-16|Standardized application number=2021US-18258956|Event publication date=2021-12-16|Event code=US/EXMR|Event group=Administrative notifications|USPTO Examiner Name|PRIMARY EXAMINER:NASSIRI MOTLAGH, ANITA|Event publication date=2021-12-16|Event code=US/ART|Event group=Administrative notifications|USPTO Art Group|ART=1734|Event publication date=2021-12-16|Event code=US/DK|Event group=Examination events|Attorney Docket Number|Docket Nbr: 09980042US|Event publication date=2021-12-16|Event code=US/CUST|Event group=Examination events|Attorney/Agent Customer Number|Customer Nbr: 62008|Event publication date=2021-12-16|Event code=US/SMALL|Event group=Administrative notifications|Appl Has Filed a Verified Statement of Micro to Small Entity Status|Business Entity Status: Small|Event publication date=2021-12-16|Event code=US/AIA|Event group=Administrative notifications|First Inventor File 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SOCIETA' BENEFIT, ITALY|Effective date of the event=2023-06-12|Event publication date=2023-07-20|Event code=US/SMALL|Event group=Administrative notifications|Appl Has Filed a Verified Statement of Micro to Small Entity Status|Event publication date=2023-08-04|Event code=US/PETDGMS|Event group=ACL|Record Petition Decision of Granted to Make Special|Event publication date=2023-08-04|Event code=US/PDPH|Event group=ACL Examination events|Petition Decision PPH Decision|Event publication date=2023-08-30|Event code=US/PTARDY|Event indicator=Pos|Event group=Examination events|Patent Term Adjustment - Ready for Examination|Event publication date=2023-08-31|Event code=US/M903|Event indicator=Pos|Event group=Examination events OAO|Notice of DO/EO Acceptance Mailed|Event publication date=2023-08-31|Event code=US/APPFILEREC|Event group=Administrative notifications OAO|Filing Receipt|Event publication date=2023-09-27|Event code=US/DOCK|Event indicator=Pos|Event group=Examination events|Case Docketed to Examiner|Event publication date=2023-10-14|Event code=US/DOCK|Event indicator=Pos|Event group=Examination events|Case Docketed to Examiner|Event publication date=2023-10-26|Event code=US/CTNF|Event group=Examination events OA OAO|Non-Final Rejection|Event publication date=2023-10-30|Event code=US/112NF|Event indicator=Neg|Event group=Examination events|Non-final rejection reason 112 - 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LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2022/137038)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2022/137038)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, ME, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4267282)|EP; AT; BE; BG; DE; DK; EE; FI; FR; GB; IT; LT; LU; LV; MT; NL; NO; PT; SE; SI|(US12070720)|US|(US20240375076)|US|(WO2022/137038)|AE; AU; CA; CN; DZ; EP; IN; 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SOCIETA' BENEFIT , CITY=Galbiate , COUNTRY=IT , ATYP=Non-US Company|(CL2023001837)|NAME=LIMENET S.R.L. SOCIETA' BENEFIT I-23851 Galbiate (LC) Via Filanda Maggiore, 5, IT | (EP4267282)|IT|(EP4267282)|IT||(WO2022/137038)|IT|||(CA3202902)|CA|(CA3202902)|CA||(AU2021404910)|AU | (EP4267282)|NAME=Belloni, Giancarlo;Thinx S.r.l. Piazzale Luigi Cadorna, 10 , CITY=20123 Milano , COUNTRY=IT , REG=101882651|(EP4267282)|NAME=Belloni, Giancarlo;Thinx S.r.l. Piazzale Luigi Cadorna, 10 , CITY=20123 Milano , COUNTRY=IT , REG=101882651|(US12070720)|NAME=Maier & Maier, PLLC|(WO2022/137038)|NAME=BELLONI, Giancarlo et al. c/o THINX S.r.l. Piazzale L. Cadorna, 10 I-20123 Milano , POSTCODE=I-20123 , COUNTRY=IT|(CN116964002)|NAME=LI JIE;BEIJING KANGXIN INTELLECTUAL PROPERTY LTD. , REG=11240|(CN116964002)|NAME=LI JIE;BEIJING KANGXIN INTELLECTUAL PROPERTY LTD. , REG=11240|(CA3202902)|NAME=CPST INTELLECTUAL PROPERTY INC. 130 QUEENS QUAY EAST EAST TOWER, SUITE 809 , CITY=TORONTO , POSTCODE=M5A 0P6 , COUNTRY=CA , REG=12179|(CA3202902)|NAME=CPST INTELLECTUAL PROPERTY INC. , COUNTRY=CA|(AEP6001584/2023)|NAME=ABU GHAZALEH INTELLECTUAL PROPERTY - DUBAI BRANCH Gulf Towers, Entrance A2, 7th Floor, Oud Metha Road, Bur Dubai, Dubai , REG=557523|(AU2021404910)|NAME=Baxter Patent Attorneys Pty Ltd Level 12 10 Carrington St , CITY=Sydney , STATE=NSW , POSTCODE=2000 , COUNTRY=AU | |(EP4267282)|IT|(EP4267282)|IT|(US12070720)|IT|(US20230390699)|IT|(US20240375076)|IT|(WO2022/137038)|IT|(CN116964002)|IT||(CA3202902)|IT|(CA3202902)|IT|(AEP6001584/2023)|IT|||| | (EP4267282)|NAME=CAPPELLO, Giovanni|(EP4267282)|NAME=CAPPELLO, Giovanni, CITY=23851 Galbiate (LC), COUNTRY=IT|(EP4267282)|NAME=CAPPELLO, Giovanni, CITY=23851 Galbiate (LC), COUNTRY=IT|(US12070720)|NAME=Cappello Giovanni, CITY=Galbiate, COUNTRY=IT|(US20230390699)|NAME=CAPPELLO Giovanni, CITY=Galbiate, COUNTRY=IT|(US20240375076)|NAME=CAPPELLO Giovanni, CITY=Galbiate, COUNTRY=IT|(WO2022/137038)|NAME=CAPPELLO, Giovanni Via del Tuf SNC I-23851 Galbiate (LC), POSTCODE=I-23851, COUNTRY=IT|(CN116964002)|NAME=Giovanni Capello Italy ryco, CITY=Lecco, STATE=Lecco , COUNTRY=IT|(CN116964002)|NAME=CAPPELLO GIOVANNI|(CA3202902)|NAME=CAPPELLO GIOVANNI, COUNTRY=IT|(CA3202902)|NAME=CAPPELLO, GIOVANNI, COUNTRY=IT|(AEP6001584/2023)|NAME=Giovanni CAPPELLO Via del Tuf SNC, I-23851 Galbiate (LC), COUNTRY=IT|(IN202317042419)|NAME=Cappello Giovanni|(CL2023001837)|NAME=Giovanni CAPPELLO I-20123 Milano c/o TRINX S.r.l., Piazzale L. Cadorna, 10|(AU2021404910)|NAME=CAPPELLO, Giovanni|(IT202000031562)|NAME=Cappello, Giovanni | (US20240375076)|9|(WO2022/137038)|9|(IN202317042419)|10|(CN116964002)|10|(US12070720)|9| | 4 | 11 | (EP4267282)|WO2022/137038|(US12070720)|WO2022/137038|(CN116964002)|WO2022/137038|(CA3202902)|WO2022/137038|(AEP6001584/2023)|WO2022/137038|(IN202317042419)|WO2022/137038|(AU2021404910)|WO2022/137038 | (EP4267282)|Gazette date: GAZDATE=2024-05-01||(EP4267282)|Number of Claims: NCL=15||(US12070720)|Number of Claims: NCL=18|Number of Drawings: NDR=10|Number of Figures: NFG=10|Independent Claim Number: ICL=1,9|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1|Extended under 35 USC 154(b) the following days: EXTD=0|Primary examiner: Nassiri-Motlagh Anita|Art Unit.: ART =1734||(US20230390699)|Number of Claims: NCL=15|Number of Drawings: NDR=10|Number of Figures: NFG=10|Independent Claim Number: ICL=16,24|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=16|Primary examiner: Nassiri-Motlagh Anita|Art Unit.: ART =1734||(US20240375076)|Number of Claims: NCL=18|Number of Drawings: NDR=10|Number of Figures: NFG=10|Independent Claim Number: ICL=1,11|Number of Independent Claims: NICL=2|Exemplary Claim Number: ECL=1||(WO2022/137038)|Number of Claims: NCL=15|Extended kind: EXTK=x||(CN116964002)|Number of Claims: NCL=16|Gazette date: GAZDATE=2024-09-20|Gazette number: GAZNUM=40-3802|Substantial examination effective date: 20231114 Examination duration: 10 months|Number of Pages: NPAGES=28|Primary examiner: 白璐|Primary examiner: Bai Lu||(CN116964002)|Number of Claims: NCL=15|Gazette date: GAZDATE=2023-10-27|Gazette number: GAZNUM=39-4302|Substantial examination effective date: 20231114 Examination duration: 10 months|Number of Pages: NPAGES=28|Primary examiner: 白璐|Primary examiner: Bai Lu||(CA3202902)|Number of Claims: NCL=15||(AEP6001584/2023)|PCT National Entry||(IN202317042419)|Number of Claims: NCL=15||(IT202000031562)|Number of Claims: NCL=9|Number of Pages: NPAGES=39| | (US12070720)|Previous publication: US20230390699 A1 2023-12-07 [US20230390699]|(US20240375076)|CIP of: US18/258,956 FDD=2023-06-22 [2023US-18258956]|CIP of: US12070720 |CIP of: WOIB2021/061832 FDD=2021-12-16 [2021WO-IB61832]|(CN116964002)|Previous publication: CN116964002 A 2023-10-27 [CN116964002]|(CA3202902)|Division of: CA3202902 FDD=2021-12-16 [2021CA-3202902] | (EP4267282)|ITALIAN (ITA) | (CA3202902)|Patent|(US20240375076)|Patent|(AE20236001584)|Patent|(CN116964002B)|Patent|(US12070720)|Patent|(IN202317042419)|Patent|(EP4267282)|Patent|(EP4267282)|Patent|(US20230390699)|Patent|(CL202301837)|Patent|(EP4267282)|Patent|(CN116964002)|Patent|(AU2021404910)|Patent|(CA3202902)|Patent|(WO2022137038)|Patent|(IT202000031562)|Patent | Titre: (EP4267282)|Plant and method for producing decarbonized oxide or hydroxide using carbonate and electric power Résumé: (EP4267282)|A plant and a method for producing decarbonized oxide or hydroxide using carbonate, water and electric power are described. The plant (100) comprises an electric calciner (10), a contactor (20), a pH correction apparatus (30) and a dosing device (40). The plant (100) is adapted to receive at the inlet electric power, carbonate and water, and to release at the outlet decarbonized oxide or hydroxide and a buffered ionic mixture rich in bicarbonates, which, once released into the sea, represents the permanent storage for CO2. The plant (100) uses the bicarbonates as permanent CO2 storage in the sea: this storage allows a CO2 storage at low costs and in modular plants. Autre: (EP4267282)|1. Plant (100) for producing decarbonized oxide or hydroxide, comprising an electric calciner (10), a contactor (20), a pH correction apparatus (30) and a dosing device (40), wherein:| - the electric calciner (10) is adapted to receive at the inlet a flow of carbonate (110), electric power (120) and to release at the outlet at least one flow of carbonic gas (140) at high temperature and at least one flow of oxide (130);| - the flow of oxide (130) is adapted to provide a flow of buffering substance;| - the contactor (20) is adapted to receive at the inlet the flow of carbonic gas (140) released by the electric calciner (10), a flow of carbonate (220), a flow of water (210);| - the contactor (20) is adapted to make the carbonate (220) react with water (210) and the CO2 present in the carbonic gas (140) according to the following reactions | and| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet at least one flow of ionic mixture (230);| - the contactor (20) is provided with means for releasing non-soluble gases (221);| - the pH correction apparatus (30) is adapted to receive at the inlet at least one flow of buffering substance (440; 640) and the flow of ionic mixture (230), is adapted to make the ionic mixture (230) react with the buffering substance (440; 640) according to the following reactions| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq)|and to release at the outlet a flow of buffered ionic mixture (240);| - the dosing device (40) is adapted to receive at the inlet a flow of buffering substance (130; 630) deriving from the electric calciner (10) and to release at the outlet a predetermined quantity of buffering substance (440; 640) to feed the pH correction apparatus (30) and possibly a quantity of buffering substance (450; 650) available for use.|2. Plant (100) according to claim 1 wherein the buffering substance is the oxide (130; 440) originated by the electric calciner (10) and wherein the pH correction apparatus (30) is adapted to make the ionic mixture (230) react with the oxide (440) according to the reaction| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|3. Plant (100) according to claim 1, comprising a hydroxide production unit (60) installed between the electric calciner (10) and the pH correction apparatus (30) wherein:| - the hydroxide production unit (60) is suitable to receive at the inlet at least one flow (130; 440) of oxide originated by the electric calciner (10), a predetermined flow of water (610),| - the hydroxide production unit (60) is adapted to make the oxide (130; 440) react with water (610) according to the reaction| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate) and to release at the outlet a flow of hydroxide (630; 640) and possibly, a flow of vapour (620); and| - wherein the buffering substance is hydroxide (630; 640) produced by the hydroxide production unit (60).|4. Plant (100) according to claim 1, 2 or 3, comprising a control unit (50) and a meter of the chemical parameters of water (51) wherein:| - the meter of the chemical parameters of water (51) is adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture (230) or of the buffered ionic mixture (240) and to provide the measurement to the control unit (50);| - the control unit (50) is adapted to control the dosing device (40) so that it feeds the pH correction apparatus (30) with the quantity of buffering substance (440; 640) that is suitable for obtaining a buffered ionic mixture (240) with a desired pH.|5. Plant (100) according to any preceding claim wherein the contactor (20) has a volume that allows a minimum contact time of the water (210) with the carbonate (220) and the carbonic gas (140; 151) of 1000 s.|6. Plant (100) according to any preceding claim wherein the quantity of carbonate (220) introduced into the contactor (20) is zero and the contactor (20) has a volume that allows a contact time of the water with the carbonic gas (140; 151) greater than 10 s, preferably comprised between 60 s and 300 s.|7. Plant (100) according to one or more of claims 3 to 6 further comprising a conduit adapted to feed the flow of vapour (620) released by the hydroxide production unit (60) to the electric calciner (10).|8. Plant (100) according to any preceding claim further comprising a carbonate preheating unit (15), wherein the carbonate preheating unit (15) is adapted to receive at the inlet the flow of carbonic gas (140) at high temperature released by the electric calciner (10), a flow of carbonate (110) and to release at the outlet a flow of carbonic gas (151) and a preheated flow of carbonate (111).|9. Decarbonized calcination method comprising the steps of:| - providing an electric calciner (10);| - feeding the electric calciner (10) with electric power (120) and a flow of carbonate (110; 111) in order to obtain the calcination of the carbonate (110) according to the reaction| CaCO3 → CaO + CO2|(where Ca can be substituted with Mg if present in the carbonate);| - releasing at the outlet of the electric calciner (10) a flow of carbonic gas (140) at high temperature and a flow of oxide (130);| - conveying the flow of carbonic gas (140);| - conveying the flow of oxide (130);| - from the flow of oxide (130) obtaining a flow of buffering substance (440; 640);| - providing a contactor (20);| - feeding the contactor (20) with the flow of carbonic gas (140) produced by the electric calciner (10) and a predetermined flow of water (210) in order to obtain a flow of ionic mixture (230) through the reaction |;| - releasing the flow of ionic mixture (230) at the outlet of the contactor (20);| - conveying the ionic mixture (230);| - providing a dosing device (40);| - feeding the flow of buffering substance (130, 630) to the dosing device (40);| - releasing a predetermined flow of buffering substance (440; 640) at the outlet of the dosing device (40);| - conveying the flow of buffering substance (440; 640);| - providing a pH correction apparatus (30);| - feeding the pH correction apparatus (30) with the flow of ionic mixture (230) and with the predetermined flow of buffering substance (440; 640) so that the reactions take place| CaO + H2O + 2CO2 → Ca(HCO3)2(aq)|or| Ca(OH)2(aq)+2CO2 → Ca(HCO3)2(aq);| - releasing the flow of buffered ionic mixture (240) at the outlet of the pH correction apparatus (30);| - placing the flow of buffered ionic mixture (240) into the sea.|10. Method according to the preceding claim, further comprising the step of feeding the contactor (20) with a predetermined flow of carbonate (220) so that the reaction can take place| CaCO3 + CO2 + H2O → Ca(HCO3)2(aq)|(where Ca can be substituted with Mg if present in the carbonate).|11. Method according to claim 9 or 10, wherein the flow of buffering substance (440; 640) fed to the pH correction apparatus (30) is a flow of oxide (440).|12. Method according to claim 9 or 10, further comprising the steps of:| - providing a hydroxide production unit (60);| - feeding the hydroxide production unit (60) with a flow of oxide (130; 440) and a predetermined flow of water (610) so that the reaction can take place| CaO + H2O → Ca(OH)2|(where Ca can be substituted with Mg if present in the carbonate);| - releasing at least one flow of hydroxide (630) and one flow of vapour (620) at the outlet of the hydroxide production unit (60);|and wherein the flow of buffering substance (440; 640) fed to the pH correction apparatus (30) is a flow of hydroxide (640).|13. Method according to one or more of claims 9 to 12, further comprising the steps of:| - providing a control unit (50) and a meter of the chemical parameters of water (51) adapted to measure the pH and/or the alkalinity and/or the hardness of the ionic mixture (230) or of the buffered ionic mixture (240);| - providing the pH and/or alkalinity and/or hardness measurement from the pH meter (51) to the control unit (50);| - controlling the dosing device (40) by means of the control unit (50) so that it feeds the pH correction apparatus (30) with the correct quantity of buffering substance (440; 640) in order to obtain a buffered ionic mixture (240) with a desired pH.|14. Method according to claim 12 or 13, further comprising the steps of:| - conveying the flow of vapour (620); and| - feeding the flow of vapour (620) to the electric calciner (10).|15. Method according to one or more of claims 9 to 14, further comprising the steps of:| - providing a carbonate preheating unit (15);| - feeding the carbonate preheating unit (15) with the flow of carbonic gas (140) at high temperature released by the electric calciner (10) and a flow of carbonate (110);| - releasing a flow of preheated carbonate (111) from the carbonate preheating unit (15); and| - feeding the electric calciner (10) with the preheated flow of carbonate (111). | 24 | Abstract | gpt-4o-mini | no | The article focuses on producing decarbonized oxides or hydroxides using electric power and carbonate, with CO2 storage in the sea, which does not involve biomass or energy production from biomass. | ||||||||||||||
| 27 | JP2018153857 | JP2018153857 | JP6692394|JP2020030892 | 87784557 | JP6692394 B2 2020-05-13 [JP6692394]|JP2020030892 A 2020-02-27 [JP2020030892] | 2018-08-20 | 2018-08-20 | 2020-05-13|2020-02-27 | (JP6692394)|2020-05-13 | (JP6692394)|2038-08-20 | (JP6692394)|Carbon Recovery Fuel Cell Power Generation System | (JP6692394)|PROBLEM TO BE SOLVED: To provide a carbon recovery type fuel battery power generation system capable of greatly simplifying a transport and fixation process for high efficiency by inhibiting discharge of carbon dioxide gas by converting carbon dioxide generated due to power generation of a fuel battery to carbon.SOLUTION: A fuel battery power generation system 10 includes: a first fuel battery cell stack 12 and a second fuel battery cell stack 14 that generate power using fuel gas containing a carbon compound and supplied to a fuel electrode and oxidant gas containing oxygen and supplied to an air electrode and discharge off-gas; a condenser 26 for separating carbon dioxide gas from the off-gas; a water electrolysis device 70 for performing electrolysis on water to generate hydrogen gas; and a powder carbon generator 78 for making the carbon dioxide gas from the condenser 26 react with the hydrogen gas from the water electrolysis device 70 on a catalyst to generate carbon.SELECTED DRAWING: Figure 1COPYRIGHT: (C)2020,JPO&INPIT | TOKYO GAS | (JP6692394)|TOKYO GAS CO., LTD.|(JP2020030892)|TOKYO GAS CO., LTD. | KAWABATA YASUHARU|MATSUZAKI YOSHIO | (JP6692394)|KAWABATA, Yasuharu|MATSUZAKI, Yoshio|(JP2020030892)|KAWABATA YASUHARU|MATSUZAKI YOSHIO | (JP6692394)|TAIYO, NAKAJIMA & KATO|Reg. Nb: 110001519 | (JP6692394)|According to the carbon recovery type fuel cell power generation system of the present invention, it is possible to convert the carbon dioxide generated in association with the power generation of the fuel cell to carbon into carbon, which makes it easier and more stable for a long period of time than storing carbon dioxide gas.|Furthermore, in the fuel cell power generation system 10 A of the present embodiment, disposing the combustion part 22 adjacent to the oxygen permeable membrane 23 of the oxygen separation part 24 makes it possible to configure a compact combustor 20 with an oxygen permeable membrane integrally formed with the combustion part 22 and the oxygen separation part 24.|Furthermore, for CCS and BECCS, the locations where carbon dioxide gas can be injected and stored are limited (for example, because there are few oil and gas fields suitable for EOR and EGS in Japan, liquefied carbon dioxide is transported to an overseas storage site such as heavy state; It is assumed that carbon dioxide gas is injected underground with a pressure injection pump and stored). in addition, in the case of anhydrous layer storage, there is concern over the risk of discharge due to contamination of the anhydrous layer, an earthquake, or fluctuations in the vicinity, and over the risk of discharge of stored carbon dioxide gas due to effects on the ocean ecosystem, changes in geographies, or the like, even over the case of ocean storage. there is room for improvement.|This is said to account for 40%, and simplification and high efficiency are extremely important technical problems in separating, recovering, and immobilizing carbon dioxide gas.| | (JP6692394)|1. A fuel cell that generates power using fuel gas containing a carbon compound and supplied to a fuel electrode and oxidant gas containing oxygen and supplied to an air electrode, and discharges off-gas; a carbon dioxide gas separation unit that separates carbon dioxide gas from the off-gas; A water electrolyzer that electrolyzes water to generate hydrogen gas; and a water electrolyzer that electrolyzes the carbon dioxide gas from the carbon dioxide gas separation unit and the hydrogen gas from the water electrolyzer.SingleOn catalystAndA carbon generating part that generates carbon and steam.|4. A power generation system comprising: a first fuel cell that generates power by fuel gas containing a carbon compound and supplied to a first fuel electrode and oxidant gas containing oxygen and supplied to a first air electrode, and sends out first fuel electrode off-gas from the first fuel electrode to first fuel electrode off-gas channels; and a power generation system that generates power by using the first fuel electrode off-gas supplied to a second fuel electrode and oxidant gas supplied to a second air electrode, A second fuel cell that delivers second fuel electrode off-gas from the second fuel electrode to second fuel electrode off-gas flow paths; an air electrode off-gas flow path that delivers air electrode off-gas from at least one of the first air electrode and the second air electrode; and An oxygen separation unit connected to the air electrode off-gas flow path and supplied with the air electrode off-gas, the oxygen separation unit separating oxygen from the air electrode off-gas; a combustion unit supplied with the second fuel electrode off-gas and supplied with the oxygen separated by the oxygen separation unit, the combustion unit causing the second fuel electrode off-gas to undergo a combustion reaction with the oxygen; An exhaust heat input type absorption chiller or an adsorption chiller that uses the off-gas as a heat source to cool water and generate cooling water, wherein the carbon dioxide gas separation unit separates carbon dioxide gas and water by cooling combustion off-gas sent from the combustion unit with the cooling water.| | (JP6692394)|A sixth aspect of the invention is the carbon recovery fuel cell power generation system according to claim 4 or 5, further comprising: a supply unit that supplies the water separated by the carbon dioxide gas separation unit to a cooling water path of the exhaust heat input absorption chiller or a cooling water path of the adsorption chiller; The water separated by the carbon dioxide gas separation unit is used as the cooling water of the exhaust heat input type absorption chiller, as part of cooling water supplemental water of a cooling tower constituting the exhaust heat input type absorption chiller, or as part of cooling water of the adsorption chiller or as part of cooling water supplemental water of a cooling tower constituting the adsorption chiller.|The present invention relates to a carbon recovery type fuel cell power generation system, and particularly relates to a carbon recovery type fuel cell power generation system that generates power using a carbon compound fuel and is capable of converting and recovering carbon dioxide generated by the power generation into carbon.| | (JP6692394)|FUEL ELECTRODE(100,185)|CARBON DIOXIDE(100,151)|FUEL CELL(100,147)|AIR ELECTRODE(100,124)|OXYGEN(100,60)|CARBON DIOXIDE GAS(100,51)|STEAM(100,32)|POWER GENERATION(100,27)|FUEL GAS(100,26)|WATER ELECTROLYZER(100,25)|CARBON DIOXIDE GAS SEPARATION(100,24)|GAS SEPARATION(100,24)|CARBON(100,20)|CARBON RECOVERY FUEL CELL(100,20)|HYDROGEN GAS(100,17)|OXIDANT GAS(100,14)|ADSORPTION CHILLER(100,11)|CARBON COMPOUND(100,6)|CATALYST(100,3)|OCEAN ECOSYSTEM(48,1)|OXYGEN SEPARATION(46,29)|COOLING TOWER SUPPLEMENTAL WATER(37,4)|ADDITIONAL WATER(36,4)|COMPACT COMBUSTOR(34,1)|COMBUSTION(33,34)|RECOVERING CARBON(33,14)|OXYGEN PERMEABLE MEMBRANE(32,32)|ABSORPTION CHILLER(30,39)|ANHYDROUS LAYER CONTAMINATION(29,1)|OVERSEAS STORAGE(27,1)|FUEL ELECTRODE OFF GAS(25,91)|COOLING TOWER(23,8)|COOLING COMBUSTION(23,2)|OCEAN STORAGE(22,1)|FUEL CELL POWER(21,70)|COOLING WATER PATH(21,4)|EARTHQUAKE(21,1)|GEOGRAPHY(21,1)|EXHAUST(20,24)|COOLING WATER(20,12)|ANHYDROUS LAYER(20,1)|SIMPLIFICATION(20,1)|OFF GAS(19,182)|FLUCTUATION(19,1)|INPUT ABSORPTION CHILLER(18,1)|EXHAUST COOLING WATER PATH(17,2)|ANHYDROUS LAYER STORAGE(17,1)|BECCS(16,1)|COOLING TOWER PATH(15,2)|COOL WATER(14,2)|EGS(14,1)|CARBON POWDER(13,17)|ELECTRIC TURBO CHILLER(13,5)|EXHAUST HEAT INPUT(12,4)|CARBON GENERATION(12,2)|UNREACTED METHANE(11,5)|CARBON COMPOUND FUEL(11,2)|COOLING COMBUSTION OFF GAS(11,2)|PERMEATION(11,2)|AIR ELECTRODE OFF GAS(10,54)|COMBUSTION REACTION(10,21)|POWDERED CARBON GENERATOR(10,6)|CCS(10,4)|COMBUSTION SPACE(10,4)|OCEAN STORAGE CASE(10,1)|OFF GAS CHANNEL(10,1)|PRESSURE INJECTION PUMP(10,1)|COMPOSITION DETECTION(9,13)|LANDFILL DISPOSAL UNDERGROUND(9,1)|REFORMER(8,10)|CARBON PRODUCTION(8,8)|GRAPHITE(8,7)|UNREACTED CARBON MONOXIDE(8,6)|UNREACTED HYDROGEN(8,6)|HEAT EXCHANGER(7,19)|ELECTRICAL POWER(7,16)|BRANCHED AIR ELECTRODE(7,8)|ELECTROLYTE LAYER(7,8)|CARBON NANOTUBE(7,7)|STEAM REFORMING(7,7)|OXYGEN BLOWER(7,3)|RECOVERED POWDERED CARBON(7,3)|COOLANT CIRCULATION(7,2)|CARBON DIOXIDE RICH GAS(6,20)|PIPING(6,9)|ELECTRODE OFF GAS(6,8)|OXIDANT GAS PIPE(6,7)|CARBON MANUFACTURING(6,6)|HYDROCARBON GAS(6,4)|HYDROGEN BLOWER(6,3)|REFRIGERATION MACHINE(6,3)|SUPPLY PATH(6,3)|OILFIELD DEPLETION(6,1)|EXHAUST PIPE(5,9)|CIRCULATION GAS PIPE(5,6)|COMBUSTIBLE GAS COMPONENT(5,5)|WATER CONDENSATION(5,5)|FUEL GAS REGENERATION(5,4)|LIQUID ABSORBENT(5,4)|CIRCULATION GAS BLOWER B3(5,1)|CONDENSER FORTIFICATION(5,1)|DIAMOND CUTTER(5,1)|FUEL REGENERATION(5,1)|OXIDANT GAS BLOWER B2(5,1)|POWDERED CARBON PRODUCER(5,1)|COMPOSITION INFORMATION(4,7)|ELECTRODE REACTION(4,3)|FUEL CELL STACK(4,3)|REFORMED GAS PIPE(4,3)|RENEWABLE ENERGY POWER GENERATOR(4,3)|SHIFT REACTION(4,3)|AUXILIARY EQUIPMENT(4,2)|COMBUSTIBLE COMPONENT(4,2)|HEAT SOURCE(4,2)|OXYGEN SUPPLY PIPE PO(4,2)|BIOMASS GENERATION(4,1)|COMBUSTION COOLING(4,1)|DENSE MEMBRANE(4,1)|FOREIGN SUBSTANCE(4,1)|STEAM ABSORPTION(4,1)|WATER TANK(3,17)|HEAT DISSIPATION CIRCUIT(3,6)|REGULATING VALVE(3,5)|FUEL GAS PIPE(3,4)|ABSORPTION LIQUID(3,2)|BRANCH AIR ELECTRODE(3,2)|CONFIGURATION REST(3,2)|ELECTROLYSIS(3,2)|FUEL SUPPLY BLOWER B1(3,2)|IGNITION SOURCE(3,2)|IMPURITY(3,2)|OXYGEN OUTLET(3,2)|PRODUCED POWDERED CARBON(3,2)|STORAGE SITE(3,2)|SYNTHETIC DIAMOND POWDER(3,2)|ADSORPTION PATH(3,1)|CARBON NANOHORN(3,1)|DESULFURIZATION(3,1)|ELECTROLYZING(3,1)|STABLE CARBON IMMOBILIZATION(3,1)|WATER DEPENDENCY(3,1)|ELECTRODE OFF GAS PIPE(2,9)|CYLINDRICAL SHAPE(2,3)|ENHANCED OIL RECOVERY(2,3)|GENERATED CARBON MONOXIDE(2,3)|HYDROCARBON FUEL(2,3)|OXIDATION CATALYST(2,3)|OXYGEN TANK(2,3)|STEAM PIPE(2,3)|PSA(2,2)|ABSORPTION HEAT(2,1)|BIOGAS(2,1)|CARBON DIOXIDE BLOWER(2,1)|CARBON DIOXIDE RECOVERY(2,1)|CARBON DIOXIDE SEPARATION MEMBRANE(2,1)|CITY GAS(2,1)|COAL LAYER(2,1)|COLD GENERATION(2,1)|COMPRESSOR(2,1)||(JP2020030892)|FUEL ELECTRODE(100,186)|CARBON DIOXIDE(100,155)|FUEL CELL(100,147)|AIR ELECTRODE(100,124)|OXYGEN(100,61)|CARBON DIOXIDE GAS(100,54)|WATER VAPOR(100,50)|FUEL GAS(100,27)|POWER GENERATION(100,27)|WATER ELECTROLYZER(100,23)|CARBON DIOXIDE GAS SEPARATION(100,22)|GAS SEPARATION(100,22)|CARBON(100,21)|HYDROGEN GAS(100,19)|RECOVERING CARBON(100,16)|OXIDANT GAS(100,15)|ADSORPTION CHILLER(100,11)|CARBON COMPOUND(100,7)|CATALYST(100,5)|CARBON DIOXIDE GAS SEPARATING(100,3)|GAS SEPARATING(100,3)|BATTERY POWER GENERATION(100,2)|OCEAN ECOSYSTEM(48,1)|OXYGEN SEPARATION(46,29)|COOLING TOWER SUPPLEMENTAL WATER(37,4)|ADDITIONAL WATER(36,4)|COMPACT COMBUSTOR(34,1)|COMBUSTION(33,33)|OXYGEN PERMEABLE MEMBRANE(32,32)|ABSORPTION CHILLER(30,39)|CARBON RECOVERY FUEL CELL(29,19)|ANHYDROUS LAYER CONTAMINATION(29,1)|OVERSEAS STORAGE(27,1)|FUEL BATTERY GENERATION(26,1)|FUEL ELECTRODE OFF GAS(25,91)|COOLING TOWER(23,8)|COOLING COMBUSTION(23,2)|FUEL BATTERY CELL(23,2)|OCEAN STORAGE(22,1)|FUEL CELL POWER(21,70)|COOLING WATER PATH(21,4)|EARTHQUAKE(21,1)|FUEL BATTERIE(21,1)|GEOGRAPHY(21,1)|INHIBITING DISCHARGE(21,1)|EXHAUST(20,24)|COOLING WATER(20,12)|ANHYDROUS LAYER(20,1)|SIMPLIFICATION(20,1)|OFF GAS(19,184)|FLUCTUATION(19,1)|POWDER CARBON GENERATOR(19,1)|INPUT ABSORPTION CHILLER(18,1)|EXHAUST COOLING WATER PATH(17,2)|ANHYDROUS LAYER STORAGE(17,1)|FUEL BATTERY POWER(16,2)|BECCS(16,1)|COOLING TOWER PATH(15,2)|COOL WATER(14,2)|EGS(14,1)|CARBON POWDER(13,17)|ELECTRIC TURBO CHILLER(13,5)|WATER ELECTROLYSIS(13,2)|CONVERTING CARBON DIOXIDE(13,1)|EXHAUST HEAT INPUT(12,4)|CARBON GENERATION(12,2)|UNREACTED METHANE(11,5)|CARBON COMPOUND FUEL(11,2)|COOLING COMBUSTION OFF GAS(11,2)|AIR ELECTRODE OFF GAS(10,56)|COMBUSTION REACTION(10,21)|POWDERED CARBON GENERATOR(10,6)|CCS(10,4)|COMBUSTION SPACE(10,4)|FIXATION(10,1)|OCEAN STORAGE CASE(10,1)|OFF GAS CHANNEL(10,1)|PRESSURE INJECTION PUMP(10,1)|COMPOSITION DETECTION(9,13)|LANDFILL DISPOSAL UNDERGROUND(9,1)|CARBON PRODUCTION(8,8)|GRAPHITE(8,7)|UNREACTED CARBON MONOXIDE(8,6)|UNREACTED HYDROGEN(8,6)|HEAT EXCHANGER(7,19)|ELECTRICAL POWER(7,16)|BRANCHED AIR ELECTRODE(7,8)|ELECTROLYTE LAYER(7,8)|CARBON NANOTUBE(7,7)|STEAM REFORMING(7,7)|OXYGEN BLOWER(7,3)|RECOVERED POWDERED CARBON(7,3)|COOLANT CIRCULATION(7,2)|CARBON DIOXIDE RICH GAS(6,20)|PIPING(6,9)|ELECTRODE OFF GAS(6,8)|OXIDANT GAS PIPE(6,7)|REFORMER(6,7)|CARBON MANUFACTURING(6,6)|HYDROCARBON GAS(6,4)|HYDROGEN BLOWER(6,3)|REFRIGERATION MACHINE(6,3)|SUPPLY PATH(6,3)|OILFIELD DEPLETION(6,1)|EXHAUST PIPE(5,9)|CIRCULATION GAS PIPE(5,6)|COMBUSTIBLE GAS COMPONENT(5,5)|WATER CONDENSATION(5,5)|FUEL GAS REGENERATION(5,4)|LIQUID ABSORBENT(5,4)|CIRCULATION GAS BLOWER B3(5,1)|CONDENSER FORTIFICATION(5,1)|DIAMOND CUTTER(5,1)|FUEL REGENERATION(5,1)|OXIDANT GAS BLOWER B2(5,1)|POWDERED CARBON PRODUCER(5,1)|COMPOSITION INFORMATION(4,7)|ELECTRODE REACTION(4,3)|FUEL CELL STACK(4,3)|REFORMED GAS PIPE(4,3)|RENEWABLE ENERGY POWER GENERATOR(4,3)|SHIFT REACTION(4,3)|AUXILIARY EQUIPMENT(4,2)|COMBUSTIBLE COMPONENT(4,2)|HEAT SOURCE(4,2)|OXYGEN SUPPLY PIPE PO(4,2)|BIOMASS GENERATION(4,1)|COMBUSTION COOLING(4,1)|DENSE MEMBRANE(4,1)|FOREIGN SUBSTANCE(4,1)|STEAM ABSORPTION(4,1)|WATER TANK(3,17)|HEAT DISSIPATION CIRCUIT(3,6)|REGULATING VALVE(3,5)|FUEL GAS PIPE(3,4)|ABSORPTION LIQUID(3,2)|BRANCH AIR ELECTRODE(3,2)|CONFIGURATION REST(3,2)|FUEL SUPPLY BLOWER B1(3,2)|IGNITION SOURCE(3,2)|IMPURITY(3,2)|PRODUCED POWDERED CARBON(3,2)|STORAGE SITE(3,2)|SYNTHETIC DIAMOND POWDER(3,2)|ADSORPTION PATH(3,1)|CARBON NANOHORN(3,1)|DESULFURIZATION(3,1)|ELECTROLYZING(3,1)|STABLE CARBON IMMOBILIZATION(3,1)|WATER DEPENDENCY(3,1)|ELECTRODE OFF GAS PIPE(2,9)|CYLINDRICAL SHAPE(2,3)|ENHANCED OIL RECOVERY(2,3)|GENERATED CARBON MONOXIDE(2,3)|HYDROCARBON FUEL(2,3)|OXIDATION CATALYST(2,3)|OXYGEN TANK(2,3)|STEAM PIPE(2,3)|PSA(2,2)|ABSORPTION HEAT(2,1)|BIOGAS(2,1)|CARBON DIOXIDE BLOWER(2,1)|CARBON DIOXIDE RECOVERY(2,1)|CARBON DIOXIDE SEPARATION MEMBRANE(2,1)|CITY GAS(2,1)| | (JP6692394)|1. A fuel cell that generates power using fuel gas containing a carbon compound and supplied to a fuel electrode and oxidant gas containing oxygen and supplied to an air electrode, and discharges off-gas; a carbon dioxide gas separation unit that separates carbon dioxide gas from the off-gas; A water electrolyzer that electrolyzes water to generate hydrogen gas; and a water electrolyzer that electrolyzes the carbon dioxide gas from the carbon dioxide gas separation unit and the hydrogen gas from the water electrolyzer.SingleOn catalystAndA carbon generating part that generates carbon and steam.|2. The carbon recovery fuel cell power generation system according to claim 1, wherein the water electrolyzer electrolyzes the water using at least one of electrical power generated by a renewable energy power generator and electrical power generated by the fuel cell.|3. The carbon recovery type fuel cell power generation system according to claim 1 or 2, wherein the carbon dioxide gas separation unit separates the carbon dioxide gas and water from the off-gas, and the water electrolyzer uses the water separated by the carbon dioxide gas separation unit.|4. A power generation system comprising: a first fuel cell that generates power by fuel gas containing a carbon compound and supplied to a first fuel electrode and oxidant gas containing oxygen and supplied to a first air electrode, and sends out first fuel electrode off-gas from the first fuel electrode to first fuel electrode off-gas channels; and a power generation system that generates power by using the first fuel electrode off-gas supplied to a second fuel electrode and oxidant gas supplied to a second air electrode, A second fuel cell that delivers second fuel electrode off-gas from the second fuel electrode to second fuel electrode off-gas flow paths; an air electrode off-gas flow path that delivers air electrode off-gas from at least one of the first air electrode and the second air electrode; and An oxygen separation unit connected to the air electrode off-gas flow path and supplied with the air electrode off-gas, the oxygen separation unit separating oxygen from the air electrode off-gas; a combustion unit supplied with the second fuel electrode off-gas and supplied with the oxygen separated by the oxygen separation unit, the combustion unit causing the second fuel electrode off-gas to undergo a combustion reaction with the oxygen; An exhaust heat input type absorption chiller or an adsorption chiller that uses the off-gas as a heat source to cool water and generate cooling water, wherein the carbon dioxide gas separation unit separates carbon dioxide gas and water by cooling combustion off-gas sent from the combustion unit with the cooling water.|5. The carbon recovery type fuel cell power generation system according to claim 4, wherein the first fuel cell and the second fuel cell are hydrogen ion conductive solid oxide fuel cells.|6. A supply unit that supplies the water separated by the carbon dioxide gas separation unit to a cooling water path of the exhaust heat input type absorption chiller, a cooling water replenishing path of a cooling tower constituting the exhaust heat input type absorption chiller, or a cooling water path of the adsorption chiller or a cooling water replenishing path of a cooling tower constituting the adsorption chiller; The cooling water of the exhaust heat input type absorption chiller, a portion of cooling water supplemental water of a cooling tower constituting the exhaust heat input type absorption chiller, or the cooling water of the adsorption chiller or a portion of cooling water supplemental water of a cooling tower constituting the adsorption chiller; The carbon recovery fuel cell power generation system according to claim 4 or 5, wherein the water separated by the carbon dioxide gas separation unit is used.|7. The carbon recovery fuel cell power generation system according to any one of claims 4 to 6, wherein the oxygen separation part comprises an oxygen permeable membrane that selectively permeates oxygen, and the combustion part is integrated with the oxygen separation part with a combustion space disposed on a permeation side of the oxygen permeable membrane.|8. The carbon recovery fuel cell power generation system according to any one of claims 4 to 6, wherein the oxygen separation unit comprises a high-temperature PSA device that can be driven by power generated by the first fuel cell and the second fuel cell.|9. The carbon recovery fuel cell power generation system according to any one of claims 1 to 8, wherein the carbon dioxide gas separation unit cools the off-gas to generate the carbon dioxide gas and water, and the steam generated by the carbon generation unit is supplied to the carbon dioxide gas separation unit via a supply path.|10. The carbon recovery fuel cell power generation system according to any one of claims 1 to 9, further comprising a carbon product manufacturing apparatus in which the carbon produced by the carbon producing unit is graphite, carbon nanotubes, or diamond. | (JP6692394)|TECHNICAL FIELD|[0001] The present invention relates to a carbon recovery type fuel cell power generation system, and particularly relates to a carbon recovery type fuel cell power generation system that generates power using a carbon compound fuel and is capable of converting and recovering carbon dioxide generated by the power generation into carbon.|BACKGROUND ART|[0002] When a carbon compound fuel is used in a fuel cell power generation system, exhaust gas discharged from the fuel cell contains carbon dioxide gas. Carbon dioxide gas is one cause of global warming. thus, it is conceivable to separate and recover carbon dioxide gas from exhaust gas and store the carbon dioxide gas so that the carbon dioxide gas is not released into the atmosphere.|[0003] Examples of the storing of carbon dioxide gas include recovering carbon dioxide gas and storing and immobilizing the recovered carbon dioxide gas in the ground or the like CCS (Carbon Capture and Storage); The amount of crude oil recovered from the depleted oil field is increased while storing and immobilizing the recovered carbon dioxide gas in the ground or the like EOR (Enhanced Oil Recovery); The present invention is known to be used in EGR (Enhanced Gas Recovery), which increases the amount of natural gas recovered from a depleted gas field, and ECBM (Enhanced Coal Bed Methane), which releases and recovers methane by injecting the natural gas into a coal layer.|[0004] Patent Document 1 describes, for example, a method of embedding carbon dioxide gas in the ground or injecting the carbon dioxide gas into the sea floor.|CITATION LIST|PATENT LITERATURE|[0005] PATENT CITATIONS |Japanese Patent No. 2013-196890|SUMMARY OF INVENTION|TECHNICAL PROBLEM|[0006] However, in any of the CCS including EOR, EGR, and ECBM described above, it is assumed that the carbon dioxide is transported to the storage site in a pipeline or in which the carbon dioxide gas is converted to liquefied carbon dioxide and then transported in a lorry. From the perspective of constructing a power generation system compatible with CCS, it is also desirable to construct a system capable of efficiently separating and recovering carbon dioxide gas generated during power generation and efficiently storing the recovered carbon dioxide gas.|[0007] Furthermore, for CCS and BECCS, the locations where carbon dioxide gas can be injected and stored are limited (for example, because there are few oil and gas fields suitable for EOR and EGS in Japan, liquefied carbon dioxide is transported to an overseas storage site such as heavy state; It is assumed that carbon dioxide gas is injected underground with a pressure injection pump and stored). in addition, in the case of anhydrous layer storage, there is concern over the risk of discharge due to contamination of the anhydrous layer, an earthquake, or fluctuations in the vicinity, and over the risk of discharge of stored carbon dioxide gas due to effects on the ocean ecosystem, changes in geographies, or the like, even over the case of ocean storage. there is room for improvement. The transport and pressure injection storage of carbon dioxide gas and liquefied carbon dioxide consume a great deal of energy and increase costs. In these fields of separating and recovering, immobilizing, and effective use of carbon dioxide gas, the separating and recovering of CO2 can be performed in a manner similar to that of the CCS total cost. ~70%, and the cost of immobilizing the CO2 is 3~70%. This is said to account for 40%, and simplification and high efficiency are extremely important technical problems in separating, recovering, and immobilizing carbon dioxide gas.|[0008] In light of the foregoing, an object of the present invention is to provide a carbon recovery type fuel cell power generation system capable of efficiently separating and recovering carbon dioxide generated in association with the power generation of a fuel cell, making it easy to transport and immobilize, and suppressing the release of carbon dioxide gas to the atmosphere.|TECHNICAL SOLUTION|[0009] The carbon recovery type fuel cell power generation system according to claim 1, comprising: a fuel cell that generates power by fuel gas containing a carbon compound and supplied to a fuel electrode, and oxidant gas containing oxygen and supplied to an air electrode, and discharges off-gas; A carbon dioxide gas separation unit that separates carbon dioxide gas from the off-gas; a water electrolyzer that electrolyzes water to generate hydrogen gas; and a water electrolyzer that electrolyzes the carbon dioxide gas from the carbon dioxide gas separation unit and the hydrogen gas from the water electrolyzer.SingleOn catalystAndA carbon generating part that generates carbon and steam.|[0010] The carbon recovery type fuel cell power generation system according to claim 1, wherein the fuel cell generates power using the fuel gas supplied to the fuel electrode and the oxidant gas supplied to the air electrode, and discharges off-gas. Carbon dioxide gas is separated from the off-gas discharged from the fuel cell in a carbon dioxide gas separation unit. The water electrolyzer electrolyzes water to produce hydrogen gas. The carbon generating unit is configured to generate carbon dioxide gas separated by the carbon dioxide gas separation unit and hydrogen gas generated by the water electrolyzer.SingleCatalystByProduces carbon (solid) and water vapor. In this way, in the carbon recovery type fuel cell power generation system according to claim 1, it is possible to recover carbon dioxide gas generated by power generation as solid carbon. Recovery with solid carbon suppresses the release of carbon dioxide gas to the atmosphere, greatly simplifies the transport and immobilization process, and increases efficiency, as compared to recovery with carbon dioxide gas as is.|[0011] According to the invention described in claim 2, in the carbon recovery type fuel cell power generation system described in claim 1, the water electrolyzer electrolyzes the water using at least one of electrical power generated by a renewable energy power generator and electrical power generated by the fuel cell.|[0012] The carbon recovery type fuel cell power generation system according to claim 2, wherein the water electrolyzer electrolyzes water by at least one of the electrical power generated by the renewable energy power generator and the electrical power generated by the fuel cell, It is not necessary to use power generated by a power generation apparatus that releases carbon dioxide gas in association with power generation, and it is possible to suppress the release of carbon dioxide gas into the atmosphere.|[0013] According to the invention according to claim 3, in the carbon recovery type fuel cell power generation system according to claim 1 or claim 2, the carbon dioxide gas separation unit separates the carbon dioxide gas and water from the off-gas, and the water electrolyzer uses the water separated by the carbon dioxide gas separation unit.|[0014] In the carbon recovery type fuel cell power generation system according to claim 3, since the water electrolyzer uses water separated by the carbon dioxide gas separation unit for electrolysis, it is not necessary to supply water from an external water supply or the like, and it is possible to reduce the amount of water dependency on the outside.|[0015] The invention according to claim 4, a carbon recovery fuel cell power generation system according to any one of claims 1 to 3, comprising: a first fuel cell that generates power using fuel gas containing a carbon compound and supplied to a first fuel electrode, and an oxidant gas containing oxygen and supplied to a first air electrode, and sends first fuel electrode off-gas from the first fuel electrode to first fuel electrode off-gas flow paths; A second fuel cell that generates power using the first fuel electrode off-gas supplied to a second fuel electrode and oxidant gas supplied to a second air electrode, and delivers the second fuel electrode off-gas from the second fuel electrode to second fuel electrode off-gas passages; and An air electrode off-gas flow path that sends out air electrode off-gas from at least one of the first air electrode and the second air electrode; an oxygen separation unit connected to the air electrode off-gas flow path, to which the air electrode off-gas is supplied, the oxygen separation unit separating oxygen from the air electrode off-gas; and a fuel cell supplied with the second fuel electrode off-gas and the oxygen separated by the oxygen separation unit; A combustion unit that performs a combustion reaction on the second fuel electrode off-gas with the oxygen; and an exhaust heat input type absorption chiller or an adsorption chiller that uses the off-gas as a heat source to cool water and generate cooling water, wherein the carbon dioxide gas separation unit separates carbon dioxide gas and water by cooling combustion off-gas sent from the combustion unit with the cooling water.|[0016] The carbon recovery fuel cell power generation system according to claim 4, wherein the fuel cell includes a first fuel cell and a second fuel cell. In the first fuel cell, power is generated by the fuel gas supplied to the first fuel electrode and the oxidant gas supplied to the first air electrode. In the second fuel cell, power is generated by the first fuel electrode off-gas supplied from the first fuel electrode to the second fuel electrode and the oxidant gas supplied to the second air electrode.|[0017] Air electrode off-gas is sent from at least one of the first air electrode and the second air electrode to the air electrode off-gas flow path, and the air electrode off-gas is supplied to the oxygen separation unit via the air electrode off-gas flow path. In the oxygen separation unit, oxygen is separated from the air electrode off-gas, and the separated oxygen is supplied to the combustion unit.|[0018] The second fuel electrode off-gas is sent from the second fuel electrode to the fuel electrode off-gas flow paths, and the second fuel electrode off-gas is supplied to the combustion unit via the fuel electrode off-gas flow paths. In the combustor, a combustion reaction occurs between the combustible components in the second fuel electrode off-gas and oxygen, and the combustion off-gas is sent out from the combustor.|[0019] The combustion off-gas is sent to a carbon dioxide separation unit, and carbon dioxide is separated from the combustion off-gas.|[0020] In the fuel cell power generation system according to claim 4, the second fuel electrode off-gas after being sent out from the second fuel cell is combusted in the combustion unit, so the amount of unreacted fuel gas supplied to the second fuel cell is increased compared to the case where the first fuel electrode off-gas before being supplied for power generation in the second fuel cell is combusted. Therefore, it is possible to increase the power generation efficiency of the second fuel cell.|[0021] Furthermore, in the combustor, carbon dioxide and steam are generated by a combustion reaction between oxygen and combustible components contained in the second fuel electrode off-gas. Therefore, it is possible to recover a high concentration of carbon dioxide by subtracting the combustible gas from the second fuel electrode off-gas.|[0022] In addition, the amount of unreacted fuel gas contained in the second fuel electrode off-gas is smaller and the carbon dioxide content ratio is higher than that of the first fuel electrode off-gas. Accordingly, the amount of unreacted fuel gas burned in the combustor can be reduced, and the amount of oxygen required to burn the unreacted fuel gas can be reduced.|[0023] In addition, the exhaust heat input type absorption chiller or the adsorption chiller cools water by being driven using the air electrode off-gas discharged from the fuel cell as a driving heat source, making it possible to effectively utilize the exhaust heat of the off-gas. Since the exhaust heat input type absorption type refrigeration machine or the adsorption type refrigeration machine can supply cold heat with effective use of exhaust heat, it is possible to efficiently cool water to produce cooling water with less power than when cold heat is generated by a refrigeration machine of a type that compresses and expands a refrigerant by driving a compressor with a motor.|[0024] The invention according to claim 5 is the carbon recovery fuel cell power generation system according to claim 4, wherein the first fuel cell and the second fuel cell are hydrogen ion conductive solid oxide fuel cells (PCFC: Proton Conducting Solid Oxide Fuel Cell).|[0025] In a hydrogen ion conductive solid oxide fuel cell, water vapor is generated by a power generation reaction on the air electrode side. Therefore, the amount of water vapor contained in the first fuel electrode off-gas is small, so the decrease in concentration of the fuel gas supplied to the second fuel electrode is small, and it is possible to improve the power generation efficiency of the second fuel cell. In addition, the amount of water vapor contained in the second fuel electrode off-gas is also reduced, making it possible to reduce the amount of water vapor removed from the second fuel electrode off-gas.|[0026] A sixth aspect of the invention is the carbon recovery fuel cell power generation system according to claim 4 or 5, further comprising: a supply unit that supplies the water separated by the carbon dioxide gas separation unit to a cooling water path of the exhaust heat input absorption chiller or a cooling water path of the adsorption chiller; The water separated by the carbon dioxide gas separation unit is used as the cooling water of the exhaust heat input type absorption chiller, as part of cooling water supplemental water of a cooling tower constituting the exhaust heat input type absorption chiller, or as part of cooling water of the adsorption chiller or as part of cooling water supplemental water of a cooling tower constituting the adsorption chiller.|[0027] In the carbon recovery fuel cell power generation system according to claim 6, the water separated by the carbon dioxide gas separation unit can be supplied by the supply unit to the cooling water path of the exhaust heat input type absorption chiller or the cooling water path of the adsorption type absorption chiller. Accordingly, there is no need to supply water from an external water supply or the like in the case where the cooling water in the cooling water path is insufficient, and the amount of water dependent on the outside can be reduced.|[0028] According to the invention according to claim 7, in the carbon recovery fuel cell power generation system according to any one of claims 4 to 6, the oxygen separation unit includes an oxygen permeable membrane that selectively permeates oxygen, and the combustion unit is integrated with the oxygen separation unit with a combustion space disposed on a permeation side of the oxygen permeable membrane.|[0029] According to the carbon recovery fuel cell power generation system according to claim 7, it is possible to dispose the combustion part adjacent to the oxygen permeable membrane of the oxygen separation part, and it is possible to configure the combustion part and the oxygen separation part in a compact manner.|[0030] According to the invention according to claim 8, in the carbon recovery fuel cell power generation system according to any one of claims 4 to 6, the oxygen separation unit includes a high-temperature PSA device that is driven by power generated by the first fuel cell and the second fuel cell.|[0031] According to the carbon recovery fuel cell power generation system according to claim 8, the oxygen separation unit separates oxygen from the high-temperature air electrode off-gas using the high-temperature PSA device, making it possible to efficiently separate oxygen.|[0032] According to the invention according to claim 9, in the carbon recovery type fuel cell power generation system according to any one of claims 1 to 8, the carbon dioxide gas separation unit cools the off-gas and generates the carbon dioxide gas and water, and the water vapor generated by the carbon generation unit is supplied to the carbon dioxide gas separation unit via a supply path.|[0033] The carbon recovery fuel cell power generation system according to claim 9, wherein carbon dioxide gas and water are generated by cooling the off-gas by the carbon dioxide gas separation unit. Additionally, the steam generated in the carbon generating unit is supplied to the carbon dioxide gas separating unit via a supply path, and water is generated by cooling the steam in the carbon dioxide gas separating unit. Accordingly, in the carbon dioxide gas separation unit, water generated by off-gas and water generated by cooling water vapor are obtained, making it possible to increase the amount of water generated in the system, thereby making it possible to increase the amount of hydrogen gas generated in the water electrolyzer.|[0034] The invention according to claim 10 includes a carbon product manufacturing device according to any one of claims 1 to 9, wherein the carbon produced by the carbon producing unit is graphite, carbon nanotubes, or diamond.|[0035] The carbon recovery fuel cell power generation system according to claim 10, wherein Graphite, carbon nanotubes, or diamond can be used, and carbon dioxide gas can be effectively used and immobilized safely and stably for a long period of time.|ADVANTAGEOUS EFFECTS|[0036] According to the carbon recovery type fuel cell power generation system of the present invention, it is possible to convert the carbon dioxide generated in association with the power generation of the fuel cell to carbon into carbon, which makes it easier and more stable for a long period of time than storing carbon dioxide gas.|DESCRIPTION OF DRAWINGS|[0037] Fig. 1 is a schematic view of a fuel cell power generation system according to a first embodiment. Is a block diagram illustrating a control system of the fuel cell power generation system according to the first embodiment. Is a flowchart of the flow rate regulating process of the first embodiment. Is a flowchart of a cooling water temperature regulating process of Embodiment 1. Fig. 2 is a schematic view of a fuel cell power generation system according to a second embodiment. Fig. 3 is a schematic view of a fuel cell power generation system according to a third embodiment. Fig. 4 is a schematic diagram of a fuel cell power generation system according to a fourth embodiment. Is a schematic diagram of a fuel cell power generation system according to a fifth embodiment. Is a schematic diagram of a fuel cell power generation system according to a sixth embodiment. Is a schematic diagram of a fuel cell power generation system according to a seventh embodiment. Fig. 8 is a schematic diagram of a fuel cell power generation system according to an eighth embodiment. Fig. 9 is a schematic diagram of a fuel cell power generation system according to a ninth embodiment. Is a schematic diagram of a fuel cell power generation system according to a modified example of the first embodiment.|DESCRIPTION OF EMBODIMENTS|[0038] Hereinafter, an example of an embodiment of the present invention will be described in detail with reference to the drawings.|[0039] First Embodiment Fig. 1 illustrates a fuel cell power generation system 10 A according to a first embodiment as an example of a carbon dioxide recovery type fuel cell power generation system according to the present invention. The fuel cell power generation system 10 A includes, as main components, a first fuel cell stack 12, a second fuel cell stack 14, a combustor with oxygen permeable membrane 20, a condenser 26, a first heat exchanger 30, a second heat exchanger 32, an exhaust heat input type absorption chiller 36, a water tank 27, a carbon manufacturing section 66, and the like, which are provided on-site. Furthermore, as illustrated in Fig. 2, the fuel cell power generation system 10 A is provided with a controller 40 that controls the fuel cell power generation system 10 A.|[0040] As illustrated in Fig. 1, a first fuel cell stack 12 is a hydrogen ion conductive solid oxide fuel cell (PCFC: Proton Ceramic Solid Oxide Fuel Cell); The fuel cell includes an electrolyte layer 12 C, and a first fuel electrode (fuel electrode) 12 A and a first air electrode (air electrode) 12 B laminated on front and rear surfaces of the electrolyte layer 12 C, respectively.|[0041] Note that the basic configuration of the second fuel cell stack 14 is the same as that of the first fuel cell stack 12, and includes a second fuel electrode 14 A corresponding to the first fuel electrode 12 A, a second air electrode 14 B corresponding to the first air electrode 12 B, and an electrolyte layer 14 C corresponding to the electrolyte layer 12 C.|[0042] One end of a fuel gas pipe P1 is connected to the first fuel electrode 12 A of the first fuel cell stack 12, and the other end of the fuel gas pipe P1 is connected to a fuel gas source (not illustrated). The fuel gas is sent from the fuel gas source to the first fuel electrode 12 A by the fuel supply blower B1. Note that, in the present embodiment, methane is used as the fuel gas, but the gas is not particularly limited as long as it is a gas capable of producing hydrogen by reforming, and a hydrocarbon fuel can be used. Examples of the hydrocarbon fuel include natural gas, LP gas (liquefied petroleum gas), biogas, coal reformed gas, lower hydrocarbon gas, and the like. Examples of the lower hydrocarbon gas include lower hydrocarbons having 4 or less carbons such as methane, ethane, ethylene, propane, butane, and the like, and methane used in the present embodiment is preferable. Note that the hydrocarbon fuel may be a mixture of the lower hydrocarbon gases described above, and the lower hydrocarbon gases may be natural gas, city gas, LP gas, or the like. In a case where the source gas contains impurities, a desulfurization apparatus or the like is required, but such impurities are omitted from the drawings.|[0043] A steam pipe P2 is merged and connected with the fuel gas pipe P1, and steam is appropriately supplied from a steam source (not illustrated) at startup or shutdown. The methane and the steam are merged at the fuel gas pipe P1 and supplied to the first fuel electrode 12 A. Note that in the present embodiment, as described later, a portion of the second fuel electrode off-gas is returned to the first fuel electrode 12 A and the steam is reused, so the steam from the steam pipe P2 is replenished and supplied as necessary in the process of starting up and stopping the fuel cell power generation system 10 A.|[0044] At the first fuel electrode 12 A, the fuel gas is subjected to steam reforming to produce hydrogen and carbon monoxide, as expressed in Equation (1) below. Furthermore, as shown in Formula (2) below, carbon dioxide and hydrogen are generated by a shift reaction between the generated carbon monoxide and water vapor.|[0045] CH4+ H2O 3H2+ CO... (1) CO+ H2O CO2+ H2... (2)|[0046] Then, in the first fuel electrode 12 A, hydrogen is separated into hydrogen ions and electrons, as shown in Formula (3) below.|[0047] (Fuel electrode reaction) H2 2 H++ 2 e-... (3)|[0048] The hydrogen ions migrate to the first air electrode 12 B through the electrolyte layer 12 C. The electrons move to the first air electrode through an external circuit (not illustrated). As a result, power is generated in the first fuel cell stack 12. During power generation, the first fuel cell stack 12 generates heat.|[0049] Oxidant gas (air) is supplied to the first air electrode 12 B of the first fuel cell stack 12 from an oxidant gas pipe P5. Air is introduced into the oxidant gas pipe P5 by an oxidant gas blower B2. The oxidant gas pipe P5 is provided with a second heat exchanger 32, and air flowing through the oxidant gas pipe P5 is heated by heat exchange with an air electrode off-gas flowing through an air electrode off-gas pipe P6 (described later). The heated air is supplied to the first air electrode 12 B.|[0050] At the first air electrode 12 B, as shown in Formula (4) below, hydrogen ions that have moved from the first fuel electrode 12 A through the electrolyte layer 12 C and electrons that have moved from the first fuel electrode 12 A through an external circuit react with oxygen in the oxidizer gas to generate water vapor.|[0051] (Air electrode reaction) 2 H++ 2 e-+ 1/2O2 H2O... (4)|[0052] Additionally, an air electrode off-gas pipe P6 is connected to the first air electrode 12 B. The air electrode off-gas is discharged from the first air electrode 12 B to the air electrode off-gas pipe P6. Note that the oxidizer gas pipe P5 and the air electrode off-gas pipe P6 are also connected in the same manner as the second air electrode 14 B, and the first air electrode 12 B and the second air electrode 14 B are connected in parallel.|[0053] One end of a first fuel electrode off-gas pipe P7 is connected to the first fuel electrode 12 A of the first fuel cell stack 12, and the other end of the first fuel electrode off-gas pipe P7 is connected to the second fuel electrode 14 A of the second fuel cell stack 14. The first fuel electrode off-gas is sent out from the first fuel electrode 12 A to the first fuel electrode off-gas pipe P7. The fuel electrode off-gas includes unreacted fuel gas components, unreacted hydrogen, unreacted carbon monoxide, carbon dioxide, steam, and the like.|[0054] One end of a second fuel electrode off-gas pipe P7-2 is connected to the second fuel electrode 14 A of the second fuel cell stack 14, and the second fuel electrode off-gas is sent out from the second fuel electrode 14 A. The other end of the second fuel electrode off-gas pipe P7-2 is connected to the combustor 20 with an oxygen permeable membrane. A circulation gas pipe P3 branches from the second fuel electrode off-gas pipe P7-2, and the circulation gas pipe P3 is connected to a fuel gas pipe P1 connected to the first fuel electrode 12 A. A circulation gas blower B3 is provided on the circulation gas pipe P3.|[0055] In the second fuel cell stack 14, the same power generation reaction as in the first fuel cell stack 12 is performed, and the air electrode off-gas is sent out from the second air electrode 14 B to the air electrode off-gas pipe P6. The air electrode off-gas pipe P6 connected to the second air electrode 14 B branches upstream of a merging section with the air electrode off-gas pipe P6 connected to the first air electrode 12 B, forming a branched air electrode off-gas pipe 14-2. The branch air electrode off-gas pipe P6-2 is provided with a flow rate regulating valve 42 capable of regulating the flow rate. The flow rate regulating valve 42 is connected to the control unit 40. The flow rate adjustment valve 42 is controlled by the control unit 40 to adjust the flow rate of the air electrode off-gas branching into the branch air electrode off-gas pipe P6-2. The downstream end of the branch air electrode off-gas pipe P6-2 is connected to the combustor 20 with an oxygen permeable membrane.|[0056] (a combustor with an oxygen permeable membrane) combustor with an oxygen permeable membrane 20 has a multiple cylindrical shape and includes a combustor 22 that forms an outer peripheral tube of the multiple cylindrical shape, and an oxygen separation unit 24 disposed inward of the combustor 22 in the radial direction. A combustion space 22 A is formed in the combustion portion 22.|[0057] The oxygen separation part 24 is disposed on the inner side in the radial direction of the combustion part 22, and an air flow path 24 A is formed adjacent to the combustion space 22 A. The air flow path 24 A and the combustion space 22 A are partitioned by an oxygen permeable membrane 23. As the oxygen permeable membrane 23, for example, a mixed electrically conductive ceramic of electrons and oxygen ions such as LSCF, or an oxygen ion electrically conductive ceramic dense membrane such as YSZ can be used. The other end of the second fuel electrode off-gas pipe P7-2 is connected to the inlet of the combustion space 22 A, and the downstream end of the branch air electrode off-gas pipe P6-2 is connected to the inlet of the air flow path 24 A. An oxidation catalyst is disposed inside the combustion space 22 A. Examples of the oxidation catalyst that can be used include nickel, ruthenium, and the like.|[0058] The second air electrode off-gas is supplied to the air flow path 24 A, and oxygen contained in the second air electrode off-gas passes through the oxygen permeable membrane 23 and moves to the combustion space 22 A. The second air electrode off-gas that does not move to the combustion space 22 A is exhausted to the outside from the exhaust pipe P12 connected to the outlet side of the air flow path 24 A.|[0059] The second fuel electrode off-gas is supplied to the combustion space 22 A and mixed with oxygen that has passed through and moved from the oxygen separation unit 24 through the oxygen permeable membrane 23. As a result, a combustion reaction occurs between oxygen and combustible gas components (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas via the oxidation catalyst, and carbon dioxide and steam are generated. A combustion off-gas pipe P8 is connected to an outlet side of the combustion space 22 A, and combustion off-gas is fed from the combustion space 22 A.|[0060] The combustion off-gas pipe P8 passes through the first heat exchanger 30 and is connected to the condenser 26 at the other end. In the first heat exchanger 30, the fuel gas is heated by heat exchange between the fuel gas and the combustion off-gas. A coolant circulation channel 26 A is piping in the condenser 26, and coolant from an exhaust heat input type absorption chiller 36 (described later) is circulated and supplied by driving a pump 26 P to cool the combustion off-gas. This condenses the water vapor in the combustion off-gas. The condensed water is sent to the water tank 27 via the water pipe P9.|[0061] The combustion off-gas from which the steam has been separated and removed is sent to the carbon dioxide gas pipe P10. The combustion off-gas from which water (liquid phase) has been removed by the condenser 26 is a gas having a high carbon dioxide concentration, and the combustion off-gas is referred to as a carbon dioxide-rich gas. A composition detection unit 44 is provided in the carbon dioxide gas pipe P10. The composition detection unit 44 detects the composition of the carbon dioxide rich gas sent from the condenser 26. Specifically, at least one of a concentration of a combustible gas such as methane, carbon monoxide, and hydrogen, and a concentration of carbon dioxide and oxygen is detected. The composition detection unit 44 is connected to the control unit 40, and composition information of the detected carbon dioxide-rich gas is transmitted to the control unit 40. Note that the controller 40 performs various controls so as to increase the concentration of carbon dioxide gas.|[0062] Note that a carbon manufacturing unit 66 described below is provided downstream of the carbon dioxide gas pipe P10.|[0063] A second heat exchanger 32 is provided downstream of a merging section where the air electrode off-gas pipes P6 from the first air electrode 12 B and the second air electrode 14 B are merged. In the second heat exchanger 32, heat exchange is performed between the air electrode off-gas flowing through the air electrode off-gas pipe P6 and the oxidant gas flowing through the oxidant gas pipe P5, heating the oxidant gas, and cooling the air electrode off-gas. The air electrode off-gas is supplied to the exhaust heat input type absorption chiller 36 via the second heat exchanger 32.|[0064] (Exhaust heat input type absorption chiller) Exhaust heat input type absorption chiller 36 is a heat pump that generates cold heat using exhaust heat, and as an example, a steam/heat input type absorption chiller can be used. In a steam/heat input type absorption chiller, the absorption liquid (for example, lithium bromide aqueous solution or ammonia aqueous solution) that has absorbed steam is heated by the heat of the air electrode off-gas, thereby separating water from the absorption liquid and regenerating the chiller. Water vapor is condensed in the air electrode off-gas obtained by heating and cooling the liquid absorbent, and condensed water is supplied to the water tank 27 via the water pipe P36-2. The air electrode off-gas from which the water vapor has been condensed and removed is sent to the exhaust pipe P36-1 and exhausted to the outside of the exhaust heat input type absorption chiller 36.|[0065] Note that a pump that circulates the liquid absorbent and a pump (neither illustrated) that circulates water separated from the liquid absorbent are provided inside the heat input type absorption chiller 36. These pumps are driven by DC motors, and the DC motors can be driven by DC power generated by the first fuel cell stack 12 and the second fuel cell stack 14.|[0066] The absorbing liquid regenerated by heating promotes evaporation of water by absorbing steam, contributing to the generation of cold heat. The exhaust heat input type absorption chiller 36 is connected to the cooling tower 38 via a heat dissipation circuit 37. A pump 37 P is installed in the heat dissipation circuit 37, and cooling water is supplied to the heat dissipation circuit 37 by the pump 37 P. Absorption heat generated when the liquid absorbent absorbs water vapor in the heat input type absorption chiller 36 is released from the cooling tower 38 to the atmosphere via the cooling water flowing through the heat dissipation circuit 37.|[0067] The cold heat generated by the exhaust heat input type absorption chiller 36 is supplied to the condenser 26 via the cooling water flowing through the cooling water circulation channel 26 A, the combustion off-gas is cooled by the condenser 26, and the water vapor in the combustion off-gas is further condensed and removed.|[0068] The water tank 27 is connected to a cooling water circulation channel 26 A, a heat dissipation circuit 37, and a heating medium channel (not illustrated) through which water flows as a heating medium of the exhaust heat input type absorption chiller 36. When water is insufficient in the cooling water circulation flow path 26 A, the heat dissipation circuit 37, and the heat medium flow path, water is appropriately replenished from the water tank 27.|[0069] (Carbon manufacturing unit 66) The carbon dioxide rich gas sent to the carbon dioxide gas pipe P10 is sent to the carbon manufacturing unit 66. The carbon production unit 66 includes a water electrolyzer 70, piping P14, a hydrogen blower 72, piping P15, an oxygen blower 74, an oxygen tank 76, a powdered carbon generator 78, and the like.|[0070] Water in the water tank 27 that has passed through the piping P16, the pump 80, and the water purification device 82 is supplied to the water electrolyzer 70. The water purification device 82 purifies the water from the water tank 27 (removal of foreign substances, PH adjustment, and the like). The water electrolyzer 70 can generate hydrogen gas and oxygen gas by electrolyzing water purified using electrical power obtained by the first fuel cell stack 12 and the second fuel cell stack 14. Note that the water electrolyzer 70 can electrolyze water using electric power (so-called "clean energy") obtained by renewable energy power generation (not illustrated). Examples of renewable energy power generation include photovoltaic power generation, solar power generation, hydroelectric power generation, wind power generation, geothermal power generation, wave power generation, temperature differential power generation, biomass generation, and the like, but others may also be used. In other words, from the perspective of reducing carbon dioxide in the atmosphere or suppressing the release of carbon dioxide to the atmosphere, it is preferable to use direct current electrical power obtained by the first fuel cell stack 12 and the second fuel cell stack 14 or electrical power obtained by renewable energy power generation.|[0071] Since the water electrolyzer 70 electrolyzes water using direct current electrical power obtained by the first fuel cell stack 12 and the second fuel cell stack 14 and electrical power obtained by renewable energy power generation, For example, compared to a case where AC power of a power generation apparatus releasing carbon dioxide gas is converted to DC power and used in electrolysis, it is possible to efficiently electrolyze water. Note that the water electrolyzer 70 is controlled by a control unit 40 described below.|[0072] The hydrogen gas generated in the water electrolyzer 70 is fed to the powdered carbon generator 78 via the piping P14 and the hydrogen blower 72, and the oxygen gas is fed to the oxygen tank 76 via the piping P15 and the oxygen blower 74 and stored in the oxygen tank 76. Note that the hydrogen blower 72 and the oxygen blower 74 are controlled by a control unit 40 described later.|[0073] (Configuration of Powdered Carbon Producer) As an example, the Powdered Carbon Producer 78 has a multiple cylindrical shape and includes a gas flow path 78 A having an annular shape in a plan view and a carbon fixing unit 78 B disposed inward of the gas flow path 78 A in the radial direction. In the carbon fixing unit 78 B, carbon dioxide gas fed from the condenser 26 and hydrogen gas fed from the water electrolyzer 70 are supplied. In the carbon fixing unit 78 B, a reduction reaction such as Formula (5) below is performed on carbon dioxide gas and hydrogen gas using a catalyst. CO2+ 2H2 C+ 2H2O... (5)|[0074] The C produced in the reduction reaction is powdered carbon, and can be discharged from the lower portion of the carbon fixing section 78 B. Furthermore, the H20 produced in the reduction reaction is specifically water vapor, and the water vapor is supplied to the condenser 26 via the pipe P17.|[0075] The (control unit) control unit 40 controls the entire fuel cell power generation system 10 A, and includes a CPU, a ROM, a RAM, a memory, and the like. The memory stores data, procedures, and the like necessary for flow rate adjustment processing, coolant temperature adjustment processing, and processing during normal operation, which will be described later. As illustrated in Fig. 2, the control unit 40 is connected to a flow rate regulating valve 42, a composition detection unit 44, a waste heat input type absorption chiller 36, and the like. The flow rate regulating valve 42, the composition detection unit 44, the waste heat input type absorption chiller 36, and the like are controlled by the control unit 40. Note that Fig. 2 illustrates a part of the connection relationship of the controller 40 in the fuel cell power generation system 10 A, and the controller 40 is also connected to other devices not illustrated in Fig. 2.|[0076] In the fuel cell power generation system 10 A, a pump, blower, and other auxiliary equipment are driven by power generated by the fuel cell power generation system 10 A. In order to efficiently utilize the electrical power generated by the fuel cell power generation system 10 A as a direct current without converting the electrical power to alternating current, the auxiliary equipment is preferably driven by direct current.|[0077] (Effect and Effect) Next, the operation of the fuel cell power generation system 10 A of the present embodiment will be described.|[0078] In the fuel cell power generation system 10 A, methane is sent from a gas source to a fuel gas pipe P1 by a fuel supply blower B1, heated by passing through a first heat exchanger 30, and supplied to a first fuel electrode 12 A. Steam for steam reforming is supplied from the steam pipe P2 to the first fuel electrode 12 A via the fuel gas pipe P1. Note that the supply of steam is at the time of startup or shortage, and the steam in the second fuel electrode off-gas returned from the circulation gas pipe P3 is used during rated operation, as described later.|[0079] At the first fuel electrode 12 A of the first fuel cell stack 12, the fuel gas is subjected to steam reforming, and hydrogen and carbon monoxide are produced. Furthermore, carbon dioxide and hydrogen are generated by a shift reaction between the generated carbon monoxide and water vapor.|[0080] Air is supplied to the first air electrode 12 B of the first fuel cell stack 12 via an oxidant gas pipe P5. In the first fuel cell stack 12, hydrogen ions move in the first fuel electrode 12 A and the first air electrode 12 B and the reactions described above occur to generate power. The first fuel electrode off-gas is fed from the first fuel electrode 12 A of the first fuel cell stack 12 to the first fuel electrode off-gas pipe P7. Additionally, air electrode off-gas is sent from the first air electrode 12 B to the air electrode off-gas pipe P6.|[0081] The first fuel electrode off-gas sent out from the first fuel electrode 12 A is guided to the first fuel electrode off-gas pipe P7 and supplied to the second fuel electrode 14 A of the second fuel cell stack 14. Air is supplied to the second air electrode 14 B of the second fuel cell stack 14 via an oxidant gas pipe P5. The second fuel cell stack 14 generates power in the same manner as the first fuel cell stack 12. The second fuel electrode off-gas is fed from the second fuel electrode 14 A of the second fuel cell stack 14 to the second fuel electrode off-gas pipe P7-2. Additionally, the air electrode off-gas is sent from the second air electrode 14 B to the air electrode off-gas pipe P6. A portion of the air electrode off-gas sent out from the second air electrode 14 B branches to the branched air electrode off-gas pipe P6-2, and the other portions merge with the air electrode off-gas sent out from the first air electrode 12 B.|[0082] The air electrode off-gas is supplied to the exhaust heat input type absorption chiller 36 via the second heat exchanger 32. In the second heat exchanger 32, heat exchange is performed between the air electrode off-gas and the oxidant gas, and the oxidant gas is heated by the air electrode off-gas. In the exhaust heat input type absorption chiller 36, as described above, the heat of the air electrode off-gas is used to generate cold.|[0083] A portion of the second fuel electrode off-gas branches to the circulation gas pipe P3 and is returned to the first fuel electrode 12 A. The other second fuel electrode off-gas is supplied to the combustion portion 22 of the combustor provided with an oxygen permeable membrane 20 and flows through the combustion space 22 A.|[0084] The air electrode off-gas branched to the branched air electrode off-gas pipe P6-2 is supplied to the oxygen separation unit 24 of the combustor 20 with an oxygen permeable membrane. The air electrode off-gas supplied to the oxygen separation unit 24 flows through the air flow path 24 A. In the air flow path 24 A, oxygen contained in the air electrode off-gas passes through the oxygen permeable membrane 23 and moves to the combustion space 22 A side. In the combustion space 22 A, a combustion reaction occurs between the combustible gas (methane, hydrogen, carbon monoxide, and the like) and oxygen in the second fuel electrode off-gas, and carbon dioxide and steam are generated. The combustion off-gas containing carbon dioxide and water vapor is sent from the combustion space 22 A to the combustion off-gas pipe P8. The combustion off-gas sent to the combustion off-gas pipe P8 is supplied to the condenser 26 via the first heat exchanger 30.|[0085] The combustion off-gas supplied to the condenser 26 is cooled by the cooling water from the exhaust heat input type absorption chiller 36 circulated and supplied via the cooling water circulation flow path 26 A, and the water vapor in the combustion off-gas is condensed. The condensed water is sent to the water tank 27 via the water pipe P9 and stored in the water tank 27.|[0086] The combustion off-gas from which the water vapor has been removed by the condenser 26 becomes carbon dioxide rich gas having a high carbon dioxide concentration, and is sent to the carbon dioxide gas pipe P10 by the carbon dioxide blower B4 and sent to the composition detection unit 44. In the composition detection unit 44, the composition of the carbon dioxide rich gas is detected, and the detected information is transmitted to the control unit 40.|[0087] The control unit 40 controls the flow rate adjustment valve 42 on the basis of the composition information transmitted from the composition detection unit 44 to adjust the amount of air electrode off-gas branching into the branch air electrode off-gas pipe P6-2, and controls the temperature of the cooling water supplied to the cooling water circulation flow path 26 A by the heat input type absorption chiller 36. Specifically, in the control unit 40, the following flow rate adjustment processing and coolant temperature adjustment processing are executed.|[0088] As illustrated in Fig. 3, in the flow rate regulating process, in step S10, it is determined whether the concentration of the combustible gas is within a threshold value G1 in the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44. Wherein the threshold value G1 is a sufficiently low concentration in the carbon dioxide rich gas 0.1 Approximately 5vol% to 5vol%, and a ratio of 0.1 to 1vol%. If the concentration of the combustible gas is higher than the threshold value G1, the flow rate regulating valve 42 is controlled in step S12 to increase the flow rate of the branching air electrode off-gas to the branching air electrode off-gas pipe P6-2. As a result, the amount of oxygen passing through the oxygen permeable membrane 23 and moving to the combustion space 22 A increases, and the amount of combustible gas contained in the carbon dioxide-rich gas can be reduced by causing a combustion reaction in the combustion space 22 A.|[0089] In step S10, when the concentration of the combustible gas is equal to or less than the threshold G1, in step S14, it is determined whether the concentration of oxygen is within the threshold O1 in the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44. Wherein the threshold value O1 is a sufficiently low concentration in the carbon dioxide rich gas 0.1 Approximately 5vol% to 5vol%, and a ratio of 0.1 to 1vol%. When the oxygen concentration is higher than the threshold value O1, the flow rate adjustment valve 42 is controlled in step S16 to decrease the flow rate of the air electrode off-gas branching into the branch air electrode off-gas pipe P6-2. As a result, the amount of oxygen passing through the oxygen permeable membrane 23 and moving to the combustion space 22 A is reduced, and it is possible to reduce the amount of oxygen remaining unsupplied to a combustion reaction in the combustion space 22 A.|[0090] After steps S12, S14, and S16, the process returns to step S10, and the above-described process is repeated. This flow rate adjustment process starts when the fuel cell power generation system 10 A starts operation, continues during operation, and ends when the fuel cell power generation system 10 A stops operation.|[0091] Further, as illustrated in Fig. 4, in the condensation amount adjustment processing, in step S20, it is determined whether the concentration of water vapor is within a threshold value M in the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44. Wherein the threshold value M is a sufficiently low concentration in the carbon dioxide rich gas 0.1 Approximately 5vol% to 5vol%, and a ratio of 0.1 to 1vol%. When the concentration of water vapor is higher than the threshold M, condensation fortification is performed in step S22. Specifically, the exhaust heat input type absorption chiller 36 is controlled to decrease the temperature of the cooling water supplied to the cooling water circulation flow path 26 A and increase the circulation flow rate of the cooling water. This increases the amount of water separated from the combustion off-gas by condensation in the condenser 26, making it possible to reduce the proportion of water vapor contained in the carbon dioxide-rich gas.|[0092] After steps S20 and S22, the process returns to step S20, and the above-described process is repeated. This condensation amount adjustment process starts when the operation of the fuel cell power generation system 10 A starts, continues during operation, and ends when the operation stops.|[0093] The water electrolyzer 70 electrolyzes the water fed from the water purifier 82 to produce hydrogen gas and oxygen gas. The carbon dioxide rich gas sent to the carbon dioxide gas pipe P10 is sent to the powdered carbon generator 78. In the carbon fixing unit 78 B, carbon dioxide gas fed from the condenser 26 and hydrogen gas fed from the water electrolyzer 70 are supplied to cause a reduction reaction such as that expressed by the following Formula (6). CO2+ 2H2 C+ 2H2O... (6)|[0094] In order to initiate the reaction described above, it is necessary to increase the ambient temperature, but since heat is generated by the reaction, it is not necessary to apply heat from the outside once the reaction is initiated. When starting up the powdered carbon generator 78, first, hydrogen gas and oxygen gas are supplied to the gas-flow passages 78 A to ignite the powdered carbon generator 78. After ignition, if heat is generated by a reaction of formula (6), the supply of oxygen gas and hydrogen gas is stopped.|[0095] In the carbon fixing unit 78 B, powdered carbon ((6) "C" in Formula formula) can be continuously produced by continuously feeding carbon dioxide gas and hydrogen gas. The produced powdered carbon can be removed from below the carbon fixing section 78 B. In addition, water vapor ((6) expressed by the formula H2O) produced by a reaction between carbon dioxide gas and hydrogen gas is discharged from below the carbon fixing section 78 B. Note that the water vapor discharged from the carbon fixing unit 78 B is supplied to the condenser 26 via the piping P17, cooled by the condenser 26, and turned into water.|[0096] In the fuel cell power generation system 10 A of the present embodiment, the first fuel cell stack 12 and the second fuel cell stack 14 are continuously connected and provided on-site, making it possible to efficiently manufacture powdered carbon continuously during power generation. Unless the powdered carbon is ignited and combusted, it is not released into the atmosphere as carbon dioxide gas, and it is possible to suppress the release of carbon dioxide gas to the atmosphere. In addition, the powdered carbon is also easy to transport to the storage sites, and unless placed under conditions where the ignition source and oxygen are aligned, long-term stable carbon immobilization is possible simply by landfill disposal underground or simply by being loaded on the ground. Note that the produced powdered carbon can also be used commercially as carbon black or the like.|[0097] In the fuel cell power generation system 10 A of the present embodiment, powdered carbon is produced from carbon dioxide gas, but a carbon product manufacturing device 84 in which the powdered carbon is graphite, carbon nanotubes, diamond, or the like may be further added. In the carbon product manufacturing device 84, synthetic diamond powder can be obtained by a known technique by placing the recovered powdered carbon in a high-temperature (electric heater temperature elevation) and high-pressure (electric high-pressure pressing) environment using power generated by the fuel cell power generation system 10 A, power generated by renewable energy, or the like, for example. In addition, for example, carbon nanotubes can be obtained from the recovered powdered carbon by publicly known techniques such as arc discharge methods, laser ablation methods, and CVD methods using power generated by the fuel cell power generation system 10 A, power generated by renewable energy, or the like. Furthermore, graphite can be obtained from the recovered powdered carbon using power generated by the fuel cell power generation system 10 A, power generated by renewable energy, or the like by a known technique. By using graphite, carbon nanotubes, or diamond powder as the carbon powder, combustion does not easily occur even if there is an ignition source or oxygen, and the carbon can be safely and stably fixed for a long period of time even if stacked on the ground, there is no restriction on the storage location, and energy loss and cost of transportation or press-fitting can be reduced. Graphite can also be used as pencil leads or brake pads for automobiles, carbon nanotubes can be used as semiconductors or structural materials, and synthetic diamond powders can be used as blades of diamond cutters for construction and machine tools. Note that the carbon product manufacturing device 84 is also a part of the carbon manufacturing unit 66 and is provided on-site in the fuel cell power generation system 10 A. In addition, products produced using powdered carbon are not limited to the carbon products described above, and carbon materials such as carbon nanohorns and fullerenes may be produced by a known technique and used in the commercial industry.|[0098] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, the second fuel electrode off-gas sent out from the second fuel electrode 14 A of the second fuel cell stack 14 is combusted by the combustor 22, so that The amount of unreacted fuel gas supplied for power generation in the second fuel cell stack 14 is increased compared to the case where the first fuel electrode off-gas before power generation in the second fuel cell stack 14 is combusted. Accordingly, it is possible to increase the power generation efficiency of the second fuel cell stack 14.|[0099] Furthermore, in the combustor 22, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to recover a high concentration of carbon dioxide by subtracting the combustible gas from the second fuel electrode off-gas. In addition, only oxygen in the air electrode off-gas is supplied to the combustor 22, and the second fuel electrode off-gas contains less unreacted fuel gas and has a higher carbon dioxide content than the first fuel electrode off-gas. Accordingly, the amount of unreacted fuel gas burned in the combustor 22 and the amount of oxygen required to burn the unreacted fuel gas can be reduced.|[0100] In addition, the fuel cell power generation system 10 A of the present embodiment includes the branch air electrode off-gas pipe 14-2 that branches from the air electrode off-gas pipe P6, making it possible to easily adjust the air electrode off-gas flow rate branching into the branch air electrode off-gas pipe 14-2 on the basis of the composition information of the carbon dioxide rich gas detected by the composition detection unit 44. As a result, the amount of oxygen flowing into the combustion space 22 A of the combustor 22 can be adjusted so that the amount of combustible gas and oxygen contained in the combustion off-gas is lower than a predetermined threshold.|[0101] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, the carbon dioxide concentration of the carbon dioxide-rich gas can be increased by adjusting the amount of water condensed by the condenser 26 on the basis of the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44.|[0102] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, hydrogen ion conductive solid oxide fuel cells are used for the fuel cell stack, so water vapor is not generated at the first fuel electrode 12 A. Therefore, the amount of water vapor contained in the first fuel electrode off-gas is reduced, making it possible to improve the power generation efficiency of the second fuel cell. In addition, the amount of water vapor contained in the second fuel electrode off-gas is also reduced, making it possible to reduce the amount of water vapor removed from the second fuel electrode off-gas.|[0103] Furthermore, the fuel cell power generation system 10 A of the present embodiment includes a circulating gas pipe P3 that supplies a portion of the second fuel electrode off-gas to the first fuel electrode 12 A from the upstream side of the combustor 22. Accordingly, some of the unreacted fuel gas and steam in the second fuel electrode off-gas can be reused for power generation and steam reforming of the fuel gas, respectively.|[0104] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, disposing the combustion part 22 adjacent to the oxygen permeable membrane 23 of the oxygen separation part 24 makes it possible to configure a compact combustor 20 with an oxygen permeable membrane integrally formed with the combustion part 22 and the oxygen separation part 24.|[0105] Also, in the fuel cell power generation system 10 A of the present embodiment, the heat of the air electrode off-gas is used for cold generation in the heat input type absorption chiller 36, making it possible to effectively utilize the exhaust heat from the first fuel cell stack 12 and the second fuel cell stack 14. In addition, since the air electrode off-gas contains a large amount of water vapor, the heat of condensation can also be effectively used due to the water vapor condensing in the heat input type absorption chiller 36 during heat exchange.|[0106] Note that in the present embodiment, the carbon dioxide is separated from the combustion off-gas by condensing and removing water vapor in the combustion off-gas by the condenser 26, but the carbon dioxide may be separated by other means such as a carbon dioxide separation membrane, or the carbon dioxide may be separated by a PSA apparatus.|[0107] [Second Embodiment] Next, a second embodiment of the present invention will be described. In the present embodiment, the same components as those in the first embodiment are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0108] As illustrated in Fig. 5, a fuel cell power generation system 10 B of the present embodiment is provided with a high-temperature oxygen manufacturing device 50 and a combustor 52 in place of the combustor 20 with an oxygen permeable membrane of the first embodiment. Configurations other than the high-temperature oxygen manufacturing device 50 and the combustor 52 are the same as those of the first embodiment.|[0109] The downstream end of a branch air electrode off-gas pipe P6-2 is connected to the inlet side of the high-temperature oxygen manufacturing device 50. The high-temperature oxygen producing device 50 is a device that separates oxygen from the air electrode off-gas, and as an example, a high-temperature device that adsorbs and desorbs at high temperatures (an operating temperature of 600 to 900 °C, for example) PSA can be used. A first end of an oxygen supply pipe PO is connected to an oxygen outlet side of the high-temperature oxygen manufacturing device 50. An exhaust pipe P13 is connected to the air electrode off-gas outlet side of the high-temperature oxygen manufacturing device 50 after the oxygen has been separated. The other end of the oxygen supply pipe PO is connected to the inlet side of the combustor 52. The exhaust pipe P13 opens to the outside of the fuel cell power generation system 10 B. Note that the high-temperature oxygen producing device 50 can efficiently produce oxygen using high-temperature air electrode off-gas. Additionally, the high-temperature oxygen manufacturing device 50 can be driven by direct current electrical power generated by the first fuel cell stack 12 and the second fuel cell stack 14.|[0110] The other end of the oxygen supply pipe PO and the downstream end of the second fuel electrode off-gas pipe P7-2 are connected to the inlet side of the combustor 52. Inside the combustor 52, a combustion reaction occurs between the combustible gas component (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas and oxygen supplied from the oxygen supply pipe PO, and carbon dioxide and steam are generated. A combustion off-gas pipe P8 is connected to an outlet side of the combustor 52, and combustion off-gas is fed from the combustor 52.|[0111] Next, the operation of the fuel cell power generation system 10 B of the present embodiment will be described.|[0112] In the present embodiment as well, power is generated by the first fuel cell stack 12 and the second fuel cell stack 14 in the same manner as in the fuel cell power generation system 10 A of the first embodiment. The second air electrode off-gas sent out from the second air electrode 14 B and branched to the branched air electrode off-gas pipe P6-2 is supplied to the high-temperature oxygen manufacturing device 50. In the high-temperature oxygen manufacturing device 50, oxygen is separated from the second air electrode off-gas, and the separated oxygen is supplied to the combustor 52 via the oxygen supply pipe PO. The air electrode off-gas from which oxygen has been separated is discharged from the exhaust pipe P13 to the outside.|[0113] In the combustor 52, a combustion reaction occurs between oxygen and combustible gas components (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas, and carbon dioxide and steam are generated. The combustion off-gas is sent to the combustion off-gas pipe P8, where water is separated in the condenser 26 in the same manner as in the first embodiment, the separated water is collected in the water tank 27, and the carbon dioxide rich gas is supplied to the carbon manufacturing unit 66.|[0114] In the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0115] [Third Embodiment] Next, a third embodiment of the present invention will be described. In the present embodiment, components that are the same as those in the first and second embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0116] The fuel cell power generation system 10 C of the present embodiment differs from the first embodiment in that the reformer 54 is mainly provided, the circulating gas pipe P3 is not provided, and the piping flow path associated with these configurations is not provided. The rest of the configuration is the same as that of the first embodiment.|[0117] As illustrated in Fig. 6, a fuel cell power generation system 10 C includes a reformer 54. A first end of a fuel gas pipe P1-1 is connected to an inlet side of the reformer 54. Furthermore, one end of a water supply pipe P2-2 is connected to the inlet side of the reformer 54. The other end of the water supply pipe P2-2 is connected to the water tank 27. The water supply pipe P2-2 is provided with an ion exchange resin 56 and a pump 27 B. By driving the pump 27 B, the water stored in the water tank 27 is supplied to the reformer 54 via the ion exchange resin 56.|[0118] A first end of a reformed gas pipe P1-2 is connected to an outlet side of the reformer 54. The other end of the reformed gas pipe P1-2 is connected to the first fuel electrode 12 A of the first fuel cell stack 12.|[0119] Next, the operation of the fuel cell power generation system 10 C of the present embodiment will be described.|[0120] In the reformer 54, the mixed gas of the fuel gas and the steam is heated by heat exchange with the combustion off-gas, and hydrogen and carbon monoxide are produced by a steam reforming reaction. Furthermore, carbon dioxide and hydrogen are generated by a shift reaction between the generated carbon monoxide and water vapor. Reformed gas containing unreacted fuel gas (methane), hydrogen, carbon monoxide, and carbon dioxide is supplied to the first fuel electrode 12 A through the reformed gas pipe P1-2. The first fuel cell stack 12 and the second fuel cell stack 14 generate power in the same manner as in the first embodiment.|[0121] The second fuel electrode off-gas is fed from the second fuel electrode 14 A to the second fuel electrode off-gas pipe P7-2. The second fuel electrode off-gas is supplied to the combustor 22 of the combustor with oxygen permeable membrane 20 without being branched. The air electrode off-gas is sent from the second air electrode 14 B to the air electrode off-gas pipe P6. as in the first embodiment, a portion of the air electrode off-gas is branched to the branched air electrode off-gas pipe 10-2, and the rest of the air electrode off-gas is merged with the air electrode off-gas sent from the first air electrode 12 B.|[0122] In the combustor 20 with an oxygen permeable membrane and the condenser 26, processing is performed in the same manner as in the first embodiment, and the carbon dioxide rich gas is supplied to the carbon manufacturing section 66.|[0123] In the present embodiment as well, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas in the combustor 20 provided with an oxygen permeable membrane. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0124] [Fourth Embodiment] Next, a fourth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to third embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0125] The fuel cell power generation system 10 D of the present embodiment is provided with the high-temperature oxygen manufacturing device 50 and the combustor 52 of the second embodiment in place of the combustor 20 with an oxygen permeable membrane of the third embodiment. Configurations other than the high-temperature oxygen manufacturing device 50 and the combustor 52 are the same as those of the third embodiment.|[0126] As illustrated in Fig. 7, the downstream end of a branch air electrode off-gas pipe P6-2 is connected to the inlet side of the high-temperature oxygen manufacturing device 50, and one end of an oxygen supply pipe PO is connected to the oxygen outlet side of the high-temperature oxygen manufacturing device 50. An exhaust pipe P13 is connected to the air electrode off-gas outlet side of the high-temperature oxygen manufacturing device 50 after the oxygen has been separated. The other end of the oxygen supply pipe PO is connected to the inlet side of the combustor 52. The exhaust pipe P13 opens to the outside of the fuel cell power generation system 10 D.|[0127] The other end of the oxygen supply pipe PO and the downstream end of the second fuel electrode off-gas pipe P7-2 are connected to the inlet side of the combustor 52. Inside the combustor 52, a combustion reaction occurs between the combustible gas component (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas and oxygen supplied from the oxygen supply pipe PO, and carbon dioxide and steam are generated. A combustion off-gas pipe P8 is connected to an outlet side of the combustor 52, and combustion off-gas is fed from the combustor 52.|[0128] Next, the operation of the fuel cell power generation system 10 D of the present embodiment will be described.|[0129] In the present embodiment, as with the fuel cell power generation system 10 C of the third embodiment, reformed gas is generated by steam-reforming the fuel gas in the reformer 54, and power is generated in the first fuel cell stack 12 and the second fuel cell stack 14. The second air electrode off-gas sent out from the second air electrode 14 B and branched to the branched air electrode off-gas pipe P6-2 is supplied to the high-temperature oxygen manufacturing device 50. In the high-temperature oxygen manufacturing device 50, oxygen is separated from the second air electrode off-gas, and the separated oxygen is supplied to the combustor 52 via the oxygen supply pipe PO. The air electrode off-gas from which oxygen has been separated is discharged from the exhaust pipe P13 to the outside.|[0130] In the combustor 52, a combustion reaction occurs between oxygen and combustible gas components (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas, and carbon dioxide and steam are generated. The combustion off-gas is sent to the combustion off-gas pipe P8, where water is separated in the condenser 26 in the same manner as in the first embodiment, the separated water is collected in the water tank 27, and the carbon dioxide rich gas is supplied to the carbon manufacturing unit 66.|[0131] In the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0132] [Fifth Embodiment] Next, a fifth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to fourth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0133] A fuel cell power generation system 10 E of the present embodiment differs from the first embodiment in that a third heat exchanger 34 and a condenser 35 are provided in the path of the first fuel electrode off-gas pipe P7.|[0134] As illustrated in Fig. 8, the first fuel electrode off-gas pipe P7 extends from the first fuel electrode 12 A and is connected to the condenser 35 via the third heat exchanger 34. The first fuel electrode off-gas pipe P7 extending from the first fuel electrode 12 A to the condenser 35 is denoted by reference numeral P7A. The first fuel electrode off-gas pipe P7A extends from a gas-side outlet of the condenser 35 and is connected to the second fuel electrode 14 A via the third heat exchanger 34. The first fuel electrode off-gas pipe P7 extending from the condenser 35 to the second fuel electrode 14 A is denoted by reference numeral P7B. One end of a water pipe P9-2 is connected to a liquid-side outlet of the condenser 35. The other end of the water pipe P9-2 is connected to the water tank 27. A coolant circulation channel 35 A is piping in the condenser 35, and coolant from the exhaust heat input type absorption chiller 36 is circulated and supplied by driving a pump 35 P. As a result, the first fuel electrode off-gas is cooled and the water vapor in the first fuel electrode off-gas is condensed. The condensed water is sent to the water tank 27 via the water pipe P9-2.|[0135] Next, the operation of the fuel cell power generation system 10 E of the present embodiment will be described.|[0136] In the present embodiment as well, power is generated in the first fuel cell stack 12 in the same manner as in the fuel cell power generation system 10 A of the first embodiment. The first fuel electrode off-gas sent from the first fuel electrode 12 A to the first fuel electrode off-gas pipe P7-1 is cooled by heat exchange with regenerated fuel gas (described later) in the third heat exchanger 34, and is supplied to the condenser 35. In the condenser 35, the first fuel electrode off-gas is further cooled by the cooling water circulating through the cooling water circulation flow path 35 A, and the water vapor in the first fuel electrode off-gas is condensed. Here, the temperature of the cooling water circulating through the cooling water circulation flow path 35 A is set so that the water vapor in the first fuel electrode off-gas condenses to such an extent that the amount of water vapor remaining in the regenerated fuel gas improves the power generation efficiency in the second fuel cell stack 14. The condensed water is sent to the water tank 27 via the water pipe P9-2.|[0137] The first fuel electrode off-gas from which condensed water has been separated is sent to the first fuel electrode off-gas pipe P7B as regenerated fuel gas, heated by heat exchange with the first fuel electrode off-gas before water has been separated by the third heat exchanger 34, and supplied to the second fuel electrode 14 A. The second fuel cell stack 14 generates power in the same manner as in the fuel cell power generation system 10 A of the first embodiment.|[0138] In the present embodiment, regenerated fuel gas generated by separating a portion of water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0139] Additionally, in the present embodiment too, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas in the combustion section 22 of the combustor 20 with an oxygen permeable membrane. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0140] [Sixth Embodiment] Next, a sixth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to fifth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0141] As illustrated in Fig. 9, in a fuel cell power generation system 10 F of the present embodiment, the first fuel cell stack 62 and the second fuel cell stack 64 use a solid oxide fuel cell (SOFC: Solid Oxide Fuel Cell) instead of the hydrogen ion conductive solid oxide fuel cell of the first embodiment. Accordingly, reactions occur in the first fuel electrode 62 A (fuel electrode) and the first air electrode 62 B (air electrode) as follows. Note that the same applies to the second fuel electrode 64 A and the second air electrode 64 B.|[0142] In the first air electrode 62 B, oxygen ions are generated as a result of a reaction between oxygen and electrons in the oxidizer gas, as expressed in Formula (5) below. The generated oxygen ions pass through the electrolyte layer 62 C and reach the first fuel electrode 62 A of the first fuel cell stack 62.|[0143] (Air electrode reaction) 1/2O2+ 2 e- O2-... (5)|[0144] On the other hand, in the first fuel electrode 62 A of the first fuel cell stack 62, oxygen ions that have passed through the electrolyte layer 62 C react with hydrogen and carbon monoxide in the fuel gas, and water vapor, carbon dioxide, and electrons are generated, as shown in Formulas (6) and (7) below. Electrons generated by the first fuel electrode 62 A move from the first fuel electrode 62 A to the first air electrode 62 B through an external circuit, so that power is generated.|[0145] (Fuel electrode reaction) H2+ O2- H2O+ 2 e-... (6) CO+ O2- CO2+ 2 e-... (7)|[0146] In the solid oxide fuel cell, since water vapor is generated by the first fuel electrode 62 A and the second fuel electrode 64 A, the amount of water vapor contained in the first fuel electrode off-gas and the second fuel electrode off-gas is greater than in the hydrogen ion conductive solid oxide fuel cell. On the other hand, water vapor is not generated in the first air electrode 62 B and the second air electrode 64 B. The air electrode off-gas supplied to the exhaust heat input type absorption chiller 36 is exhausted from the exhaust pipe P36-1 after heat exchange.|[0147] The other configurations of the fuel cell power generation system 10 F of the present embodiment are the same as those of the fifth embodiment, and a third heat exchanger 34 and a condenser 35 are provided in the path of the first fuel electrode off-gas pipe P7. Here, since the amounts of water vapor contained in the first fuel electrode off-gas and the second fuel electrode off-gas are greater than in the fuel cell power generation system 10 E, the temperature of the cooling water circulating through the cooling water circulation flow path 35 A is set so as to increase the amount of water vapor removed by condensation in the condenser 35. The condensed water is sent to the water tank 27 via the water pipe P9-2.|[0148] In the present embodiment, regenerated fuel gas generated by separating a portion of water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0149] Additionally, in the present embodiment too, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas in the combustion section 22 of the combustor 20 with an oxygen permeable membrane. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0150] [Seventh Embodiment] Next, a seventh embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to sixth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0151] As illustrated in Fig. 10, a fuel cell power generation system 10 G of the present embodiment is provided with the same high-temperature oxygen producing device 50 and combustor 52 as those of the second embodiment instead of the combustor 20 with an oxygen permeable membrane of the sixth embodiment. Configurations other than the high-temperature oxygen manufacturing device 50, the combustor 52, and piping associated therewith are the same as those of the sixth embodiment.|[0152] In the present embodiment as well, the regenerated fuel gas generated by separating a portion of the water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0153] Additionally, in the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0154] [Eighth Embodiment] Next, an eighth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to seventh embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0155] As illustrated in Fig. 11, a fuel cell power generation system 10 H of the present embodiment differs from that of the sixth embodiment in that a reformer 54 is provided, a recirculating gas pipe P3 is not provided, and piping flow paths related to these configurations are different from those of the sixth embodiment. The rest of the configuration is the same as that of the sixth embodiment.|[0156] In the present embodiment as well, the regenerated fuel gas generated by separating a portion of the water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0157] Additionally, in the present embodiment as well, carbon dioxide and steam are generated in the combustor 22 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0158] [Ninth Embodiment] Next, a ninth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to eighth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0159] As illustrated in Fig. 11, a fuel cell power generation system 10 I of the present embodiment is provided with a high-temperature oxygen producing device 50 and a combustor 52 of a seventh embodiment in place of the combustor 20 with an oxygen permeable membrane of the eighth embodiment. Configurations other than the high-temperature oxygen manufacturing device 50 and the combustor 52 are the same as those of the eighth embodiment.|[0160] In the present embodiment as well, the regenerated fuel gas generated by separating a portion of the water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0161] Additionally, in the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0162] [Other embodiments] a first embodiment of the carbon recovery fuel cell power generation system of the present invention has been described above, but the present invention is not limited to the first embodiment and, of course, various modifications may be made without departing from the gist of the present invention.|[0163] Other fuel cells, such as a molten carbonate fuel cell (MCFC), a phosphoric acid fuel cell (PAFC), and a solid polymer fuel cell (PEFC), can also be used as the fuel cell of the present invention.|[0164] Note that, in the first to ninth embodiments described above, the exhaust heat input type absorption chiller 36 is used to generate cold, but instead of the exhaust heat input type absorption chiller 36, a heat pump that utilizes another exhaust heat, such as an adsorption chiller, may be used to generate cold.|[0165] Furthermore, instead of the heat input type absorption chiller 36, the fuel cell power generation system 10 J may use an electric turbo chiller 60 that generates cold heat by using electric power without using exhaust heat. Fig. 13 illustrates, as an example, a fuel cell power generation system 10 A of the first embodiment in which the heat input absorption chiller 36 is replaced with an electric turbo chiller 60. The second to ninth embodiments may also be substituted in the same manner. In the fuel cell power generation system 10 J, the air electrode off-gas is discharged to the outside of the system after heat exchange in the second heat exchanger 32. The electric turbo chiller 60 can be driven by power generated by the fuel cell power generation system 10 J. The electric turbo chiller 60 generally has high cooling efficiency, making it possible to operate the fuel cell power generation system 10 J with high efficiency even when generated electrical power is used. Note that in this case as well, in order to efficiently utilize the generated electrical power without converting it to alternating current, the electric turbo chiller 60 is preferably driven by direct current.|REFERENCE SIGNS LIST|[0166] 10 A to 10 J fuel cell power generation system (carbon recovery fuel cell power generation system) 12; 62 first fuel cell stack (first fuel cell) 12 A; 62 A first fuel electrode 12 B; 62 B first air electrode 14; 64 Second fuel cell stack (second fuel cell) 14 A, 64 A second fuel electrode 14 B, 64 B second air electrode 20 combustor with oxygen permeable membrane 22 combustion section, 22 A combustion space 23 oxygen permeable membrane, 24 Oxygen separation unit 26 condenser (carbon dioxide separation unit) 35 condenser (fuel regeneration unit) 36 exhaust heat input type absorption chiller 50 high temperature oxygen production apparatus (oxygen separation unit) 52 combustor (combustor), 54 reformer; 70 Water electrolyzer 78 powdered carbon generator (carbon generating unit) 84 carbon product manufacturing apparatus P3 Circulation gas pipe (circulation flow path) P6 air electrode off-gas pipe (air electrode off-gas flow path) P6-2 branched air electrode off-gas pipe (branched air electrode off-gas flow path) P7 second fuel electrode off-gas pipe (second fuel electrode off-gas flow path) | (JP6692394)|TECHNICAL FIELD|[0001] The present invention relates to a carbon recovery type fuel cell power generation system, and particularly relates to a carbon recovery type fuel cell power generation system that generates power using a carbon compound fuel and is capable of converting and recovering carbon dioxide generated by the power generation into carbon.|BACKGROUND ART|[0002] When a carbon compound fuel is used in a fuel cell power generation system, exhaust gas discharged from the fuel cell contains carbon dioxide gas. Carbon dioxide gas is one cause of global warming. thus, it is conceivable to separate and recover carbon dioxide gas from exhaust gas and store the carbon dioxide gas so that the carbon dioxide gas is not released into the atmosphere.|[0003] Examples of the storing of carbon dioxide gas include recovering carbon dioxide gas and storing and immobilizing the recovered carbon dioxide gas in the ground or the like CCS (Carbon Capture and Storage); The amount of crude oil recovered from the depleted oil field is increased while storing and immobilizing the recovered carbon dioxide gas in the ground or the like EOR (Enhanced Oil Recovery); The present invention is known to be used in EGR (Enhanced Gas Recovery), which increases the amount of natural gas recovered from a depleted gas field, and ECBM (Enhanced Coal Bed Methane), which releases and recovers methane by injecting the natural gas into a coal layer.|[0004] Patent Document 1 describes, for example, a method of embedding carbon dioxide gas in the ground or injecting the carbon dioxide gas into the sea floor.|CITATION LIST|PATENT LITERATURE|[0005] PATENT CITATIONS |Japanese Patent No. 2013-196890|SUMMARY OF INVENTION|TECHNICAL PROBLEM|[0006] However, in any of the CCS including EOR, EGR, and ECBM described above, it is assumed that the carbon dioxide is transported to the storage site in a pipeline or in which the carbon dioxide gas is converted to liquefied carbon dioxide and then transported in a lorry. From the perspective of constructing a power generation system compatible with CCS, it is also desirable to construct a system capable of efficiently separating and recovering carbon dioxide gas generated during power generation and efficiently storing the recovered carbon dioxide gas.|[0007] Furthermore, for CCS and BECCS, the locations where carbon dioxide gas can be injected and stored are limited (for example, because there are few oil and gas fields suitable for EOR and EGS in Japan, liquefied carbon dioxide is transported to an overseas storage site such as heavy state; It is assumed that carbon dioxide gas is injected underground with a pressure injection pump and stored). in addition, in the case of anhydrous layer storage, there is concern over the risk of discharge due to contamination of the anhydrous layer, an earthquake, or fluctuations in the vicinity, and over the risk of discharge of stored carbon dioxide gas due to effects on the ocean ecosystem, changes in geographies, or the like, even over the case of ocean storage. there is room for improvement. The transport and pressure injection storage of carbon dioxide gas and liquefied carbon dioxide consume a great deal of energy and increase costs. In these fields of separating and recovering, immobilizing, and effective use of carbon dioxide gas, the separating and recovering of CO2 can be performed in a manner similar to that of the CCS total cost. ~70%, and the cost of immobilizing the CO2 is 3~70%. This is said to account for 40%, and simplification and high efficiency are extremely important technical problems in separating, recovering, and immobilizing carbon dioxide gas.|[0008] In light of the foregoing, an object of the present invention is to provide a carbon recovery type fuel cell power generation system capable of efficiently separating and recovering carbon dioxide generated in association with the power generation of a fuel cell, making it easy to transport and immobilize, and suppressing the release of carbon dioxide gas to the atmosphere.|TECHNICAL SOLUTION|[0009] The carbon recovery type fuel cell power generation system according to claim 1, comprising: a fuel cell that generates power by fuel gas containing a carbon compound and supplied to a fuel electrode, and oxidant gas containing oxygen and supplied to an air electrode, and discharges off-gas; A carbon dioxide gas separation unit that separates carbon dioxide gas from the off-gas; a water electrolyzer that electrolyzes water to generate hydrogen gas; and a water electrolyzer that electrolyzes the carbon dioxide gas from the carbon dioxide gas separation unit and the hydrogen gas from the water electrolyzer.SingleOn catalystAndA carbon generating part that generates carbon and steam.|[0010] The carbon recovery type fuel cell power generation system according to claim 1, wherein the fuel cell generates power using the fuel gas supplied to the fuel electrode and the oxidant gas supplied to the air electrode, and discharges off-gas. Carbon dioxide gas is separated from the off-gas discharged from the fuel cell in a carbon dioxide gas separation unit. The water electrolyzer electrolyzes water to produce hydrogen gas. The carbon generating unit is configured to generate carbon dioxide gas separated by the carbon dioxide gas separation unit and hydrogen gas generated by the water electrolyzer.SingleCatalystByProduces carbon (solid) and water vapor. In this way, in the carbon recovery type fuel cell power generation system according to claim 1, it is possible to recover carbon dioxide gas generated by power generation as solid carbon. Recovery with solid carbon suppresses the release of carbon dioxide gas to the atmosphere, greatly simplifies the transport and immobilization process, and increases efficiency, as compared to recovery with carbon dioxide gas as is.|[0011] According to the invention described in claim 2, in the carbon recovery type fuel cell power generation system described in claim 1, the water electrolyzer electrolyzes the water using at least one of electrical power generated by a renewable energy power generator and electrical power generated by the fuel cell.|[0012] The carbon recovery type fuel cell power generation system according to claim 2, wherein the water electrolyzer electrolyzes water by at least one of the electrical power generated by the renewable energy power generator and the electrical power generated by the fuel cell, It is not necessary to use power generated by a power generation apparatus that releases carbon dioxide gas in association with power generation, and it is possible to suppress the release of carbon dioxide gas into the atmosphere.|[0013] According to the invention according to claim 3, in the carbon recovery type fuel cell power generation system according to claim 1 or claim 2, the carbon dioxide gas separation unit separates the carbon dioxide gas and water from the off-gas, and the water electrolyzer uses the water separated by the carbon dioxide gas separation unit.|[0014] In the carbon recovery type fuel cell power generation system according to claim 3, since the water electrolyzer uses water separated by the carbon dioxide gas separation unit for electrolysis, it is not necessary to supply water from an external water supply or the like, and it is possible to reduce the amount of water dependency on the outside.|[0015] The invention according to claim 4, a carbon recovery fuel cell power generation system according to any one of claims 1 to 3, comprising: a first fuel cell that generates power using fuel gas containing a carbon compound and supplied to a first fuel electrode, and an oxidant gas containing oxygen and supplied to a first air electrode, and sends first fuel electrode off-gas from the first fuel electrode to first fuel electrode off-gas flow paths; A second fuel cell that generates power using the first fuel electrode off-gas supplied to a second fuel electrode and oxidant gas supplied to a second air electrode, and delivers the second fuel electrode off-gas from the second fuel electrode to second fuel electrode off-gas passages; and An air electrode off-gas flow path that sends out air electrode off-gas from at least one of the first air electrode and the second air electrode; an oxygen separation unit connected to the air electrode off-gas flow path, to which the air electrode off-gas is supplied, the oxygen separation unit separating oxygen from the air electrode off-gas; and a fuel cell supplied with the second fuel electrode off-gas and the oxygen separated by the oxygen separation unit; A combustion unit that performs a combustion reaction on the second fuel electrode off-gas with the oxygen; and an exhaust heat input type absorption chiller or an adsorption chiller that uses the off-gas as a heat source to cool water and generate cooling water, wherein the carbon dioxide gas separation unit separates carbon dioxide gas and water by cooling combustion off-gas sent from the combustion unit with the cooling water.|[0016] The carbon recovery fuel cell power generation system according to claim 4, wherein the fuel cell includes a first fuel cell and a second fuel cell. In the first fuel cell, power is generated by the fuel gas supplied to the first fuel electrode and the oxidant gas supplied to the first air electrode. In the second fuel cell, power is generated by the first fuel electrode off-gas supplied from the first fuel electrode to the second fuel electrode and the oxidant gas supplied to the second air electrode.|[0017] Air electrode off-gas is sent from at least one of the first air electrode and the second air electrode to the air electrode off-gas flow path, and the air electrode off-gas is supplied to the oxygen separation unit via the air electrode off-gas flow path. In the oxygen separation unit, oxygen is separated from the air electrode off-gas, and the separated oxygen is supplied to the combustion unit.|[0018] The second fuel electrode off-gas is sent from the second fuel electrode to the fuel electrode off-gas flow paths, and the second fuel electrode off-gas is supplied to the combustion unit via the fuel electrode off-gas flow paths. In the combustor, a combustion reaction occurs between the combustible components in the second fuel electrode off-gas and oxygen, and the combustion off-gas is sent out from the combustor.|[0019] The combustion off-gas is sent to a carbon dioxide separation unit, and carbon dioxide is separated from the combustion off-gas.|[0020] In the fuel cell power generation system according to claim 4, the second fuel electrode off-gas after being sent out from the second fuel cell is combusted in the combustion unit, so the amount of unreacted fuel gas supplied to the second fuel cell is increased compared to the case where the first fuel electrode off-gas before being supplied for power generation in the second fuel cell is combusted. Therefore, it is possible to increase the power generation efficiency of the second fuel cell.|[0021] Furthermore, in the combustor, carbon dioxide and steam are generated by a combustion reaction between oxygen and combustible components contained in the second fuel electrode off-gas. Therefore, it is possible to recover a high concentration of carbon dioxide by subtracting the combustible gas from the second fuel electrode off-gas.|[0022] In addition, the amount of unreacted fuel gas contained in the second fuel electrode off-gas is smaller and the carbon dioxide content ratio is higher than that of the first fuel electrode off-gas. Accordingly, the amount of unreacted fuel gas burned in the combustor can be reduced, and the amount of oxygen required to burn the unreacted fuel gas can be reduced.|[0023] In addition, the exhaust heat input type absorption chiller or the adsorption chiller cools water by being driven using the air electrode off-gas discharged from the fuel cell as a driving heat source, making it possible to effectively utilize the exhaust heat of the off-gas. Since the exhaust heat input type absorption type refrigeration machine or the adsorption type refrigeration machine can supply cold heat with effective use of exhaust heat, it is possible to efficiently cool water to produce cooling water with less power than when cold heat is generated by a refrigeration machine of a type that compresses and expands a refrigerant by driving a compressor with a motor.|[0024] The invention according to claim 5 is the carbon recovery fuel cell power generation system according to claim 4, wherein the first fuel cell and the second fuel cell are hydrogen ion conductive solid oxide fuel cells (PCFC: Proton Conducting Solid Oxide Fuel Cell).|[0025] In a hydrogen ion conductive solid oxide fuel cell, water vapor is generated by a power generation reaction on the air electrode side. Therefore, the amount of water vapor contained in the first fuel electrode off-gas is small, so the decrease in concentration of the fuel gas supplied to the second fuel electrode is small, and it is possible to improve the power generation efficiency of the second fuel cell. In addition, the amount of water vapor contained in the second fuel electrode off-gas is also reduced, making it possible to reduce the amount of water vapor removed from the second fuel electrode off-gas.|[0026] A sixth aspect of the invention is the carbon recovery fuel cell power generation system according to claim 4 or 5, further comprising: a supply unit that supplies the water separated by the carbon dioxide gas separation unit to a cooling water path of the exhaust heat input absorption chiller or a cooling water path of the adsorption chiller; The water separated by the carbon dioxide gas separation unit is used as the cooling water of the exhaust heat input type absorption chiller, as part of cooling water supplemental water of a cooling tower constituting the exhaust heat input type absorption chiller, or as part of cooling water of the adsorption chiller or as part of cooling water supplemental water of a cooling tower constituting the adsorption chiller.|[0027] In the carbon recovery fuel cell power generation system according to claim 6, the water separated by the carbon dioxide gas separation unit can be supplied by the supply unit to the cooling water path of the exhaust heat input type absorption chiller or the cooling water path of the adsorption type absorption chiller. Accordingly, there is no need to supply water from an external water supply or the like in the case where the cooling water in the cooling water path is insufficient, and the amount of water dependent on the outside can be reduced.|[0028] According to the invention according to claim 7, in the carbon recovery fuel cell power generation system according to any one of claims 4 to 6, the oxygen separation unit includes an oxygen permeable membrane that selectively permeates oxygen, and the combustion unit is integrated with the oxygen separation unit with a combustion space disposed on a permeation side of the oxygen permeable membrane.|[0029] According to the carbon recovery fuel cell power generation system according to claim 7, it is possible to dispose the combustion part adjacent to the oxygen permeable membrane of the oxygen separation part, and it is possible to configure the combustion part and the oxygen separation part in a compact manner.|[0030] According to the invention according to claim 8, in the carbon recovery fuel cell power generation system according to any one of claims 4 to 6, the oxygen separation unit includes a high-temperature PSA device that is driven by power generated by the first fuel cell and the second fuel cell.|[0031] According to the carbon recovery fuel cell power generation system according to claim 8, the oxygen separation unit separates oxygen from the high-temperature air electrode off-gas using the high-temperature PSA device, making it possible to efficiently separate oxygen.|[0032] According to the invention according to claim 9, in the carbon recovery type fuel cell power generation system according to any one of claims 1 to 8, the carbon dioxide gas separation unit cools the off-gas and generates the carbon dioxide gas and water, and the water vapor generated by the carbon generation unit is supplied to the carbon dioxide gas separation unit via a supply path.|[0033] The carbon recovery fuel cell power generation system according to claim 9, wherein carbon dioxide gas and water are generated by cooling the off-gas by the carbon dioxide gas separation unit. Additionally, the steam generated in the carbon generating unit is supplied to the carbon dioxide gas separating unit via a supply path, and water is generated by cooling the steam in the carbon dioxide gas separating unit. Accordingly, in the carbon dioxide gas separation unit, water generated by off-gas and water generated by cooling water vapor are obtained, making it possible to increase the amount of water generated in the system, thereby making it possible to increase the amount of hydrogen gas generated in the water electrolyzer.|[0034] The invention according to claim 10 includes a carbon product manufacturing device according to any one of claims 1 to 9, wherein the carbon produced by the carbon producing unit is graphite, carbon nanotubes, or diamond.|[0035] The carbon recovery fuel cell power generation system according to claim 10, wherein Graphite, carbon nanotubes, or diamond can be used, and carbon dioxide gas can be effectively used and immobilized safely and stably for a long period of time.|ADVANTAGEOUS EFFECTS|[0036] According to the carbon recovery type fuel cell power generation system of the present invention, it is possible to convert the carbon dioxide generated in association with the power generation of the fuel cell to carbon into carbon, which makes it easier and more stable for a long period of time than storing carbon dioxide gas.|DESCRIPTION OF DRAWINGS|[0037] Fig. 1 is a schematic view of a fuel cell power generation system according to a first embodiment. Is a block diagram illustrating a control system of the fuel cell power generation system according to the first embodiment. Is a flowchart of the flow rate regulating process of the first embodiment. Is a flowchart of a cooling water temperature regulating process of Embodiment 1. Fig. 2 is a schematic view of a fuel cell power generation system according to a second embodiment. Fig. 3 is a schematic view of a fuel cell power generation system according to a third embodiment. Fig. 4 is a schematic diagram of a fuel cell power generation system according to a fourth embodiment. Is a schematic diagram of a fuel cell power generation system according to a fifth embodiment. Is a schematic diagram of a fuel cell power generation system according to a sixth embodiment. Is a schematic diagram of a fuel cell power generation system according to a seventh embodiment. Fig. 8 is a schematic diagram of a fuel cell power generation system according to an eighth embodiment. Fig. 9 is a schematic diagram of a fuel cell power generation system according to a ninth embodiment. Is a schematic diagram of a fuel cell power generation system according to a modified example of the first embodiment.|DESCRIPTION OF EMBODIMENTS|[0038] Hereinafter, an example of an embodiment of the present invention will be described in detail with reference to the drawings.|[0039] First Embodiment Fig. 1 illustrates a fuel cell power generation system 10 A according to a first embodiment as an example of a carbon dioxide recovery type fuel cell power generation system according to the present invention. The fuel cell power generation system 10 A includes, as main components, a first fuel cell stack 12, a second fuel cell stack 14, a combustor with oxygen permeable membrane 20, a condenser 26, a first heat exchanger 30, a second heat exchanger 32, an exhaust heat input type absorption chiller 36, a water tank 27, a carbon manufacturing section 66, and the like, which are provided on-site. Furthermore, as illustrated in Fig. 2, the fuel cell power generation system 10 A is provided with a controller 40 that controls the fuel cell power generation system 10 A.|[0040] As illustrated in Fig. 1, a first fuel cell stack 12 is a hydrogen ion conductive solid oxide fuel cell (PCFC: Proton Ceramic Solid Oxide Fuel Cell); The fuel cell includes an electrolyte layer 12 C, and a first fuel electrode (fuel electrode) 12 A and a first air electrode (air electrode) 12 B laminated on front and rear surfaces of the electrolyte layer 12 C, respectively.|[0041] Note that the basic configuration of the second fuel cell stack 14 is the same as that of the first fuel cell stack 12, and includes a second fuel electrode 14 A corresponding to the first fuel electrode 12 A, a second air electrode 14 B corresponding to the first air electrode 12 B, and an electrolyte layer 14 C corresponding to the electrolyte layer 12 C.|[0042] One end of a fuel gas pipe P1 is connected to the first fuel electrode 12 A of the first fuel cell stack 12, and the other end of the fuel gas pipe P1 is connected to a fuel gas source (not illustrated). The fuel gas is sent from the fuel gas source to the first fuel electrode 12 A by the fuel supply blower B1. Note that, in the present embodiment, methane is used as the fuel gas, but the gas is not particularly limited as long as it is a gas capable of producing hydrogen by reforming, and a hydrocarbon fuel can be used. Examples of the hydrocarbon fuel include natural gas, LP gas (liquefied petroleum gas), biogas, coal reformed gas, lower hydrocarbon gas, and the like. Examples of the lower hydrocarbon gas include lower hydrocarbons having 4 or less carbons such as methane, ethane, ethylene, propane, butane, and the like, and methane used in the present embodiment is preferable. Note that the hydrocarbon fuel may be a mixture of the lower hydrocarbon gases described above, and the lower hydrocarbon gases may be natural gas, city gas, LP gas, or the like. In a case where the source gas contains impurities, a desulfurization apparatus or the like is required, but such impurities are omitted from the drawings.|[0043] A steam pipe P2 is merged and connected with the fuel gas pipe P1, and steam is appropriately supplied from a steam source (not illustrated) at startup or shutdown. The methane and the steam are merged at the fuel gas pipe P1 and supplied to the first fuel electrode 12 A. Note that in the present embodiment, as described later, a portion of the second fuel electrode off-gas is returned to the first fuel electrode 12 A and the steam is reused, so the steam from the steam pipe P2 is replenished and supplied as necessary in the process of starting up and stopping the fuel cell power generation system 10 A.|[0044] At the first fuel electrode 12 A, the fuel gas is subjected to steam reforming to produce hydrogen and carbon monoxide, as expressed in Equation (1) below. Furthermore, as shown in Formula (2) below, carbon dioxide and hydrogen are generated by a shift reaction between the generated carbon monoxide and water vapor.|[0045] CH4+ H2O 3H2+ CO... (1) CO+ H2O CO2+ H2... (2)|[0046] Then, in the first fuel electrode 12 A, hydrogen is separated into hydrogen ions and electrons, as shown in Formula (3) below.|[0047] (Fuel electrode reaction) H2 2 H++ 2 e-... (3)|[0048] The hydrogen ions migrate to the first air electrode 12 B through the electrolyte layer 12 C. The electrons move to the first air electrode through an external circuit (not illustrated). As a result, power is generated in the first fuel cell stack 12. During power generation, the first fuel cell stack 12 generates heat.|[0049] Oxidant gas (air) is supplied to the first air electrode 12 B of the first fuel cell stack 12 from an oxidant gas pipe P5. Air is introduced into the oxidant gas pipe P5 by an oxidant gas blower B2. The oxidant gas pipe P5 is provided with a second heat exchanger 32, and air flowing through the oxidant gas pipe P5 is heated by heat exchange with an air electrode off-gas flowing through an air electrode off-gas pipe P6 (described later). The heated air is supplied to the first air electrode 12 B.|[0050] At the first air electrode 12 B, as shown in Formula (4) below, hydrogen ions that have moved from the first fuel electrode 12 A through the electrolyte layer 12 C and electrons that have moved from the first fuel electrode 12 A through an external circuit react with oxygen in the oxidizer gas to generate water vapor.|[0051] (Air electrode reaction) 2 H++ 2 e-+ 1/2O2 H2O... (4)|[0052] Additionally, an air electrode off-gas pipe P6 is connected to the first air electrode 12 B. The air electrode off-gas is discharged from the first air electrode 12 B to the air electrode off-gas pipe P6. Note that the oxidizer gas pipe P5 and the air electrode off-gas pipe P6 are also connected in the same manner as the second air electrode 14 B, and the first air electrode 12 B and the second air electrode 14 B are connected in parallel.|[0053] One end of a first fuel electrode off-gas pipe P7 is connected to the first fuel electrode 12 A of the first fuel cell stack 12, and the other end of the first fuel electrode off-gas pipe P7 is connected to the second fuel electrode 14 A of the second fuel cell stack 14. The first fuel electrode off-gas is sent out from the first fuel electrode 12 A to the first fuel electrode off-gas pipe P7. The fuel electrode off-gas includes unreacted fuel gas components, unreacted hydrogen, unreacted carbon monoxide, carbon dioxide, steam, and the like.|[0054] One end of a second fuel electrode off-gas pipe P7-2 is connected to the second fuel electrode 14 A of the second fuel cell stack 14, and the second fuel electrode off-gas is sent out from the second fuel electrode 14 A. The other end of the second fuel electrode off-gas pipe P7-2 is connected to the combustor 20 with an oxygen permeable membrane. A circulation gas pipe P3 branches from the second fuel electrode off-gas pipe P7-2, and the circulation gas pipe P3 is connected to a fuel gas pipe P1 connected to the first fuel electrode 12 A. A circulation gas blower B3 is provided on the circulation gas pipe P3.|[0055] In the second fuel cell stack 14, the same power generation reaction as in the first fuel cell stack 12 is performed, and the air electrode off-gas is sent out from the second air electrode 14 B to the air electrode off-gas pipe P6. The air electrode off-gas pipe P6 connected to the second air electrode 14 B branches upstream of a merging section with the air electrode off-gas pipe P6 connected to the first air electrode 12 B, forming a branched air electrode off-gas pipe 14-2. The branch air electrode off-gas pipe P6-2 is provided with a flow rate regulating valve 42 capable of regulating the flow rate. The flow rate regulating valve 42 is connected to the control unit 40. The flow rate adjustment valve 42 is controlled by the control unit 40 to adjust the flow rate of the air electrode off-gas branching into the branch air electrode off-gas pipe P6-2. The downstream end of the branch air electrode off-gas pipe P6-2 is connected to the combustor 20 with an oxygen permeable membrane.|[0056] (a combustor with an oxygen permeable membrane) combustor with an oxygen permeable membrane 20 has a multiple cylindrical shape and includes a combustor 22 that forms an outer peripheral tube of the multiple cylindrical shape, and an oxygen separation unit 24 disposed inward of the combustor 22 in the radial direction. A combustion space 22 A is formed in the combustion portion 22.|[0057] The oxygen separation part 24 is disposed on the inner side in the radial direction of the combustion part 22, and an air flow path 24 A is formed adjacent to the combustion space 22 A. The air flow path 24 A and the combustion space 22 A are partitioned by an oxygen permeable membrane 23. As the oxygen permeable membrane 23, for example, a mixed electrically conductive ceramic of electrons and oxygen ions such as LSCF, or an oxygen ion electrically conductive ceramic dense membrane such as YSZ can be used. The other end of the second fuel electrode off-gas pipe P7-2 is connected to the inlet of the combustion space 22 A, and the downstream end of the branch air electrode off-gas pipe P6-2 is connected to the inlet of the air flow path 24 A. An oxidation catalyst is disposed inside the combustion space 22 A. Examples of the oxidation catalyst that can be used include nickel, ruthenium, and the like.|[0058] The second air electrode off-gas is supplied to the air flow path 24 A, and oxygen contained in the second air electrode off-gas passes through the oxygen permeable membrane 23 and moves to the combustion space 22 A. The second air electrode off-gas that does not move to the combustion space 22 A is exhausted to the outside from the exhaust pipe P12 connected to the outlet side of the air flow path 24 A.|[0059] The second fuel electrode off-gas is supplied to the combustion space 22 A and mixed with oxygen that has passed through and moved from the oxygen separation unit 24 through the oxygen permeable membrane 23. As a result, a combustion reaction occurs between oxygen and combustible gas components (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas via the oxidation catalyst, and carbon dioxide and steam are generated. A combustion off-gas pipe P8 is connected to an outlet side of the combustion space 22 A, and combustion off-gas is fed from the combustion space 22 A.|[0060] The combustion off-gas pipe P8 passes through the first heat exchanger 30 and is connected to the condenser 26 at the other end. In the first heat exchanger 30, the fuel gas is heated by heat exchange between the fuel gas and the combustion off-gas. A coolant circulation channel 26 A is piping in the condenser 26, and coolant from an exhaust heat input type absorption chiller 36 (described later) is circulated and supplied by driving a pump 26 P to cool the combustion off-gas. This condenses the water vapor in the combustion off-gas. The condensed water is sent to the water tank 27 via the water pipe P9.|[0061] The combustion off-gas from which the steam has been separated and removed is sent to the carbon dioxide gas pipe P10. The combustion off-gas from which water (liquid phase) has been removed by the condenser 26 is a gas having a high carbon dioxide concentration, and the combustion off-gas is referred to as a carbon dioxide-rich gas. A composition detection unit 44 is provided in the carbon dioxide gas pipe P10. The composition detection unit 44 detects the composition of the carbon dioxide rich gas sent from the condenser 26. Specifically, at least one of a concentration of a combustible gas such as methane, carbon monoxide, and hydrogen, and a concentration of carbon dioxide and oxygen is detected. The composition detection unit 44 is connected to the control unit 40, and composition information of the detected carbon dioxide-rich gas is transmitted to the control unit 40. Note that the controller 40 performs various controls so as to increase the concentration of carbon dioxide gas.|[0062] Note that a carbon manufacturing unit 66 described below is provided downstream of the carbon dioxide gas pipe P10.|[0063] A second heat exchanger 32 is provided downstream of a merging section where the air electrode off-gas pipes P6 from the first air electrode 12 B and the second air electrode 14 B are merged. In the second heat exchanger 32, heat exchange is performed between the air electrode off-gas flowing through the air electrode off-gas pipe P6 and the oxidant gas flowing through the oxidant gas pipe P5, heating the oxidant gas, and cooling the air electrode off-gas. The air electrode off-gas is supplied to the exhaust heat input type absorption chiller 36 via the second heat exchanger 32.|[0064] (Exhaust heat input type absorption chiller) Exhaust heat input type absorption chiller 36 is a heat pump that generates cold heat using exhaust heat, and as an example, a steam/heat input type absorption chiller can be used. In a steam/heat input type absorption chiller, the absorption liquid (for example, lithium bromide aqueous solution or ammonia aqueous solution) that has absorbed steam is heated by the heat of the air electrode off-gas, thereby separating water from the absorption liquid and regenerating the chiller. Water vapor is condensed in the air electrode off-gas obtained by heating and cooling the liquid absorbent, and condensed water is supplied to the water tank 27 via the water pipe P36-2. The air electrode off-gas from which the water vapor has been condensed and removed is sent to the exhaust pipe P36-1 and exhausted to the outside of the exhaust heat input type absorption chiller 36.|[0065] Note that a pump that circulates the liquid absorbent and a pump (neither illustrated) that circulates water separated from the liquid absorbent are provided inside the heat input type absorption chiller 36. These pumps are driven by DC motors, and the DC motors can be driven by DC power generated by the first fuel cell stack 12 and the second fuel cell stack 14.|[0066] The absorbing liquid regenerated by heating promotes evaporation of water by absorbing steam, contributing to the generation of cold heat. The exhaust heat input type absorption chiller 36 is connected to the cooling tower 38 via a heat dissipation circuit 37. A pump 37 P is installed in the heat dissipation circuit 37, and cooling water is supplied to the heat dissipation circuit 37 by the pump 37 P. Absorption heat generated when the liquid absorbent absorbs water vapor in the heat input type absorption chiller 36 is released from the cooling tower 38 to the atmosphere via the cooling water flowing through the heat dissipation circuit 37.|[0067] The cold heat generated by the exhaust heat input type absorption chiller 36 is supplied to the condenser 26 via the cooling water flowing through the cooling water circulation channel 26 A, the combustion off-gas is cooled by the condenser 26, and the water vapor in the combustion off-gas is further condensed and removed.|[0068] The water tank 27 is connected to a cooling water circulation channel 26 A, a heat dissipation circuit 37, and a heating medium channel (not illustrated) through which water flows as a heating medium of the exhaust heat input type absorption chiller 36. When water is insufficient in the cooling water circulation flow path 26 A, the heat dissipation circuit 37, and the heat medium flow path, water is appropriately replenished from the water tank 27.|[0069] (Carbon manufacturing unit 66) The carbon dioxide rich gas sent to the carbon dioxide gas pipe P10 is sent to the carbon manufacturing unit 66. The carbon production unit 66 includes a water electrolyzer 70, piping P14, a hydrogen blower 72, piping P15, an oxygen blower 74, an oxygen tank 76, a powdered carbon generator 78, and the like.|[0070] Water in the water tank 27 that has passed through the piping P16, the pump 80, and the water purification device 82 is supplied to the water electrolyzer 70. The water purification device 82 purifies the water from the water tank 27 (removal of foreign substances, PH adjustment, and the like). The water electrolyzer 70 can generate hydrogen gas and oxygen gas by electrolyzing water purified using electrical power obtained by the first fuel cell stack 12 and the second fuel cell stack 14. Note that the water electrolyzer 70 can electrolyze water using electric power (so-called "clean energy") obtained by renewable energy power generation (not illustrated). Examples of renewable energy power generation include photovoltaic power generation, solar power generation, hydroelectric power generation, wind power generation, geothermal power generation, wave power generation, temperature differential power generation, biomass generation, and the like, but others may also be used. In other words, from the perspective of reducing carbon dioxide in the atmosphere or suppressing the release of carbon dioxide to the atmosphere, it is preferable to use direct current electrical power obtained by the first fuel cell stack 12 and the second fuel cell stack 14 or electrical power obtained by renewable energy power generation.|[0071] Since the water electrolyzer 70 electrolyzes water using direct current electrical power obtained by the first fuel cell stack 12 and the second fuel cell stack 14 and electrical power obtained by renewable energy power generation, For example, compared to a case where AC power of a power generation apparatus releasing carbon dioxide gas is converted to DC power and used in electrolysis, it is possible to efficiently electrolyze water. Note that the water electrolyzer 70 is controlled by a control unit 40 described below.|[0072] The hydrogen gas generated in the water electrolyzer 70 is fed to the powdered carbon generator 78 via the piping P14 and the hydrogen blower 72, and the oxygen gas is fed to the oxygen tank 76 via the piping P15 and the oxygen blower 74 and stored in the oxygen tank 76. Note that the hydrogen blower 72 and the oxygen blower 74 are controlled by a control unit 40 described later.|[0073] (Configuration of Powdered Carbon Producer) As an example, the Powdered Carbon Producer 78 has a multiple cylindrical shape and includes a gas flow path 78 A having an annular shape in a plan view and a carbon fixing unit 78 B disposed inward of the gas flow path 78 A in the radial direction. In the carbon fixing unit 78 B, carbon dioxide gas fed from the condenser 26 and hydrogen gas fed from the water electrolyzer 70 are supplied. In the carbon fixing unit 78 B, a reduction reaction such as Formula (5) below is performed on carbon dioxide gas and hydrogen gas using a catalyst. CO2+ 2H2 C+ 2H2O... (5)|[0074] The C produced in the reduction reaction is powdered carbon, and can be discharged from the lower portion of the carbon fixing section 78 B. Furthermore, the H20 produced in the reduction reaction is specifically water vapor, and the water vapor is supplied to the condenser 26 via the pipe P17.|[0075] The (control unit) control unit 40 controls the entire fuel cell power generation system 10 A, and includes a CPU, a ROM, a RAM, a memory, and the like. The memory stores data, procedures, and the like necessary for flow rate adjustment processing, coolant temperature adjustment processing, and processing during normal operation, which will be described later. As illustrated in Fig. 2, the control unit 40 is connected to a flow rate regulating valve 42, a composition detection unit 44, a waste heat input type absorption chiller 36, and the like. The flow rate regulating valve 42, the composition detection unit 44, the waste heat input type absorption chiller 36, and the like are controlled by the control unit 40. Note that Fig. 2 illustrates a part of the connection relationship of the controller 40 in the fuel cell power generation system 10 A, and the controller 40 is also connected to other devices not illustrated in Fig. 2.|[0076] In the fuel cell power generation system 10 A, a pump, blower, and other auxiliary equipment are driven by power generated by the fuel cell power generation system 10 A. In order to efficiently utilize the electrical power generated by the fuel cell power generation system 10 A as a direct current without converting the electrical power to alternating current, the auxiliary equipment is preferably driven by direct current.|[0077] (Effect and Effect) Next, the operation of the fuel cell power generation system 10 A of the present embodiment will be described.|[0078] In the fuel cell power generation system 10 A, methane is sent from a gas source to a fuel gas pipe P1 by a fuel supply blower B1, heated by passing through a first heat exchanger 30, and supplied to a first fuel electrode 12 A. Steam for steam reforming is supplied from the steam pipe P2 to the first fuel electrode 12 A via the fuel gas pipe P1. Note that the supply of steam is at the time of startup or shortage, and the steam in the second fuel electrode off-gas returned from the circulation gas pipe P3 is used during rated operation, as described later.|[0079] At the first fuel electrode 12 A of the first fuel cell stack 12, the fuel gas is subjected to steam reforming, and hydrogen and carbon monoxide are produced. Furthermore, carbon dioxide and hydrogen are generated by a shift reaction between the generated carbon monoxide and water vapor.|[0080] Air is supplied to the first air electrode 12 B of the first fuel cell stack 12 via an oxidant gas pipe P5. In the first fuel cell stack 12, hydrogen ions move in the first fuel electrode 12 A and the first air electrode 12 B and the reactions described above occur to generate power. The first fuel electrode off-gas is fed from the first fuel electrode 12 A of the first fuel cell stack 12 to the first fuel electrode off-gas pipe P7. Additionally, air electrode off-gas is sent from the first air electrode 12 B to the air electrode off-gas pipe P6.|[0081] The first fuel electrode off-gas sent out from the first fuel electrode 12 A is guided to the first fuel electrode off-gas pipe P7 and supplied to the second fuel electrode 14 A of the second fuel cell stack 14. Air is supplied to the second air electrode 14 B of the second fuel cell stack 14 via an oxidant gas pipe P5. The second fuel cell stack 14 generates power in the same manner as the first fuel cell stack 12. The second fuel electrode off-gas is fed from the second fuel electrode 14 A of the second fuel cell stack 14 to the second fuel electrode off-gas pipe P7-2. Additionally, the air electrode off-gas is sent from the second air electrode 14 B to the air electrode off-gas pipe P6. A portion of the air electrode off-gas sent out from the second air electrode 14 B branches to the branched air electrode off-gas pipe P6-2, and the other portions merge with the air electrode off-gas sent out from the first air electrode 12 B.|[0082] The air electrode off-gas is supplied to the exhaust heat input type absorption chiller 36 via the second heat exchanger 32. In the second heat exchanger 32, heat exchange is performed between the air electrode off-gas and the oxidant gas, and the oxidant gas is heated by the air electrode off-gas. In the exhaust heat input type absorption chiller 36, as described above, the heat of the air electrode off-gas is used to generate cold.|[0083] A portion of the second fuel electrode off-gas branches to the circulation gas pipe P3 and is returned to the first fuel electrode 12 A. The other second fuel electrode off-gas is supplied to the combustion portion 22 of the combustor provided with an oxygen permeable membrane 20 and flows through the combustion space 22 A.|[0084] The air electrode off-gas branched to the branched air electrode off-gas pipe P6-2 is supplied to the oxygen separation unit 24 of the combustor 20 with an oxygen permeable membrane. The air electrode off-gas supplied to the oxygen separation unit 24 flows through the air flow path 24 A. In the air flow path 24 A, oxygen contained in the air electrode off-gas passes through the oxygen permeable membrane 23 and moves to the combustion space 22 A side. In the combustion space 22 A, a combustion reaction occurs between the combustible gas (methane, hydrogen, carbon monoxide, and the like) and oxygen in the second fuel electrode off-gas, and carbon dioxide and steam are generated. The combustion off-gas containing carbon dioxide and water vapor is sent from the combustion space 22 A to the combustion off-gas pipe P8. The combustion off-gas sent to the combustion off-gas pipe P8 is supplied to the condenser 26 via the first heat exchanger 30.|[0085] The combustion off-gas supplied to the condenser 26 is cooled by the cooling water from the exhaust heat input type absorption chiller 36 circulated and supplied via the cooling water circulation flow path 26 A, and the water vapor in the combustion off-gas is condensed. The condensed water is sent to the water tank 27 via the water pipe P9 and stored in the water tank 27.|[0086] The combustion off-gas from which the water vapor has been removed by the condenser 26 becomes carbon dioxide rich gas having a high carbon dioxide concentration, and is sent to the carbon dioxide gas pipe P10 by the carbon dioxide blower B4 and sent to the composition detection unit 44. In the composition detection unit 44, the composition of the carbon dioxide rich gas is detected, and the detected information is transmitted to the control unit 40.|[0087] The control unit 40 controls the flow rate adjustment valve 42 on the basis of the composition information transmitted from the composition detection unit 44 to adjust the amount of air electrode off-gas branching into the branch air electrode off-gas pipe P6-2, and controls the temperature of the cooling water supplied to the cooling water circulation flow path 26 A by the heat input type absorption chiller 36. Specifically, in the control unit 40, the following flow rate adjustment processing and coolant temperature adjustment processing are executed.|[0088] As illustrated in Fig. 3, in the flow rate regulating process, in step S10, it is determined whether the concentration of the combustible gas is within a threshold value G1 in the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44. Wherein the threshold value G1 is a sufficiently low concentration in the carbon dioxide rich gas 0.1 Approximately 5vol% to 5vol%, and a ratio of 0.1 to 1vol%. If the concentration of the combustible gas is higher than the threshold value G1, the flow rate regulating valve 42 is controlled in step S12 to increase the flow rate of the branching air electrode off-gas to the branching air electrode off-gas pipe P6-2. As a result, the amount of oxygen passing through the oxygen permeable membrane 23 and moving to the combustion space 22 A increases, and the amount of combustible gas contained in the carbon dioxide-rich gas can be reduced by causing a combustion reaction in the combustion space 22 A.|[0089] In step S10, when the concentration of the combustible gas is equal to or less than the threshold G1, in step S14, it is determined whether the concentration of oxygen is within the threshold O1 in the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44. Wherein the threshold value O1 is a sufficiently low concentration in the carbon dioxide rich gas 0.1 Approximately 5vol% to 5vol%, and a ratio of 0.1 to 1vol%. When the oxygen concentration is higher than the threshold value O1, the flow rate adjustment valve 42 is controlled in step S16 to decrease the flow rate of the air electrode off-gas branching into the branch air electrode off-gas pipe P6-2. As a result, the amount of oxygen passing through the oxygen permeable membrane 23 and moving to the combustion space 22 A is reduced, and it is possible to reduce the amount of oxygen remaining unsupplied to a combustion reaction in the combustion space 22 A.|[0090] After steps S12, S14, and S16, the process returns to step S10, and the above-described process is repeated. This flow rate adjustment process starts when the fuel cell power generation system 10 A starts operation, continues during operation, and ends when the fuel cell power generation system 10 A stops operation.|[0091] Further, as illustrated in Fig. 4, in the condensation amount adjustment processing, in step S20, it is determined whether the concentration of water vapor is within a threshold value M in the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44. Wherein the threshold value M is a sufficiently low concentration in the carbon dioxide rich gas 0.1 Approximately 5vol% to 5vol%, and a ratio of 0.1 to 1vol%. When the concentration of water vapor is higher than the threshold M, condensation fortification is performed in step S22. Specifically, the exhaust heat input type absorption chiller 36 is controlled to decrease the temperature of the cooling water supplied to the cooling water circulation flow path 26 A and increase the circulation flow rate of the cooling water. This increases the amount of water separated from the combustion off-gas by condensation in the condenser 26, making it possible to reduce the proportion of water vapor contained in the carbon dioxide-rich gas.|[0092] After steps S20 and S22, the process returns to step S20, and the above-described process is repeated. This condensation amount adjustment process starts when the operation of the fuel cell power generation system 10 A starts, continues during operation, and ends when the operation stops.|[0093] The water electrolyzer 70 electrolyzes the water fed from the water purifier 82 to produce hydrogen gas and oxygen gas. The carbon dioxide rich gas sent to the carbon dioxide gas pipe P10 is sent to the powdered carbon generator 78. In the carbon fixing unit 78 B, carbon dioxide gas fed from the condenser 26 and hydrogen gas fed from the water electrolyzer 70 are supplied to cause a reduction reaction such as that expressed by the following Formula (6). CO2+ 2H2 C+ 2H2O... (6)|[0094] In order to initiate the reaction described above, it is necessary to increase the ambient temperature, but since heat is generated by the reaction, it is not necessary to apply heat from the outside once the reaction is initiated. When starting up the powdered carbon generator 78, first, hydrogen gas and oxygen gas are supplied to the gas-flow passages 78 A to ignite the powdered carbon generator 78. After ignition, if heat is generated by a reaction of formula (6), the supply of oxygen gas and hydrogen gas is stopped.|[0095] In the carbon fixing unit 78 B, powdered carbon ((6) "C" in Formula formula) can be continuously produced by continuously feeding carbon dioxide gas and hydrogen gas. The produced powdered carbon can be removed from below the carbon fixing section 78 B. In addition, water vapor ((6) expressed by the formula H2O) produced by a reaction between carbon dioxide gas and hydrogen gas is discharged from below the carbon fixing section 78 B. Note that the water vapor discharged from the carbon fixing unit 78 B is supplied to the condenser 26 via the piping P17, cooled by the condenser 26, and turned into water.|[0096] In the fuel cell power generation system 10 A of the present embodiment, the first fuel cell stack 12 and the second fuel cell stack 14 are continuously connected and provided on-site, making it possible to efficiently manufacture powdered carbon continuously during power generation. Unless the powdered carbon is ignited and combusted, it is not released into the atmosphere as carbon dioxide gas, and it is possible to suppress the release of carbon dioxide gas to the atmosphere. In addition, the powdered carbon is also easy to transport to the storage sites, and unless placed under conditions where the ignition source and oxygen are aligned, long-term stable carbon immobilization is possible simply by landfill disposal underground or simply by being loaded on the ground. Note that the produced powdered carbon can also be used commercially as carbon black or the like.|[0097] In the fuel cell power generation system 10 A of the present embodiment, powdered carbon is produced from carbon dioxide gas, but a carbon product manufacturing device 84 in which the powdered carbon is graphite, carbon nanotubes, diamond, or the like may be further added. In the carbon product manufacturing device 84, synthetic diamond powder can be obtained by a known technique by placing the recovered powdered carbon in a high-temperature (electric heater temperature elevation) and high-pressure (electric high-pressure pressing) environment using power generated by the fuel cell power generation system 10 A, power generated by renewable energy, or the like, for example. In addition, for example, carbon nanotubes can be obtained from the recovered powdered carbon by publicly known techniques such as arc discharge methods, laser ablation methods, and CVD methods using power generated by the fuel cell power generation system 10 A, power generated by renewable energy, or the like. Furthermore, graphite can be obtained from the recovered powdered carbon using power generated by the fuel cell power generation system 10 A, power generated by renewable energy, or the like by a known technique. By using graphite, carbon nanotubes, or diamond powder as the carbon powder, combustion does not easily occur even if there is an ignition source or oxygen, and the carbon can be safely and stably fixed for a long period of time even if stacked on the ground, there is no restriction on the storage location, and energy loss and cost of transportation or press-fitting can be reduced. Graphite can also be used as pencil leads or brake pads for automobiles, carbon nanotubes can be used as semiconductors or structural materials, and synthetic diamond powders can be used as blades of diamond cutters for construction and machine tools. Note that the carbon product manufacturing device 84 is also a part of the carbon manufacturing unit 66 and is provided on-site in the fuel cell power generation system 10 A. In addition, products produced using powdered carbon are not limited to the carbon products described above, and carbon materials such as carbon nanohorns and fullerenes may be produced by a known technique and used in the commercial industry.|[0098] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, the second fuel electrode off-gas sent out from the second fuel electrode 14 A of the second fuel cell stack 14 is combusted by the combustor 22, so that The amount of unreacted fuel gas supplied for power generation in the second fuel cell stack 14 is increased compared to the case where the first fuel electrode off-gas before power generation in the second fuel cell stack 14 is combusted. Accordingly, it is possible to increase the power generation efficiency of the second fuel cell stack 14.|[0099] Furthermore, in the combustor 22, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to recover a high concentration of carbon dioxide by subtracting the combustible gas from the second fuel electrode off-gas. In addition, only oxygen in the air electrode off-gas is supplied to the combustor 22, and the second fuel electrode off-gas contains less unreacted fuel gas and has a higher carbon dioxide content than the first fuel electrode off-gas. Accordingly, the amount of unreacted fuel gas burned in the combustor 22 and the amount of oxygen required to burn the unreacted fuel gas can be reduced.|[0100] In addition, the fuel cell power generation system 10 A of the present embodiment includes the branch air electrode off-gas pipe 14-2 that branches from the air electrode off-gas pipe P6, making it possible to easily adjust the air electrode off-gas flow rate branching into the branch air electrode off-gas pipe 14-2 on the basis of the composition information of the carbon dioxide rich gas detected by the composition detection unit 44. As a result, the amount of oxygen flowing into the combustion space 22 A of the combustor 22 can be adjusted so that the amount of combustible gas and oxygen contained in the combustion off-gas is lower than a predetermined threshold.|[0101] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, the carbon dioxide concentration of the carbon dioxide-rich gas can be increased by adjusting the amount of water condensed by the condenser 26 on the basis of the composition information of the carbon dioxide-rich gas detected by the composition detection unit 44.|[0102] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, hydrogen ion conductive solid oxide fuel cells are used for the fuel cell stack, so water vapor is not generated at the first fuel electrode 12 A. Therefore, the amount of water vapor contained in the first fuel electrode off-gas is reduced, making it possible to improve the power generation efficiency of the second fuel cell. In addition, the amount of water vapor contained in the second fuel electrode off-gas is also reduced, making it possible to reduce the amount of water vapor removed from the second fuel electrode off-gas.|[0103] Furthermore, the fuel cell power generation system 10 A of the present embodiment includes a circulating gas pipe P3 that supplies a portion of the second fuel electrode off-gas to the first fuel electrode 12 A from the upstream side of the combustor 22. Accordingly, some of the unreacted fuel gas and steam in the second fuel electrode off-gas can be reused for power generation and steam reforming of the fuel gas, respectively.|[0104] Furthermore, in the fuel cell power generation system 10 A of the present embodiment, disposing the combustion part 22 adjacent to the oxygen permeable membrane 23 of the oxygen separation part 24 makes it possible to configure a compact combustor 20 with an oxygen permeable membrane integrally formed with the combustion part 22 and the oxygen separation part 24.|[0105] Also, in the fuel cell power generation system 10 A of the present embodiment, the heat of the air electrode off-gas is used for cold generation in the heat input type absorption chiller 36, making it possible to effectively utilize the exhaust heat from the first fuel cell stack 12 and the second fuel cell stack 14. In addition, since the air electrode off-gas contains a large amount of water vapor, the heat of condensation can also be effectively used due to the water vapor condensing in the heat input type absorption chiller 36 during heat exchange.|[0106] Note that in the present embodiment, the carbon dioxide is separated from the combustion off-gas by condensing and removing water vapor in the combustion off-gas by the condenser 26, but the carbon dioxide may be separated by other means such as a carbon dioxide separation membrane, or the carbon dioxide may be separated by a PSA apparatus.|[0107] [Second Embodiment] Next, a second embodiment of the present invention will be described. In the present embodiment, the same components as those in the first embodiment are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0108] As illustrated in Fig. 5, a fuel cell power generation system 10 B of the present embodiment is provided with a high-temperature oxygen manufacturing device 50 and a combustor 52 in place of the combustor 20 with an oxygen permeable membrane of the first embodiment. Configurations other than the high-temperature oxygen manufacturing device 50 and the combustor 52 are the same as those of the first embodiment.|[0109] The downstream end of a branch air electrode off-gas pipe P6-2 is connected to the inlet side of the high-temperature oxygen manufacturing device 50. The high-temperature oxygen producing device 50 is a device that separates oxygen from the air electrode off-gas, and as an example, a high-temperature device that adsorbs and desorbs at high temperatures (an operating temperature of 600 to 900 °C, for example) PSA can be used. A first end of an oxygen supply pipe PO is connected to an oxygen outlet side of the high-temperature oxygen manufacturing device 50. An exhaust pipe P13 is connected to the air electrode off-gas outlet side of the high-temperature oxygen manufacturing device 50 after the oxygen has been separated. The other end of the oxygen supply pipe PO is connected to the inlet side of the combustor 52. The exhaust pipe P13 opens to the outside of the fuel cell power generation system 10 B. Note that the high-temperature oxygen producing device 50 can efficiently produce oxygen using high-temperature air electrode off-gas. Additionally, the high-temperature oxygen manufacturing device 50 can be driven by direct current electrical power generated by the first fuel cell stack 12 and the second fuel cell stack 14.|[0110] The other end of the oxygen supply pipe PO and the downstream end of the second fuel electrode off-gas pipe P7-2 are connected to the inlet side of the combustor 52. Inside the combustor 52, a combustion reaction occurs between the combustible gas component (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas and oxygen supplied from the oxygen supply pipe PO, and carbon dioxide and steam are generated. A combustion off-gas pipe P8 is connected to an outlet side of the combustor 52, and combustion off-gas is fed from the combustor 52.|[0111] Next, the operation of the fuel cell power generation system 10 B of the present embodiment will be described.|[0112] In the present embodiment as well, power is generated by the first fuel cell stack 12 and the second fuel cell stack 14 in the same manner as in the fuel cell power generation system 10 A of the first embodiment. The second air electrode off-gas sent out from the second air electrode 14 B and branched to the branched air electrode off-gas pipe P6-2 is supplied to the high-temperature oxygen manufacturing device 50. In the high-temperature oxygen manufacturing device 50, oxygen is separated from the second air electrode off-gas, and the separated oxygen is supplied to the combustor 52 via the oxygen supply pipe PO. The air electrode off-gas from which oxygen has been separated is discharged from the exhaust pipe P13 to the outside.|[0113] In the combustor 52, a combustion reaction occurs between oxygen and combustible gas components (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas, and carbon dioxide and steam are generated. The combustion off-gas is sent to the combustion off-gas pipe P8, where water is separated in the condenser 26 in the same manner as in the first embodiment, the separated water is collected in the water tank 27, and the carbon dioxide rich gas is supplied to the carbon manufacturing unit 66.|[0114] In the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0115] [Third Embodiment] Next, a third embodiment of the present invention will be described. In the present embodiment, components that are the same as those in the first and second embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0116] The fuel cell power generation system 10 C of the present embodiment differs from the first embodiment in that the reformer 54 is mainly provided, the circulating gas pipe P3 is not provided, and the piping flow path associated with these configurations is not provided. The rest of the configuration is the same as that of the first embodiment.|[0117] As illustrated in Fig. 6, a fuel cell power generation system 10 C includes a reformer 54. A first end of a fuel gas pipe P1-1 is connected to an inlet side of the reformer 54. Furthermore, one end of a water supply pipe P2-2 is connected to the inlet side of the reformer 54. The other end of the water supply pipe P2-2 is connected to the water tank 27. The water supply pipe P2-2 is provided with an ion exchange resin 56 and a pump 27 B. By driving the pump 27 B, the water stored in the water tank 27 is supplied to the reformer 54 via the ion exchange resin 56.|[0118] A first end of a reformed gas pipe P1-2 is connected to an outlet side of the reformer 54. The other end of the reformed gas pipe P1-2 is connected to the first fuel electrode 12 A of the first fuel cell stack 12.|[0119] Next, the operation of the fuel cell power generation system 10 C of the present embodiment will be described.|[0120] In the reformer 54, the mixed gas of the fuel gas and the steam is heated by heat exchange with the combustion off-gas, and hydrogen and carbon monoxide are produced by a steam reforming reaction. Furthermore, carbon dioxide and hydrogen are generated by a shift reaction between the generated carbon monoxide and water vapor. Reformed gas containing unreacted fuel gas (methane), hydrogen, carbon monoxide, and carbon dioxide is supplied to the first fuel electrode 12 A through the reformed gas pipe P1-2. The first fuel cell stack 12 and the second fuel cell stack 14 generate power in the same manner as in the first embodiment.|[0121] The second fuel electrode off-gas is fed from the second fuel electrode 14 A to the second fuel electrode off-gas pipe P7-2. The second fuel electrode off-gas is supplied to the combustor 22 of the combustor with oxygen permeable membrane 20 without being branched. The air electrode off-gas is sent from the second air electrode 14 B to the air electrode off-gas pipe P6. as in the first embodiment, a portion of the air electrode off-gas is branched to the branched air electrode off-gas pipe 10-2, and the rest of the air electrode off-gas is merged with the air electrode off-gas sent from the first air electrode 12 B.|[0122] In the combustor 20 with an oxygen permeable membrane and the condenser 26, processing is performed in the same manner as in the first embodiment, and the carbon dioxide rich gas is supplied to the carbon manufacturing section 66.|[0123] In the present embodiment as well, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas in the combustor 20 provided with an oxygen permeable membrane. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0124] [Fourth Embodiment] Next, a fourth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to third embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0125] The fuel cell power generation system 10 D of the present embodiment is provided with the high-temperature oxygen manufacturing device 50 and the combustor 52 of the second embodiment in place of the combustor 20 with an oxygen permeable membrane of the third embodiment. Configurations other than the high-temperature oxygen manufacturing device 50 and the combustor 52 are the same as those of the third embodiment.|[0126] As illustrated in Fig. 7, the downstream end of a branch air electrode off-gas pipe P6-2 is connected to the inlet side of the high-temperature oxygen manufacturing device 50, and one end of an oxygen supply pipe PO is connected to the oxygen outlet side of the high-temperature oxygen manufacturing device 50. An exhaust pipe P13 is connected to the air electrode off-gas outlet side of the high-temperature oxygen manufacturing device 50 after the oxygen has been separated. The other end of the oxygen supply pipe PO is connected to the inlet side of the combustor 52. The exhaust pipe P13 opens to the outside of the fuel cell power generation system 10 D.|[0127] The other end of the oxygen supply pipe PO and the downstream end of the second fuel electrode off-gas pipe P7-2 are connected to the inlet side of the combustor 52. Inside the combustor 52, a combustion reaction occurs between the combustible gas component (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas and oxygen supplied from the oxygen supply pipe PO, and carbon dioxide and steam are generated. A combustion off-gas pipe P8 is connected to an outlet side of the combustor 52, and combustion off-gas is fed from the combustor 52.|[0128] Next, the operation of the fuel cell power generation system 10 D of the present embodiment will be described.|[0129] In the present embodiment, as with the fuel cell power generation system 10 C of the third embodiment, reformed gas is generated by steam-reforming the fuel gas in the reformer 54, and power is generated in the first fuel cell stack 12 and the second fuel cell stack 14. The second air electrode off-gas sent out from the second air electrode 14 B and branched to the branched air electrode off-gas pipe P6-2 is supplied to the high-temperature oxygen manufacturing device 50. In the high-temperature oxygen manufacturing device 50, oxygen is separated from the second air electrode off-gas, and the separated oxygen is supplied to the combustor 52 via the oxygen supply pipe PO. The air electrode off-gas from which oxygen has been separated is discharged from the exhaust pipe P13 to the outside.|[0130] In the combustor 52, a combustion reaction occurs between oxygen and combustible gas components (unreacted methane, unreacted hydrogen, unreacted carbon monoxide, and the like) in the second fuel electrode off-gas, and carbon dioxide and steam are generated. The combustion off-gas is sent to the combustion off-gas pipe P8, where water is separated in the condenser 26 in the same manner as in the first embodiment, the separated water is collected in the water tank 27, and the carbon dioxide rich gas is supplied to the carbon manufacturing unit 66.|[0131] In the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0132] [Fifth Embodiment] Next, a fifth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to fourth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0133] A fuel cell power generation system 10 E of the present embodiment differs from the first embodiment in that a third heat exchanger 34 and a condenser 35 are provided in the path of the first fuel electrode off-gas pipe P7.|[0134] As illustrated in Fig. 8, the first fuel electrode off-gas pipe P7 extends from the first fuel electrode 12 A and is connected to the condenser 35 via the third heat exchanger 34. The first fuel electrode off-gas pipe P7 extending from the first fuel electrode 12 A to the condenser 35 is denoted by reference numeral P7A. The first fuel electrode off-gas pipe P7A extends from a gas-side outlet of the condenser 35 and is connected to the second fuel electrode 14 A via the third heat exchanger 34. The first fuel electrode off-gas pipe P7 extending from the condenser 35 to the second fuel electrode 14 A is denoted by reference numeral P7B. One end of a water pipe P9-2 is connected to a liquid-side outlet of the condenser 35. The other end of the water pipe P9-2 is connected to the water tank 27. A coolant circulation channel 35 A is piping in the condenser 35, and coolant from the exhaust heat input type absorption chiller 36 is circulated and supplied by driving a pump 35 P. As a result, the first fuel electrode off-gas is cooled and the water vapor in the first fuel electrode off-gas is condensed. The condensed water is sent to the water tank 27 via the water pipe P9-2.|[0135] Next, the operation of the fuel cell power generation system 10 E of the present embodiment will be described.|[0136] In the present embodiment as well, power is generated in the first fuel cell stack 12 in the same manner as in the fuel cell power generation system 10 A of the first embodiment. The first fuel electrode off-gas sent from the first fuel electrode 12 A to the first fuel electrode off-gas pipe P7-1 is cooled by heat exchange with regenerated fuel gas (described later) in the third heat exchanger 34, and is supplied to the condenser 35. In the condenser 35, the first fuel electrode off-gas is further cooled by the cooling water circulating through the cooling water circulation flow path 35 A, and the water vapor in the first fuel electrode off-gas is condensed. Here, the temperature of the cooling water circulating through the cooling water circulation flow path 35 A is set so that the water vapor in the first fuel electrode off-gas condenses to such an extent that the amount of water vapor remaining in the regenerated fuel gas improves the power generation efficiency in the second fuel cell stack 14. The condensed water is sent to the water tank 27 via the water pipe P9-2.|[0137] The first fuel electrode off-gas from which condensed water has been separated is sent to the first fuel electrode off-gas pipe P7B as regenerated fuel gas, heated by heat exchange with the first fuel electrode off-gas before water has been separated by the third heat exchanger 34, and supplied to the second fuel electrode 14 A. The second fuel cell stack 14 generates power in the same manner as in the fuel cell power generation system 10 A of the first embodiment.|[0138] In the present embodiment, regenerated fuel gas generated by separating a portion of water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0139] Additionally, in the present embodiment too, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas in the combustion section 22 of the combustor 20 with an oxygen permeable membrane. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0140] [Sixth Embodiment] Next, a sixth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to fifth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0141] As illustrated in Fig. 9, in a fuel cell power generation system 10 F of the present embodiment, the first fuel cell stack 62 and the second fuel cell stack 64 use a solid oxide fuel cell (SOFC: Solid Oxide Fuel Cell) instead of the hydrogen ion conductive solid oxide fuel cell of the first embodiment. Accordingly, reactions occur in the first fuel electrode 62 A (fuel electrode) and the first air electrode 62 B (air electrode) as follows. Note that the same applies to the second fuel electrode 64 A and the second air electrode 64 B.|[0142] In the first air electrode 62 B, oxygen ions are generated as a result of a reaction between oxygen and electrons in the oxidizer gas, as expressed in Formula (5) below. The generated oxygen ions pass through the electrolyte layer 62 C and reach the first fuel electrode 62 A of the first fuel cell stack 62.|[0143] (Air electrode reaction) 1/2O2+ 2 e- O2-... (5)|[0144] On the other hand, in the first fuel electrode 62 A of the first fuel cell stack 62, oxygen ions that have passed through the electrolyte layer 62 C react with hydrogen and carbon monoxide in the fuel gas, and water vapor, carbon dioxide, and electrons are generated, as shown in Formulas (6) and (7) below. Electrons generated by the first fuel electrode 62 A move from the first fuel electrode 62 A to the first air electrode 62 B through an external circuit, so that power is generated.|[0145] (Fuel electrode reaction) H2+ O2- H2O+ 2 e-... (6) CO+ O2- CO2+ 2 e-... (7)|[0146] In the solid oxide fuel cell, since water vapor is generated by the first fuel electrode 62 A and the second fuel electrode 64 A, the amount of water vapor contained in the first fuel electrode off-gas and the second fuel electrode off-gas is greater than in the hydrogen ion conductive solid oxide fuel cell. On the other hand, water vapor is not generated in the first air electrode 62 B and the second air electrode 64 B. The air electrode off-gas supplied to the exhaust heat input type absorption chiller 36 is exhausted from the exhaust pipe P36-1 after heat exchange.|[0147] The other configurations of the fuel cell power generation system 10 F of the present embodiment are the same as those of the fifth embodiment, and a third heat exchanger 34 and a condenser 35 are provided in the path of the first fuel electrode off-gas pipe P7. Here, since the amounts of water vapor contained in the first fuel electrode off-gas and the second fuel electrode off-gas are greater than in the fuel cell power generation system 10 E, the temperature of the cooling water circulating through the cooling water circulation flow path 35 A is set so as to increase the amount of water vapor removed by condensation in the condenser 35. The condensed water is sent to the water tank 27 via the water pipe P9-2.|[0148] In the present embodiment, regenerated fuel gas generated by separating a portion of water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0149] Additionally, in the present embodiment too, carbon dioxide and steam are generated by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas in the combustion section 22 of the combustor 20 with an oxygen permeable membrane. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0150] [Seventh Embodiment] Next, a seventh embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to sixth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0151] As illustrated in Fig. 10, a fuel cell power generation system 10 G of the present embodiment is provided with the same high-temperature oxygen producing device 50 and combustor 52 as those of the second embodiment instead of the combustor 20 with an oxygen permeable membrane of the sixth embodiment. Configurations other than the high-temperature oxygen manufacturing device 50, the combustor 52, and piping associated therewith are the same as those of the sixth embodiment.|[0152] In the present embodiment as well, the regenerated fuel gas generated by separating a portion of the water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0153] Additionally, in the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0154] [Eighth Embodiment] Next, an eighth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to seventh embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0155] As illustrated in Fig. 11, a fuel cell power generation system 10 H of the present embodiment differs from that of the sixth embodiment in that a reformer 54 is provided, a recirculating gas pipe P3 is not provided, and piping flow paths related to these configurations are different from those of the sixth embodiment. The rest of the configuration is the same as that of the sixth embodiment.|[0156] In the present embodiment as well, the regenerated fuel gas generated by separating a portion of the water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0157] Additionally, in the present embodiment as well, carbon dioxide and steam are generated in the combustor 22 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0158] [Ninth Embodiment] Next, a ninth embodiment of the present invention will be described. In the present embodiment, the same components as those in the first to eighth embodiments are denoted by the same reference signs, and detailed descriptions thereof are omitted.|[0159] As illustrated in Fig. 11, a fuel cell power generation system 10 I of the present embodiment is provided with a high-temperature oxygen producing device 50 and a combustor 52 of a seventh embodiment in place of the combustor 20 with an oxygen permeable membrane of the eighth embodiment. Configurations other than the high-temperature oxygen manufacturing device 50 and the combustor 52 are the same as those of the eighth embodiment.|[0160] In the present embodiment as well, the regenerated fuel gas generated by separating a portion of the water vapor from the first fuel electrode off-gas is supplied to the second fuel electrode 14 A, making it possible to improve the power generation efficiency of the second fuel cell stack 14.|[0161] Additionally, in the present embodiment as well, carbon dioxide and steam are generated in the combustor 52 by a combustion reaction between oxygen and the combustible gas contained in the second fuel electrode off-gas. Therefore, it is possible to reduce the combustible gas from the second fuel electrode off-gas, recover a high concentration of carbon dioxide, and efficiently obtain powdered carbon.|[0162] [Other embodiments] a first embodiment of the carbon recovery fuel cell power generation system of the present invention has been described above, but the present invention is not limited to the first embodiment and, of course, various modifications may be made without departing from the gist of the present invention.|[0163] Other fuel cells, such as a molten carbonate fuel cell (MCFC), a phosphoric acid fuel cell (PAFC), and a solid polymer fuel cell (PEFC), can also be used as the fuel cell of the present invention.|[0164] Note that, in the first to ninth embodiments described above, the exhaust heat input type absorption chiller 36 is used to generate cold, but instead of the exhaust heat input type absorption chiller 36, a heat pump that utilizes another exhaust heat, such as an adsorption chiller, may be used to generate cold.|[0165] Furthermore, instead of the heat input type absorption chiller 36, the fuel cell power generation system 10 J may use an electric turbo chiller 60 that generates cold heat by using electric power without using exhaust heat. Fig. 13 illustrates, as an example, a fuel cell power generation system 10 A of the first embodiment in which the heat input absorption chiller 36 is replaced with an electric turbo chiller 60. The second to ninth embodiments may also be substituted in the same manner. In the fuel cell power generation system 10 J, the air electrode off-gas is discharged to the outside of the system after heat exchange in the second heat exchanger 32. The electric turbo chiller 60 can be driven by power generated by the fuel cell power generation system 10 J. The electric turbo chiller 60 generally has high cooling efficiency, making it possible to operate the fuel cell power generation system 10 J with high efficiency even when generated electrical power is used. Note that in this case as well, in order to efficiently utilize the generated electrical power without converting it to alternating current, the electric turbo chiller 60 is preferably driven by direct current.|REFERENCE SIGNS LIST|[0166] 10 A to 10 J fuel cell power generation system (carbon recovery fuel cell power generation system) 12; 62 first fuel cell stack (first fuel cell) 12 A; 62 A first fuel electrode 12 B; 62 B first air electrode 14; 64 Second fuel cell stack (second fuel cell) 14 A, 64 A second fuel electrode 14 B, 64 B second air electrode 20 combustor with oxygen permeable membrane 22 combustion section, 22 A combustion space 23 oxygen permeable membrane, 24 Oxygen separation unit 26 condenser (carbon dioxide separation unit) 35 condenser (fuel regeneration unit) 36 exhaust heat input type absorption chiller 50 high temperature oxygen production apparatus (oxygen separation unit) 52 combustor (combustor), 54 reformer; 70 Water electrolyzer 78 powdered carbon generator (carbon generating unit) 84 carbon product manufacturing apparatus P3 Circulation gas pipe (circulation flow path) P6 air electrode off-gas pipe (air electrode off-gas flow path) P6-2 branched air electrode off-gas pipe (branched air electrode off-gas flow path) P7 second fuel electrode off-gas pipe (second fuel electrode off-gas flow path) | Family Number|(87784557)|87784557|Advantages / Prev. Drawbacks|(JP6692394 B2)|Furthermore, for CCS and BECCS, the locations where carbon dioxide gas can be injected and stored are limited (for example, because there are few oil and gas fields suitable for EOR and EGS in Japan, liquefied carbon dioxide is transported to an overseas storage site such (...) |(JP2020030892 A)|Furthermore, for CCS and BECCS, the locations where carbon dioxide gas can be injected and stored are limited (for example, because there are few oil and gas fields suitable for EOR and EGS in Japan, liquefied carbon dioxide is transported to an overseas storage site such (...) | | Electrical machinery, apparatus, energy | Y02E-060/50 | Y02E-060/50 | H01M-008/00|H01M-008/02|H01M-008/04|H01M-008/06|H01M-008/0656|H01M-008/0662|H01M-008/0668|H01M-008/12|H01M-008/1246|H01M-008/249 | H01M-008/00|H01M-008/02|H01M-008/04|H01M-008/06|H01M-008/0656|H01M-008/0662|H01M-008/0668|H01M-008/10|H01M-008/12|H01M-008/1246|H01M-008/249 | 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intermediate code: R250 | (JP6692394)|JP | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=8JgsxTHjV4KjY3X2pLxhTDeISh8T7V+NNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=JP6692394&ekey=985&xpn=JP6692394&kind=B2 | https://www.j-platpat.inpit.go.jp/c1801/PU/JP-2018-153857/10/en | https://permalink.orbit.com/RenderStaticFirstPage?XPN=9Wp%252BklBTJ5%252F4%252BC%252F5M6pym3fDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | JP | (JP6692394)|NAME=TAIYO, NAKAJIMA & KATO , REG=110001519|(JP2020030892)|NAME=TAIYO, NAKAJIMA & KATO , REG=110001519 | (JP6692394)|NAME=KAWABATA, Yasuharu|NAME=MATSUZAKI, Yoshio|(JP2020030892)|NAME=KAWABATA YASUHARU|NAME=MATSUZAKI YOSHIO | (JP6692394)|12 | 1 | 1 | (JP6692394)|Number of Claims: NCL=10|Form: FORM=OL|Number of Pages: NPAGES=27|Request for examination: REQEXA=true||(JP2020030892)|Number of Claims: NCL=10|Number of Figures: NFG=1|Form: FORM=OL|Number of Pages: NPAGES=27|Request for examination: REQEXA=true| | (JP6692394)|JAPANESE (JPN) | (JP6692394)|Patent|(JP2020030892)|Patent | Titre: (JP6692394)|Carbon Recovery Fuel Cell Power Generation System Résumé: (JP6692394)|PROBLEM TO BE SOLVED: To provide a carbon recovery type fuel battery power generation system capable of greatly simplifying a transport and fixation process for high efficiency by inhibiting discharge of carbon dioxide gas by converting carbon dioxide generated due to power generation of a fuel battery to carbon.SOLUTION: A fuel battery power generation system 10 includes: a first fuel battery cell stack 12 and a second fuel battery cell stack 14 that generate power using fuel gas containing a carbon compound and supplied to a fuel electrode and oxidant gas containing oxygen and supplied to an air electrode and discharge off-gas; a condenser 26 for separating carbon dioxide gas from the off-gas; a water electrolysis device 70 for performing electrolysis on water to generate hydrogen gas; and a powder carbon generator 78 for making the carbon dioxide gas from the condenser 26 react with the hydrogen gas from the water electrolysis device 70 on a catalyst to generate carbon.SELECTED DRAWING: Figure 1COPYRIGHT: (C)2020,JPO&INPIT Autre: (JP6692394)|1. A fuel cell that generates power using fuel gas containing a carbon compound and supplied to a fuel electrode and oxidant gas containing oxygen and supplied to an air electrode, and discharges off-gas; a carbon dioxide gas separation unit that separates carbon dioxide gas from the off-gas; A water electrolyzer that electrolyzes water to generate hydrogen gas; and a water electrolyzer that electrolyzes the carbon dioxide gas from the carbon dioxide gas separation unit and the hydrogen gas from the water electrolyzer.SingleOn catalystAndA carbon generating part that generates carbon and steam.|2. The carbon recovery fuel cell power generation system according to claim 1, wherein the water electrolyzer electrolyzes the water using at least one of electrical power generated by a renewable energy power generator and electrical power generated by the fuel cell.|3. The carbon recovery type fuel cell power generation system according to claim 1 or 2, wherein the carbon dioxide gas separation unit separates the carbon dioxide gas and water from the off-gas, and the water electrolyzer uses the water separated by the carbon dioxide gas separation unit.|4. A power generation system comprising: a first fuel cell that generates power by fuel gas containing a carbon compound and supplied to a first fuel electrode and oxidant gas containing oxygen and supplied to a first air electrode, and sends out first fuel electrode off-gas from the first fuel electrode to first fuel electrode off-gas channels; and a power generation system that generates power by using the first fuel electrode off-gas supplied to a second fuel electrode and oxidant gas supplied to a second air electrode, A second fuel cell that delivers second fuel electrode off-gas from the second fuel electrode to second fuel electrode off-gas flow paths; an air electrode off-gas flow path that delivers air electrode off-gas from at least one of the first air electrode and the second air electrode; and An oxygen separation unit connected to the air electrode off-gas flow path and supplied with the air electrode off-gas, the oxygen separation unit separating oxygen from the air electrode off-gas; a combustion unit supplied with the second fuel electrode off-gas and supplied with the oxygen separated by the oxygen separation unit, the combustion unit causing the second fuel electrode off-gas to undergo a combustion reaction with the oxygen; An exhaust heat input type absorption chiller or an adsorption chiller that uses the off-gas as a heat source to cool water and generate cooling water, wherein the carbon dioxide gas separation unit separates carbon dioxide gas and water by cooling combustion off-gas sent from the combustion unit with the cooling water.|5. The carbon recovery type fuel cell power generation system according to claim 4, wherein the first fuel cell and the second fuel cell are hydrogen ion conductive solid oxide fuel cells.|6. A supply unit that supplies the water separated by the carbon dioxide gas separation unit to a cooling water path of the exhaust heat input type absorption chiller, a cooling water replenishing path of a cooling tower constituting the exhaust heat input type absorption chiller, or a cooling water path of the adsorption chiller or a cooling water replenishing path of a cooling tower constituting the adsorption chiller; The cooling water of the exhaust heat input type absorption chiller, a portion of cooling water supplemental water of a cooling tower constituting the exhaust heat input type absorption chiller, or the cooling water of the adsorption chiller or a portion of cooling water supplemental water of a cooling tower constituting the adsorption chiller; The carbon recovery fuel cell power generation system according to claim 4 or 5, wherein the water separated by the carbon dioxide gas separation unit is used.|7. The carbon recovery fuel cell power generation system according to any one of claims 4 to 6, wherein the oxygen separation part comprises an oxygen permeable membrane that selectively permeates oxygen, and the combustion part is integrated with the oxygen separation part with a combustion space disposed on a permeation side of the oxygen permeable membrane.|8. The carbon recovery fuel cell power generation system according to any one of claims 4 to 6, wherein the oxygen separation unit comprises a high-temperature PSA device that can be driven by power generated by the first fuel cell and the second fuel cell.|9. The carbon recovery fuel cell power generation system according to any one of claims 1 to 8, wherein the carbon dioxide gas separation unit cools the off-gas to generate the carbon dioxide gas and water, and the steam generated by the carbon generation unit is supplied to the carbon dioxide gas separation unit via a supply path.|10. The carbon recovery fuel cell power generation system according to any one of claims 1 to 9, further comprising a carbon product manufacturing apparatus in which the carbon produced by the carbon producing unit is graphite, carbon nanotubes, or diamond. | 28 | Abstract | gpt-4o-mini | no | The article focuses on a fuel cell system that converts CO₂ into carbon, without involving biomass for energy production or capturing CO₂ from biomass sources. | |||||||||||||||||||||
| 28 | GB202201121 | GB202201121 | GB2615109|GB202201121 | 99263641 | GB2615109 A 2023-08-02 [GB2615109]|GB202201121 D0 2022-03-16 [GB202201121] | 2022-01-28 | 2022-01-28 | 2023-08-02|2022-03-16 | (GB2615109)|2024-06-12 | (GB2615109)|Extraction device | (GB2615109)|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from exhaust flue gas, comprising a primary heat exchanger 10, which connects to a first heat exchanger 20, which cools the flue gas, and a storage tank 36, comprising a throttle valve 32 and a storage capacity. In some embodiments, there may be multiple heat exchangers, or gaseous nitrogen may be transferred from the storage tank for use in the heat exchanger. | PURIFIRE LABS | (GB2615109)|PuriFire Labs Limited|(GB202201121)|PuriFire Labs Limited | MATTHEW PEARCE|RAY MIDDLETON | (GB2615109)|Matthew Pearce|Ray Middleton | (GB2615109)|As such, the apparatus of the invention can advantageously be used to extract carbon dioxide from a range of sources, such as exhaust flue gases, such as from boilers, engines, and fossil fuel-fired power stations.|The apparatus and method of the invention advantageously provide a means for reducing the carbon dioxide emissions of energy generating devices.|The present invention solves the above-mentioned problems by providing an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas.|Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. Post combustion carbon capture and storage with amine scrubbing technologies in coal-fired power plants is a recent technology application, but even with subsidies it is expensive, typically costing between $80/tonne of carbon dioxide for first of a kind technologies and $60/tonne of carbon dioxide for next of a kind technology.| | (GB2615109)|1. An apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising:a) a primary heat exchanger for receiving and cooling the exhaust flue gas;b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; andc) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises:(i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and(ii) a holding tank for containing solid and/or liquid carbon dioxide.|17. A method for producing solid or liquid carbon dioxide from exhaust flue gas, the method comprising:a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas;b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondary heat exchanger; andc) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.| | (GB2615109)|The invention also provides a method for producing solid and/or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondary heat exchanger; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising: a) a primary heat exchanger for receiving and cooling the exhaust flue gas; b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and (ii) a holding tank for containing solid and/or liquid carbon dioxide.|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from exhaust flue gas. The invention also relates to methods for extracting solid or liquid carbon dioxide from exhaust flue gas.| | (GB2615109)|FLUE GAS(100,195)|CARBON DIOXIDE(100,112)|COOLED EXHAUST(100,51)|LIQUID CARBON DIOXIDE(100,26)|SOLID EXTRACTION(100,5)|SOLID PRODUCTION(100,3)|COLLECTION VESSEL(91,30)|PRIMARY COMPRESSOR(87,41)|COOLED EXHAUST FLUE GAS(85,51)|THROTTLING VALVE(73,24)|CARBON DIOXIDE COLLECTION VESSEL(70,30)|AMINE SCRUBBING(65,1)|FLUID COMMUNICATION(55,19)|SECONDARY HEAT EXCHANGER(52,66)|EXHAUST FLUE GAS(52,63)|PRIMARY HEAT EXCHANGER(50,77)|LABYRINTH CHAMBER(38,9)|POST COMBUSTION CARBON CAPTURE(38,1)|GAS BYPASS(32,14)|SUBSIDY(32,1)|BIOMASS(28,1)|HYDRAULIC PRESSING(23,4)|CARBON DIOXIDE EMISSION(21,8)|BECCS(21,2)|ENERGY GENERATION(21,2)|REMOVING GAS(21,1)|SEPARATED NITROGEN GAS(20,2)|CARBON DIOXIDE GAS REMOVAL(19,1)|COAL(18,2)|ELECTRICITY GENERATION(18,2)|FIRED POWER STATION(18,2)|EXCESS EXHAUST FLUE GAS(17,4)|EXOGENOUS COOLANT CONDUIT(17,2)|BOILER(16,8)|FOSSIL FUEL(16,6)|HEAT EXCHANGE CHILLER LABYRINTH(16,6)|UNIDIRECTIONAL FLOW(16,4)|HOLDING TANK(15,8)|COLD NITROGEN GAS(15,5)|COMPRESSION(15,5)|EXOGENOUS GASEOUS NITROGEN(14,3)|THROTTLING VALVE OUTLET(14,3)|EXHAUST FLUE EXIT(13,2)|EXHAUST COOLING(12,5)|DOWNWARD DIRECTIONAL TUBING(11,2)|EXHAUST FLUE MODIFICATION(11,2)|WASTEFUL DECOMMISSIONING(10,1)|COMPRESSED EXHAUST FLUE GAS(9,3)|COMPRESSED COOLED EXHAUST(9,2)|THROTTLING VALVE INLET(9,2)|VIRGIN FOSSIL FUEL(9,2)|ABATEMENT ALTERNATIVE SCENARIO(9,1)|ATMOSPHERIC GLOBAL EMISSION(9,1)|ELECTRICITY MWH(9,1)|GIGA TONNE(9,1)|NONHALOGENATED HYDROCARBON(9,1)|NONPOLLUTING RETROFITTED ALTERNATIVE(9,1)|OLD COAL FIRED ELECTRICITY(9,1)|UNMET INDUSTRIAL DEMAND(9,1)|TERTIARY HEAT EXCHANGER(8,4)|COAL FIRED POWER PLANT(8,2)|AMMONIA FERTILIZER(8,1)|EXPENSIVE DECOMMISSIONING(8,1)|MAJORITY CONTAMINANT(8,1)|NITROGEN GAS PUMPING(8,1)|PROPELLING EXHAUST(8,1)|SUSTAINABLE FUEL(8,1)|UREA FERTILIZER PRODUCTION(8,1)|PARTITIONED PARALLEL EXHAUST CHAMBER(7,3)|SHOCK HEAT(7,3)|COOLANT VALVE(7,2)|GENERATION PLANT(7,2)|ADIABATIC DROP(6,1)|COAL FUEL(6,1)|EXHAUST FLUE GAS PROPELLANT(6,1)|MAINTENANCE COMPRESSOR(6,1)|PERTINENT MARKET(6,1)|REVERSE SUBLIMATION(6,1)|THROTTLING VALVE CONTENT(6,1)|TRANSITIONARY PASSAGE(6,1)|TUBULAR CONE EXTENSION(6,1)|TUBULAR CONE ORIENTATION(6,1)|CARBON DIOXIDE ICE(5,4)|INITIATION(5,4)|COLD GASEOUS NITROGEN FLOW(5,3)|ALUMINUM(5,2)|CONTRIBUTION REDUCTION(5,2)|EVAPORATOR(5,2)|GASEOUS CARBON DIOXIDE(5,2)|PRIMARY COOLING(5,2)|URGENT NEED(5,2)|VOLUMETRIC SPACE(5,2)|CARBON DIOXIDE REMEDIATION(5,1)|CARBON DIOXIDE TONNE(5,1)|CONE TUBULAR DIAMETER(5,1)|HYDROCHLOROFLUOROCARBON(5,1)|HYDROFLUOROCARBON(5,1)|INTERCONNECTION(5,1)|INTERNAL ROTOR(5,1)|MANIFOLD HOUSING(5,1)|NETWORK ARRAY MATRIX(5,1)|NITROGEN GAS STORAGE VESSEL(5,1)|NITROGEN GAS TRANSFER CONDUIT(5,1)|OIL RESERVOIR DEPLETION(5,1)|PUMPING NITROGEN(5,1)|RETROCONVERSION(5,1)|SIMULTANEOUS DROP(5,1)|SUDDEN DROP(5,1)|TONNAGE(5,1)|TUBULAR APERTURE(5,1)|VENTING TUBE(5,1)|BIOENERGY(4,1)|BIOFUEL(4,1)|BRIDGING BAR(4,1)|BURIAL(4,1)|BYPASS(4,1)|CARBON DIOXIDE SNOW(4,1)|CHIMNEY DESIGN(4,1)|CIRCULATION(4,1)|EXTRACTED GASEOUS NITROGEN FLOW(4,1)|EXTRACTING CARBON DIOXIDE(4,1)|GAS COMPRESSOR ROTATION(4,1)|GAS VELOCITY(4,1)| | (GB2615109)|1. An apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising:|a) a primary heat exchanger for receiving and cooling the exhaust flue gas;|b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and|c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises:|(i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and|(ii) a holding tank for containing solid and/or liquid carbon dioxide.|2. The apparatus of claim 1 further comprising one or more secondary heat exchangers for receiving and cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|3. The apparatus of claim 1 or claim 2, wherein the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen, wherein the outlet is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers.|4. The apparatus of any preceding claim further comprising means for connecting in fluid communication the primary heat exchanger and the exhaust flue.|5. The apparatus of any preceding claim further comprising a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.|6. The apparatus of any preceding claim, wherein the primary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel.|7. The apparatus of claim 6, wherein the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas.|8. The apparatus of any of claims 2-7, wherein the secondary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel.|9. The apparatus of claim 8, wherein the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas.|10. The apparatus of any preceding claim further comprising an impeller for propelling the exhaust flue gas into the primary heat exchanger.|11. The apparatus of any preceding claim further comprising one or more impellers for propelling the compressed cooled exhaust flue gas into one or more of the one or more secondary heat exchangers.|12. The apparatus of any preceding claim further comprising a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor.|13. The apparatus of any preceding claim, wherein one or more of the one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor.|14. The apparatus of any preceding claim, wherein one or more of the one or more secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|15. The apparatus of any preceding claim, wherein: (a) one or more of the secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more of the secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|16. The apparatus of any preceding claim, wherein the apparatus comprises one or more valves for maintaining unidirectional flow of exhaust flue gas.|17. A method for producing solid or liquid carbon dioxide from exhaust flue gas, the method comprising:|a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas;|b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondary heat exchanger; and|c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|18. The method of claim 17, wherein the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger.|19. The method of claim 17 or claim 18, wherein the cooling comprises reducing the temperature of the gas to less than -10°C.|20. The method of any of claims 17-19, wherein the compressing comprises compressing the gas to at least 1 M Pa.|21. The method of any of claims 17-20, wherein the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing. | (GB2615109)|FIELD OF THE INVENTION|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from exhaust flue gas. The invention also relates to methods for extracting solid or liquid carbon dioxide from exhaust flue gas.|BACKGROUND OF THE INVENTION|Global carbon dioxide emissions amount to over 10 giga tonnes per year. Simultaneously, there is a considerable requirement for carbon dioxide in a multitude of applications, such as urea fertiliser production, enhanced oil recovery processes, production of food and beverages, and other industrial processes. Approximately 250 million tonnes of carbon dioxide, corresponding to approximately 2.5% of all global emissions, are used each year for these purposes. Presently, almost all such carbon dioxide is derived from fossil fuel based sources.|In line with multiple unilateral governmental policies to reduce atmospheric global emissions of carbon dioxide, many nations are either decommissioning, scrapping or modifying existing coal-fired power stations or considering other abatement alternative scenarios. Coal-fired power stations emit approximately 80 tonnes of carbon dioxide gas per hour for every 100 MWh of electricity power generation capacity, depending on their construction and the coal fuel type being burned. This gross carbon dioxide emissions capacity exceeds comparative tonnages remediated for bioenergy with carbon capture and storage (BECCS). Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. Post combustion carbon capture and storage with amine scrubbing technologies in coal-fired power plants is a recent technology application, but even with subsidies it is expensive, typically costing between $80/tonne of carbon dioxide for first of a kind technologies and $60/tonne of carbon dioxide for next of a kind technology.|Retro-conversion of older coal-fired electricity power generation plants for carbon dioxide remediation was not considered as a future possibility when these plants were built, resulting in low availability of physical space and high costs. With many coal-fired power plants not able to be converted into environmentally benign non-polluting retro-fitted alternatives, some are now being shut down as a result of new legislation policies. This, in turn, drives an increased demand for electricity generation from alternative sources.|There exists an urgent and unmet need for carbon capture processes that are efficient, scalable and inexpensive. To avoid expensive and wasteful decommissioning of existing coal-fired electricity power generation plants, there exists an urgent and unmet need for carbon capture processes that reduce the carbon dioxide emissions from these plants to the environment. There is also an unmet industrial demand for carbon dioxide that is not derived directly from virgin fossil fuels e.g. for use in the ammonia fertiliser, enhanced oil recovery, medical, food and beverage industries.|SUMMARY OF THE INVENTION|The present invention solves the above-mentioned problems by providing an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas. Advantageously, the apparatus of the invention can be used to extract and capture carbon dioxide that would otherwise be released into the atmosphere, thereby reducing contributions to global carbon dioxide emissions. Carbon dioxide extracted by the invention may be stored to prevent its entry into the atmosphere. Carbon dioxide extracted by the invention may also be used in industry, e.g. to reduce the reliance on carbon dioxide produced from virgin fossil fuels, thereby further reducing carbon dioxide emissions. The present invention is not limited to any particular type of exhaust flue gas. Likewise, the present invention is not limited to any particular type of flue. As such, the apparatus of the invention can advantageously be used to extract carbon dioxide from a range of sources, such as exhaust flue gases, such as from boilers, engines, and fossil fuel-fired power stations.|The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising: a) a primary heat exchanger for receiving and cooling the exhaust flue gas; b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and (ii) a holding tank for containing solid and/or liquid carbon dioxide.|In some embodiments, the apparatus further comprises one or more secondary heat exchangers for receiving and cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen, wherein the outlet is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers.|In some embodiments, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue.|In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.|In some embodiments, the primary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas.|In some embodiments, the secondary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas.|In some embodiments, the apparatus further comprises an impeller for propelling the exhaust flue gas into the primary heat exchanger.|In some embodiments, the apparatus further comprises one or more impellers for propelling the compressed cooled exhaust flue gas into one or more of the one or more secondary heat exchangers.|In some embodiments, the apparatus further comprises a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor.|In some embodiments, one or more of the one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor.|In some embodiments, one or more of the one or more secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|In some embodiments, one or more of the secondary heat exchangers is situated between the primary compressor and the secondary compressor; and one or more of the secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|In some embodiments, the apparatus further comprises one or more valves for maintaining unidirectional flow of exhaust flue gas.|The invention also provides a method for producing solid and/or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondary heat exchanger; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|In some embodiments, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger.|In some embodiments, the cooling comprises reducing the temperature of the gas to less than -10°C. In some embodiments, the compressing comprises compressing the gas to at least 1 MPa.|In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice. In some embodiments, conversion of solid carbon dioxide to carbon dioxide ice is by hydraulic pressing.|DETAILED DESCRIPTION OF THE INVENTION|The present invention is based on the surprising discovery that solid and/or liquid carbon dioxide can be efficiently extracted from exhaust flue gas by varying the pressure and temperature of the exhaust flue gas. The apparatus and method of the invention advantageously provide a means for reducing the carbon dioxide emissions of energy generating devices. Moreover, carbon dioxide extracted by the apparatus and method of the invention has a number of applications in industry. Carbon dioxide extracted by the apparatus and methods of the invention may also be stored, to prevent its entry to the atmosphere, thereby reducing contributions to greenhouse gases.|Advantageously, the apparatus of the invention can be used to reduce the carbon dioxide emissions from existing electricity generating power stations by extracting carbon dioxide from the exhaust flue gases generated by said power stations. Reducing the negative environmental impact of these power stations, by reducing their carbon dioxide emissions without sacrificing the efficiency of energy generation, may help avoid these power stations being decommissioned.|Liquid carbon dioxide extracted using the apparatus and methods of the invention can be stored in subterraneous storage systems. Liquid carbon dioxide at high subterraneous pressures may be maintained for a long time in liquid state due to increased pressure from burial in subterranean lakes of liquid carbon dioxide, resulting in limited surface leakage over an extended period of time. This is a desirable alternative to the current practise of allowing carbon dioxide to be released into the atmosphere. Liquid carbon dioxide extracted using the apparatus of the invention may also be used to produce pressure changes within underground water and oil reservoirs, for applications such as instigating enhanced oil recovery and/or additional extraction of oil from otherwise depleted oil reservoirs.|Exhaust flue gas is typically generated by the combustion of a fuel, such as a fossil fuel (e.g. coal), biofuel or sustainable fuel. Exhaust flue gas may be generated by various energy generating devices, e.g. boilers, engines, generators, and power stations (e.g. fossil fuel-fired power stations).|In some embodiments, exhaust flue gas is treated by flue gas desulphurisation (FGD) methods to remove sulphur dioxide prior to delivery of the exhaust flue gas to the apparatus of the invention. In some embodiments, exhaust flue gas is post-desulphurisation exhaust flue gas. Typical post-desulphurisation exhaust flue gas comprises mainly gaseous carbon dioxide and nitrogen.|The apparatus of the invention comprises a primary heat exchanger for receiving and cooling exhaust flue gas. The primary heat exchanger may be any heat exchanger capable of reducing the temperature of the exhaust flue gas.|In some embodiments, the primary heat exchanger comprises one or more conduits for receiving coolant. The conduit(s) act as a conductor of heat from the exhaust flue gases to the coolant thereby simultaneously cooling the exhaust flue gas and increasing the temperature of the coolant. In some embodiments, the primary heat exchanger comprises a plurality of conduits for receiving coolant. In some embodiments, the primary heat exchanger comprises an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas. Advantageously, an array of conduits provides a large surface area for contacting the exhaust flue gas in the labyrinth chamber thereby allowing even faster cooling of the exhaust flue gas.|In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium.|In some embodiments, the coolant is gaseous nitrogen. In some embodiments, the coolant is gaseous nitrogen extracted from the exhaust flue gas. As used herein, extracted gaseous nitrogen refers to gaseous nitrogen that has been extracted from the exhaust flue gas.|In some embodiments, the coolant is an exogenous coolant. An exogenous coolant may be employed to cool the exhaust flue gas in one or more heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, the exogenous coolant is used to cool exhaust flue gas until sufficient gaseous nitrogen is extracted from the exhaust flue gas to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool exhaust flue gas in the primary heat exchanger and/or one or more secondary heat exchangers.|In some embodiments, the primary heat exchanger and/or secondary heat exchangers comprise one or more conduits for receiving exogenous coolant which are separate from the one or more conduits configured to receive extracted gaseous nitrogen. In some embodiments, the apparatus comprises a compressor and an evaporator in fluid communication with the one or more exogenous coolant conduits. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers, the compressor and evaporator, Circulation may be automatic or may be manually controlled. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers to increase the rate of cooling of exhaust flue gas by the primary and/or secondary heat exchangers.|The exogenous coolant may be any coolant suitable to cool exhaust flue gas in the primary and/or secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. In some embodiments, the exogenous coolant is a gas or liquid refrigerant. In some embodiments, the exogenous coolant comprises one or more of fluorocarbon, chlorofluorocarbon (R12), hydrochlorofluorocarbon (R22), hydrofluorocarbon (R410A, R134) freon, ammonia, sulphur dioxide, non-halogenated hydrocarbon, R404A, R407A, R407C, R407F, and R507.|After cooling exhaust flue gas in the primary heat exchanger, coolant comprising extracted gaseous nitrogen is typically vented into the atmosphere.|In some embodiments, the primary heat exchanger comprises a control means for regulating the flow of coolant through the conduit(s). The rate of flow of the coolant determines the rate of cooling of the exhaust flue gas. Increasing the flow of coolant typically increases the rate of cooling of the exhaust flue gas. Reducing the flow of coolant typically reduces the rate of cooling of the exhaust flue gas. The control means may comprise flow sensors. The control means may reduce the flow of coolant in response to reduced flow of exhaust flue gas into the primary heat exchanger. The control means may increase the flow of coolant in response to increased flow of exhaust flue gas into the primary heat exchanger. In some embodiments, the control means is configured to control the flow of extracted gaseous nitrogen through the conduit(s). In some embodiments, the control means is configured to control the flow of exogenous coolant through the one or more exogenous coolant conduits. In some embodiments, the control means comprises a coolant valve configured to control the flow of coolant through the conduit(s). In some embodiments, the coolant valve is a flow control valve.|In some embodiments, the apparatus further comprises an impeller for propelling exhaust flue gas into the primary heat exchanger. The impeller may be any rotatable component capable of propelling exhaust flue gas into the primary heat exchanger. In some embodiments, the apparatus comprises a manifold for housing the impeller.|In some embodiments, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the exhaust flue. Typically, the connection means is configured to connect to the exit point of an exhaust flue, i.e. the region of an exhaust flue that releases exhaust flue gas into the environment. In some embodiments, the connecting means is configured to direct exhaust flue gases to ground level, or a subterranean level. In some embodiments, the impeller is situated between the connection means and the primary heat exchanger.|The primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the exhaust flue during normal operation of the energy generating device to which the exhaust flue is connected, e.g. engine, boiler or power station.|In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas. Typically, the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The gas bypass system provides a regulatory control mechanism to avoid unwanted back pressure on the exhaust flue, e.g. when the flow of exhaust flue gas in the exhaust flue exceeds the maximum flow rate of the apparatus e.g. the maximum flow rate of the primary heat exchanger. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber with a gaseous flow control mechanism. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber having a modified heat and pressure take-off. Advantageously, a modified heat and pressure take-off ensures that exhaust flue modifications do not compromise the designed operations and efficiency of the energy generating device. In some embodiments, the gas bypass system comprises a unidirectional gas flow valve flap.|In some embodiments, the primary heat exchanger is configured to cool the exhaust flue gas to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. As used herein, cooled exhaust flue gas refers to exhaust flue gas that has been cooled by the primary heat exchanger.|The apparatus also comprises a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger. The primary compressor compresses cooled exhaust flue gas from the primary heat exchanger to provide compressed cooled exhaust flue gas.|In some embodiments, the apparatus further comprises one or more secondary heat exchangers for cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the apparatus further comprises one or more secondary compressors for compressing compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the apparatus further comprises: (i) a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor; and (ii) a secondary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor.|In some embodiments, the apparatus further comprises: (i) a secondary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the primary compressor; and (ii) a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger.|In some embodiments, the apparatus further comprises: (i) a secondary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the primary compressor; (ii) a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger; and (iii) a tertiary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor. In this embodiment, during operation the cooled exhaust flue gas from the primary heat exchanger is: (i) compressed by the primary compressor; (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the tertiary heat exchanger, prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the secondary heat exchanger is configured to receive and cool compressed cooled exhaust flue gas from both the primary compressor and the secondary compressor. In this embodiment, during operation the cooled exhaust flue gas from the primary heat exchanger is: (i) compressed by the primary compressor; (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the secondary heat exchanger prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|The compressor may be any compressor capable of increasing the pressure of a gas. In some embodiments, the primary compressor and/or secondary compressor is a high volume reciprocating compressor or a rotational gas compressor.|As used herein, cooled compressed exhaust flue gas refers to exhaust flue gas that has been cooled in the primary heat exchanger and compressed by the primary compressor. In embodiments comprising a secondary compressor, the term cooled compressed exhaust flue gas also refers to exhaust flue gas that has been cooled in the primary heat exchanger and compressed by both the primary and secondary compressors. The term cooled compressed exhaust flue gas also refers to exhaust flue gas that has been cooled in the primary heat exchanger, compressed by at least the primary compressor, and cooled by one or more secondary heat exchangers.|Heat exchangers for receiving and cooling compressed cooled exhaust flue gas from a compressor may be any heat exchanger capable of reducing the temperature of a gas. In some embodiments, the one or more secondary heat exchangers comprise one or more conduits for receiving coolant. In some embodiments, the one or more secondary heat exchangers comprise an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas from the primary compressor and/or the secondary compressor. In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium.|In some embodiments, the coolant is gaseous nitrogen. In some embodiments, the coolant is gaseous nitrogen extracted from the exhaust flue gas. In some embodiments, the coolant is an exogenous coolant. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen.|In some embodiments, the one or more secondary heat exchangers comprise control means for regulating the flow of coolant through the conduit(s). In some embodiments, the control means for regulating the flow of coolant through the conduit(s) of the primary heat exchanger also controls the flow of coolant through the conduit(s) of the one or more secondary heat exchangers.|In some embodiments, the conduit(s) of the primary heat exchanger are in fluid communication with the conduit(s) of the one or more secondary heat exchangers.|In some embodiments, the one or more secondary heat exchanger comprise an impeller for propelling compressed cooled exhaust flue gas into the one or more secondary heat exchangers.|In some embodiments, the primary compressor is configured to compress the exhaust flue gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, the secondary compressor is configured to compress the exhaust flue gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In embodiments wherein the apparatus comprises a primary compressor and a secondary compressor, in some embodiments, the primary compressor is configured to compress the exhaust flue gas to at least 1 MPa, and the secondary compressor is configured to compress the exhaust flue gas to at least 10 MPa.|In some embodiments, the one or more secondary heat exchangers are configured to cool the exhaust flue gas to a temperature of less than 0°C, less than -5°C, or less than -10°C.|The apparatus also comprises a carbon dioxide collection vessel. The carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas; and (ii) a holding tank for containing solid and/or liquid carbon dioxide.|In some embodiments, the throttling valve is configured to receive compressed cooled exhaust flue gas from the primary compressor. In some embodiments, the throttling valve is configured to receive compressed cooled exhaust flue gas from the secondary compressor. In some embodiments, the throttling valve is configured to receive compressed cooled exhaust flue gas from the one or more secondary heat exchangers.|The throttling valve may be any valve that is capable of changing unilateral flow into turbulent flow. A throttling valve typically comprises an inlet and an outlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 10-fold, at least 20-fold, at least 30-fold, at least 40-fold, at least 50-fold, at least 60-fold, at least 70-fold, at least 80-fold, at least 90-fold, or at least 100-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the crosssectional area of the throttling valve outlet is at least 50-fold greater than the cross-sectional area of the throttling valve inlet.|In some embodiments, the carbon dioxide collection vessel comprises a tubular cone extending from the throttling valve outlet wherein the tubular diameter of the cone increases as it extends outwards from the throttling valve.|In some embodiments, the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen. In some embodiments, the outlet for gaseous nitrogen is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers. In some embodiments, the outlet is in fluid communication with a gaseous nitrogen storage vessel which is in fluid communication with the primary heat exchanger and/or the one or more secondary heat exchangers. As described in more detail above, the apparatus may comprise a control means for regulating the flow of extracted gaseous nitrogen through the primary heat exchanger and/or through the one or more secondary heat exchangers.|The holding tank is typically configured to accommodate the volumetric space required for the collection of solid and/or liquid carbon dioxide.|In some embodiments, the apparatus is insulated to reduce heat influx from the external environment.|In some embodiments, the apparatus comprises transfer conduits for delivering exhaust flue gas through the apparatus from one component of the apparatus to a subsequent component of the apparatus. In some embodiments, the transfer conduits are insulated. Components of the apparatus include the primary heat exchanger, the primary compressor, and the carbon dioxide collection vessel. Components of the apparatus may also comprise one or more secondary heat exchanger and one or more secondary compressors.|In some embodiments, the apparatus further comprises one or more valves for maintaining unidirectional flow of exhaust flue gas. In some embodiments, the valves are cryogenic non-return check valves. Advantageously, valves prevent thermal bridging and maintain states of matter.|In some embodiments, the apparatus further comprises additional heat exchangers and/or compressors for maintaining the temperature and pressure of the exhaust flue gas within the apparatus.|The invention provides a method for producing solid and/or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to: (i) a secondary heat exchanger and/or (ii) a secondary compressor; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|In some embodiments, the method of the invention comprises delivering exhaust flue gas to the apparatus of the invention as described above.|In some embodiments, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide to provide extracted gaseous nitrogen. The extracted gaseous nitrogen may be collected and stored. In some embodiments, the method comprises supplying the extracted gaseous nitrogen to the primary heat exchanger and/or secondary heat exchanger.|In some embodiments, the method comprises employing an exogenous coolant to cool the exhaust flue gas in the primary heat exchanger during initiation of the carbon dioxide extraction process. In embodiments wherein the apparatus comprises one or more secondary heat exchangers, in some embodiments, the method comprises employing an exogenous coolant to cool the exhaust flue gas in one or more of the secondary heat exchangers during initiation of the carbon dioxide extraction process.|In some embodiments, the exogenous coolant is used to cool exhaust flue gas until sufficient gaseous nitrogen is extracted from the exhaust flue gas to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool exhaust flue gas in the primary heat exchanger and/or one or more secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen.|In some embodiments, the method comprises regulating the flow of coolant through the primary heat exchanger and/or the secondary heat exchanger. The rate of flow of the coolant determines the rate of cooling of the exhaust flue gas. Increasing the flow of coolant typically increases the rate of cooling of the exhaust flue gas. Reducing the flow of coolant typically reduces the rate of cooling of the exhaust flue gas.|In some embodiments, the primary heat exchanger cools exhaust flue gas to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than|- 40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. In some embodiments, the primary heat exchanger cools exhaust flue gas to a temperature of less than -30°C, optionally less than|- 40°C.|In some embodiments, the compressing comprises compressing the exhaust flue gas to least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, compressing comprises compressing the exhaust flue gas to at least 10 MPa. In some embodiments, the compressing comprises compressing the cooled exhaust flue gas more than once. In some embodiments, the method comprises initially compressing the exhaust flue gas to at least 1 MPa and then subsequently compressing the exhaust flue gas to at least 10 MPa.|In some embodiments, the method further comprises delivering compressed cooled exhaust flue gas to a secondary heat exchanger. In some embodiments, the secondary heat exchanger cools the compressed cooled exhaust flue gas to a temperature of less than 0°C, less than -5°C, or less than -10°C.|In some embodiments, the method comprises: (i) compressing the cooled exhaust flue gas; (ii) cooling the compressed cooled exhaust flue gas; (iii) compressing the cooled exhaust flue gas; and then (iv) cooling the compressed cooled exhaust flue gas. In some embodiments, the method comprises: (i) compressing the cooled exhaust flue gas to less than 1 MPa; (ii) cooling the compressed cooled exhaust flue gas to a temperature of less than -10°C; (iii) compressing the cooled exhaust flue gas to less than 10 MPa; and then (iv) cooling the compressed cooled exhaust flue gas to a temperature of less than -10°C.|In some embodiments, the method comprises collecting solid carbon dioxide and allowing it to melt to form liquid carbon dioxide. In some embodiments, carbon dioxide is maintained at a pressure of at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, or at least 5 MPa in the holding tank. In some embodiments, carbon dioxide is maintained at a pressure of 3 MPa in the holding tank. In some embodiments, liquid carbon dioxide is stored in cryogenic pressure vessel equipment.|In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice. In some embodiments, solid carbon dioxide is converted to carbon dioxide ice by hydraulic pressing.|Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying figures which are not drawn to scale.|Figure 1 provides a schematic representation of an exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, and carbon dioxide collection vessel.|Figure 2 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, and carbon dioxide collection vessel.|Figure 3 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary compressor, and carbon dioxide collection vessel.|Figure 4 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, secondary compressor, tertiary heat exchanger, and carbon dioxide collection vessel.|An exemplary apparatus according to the invention is shown in Figure 1. The apparatus of the invention comprises a primary heat exchanger 10, a primary compressor 20, and a carbon dioxide collection vessel 30 comprising a throttling valve 32 and a holding tank 36. The apparatus may comprise means 12 for connecting to an exhaust flue. The apparatus may further comprise an impeller 14 for propelling exhaust flue gas into the primary heat exchanger 10. The carbon dioxide collection vessel 30 may comprise an outlet 34 for extracting gaseous nitrogen, and a gaseous nitrogen transfer conduit 40 in fluid communication with the primary heat exchanger 10.|The apparatus of Figure 2 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60.|The apparatus of Figure 3 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32.|The apparatus of Figure 4 comprises the features of the apparatus of Figure 1 and additionally comprises: a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20; a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger 60; and a tertiary heat exchanger 65 for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor 25. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60 and/or tertiary heat exchanger 65.|Transfer conduits 50-58 are for transferring exhaust flue gas through the apparatus as depicted in Figures 1-4.|Specific example|The invention will now be described with reference to the following non-limiting example.|Exhaust flue gases may be redirected from the exhaust flue exit point that connects with the open-air environment, such as the above ground open air exit of a chimney into the lower atmosphere between 20 and 100 metres above ground level. The exhaust flue exit may be adapted to connect to a connection means, e.g. tubing comprising a 180° bend, to redirect exhaust flue gases towards the primary heat exchanger which may be at ground level. This downward directional tubing may connect to a manifold housing an internal impeller for propelling exhaust flue gases into the primary heat exchanger, optionally into a labyrinth chamber of the primary heat exchanger. This downward directional tubing may connect directly to the primary heat exchanger. The primary heat exchanger may comprise a labyrinth chamber comprising a network array matrix of interconnecting channels and tubing that inter-collectively contain a series of pressure vessel conduits acting as a large heat exchanger for the transport of a coolant, e.g. cold and vented gaseous nitrogen. This cold, gaseous nitrogen does not typically come into direct contact with the exhaust flue gases. The pressure vessel tubing of the conduits acts as a conductor of heat from the exhaust flue gases into the coolant, e.g. the gaseous nitrogen, thereby heating the coolant and simultaneously cooling the exhaust flue gases in the heat exchange chiller labyrinth. The exhaust flue gases may be cooled to a temperature of at least -40°C. Gaseous nitrogen may be allowed to cool and vented to the atmosphere after flowing through the conduits of the primary heat exchanger.|Control over the temperature of the exhaust flue gases in the primary heat exchanger may be performed by control means configured to control the rate of flow of the cold gaseous nitrogen in the heat exchange chiller labyrinth. Increasing the rate of flow of cold gaseous nitrogen cools the exhaust flue gases quicker and slowing the rate of flow of cold gaseous nitrogen helps prevent the exhaust flue gases cooling down below the desired temperature, e.g. -40°C. Flow rate may be controlled by flow sensors in the cold gaseous nitrogen pumping system. The size of the heat exchange chiller labyrinth is typically designed to match the known maximum gas flow rate obtained from the exhaust flue during functional operation of the engine, boiler or coal-fired power station, so that the thermodynamic heat fluxes of the two temperature regimes are synchronised to accommodate from the known temperature of the gases upon leaving the original chimney design until exiting the heat exchange chiller labyrinth system. Typically, this may result in a temperature drop from between 50°C and 90°C to between -10°C and -40°C, ideally at least -30°C, or preferably at least -40°C.|The main function of chilling the exhaust flue gases is to prepare the gases for phase change. The heat exchange chiller labyrinth itself does not initiate the phase change - it changes the temperature of the gases but not the pressure. As such, the exhaust flue gases are typically cooled to a temperature of 40°C and remain in gaseous state at the point of leaving the primary heat exchanger. As the cooled exhaust flue gases leave the primary heat exchanger, the external surface of the transfer conduits that deliver cooled exhaust flue gases through the apparatus are typically insulated to ensure that the gases remain at their cooled temperature throughout their transitionary passage to formation of primarily solid carbon dioxide and secondarily liquid carbon dioxide.|Upon leaving the heat exchange chiller labyrinth, the cooled exhaust flue gas is typically delivered via transfer conduit(s) to a primary compressor. The primary compressor may compress the exhaust flue gases from approximately 10 KPa to approximately 1 MPa. After primary stage compression, exhaust flue gases may be partially warmed as a result of a reduction in their volume during the compression process. Exhaust flue gases may then be chilled back to about -10°C in a secondary heat exchanger. The compressed cooled exhaust flue gas may then be compressed by a secondary compressor to compress the compressed cooled exhaust flue gas from approximately 1 MPa to 10 MPa. Compressed cooled exhaust flue gases may then be chilled back to -10°C via exposure to the same secondary heat exchanger or a tertiary heat exchanger.|Compressed cooled exhaust flue gases typically contain multiphase flow of gaseous nitrogen, as well as chilled gaseous carbon dioxide. Other majority contaminants from coal-fired power station may have previously been removed using a flue gas desulphurisation cleaning process for removal of SOx, prior to delivery of the exhaust flue gas to the primary heat exchanger, thus ensuring that most of the gases in the apparatus comprise gaseous nitrogen and carbon dioxide. This cold gas mixture may be maintained within the system by means of placement of cryogenic non-return check valves in unidirectional flow. Check valves may help to prevent thermal bridging and maintain states of matter. Optionally, adjacent and strategically placed heat exchangers and/or maintenance compressors may be present to ensure that during transit of the exhaust flue gases through the apparatus, the temperature and pressure of the gas is maintained.|The compressed cooled exhaust flue gas is delivered to a throttling valve. The throttling valve acts to change unilateral liquid flow into turbulent flow. In the throttling valve there is typically an adiabatic drop due to the pressure drop with increased gas velocity. Simultaneously, upon ejection of the compressed cooled exhaust flue gas from the throttling valve, the tubular aperture may be significantly increased, e.g. at least 50-fold, so that the cross-sectional area of the compressed cooled exhaust flue gas before the throttling valve is significantly smaller than the cross-sectional area, e.g. 1/50 of the cross-sectional area, of the venting tube after the throttling valve. Simultaneously, the exit from the throttling valve may extend in a tubular cone orientation as the output end of the contents of throttling valve of the compressed cooled exhaust flue gas extend into the larger aperture holding chamber. The tubular cone extension on the output side of the throttling valve may act to create cyclonic turbulent flow and a sudden drop in pressure, with a simultaneous drop in temperature. This typically creates the phase change formation from gaseous cold carbon dioxide into a deposition phase transition, or reverse sublimation process into solid carbon dioxide 'snow' at a temperature below -78°C and mixed with cold gaseous nitrogen. The cold gaseous nitrogen may be vented, collected and pumped for reverse passage through the primary and/or secondary heat exchangers. The holding tank is typically designed to accommodate the volumetric space required for the input of solid carbon dioxide 'snow', so that its accumulation can readily be melted from solid carbon dioxide 'snow' into liquid carbon dioxide. The entire cooled zone from the primary heat exchanger through to the carbon dioxide collection vessel may be insulated to prevent heat influx from the external environment. The liquid carbon dioxide product may be stored using conventional cryogenic pressure vessel equipment of either tank or bulk storage systems, and transported to pertinent markets worldwide. Alternatively, hydraulic pressing may be used as a functional methodology to change the form of solid crystalline carbon dioxide snow into compressed carbon dioxide ice, or dry ice.|The apparatus may comprise a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The purpose of the gas bypass system is to act as a regulatory control mechanism, coupling to the exhaust flue and preceding placement of the primary heat exchanger described herein. The gas bypass system simultaneously avoids unwanted back pressure on the engine or boiler, allowing smooth, continuous and uninterrupted flow of exhaust flue gases from the engine or boiler, thereby ensuring that the regulatory control feedback mechanism for the temperature and pressure of the engine or boiler is functional. The exhaust flue gas bypass system may be constructed as a partitioned parallel exhaust chamber with a warmer than ambient temperature internal gaseous flow control mechanism. The secondary partitioned parallel exhaust chamber may have a modified heat and pressure take-off ensuring that exhaust flue modifications do not compromise or have any effects on the designed operations and efficiency of the engine or boiler by means of a unidirectional gas flow valve flap. | (GB2615109)|FIELD OF THE INVENTION|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from exhaust flue gas. The invention also relates to methods for extracting solid or liquid carbon dioxide from exhaust flue gas.|BACKGROUND OF THE INVENTION|Global carbon dioxide emissions amount to over 10 giga tonnes per year. Simultaneously, there is a considerable requirement for carbon dioxide in a multitude of applications, such as urea fertiliser production, enhanced oil recovery processes, production of food and beverages, and other industrial processes. Approximately 250 million tonnes of carbon dioxide, corresponding to approximately 2.5% of all global emissions, are used each year for these purposes. Presently, almost all such carbon dioxide is derived from fossil fuel based sources.|In line with multiple unilateral governmental policies to reduce atmospheric global emissions of carbon dioxide, many nations are either decommissioning, scrapping or modifying existing coal-fired power stations or considering other abatement alternative scenarios. Coal-fired power stations emit approximately 80 tonnes of carbon dioxide gas per hour for every 100 MWh of electricity power generation capacity, depending on their construction and the coal fuel type being burned. This gross carbon dioxide emissions capacity exceeds comparative tonnages remediated for bioenergy with carbon capture and storage (BECCS). Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. Post combustion carbon capture and storage with amine scrubbing technologies in coal-fired power plants is a recent technology application, but even with subsidies it is expensive, typically costing between $80/tonne of carbon dioxide for first of a kind technologies and $60/tonne of carbon dioxide for next of a kind technology.|Retro-conversion of older coal-fired electricity power generation plants for carbon dioxide remediation was not considered as a future possibility when these plants were built, resulting in low availability of physical space and high costs. With many coal-fired power plants not able to be converted into environmentally benign non-polluting retro-fitted alternatives, some are now being shut down as a result of new legislation policies. This, in turn, drives an increased demand for electricity generation from alternative sources.|There exists an urgent and unmet need for carbon capture processes that are efficient, scalable and inexpensive. To avoid expensive and wasteful decommissioning of existing coal-fired electricity power generation plants, there exists an urgent and unmet need for carbon capture processes that reduce the carbon dioxide emissions from these plants to the environment. There is also an unmet industrial demand for carbon dioxide that is not derived directly from virgin fossil fuels e.g. for use in the ammonia fertiliser, enhanced oil recovery, medical, food and beverage industries.|SUMMARY OF THE INVENTION|The present invention solves the above-mentioned problems by providing an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas. Advantageously, the apparatus of the invention can be used to extract and capture carbon dioxide that would otherwise be released into the atmosphere, thereby reducing contributions to global carbon dioxide emissions. Carbon dioxide extracted by the invention may be stored to prevent its entry into the atmosphere. Carbon dioxide extracted by the invention may also be used in industry, e.g. to reduce the reliance on carbon dioxide produced from virgin fossil fuels, thereby further reducing carbon dioxide emissions. The present invention is not limited to any particular type of exhaust flue gas. Likewise, the present invention is not limited to any particular type of flue. As such, the apparatus of the invention can advantageously be used to extract carbon dioxide from a range of sources, such as exhaust flue gases, such as from boilers, engines, and fossil fuel-fired power stations.|The invention provides an apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising: a) a primary heat exchanger for receiving and cooling the exhaust flue gas; b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and (ii) a holding tank for containing solid and/or liquid carbon dioxide.|In some embodiments, the apparatus further comprises one or more secondary heat exchangers for receiving and cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen, wherein the outlet is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers.|In some embodiments, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger and the exhaust flue.|In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.|In some embodiments, the primary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas.|In some embodiments, the secondary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas.|In some embodiments, the apparatus further comprises an impeller for propelling the exhaust flue gas into the primary heat exchanger.|In some embodiments, the apparatus further comprises one or more impellers for propelling the compressed cooled exhaust flue gas into one or more of the one or more secondary heat exchangers.|In some embodiments, the apparatus further comprises a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor.|In some embodiments, one or more of the one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor.|In some embodiments, one or more of the one or more secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|In some embodiments, one or more of the secondary heat exchangers is situated between the primary compressor and the secondary compressor; and one or more of the secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|In some embodiments, the apparatus further comprises one or more valves for maintaining unidirectional flow of exhaust flue gas.|The invention also provides a method for producing solid and/or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondary heat exchanger; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|In some embodiments, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger.|In some embodiments, the cooling comprises reducing the temperature of the gas to less than -10°C. In some embodiments, the compressing comprises compressing the gas to at least 1 MPa.|In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice. In some embodiments, conversion of solid carbon dioxide to carbon dioxide ice is by hydraulic pressing.|DETAILED DESCRIPTION OF THE INVENTION|The present invention is based on the surprising discovery that solid and/or liquid carbon dioxide can be efficiently extracted from exhaust flue gas by varying the pressure and temperature of the exhaust flue gas. The apparatus and method of the invention advantageously provide a means for reducing the carbon dioxide emissions of energy generating devices. Moreover, carbon dioxide extracted by the apparatus and method of the invention has a number of applications in industry. Carbon dioxide extracted by the apparatus and methods of the invention may also be stored, to prevent its entry to the atmosphere, thereby reducing contributions to greenhouse gases.|Advantageously, the apparatus of the invention can be used to reduce the carbon dioxide emissions from existing electricity generating power stations by extracting carbon dioxide from the exhaust flue gases generated by said power stations. Reducing the negative environmental impact of these power stations, by reducing their carbon dioxide emissions without sacrificing the efficiency of energy generation, may help avoid these power stations being decommissioned.|Liquid carbon dioxide extracted using the apparatus and methods of the invention can be stored in subterraneous storage systems. Liquid carbon dioxide at high subterraneous pressures may be maintained for a long time in liquid state due to increased pressure from burial in subterranean lakes of liquid carbon dioxide, resulting in limited surface leakage over an extended period of time. This is a desirable alternative to the current practise of allowing carbon dioxide to be released into the atmosphere. Liquid carbon dioxide extracted using the apparatus of the invention may also be used to produce pressure changes within underground water and oil reservoirs, for applications such as instigating enhanced oil recovery and/or additional extraction of oil from otherwise depleted oil reservoirs.|Exhaust flue gas is typically generated by the combustion of a fuel, such as a fossil fuel (e.g. coal), biofuel or sustainable fuel. Exhaust flue gas may be generated by various energy generating devices, e.g. boilers, engines, generators, and power stations (e.g. fossil fuel-fired power stations).|In some embodiments, exhaust flue gas is treated by flue gas desulphurisation (FGD) methods to remove sulphur dioxide prior to delivery of the exhaust flue gas to the apparatus of the invention. In some embodiments, exhaust flue gas is post-desulphurisation exhaust flue gas. Typical post-desulphurisation exhaust flue gas comprises mainly gaseous carbon dioxide and nitrogen.|The apparatus of the invention comprises a primary heat exchanger for receiving and cooling exhaust flue gas. The primary heat exchanger may be any heat exchanger capable of reducing the temperature of the exhaust flue gas.|In some embodiments, the primary heat exchanger comprises one or more conduits for receiving coolant. The conduit(s) act as a conductor of heat from the exhaust flue gases to the coolant thereby simultaneously cooling the exhaust flue gas and increasing the temperature of the coolant. In some embodiments, the primary heat exchanger comprises a plurality of conduits for receiving coolant. In some embodiments, the primary heat exchanger comprises an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas. Advantageously, an array of conduits provides a large surface area for contacting the exhaust flue gas in the labyrinth chamber thereby allowing even faster cooling of the exhaust flue gas.|In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium.|In some embodiments, the coolant is gaseous nitrogen. In some embodiments, the coolant is gaseous nitrogen extracted from the exhaust flue gas. As used herein, extracted gaseous nitrogen refers to gaseous nitrogen that has been extracted from the exhaust flue gas.|In some embodiments, the coolant is an exogenous coolant. An exogenous coolant may be employed to cool the exhaust flue gas in one or more heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, the exogenous coolant is used to cool exhaust flue gas until sufficient gaseous nitrogen is extracted from the exhaust flue gas to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool exhaust flue gas in the primary heat exchanger and/or one or more secondary heat exchangers.|In some embodiments, the primary heat exchanger and/or secondary heat exchangers comprise one or more conduits for receiving exogenous coolant which are separate from the one or more conduits configured to receive extracted gaseous nitrogen. In some embodiments, the apparatus comprises a compressor and an evaporator in fluid communication with the one or more exogenous coolant conduits. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers, the compressor and evaporator, Circulation may be automatic or may be manually controlled. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers during initiation of the carbon dioxide extraction process. In some embodiments, exogenous coolant is circulated through the primary and/or secondary heat exchangers to increase the rate of cooling of exhaust flue gas by the primary and/or secondary heat exchangers.|The exogenous coolant may be any coolant suitable to cool exhaust flue gas in the primary and/or secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen. In some embodiments, the exogenous coolant is a gas or liquid refrigerant. In some embodiments, the exogenous coolant comprises one or more of fluorocarbon, chlorofluorocarbon (R12), hydrochlorofluorocarbon (R22), hydrofluorocarbon (R410A, R134) freon, ammonia, sulphur dioxide, non-halogenated hydrocarbon, R404A, R407A, R407C, R407F, and R507.|After cooling exhaust flue gas in the primary heat exchanger, coolant comprising extracted gaseous nitrogen is typically vented into the atmosphere.|In some embodiments, the primary heat exchanger comprises a control means for regulating the flow of coolant through the conduit(s). The rate of flow of the coolant determines the rate of cooling of the exhaust flue gas. Increasing the flow of coolant typically increases the rate of cooling of the exhaust flue gas. Reducing the flow of coolant typically reduces the rate of cooling of the exhaust flue gas. The control means may comprise flow sensors. The control means may reduce the flow of coolant in response to reduced flow of exhaust flue gas into the primary heat exchanger. The control means may increase the flow of coolant in response to increased flow of exhaust flue gas into the primary heat exchanger. In some embodiments, the control means is configured to control the flow of extracted gaseous nitrogen through the conduit(s). In some embodiments, the control means is configured to control the flow of exogenous coolant through the one or more exogenous coolant conduits. In some embodiments, the control means comprises a coolant valve configured to control the flow of coolant through the conduit(s). In some embodiments, the coolant valve is a flow control valve.|In some embodiments, the apparatus further comprises an impeller for propelling exhaust flue gas into the primary heat exchanger. The impeller may be any rotatable component capable of propelling exhaust flue gas into the primary heat exchanger. In some embodiments, the apparatus comprises a manifold for housing the impeller.|In some embodiments, the apparatus further comprises means for connecting in fluid communication the primary heat exchanger to the exhaust flue. Typically, the connection means is configured to connect to the exit point of an exhaust flue, i.e. the region of an exhaust flue that releases exhaust flue gas into the environment. In some embodiments, the connecting means is configured to direct exhaust flue gases to ground level, or a subterranean level. In some embodiments, the impeller is situated between the connection means and the primary heat exchanger.|The primary heat exchanger is typically configured to allow a gas flow rate that is the same or higher than the maximum gas flow rate of the exhaust flue during normal operation of the energy generating device to which the exhaust flue is connected, e.g. engine, boiler or power station.|In some embodiments, the apparatus further comprises a gas bypass system for venting excess exhaust flue gas. Typically, the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The gas bypass system provides a regulatory control mechanism to avoid unwanted back pressure on the exhaust flue, e.g. when the flow of exhaust flue gas in the exhaust flue exceeds the maximum flow rate of the apparatus e.g. the maximum flow rate of the primary heat exchanger. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber with a gaseous flow control mechanism. In some embodiments, the gas bypass system comprises a partitioned parallel exhaust chamber having a modified heat and pressure take-off. Advantageously, a modified heat and pressure take-off ensures that exhaust flue modifications do not compromise the designed operations and efficiency of the energy generating device. In some embodiments, the gas bypass system comprises a unidirectional gas flow valve flap.|In some embodiments, the primary heat exchanger is configured to cool the exhaust flue gas to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than -40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. As used herein, cooled exhaust flue gas refers to exhaust flue gas that has been cooled by the primary heat exchanger.|The apparatus also comprises a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger. The primary compressor compresses cooled exhaust flue gas from the primary heat exchanger to provide compressed cooled exhaust flue gas.|In some embodiments, the apparatus further comprises one or more secondary heat exchangers for cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the apparatus further comprises one or more secondary compressors for compressing compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the apparatus further comprises: (i) a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor; and (ii) a secondary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor.|In some embodiments, the apparatus further comprises: (i) a secondary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the primary compressor; and (ii) a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger.|In some embodiments, the apparatus further comprises: (i) a secondary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the primary compressor; (ii) a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger; and (iii) a tertiary heat exchanger for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor. In this embodiment, during operation the cooled exhaust flue gas from the primary heat exchanger is: (i) compressed by the primary compressor; (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the tertiary heat exchanger, prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|In some embodiments, the secondary heat exchanger is configured to receive and cool compressed cooled exhaust flue gas from both the primary compressor and the secondary compressor. In this embodiment, during operation the cooled exhaust flue gas from the primary heat exchanger is: (i) compressed by the primary compressor; (ii) cooled by the secondary heat exchanger; (iii) compressed by the secondary compressor; and then (iv) cooled by the secondary heat exchanger prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|The compressor may be any compressor capable of increasing the pressure of a gas. In some embodiments, the primary compressor and/or secondary compressor is a high volume reciprocating compressor or a rotational gas compressor.|As used herein, cooled compressed exhaust flue gas refers to exhaust flue gas that has been cooled in the primary heat exchanger and compressed by the primary compressor. In embodiments comprising a secondary compressor, the term cooled compressed exhaust flue gas also refers to exhaust flue gas that has been cooled in the primary heat exchanger and compressed by both the primary and secondary compressors. The term cooled compressed exhaust flue gas also refers to exhaust flue gas that has been cooled in the primary heat exchanger, compressed by at least the primary compressor, and cooled by one or more secondary heat exchangers.|Heat exchangers for receiving and cooling compressed cooled exhaust flue gas from a compressor may be any heat exchanger capable of reducing the temperature of a gas. In some embodiments, the one or more secondary heat exchangers comprise one or more conduits for receiving coolant. In some embodiments, the one or more secondary heat exchangers comprise an array of conduits for receiving coolant. In some embodiments, the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas from the primary compressor and/or the secondary compressor. In some embodiments, the conduits comprise a heat tolerant, conducting material. In some embodiments, the conduits comprise a metal or metal alloy. In some embodiments, the metal or metal alloy comprises steel (e.g. stainless steel, austenitic steel or austenitic stainless steel), copper, aluminium and/or titanium.|In some embodiments, the coolant is gaseous nitrogen. In some embodiments, the coolant is gaseous nitrogen extracted from the exhaust flue gas. In some embodiments, the coolant is an exogenous coolant. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen.|In some embodiments, the one or more secondary heat exchangers comprise control means for regulating the flow of coolant through the conduit(s). In some embodiments, the control means for regulating the flow of coolant through the conduit(s) of the primary heat exchanger also controls the flow of coolant through the conduit(s) of the one or more secondary heat exchangers.|In some embodiments, the conduit(s) of the primary heat exchanger are in fluid communication with the conduit(s) of the one or more secondary heat exchangers.|In some embodiments, the one or more secondary heat exchanger comprise an impeller for propelling compressed cooled exhaust flue gas into the one or more secondary heat exchangers.|In some embodiments, the primary compressor is configured to compress the exhaust flue gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, the secondary compressor is configured to compress the exhaust flue gas to at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In embodiments wherein the apparatus comprises a primary compressor and a secondary compressor, in some embodiments, the primary compressor is configured to compress the exhaust flue gas to at least 1 MPa, and the secondary compressor is configured to compress the exhaust flue gas to at least 10 MPa.|In some embodiments, the one or more secondary heat exchangers are configured to cool the exhaust flue gas to a temperature of less than 0°C, less than -5°C, or less than -10°C.|The apparatus also comprises a carbon dioxide collection vessel. The carbon dioxide collection vessel comprises: (i) a throttling valve for receiving compressed cooled exhaust flue gas; and (ii) a holding tank for containing solid and/or liquid carbon dioxide.|In some embodiments, the throttling valve is configured to receive compressed cooled exhaust flue gas from the primary compressor. In some embodiments, the throttling valve is configured to receive compressed cooled exhaust flue gas from the secondary compressor. In some embodiments, the throttling valve is configured to receive compressed cooled exhaust flue gas from the one or more secondary heat exchangers.|The throttling valve may be any valve that is capable of changing unilateral flow into turbulent flow. A throttling valve typically comprises an inlet and an outlet. In some embodiments, the cross-sectional area of the throttling valve outlet is at least 10-fold, at least 20-fold, at least 30-fold, at least 40-fold, at least 50-fold, at least 60-fold, at least 70-fold, at least 80-fold, at least 90-fold, or at least 100-fold greater than the cross-sectional area of the throttling valve inlet. In some embodiments, the crosssectional area of the throttling valve outlet is at least 50-fold greater than the cross-sectional area of the throttling valve inlet.|In some embodiments, the carbon dioxide collection vessel comprises a tubular cone extending from the throttling valve outlet wherein the tubular diameter of the cone increases as it extends outwards from the throttling valve.|In some embodiments, the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen. In some embodiments, the outlet for gaseous nitrogen is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers. In some embodiments, the outlet is in fluid communication with a gaseous nitrogen storage vessel which is in fluid communication with the primary heat exchanger and/or the one or more secondary heat exchangers. As described in more detail above, the apparatus may comprise a control means for regulating the flow of extracted gaseous nitrogen through the primary heat exchanger and/or through the one or more secondary heat exchangers.|The holding tank is typically configured to accommodate the volumetric space required for the collection of solid and/or liquid carbon dioxide.|In some embodiments, the apparatus is insulated to reduce heat influx from the external environment.|In some embodiments, the apparatus comprises transfer conduits for delivering exhaust flue gas through the apparatus from one component of the apparatus to a subsequent component of the apparatus. In some embodiments, the transfer conduits are insulated. Components of the apparatus include the primary heat exchanger, the primary compressor, and the carbon dioxide collection vessel. Components of the apparatus may also comprise one or more secondary heat exchanger and one or more secondary compressors.|In some embodiments, the apparatus further comprises one or more valves for maintaining unidirectional flow of exhaust flue gas. In some embodiments, the valves are cryogenic non-return check valves. Advantageously, valves prevent thermal bridging and maintain states of matter.|In some embodiments, the apparatus further comprises additional heat exchangers and/or compressors for maintaining the temperature and pressure of the exhaust flue gas within the apparatus.|The invention provides a method for producing solid and/or liquid carbon dioxide from exhaust flue gas, the method comprising: a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas; b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to: (i) a secondary heat exchanger and/or (ii) a secondary compressor; and c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|In some embodiments, the method of the invention comprises delivering exhaust flue gas to the apparatus of the invention as described above.|In some embodiments, the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide to provide extracted gaseous nitrogen. The extracted gaseous nitrogen may be collected and stored. In some embodiments, the method comprises supplying the extracted gaseous nitrogen to the primary heat exchanger and/or secondary heat exchanger.|In some embodiments, the method comprises employing an exogenous coolant to cool the exhaust flue gas in the primary heat exchanger during initiation of the carbon dioxide extraction process. In embodiments wherein the apparatus comprises one or more secondary heat exchangers, in some embodiments, the method comprises employing an exogenous coolant to cool the exhaust flue gas in one or more of the secondary heat exchangers during initiation of the carbon dioxide extraction process.|In some embodiments, the exogenous coolant is used to cool exhaust flue gas until sufficient gaseous nitrogen is extracted from the exhaust flue gas to sufficiently cool the primary and/or secondary heat exchangers e.g. to achieve the desired level of cooling. In some embodiments, the exogenous coolant is used in addition to extracted gaseous nitrogen to cool exhaust flue gas in the primary heat exchanger and/or one or more secondary heat exchangers. In some embodiments, the exogenous coolant is exogenous gaseous nitrogen.|In some embodiments, the method comprises regulating the flow of coolant through the primary heat exchanger and/or the secondary heat exchanger. The rate of flow of the coolant determines the rate of cooling of the exhaust flue gas. Increasing the flow of coolant typically increases the rate of cooling of the exhaust flue gas. Reducing the flow of coolant typically reduces the rate of cooling of the exhaust flue gas.|In some embodiments, the primary heat exchanger cools exhaust flue gas to a temperature of less than -10°C, less than -15°C, less than -20°C, less than -25°C, less than -30°C, less than -35°C, less than|- 40°C, less than -45°C, less than -50°C, less than -55°C, or less than -60°C. In some embodiments, the primary heat exchanger cools exhaust flue gas to a temperature of less than -30°C, optionally less than|- 40°C.|In some embodiments, the compressing comprises compressing the exhaust flue gas to least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, at least 5 MPa, at least 6 MPa, at least 7 MPa, at least 8 MPa, at least 9 MPa, or at least 10 MPa. In some embodiments, compressing comprises compressing the exhaust flue gas to at least 10 MPa. In some embodiments, the compressing comprises compressing the cooled exhaust flue gas more than once. In some embodiments, the method comprises initially compressing the exhaust flue gas to at least 1 MPa and then subsequently compressing the exhaust flue gas to at least 10 MPa.|In some embodiments, the method further comprises delivering compressed cooled exhaust flue gas to a secondary heat exchanger. In some embodiments, the secondary heat exchanger cools the compressed cooled exhaust flue gas to a temperature of less than 0°C, less than -5°C, or less than -10°C.|In some embodiments, the method comprises: (i) compressing the cooled exhaust flue gas; (ii) cooling the compressed cooled exhaust flue gas; (iii) compressing the cooled exhaust flue gas; and then (iv) cooling the compressed cooled exhaust flue gas. In some embodiments, the method comprises: (i) compressing the cooled exhaust flue gas to less than 1 MPa; (ii) cooling the compressed cooled exhaust flue gas to a temperature of less than -10°C; (iii) compressing the cooled exhaust flue gas to less than 10 MPa; and then (iv) cooling the compressed cooled exhaust flue gas to a temperature of less than -10°C.|In some embodiments, the method comprises collecting solid carbon dioxide and allowing it to melt to form liquid carbon dioxide. In some embodiments, carbon dioxide is maintained at a pressure of at least 1 MPa, at least 2 MPa, at least 3 MPa, at least 4 MPa, or at least 5 MPa in the holding tank. In some embodiments, carbon dioxide is maintained at a pressure of 3 MPa in the holding tank. In some embodiments, liquid carbon dioxide is stored in cryogenic pressure vessel equipment.|In some embodiments, the method further comprises converting solid carbon dioxide to carbon dioxide ice. In some embodiments, solid carbon dioxide is converted to carbon dioxide ice by hydraulic pressing.|Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying figures which are not drawn to scale.|Figure 1 provides a schematic representation of an exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, and carbon dioxide collection vessel.|Figure 2 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, and carbon dioxide collection vessel.|Figure 3 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary compressor, and carbon dioxide collection vessel.|Figure 4 provides a schematic representation of another exemplary apparatus according to the invention comprising primary heat exchanger, primary compressor, secondary heat exchanger, secondary compressor, tertiary heat exchanger, and carbon dioxide collection vessel.|An exemplary apparatus according to the invention is shown in Figure 1. The apparatus of the invention comprises a primary heat exchanger 10, a primary compressor 20, and a carbon dioxide collection vessel 30 comprising a throttling valve 32 and a holding tank 36. The apparatus may comprise means 12 for connecting to an exhaust flue. The apparatus may further comprise an impeller 14 for propelling exhaust flue gas into the primary heat exchanger 10. The carbon dioxide collection vessel 30 may comprise an outlet 34 for extracting gaseous nitrogen, and a gaseous nitrogen transfer conduit 40 in fluid communication with the primary heat exchanger 10.|The apparatus of Figure 2 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60.|The apparatus of Figure 3 comprises all features of the apparatus of Figure 1 and additionally comprises a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the primary compressor 20 prior to transfer of the compressed cooled exhaust flue gas to the throttling valve 32.|The apparatus of Figure 4 comprises the features of the apparatus of Figure 1 and additionally comprises: a secondary heat exchanger 60 for receiving and cooling compressed cooled exhaust flue gas from the primary compressor 20; a secondary compressor 25 for receiving and compressing compressed cooled exhaust flue gas from the secondary heat exchanger 60; and a tertiary heat exchanger 65 for receiving and cooling compressed cooled exhaust flue gas from the secondary compressor 25. In this embodiment, the gaseous nitrogen transfer conduit 40 may also be in fluid communication with the secondary heat exchanger 60 and/or tertiary heat exchanger 65.|Transfer conduits 50-58 are for transferring exhaust flue gas through the apparatus as depicted in Figures 1-4.|Specific example|The invention will now be described with reference to the following non-limiting example.|Exhaust flue gases may be redirected from the exhaust flue exit point that connects with the open-air environment, such as the above ground open air exit of a chimney into the lower atmosphere between 20 and 100 metres above ground level. The exhaust flue exit may be adapted to connect to a connection means, e.g. tubing comprising a 180° bend, to redirect exhaust flue gases towards the primary heat exchanger which may be at ground level. This downward directional tubing may connect to a manifold housing an internal impeller for propelling exhaust flue gases into the primary heat exchanger, optionally into a labyrinth chamber of the primary heat exchanger. This downward directional tubing may connect directly to the primary heat exchanger. The primary heat exchanger may comprise a labyrinth chamber comprising a network array matrix of interconnecting channels and tubing that inter-collectively contain a series of pressure vessel conduits acting as a large heat exchanger for the transport of a coolant, e.g. cold and vented gaseous nitrogen. This cold, gaseous nitrogen does not typically come into direct contact with the exhaust flue gases. The pressure vessel tubing of the conduits acts as a conductor of heat from the exhaust flue gases into the coolant, e.g. the gaseous nitrogen, thereby heating the coolant and simultaneously cooling the exhaust flue gases in the heat exchange chiller labyrinth. The exhaust flue gases may be cooled to a temperature of at least -40°C. Gaseous nitrogen may be allowed to cool and vented to the atmosphere after flowing through the conduits of the primary heat exchanger.|Control over the temperature of the exhaust flue gases in the primary heat exchanger may be performed by control means configured to control the rate of flow of the cold gaseous nitrogen in the heat exchange chiller labyrinth. Increasing the rate of flow of cold gaseous nitrogen cools the exhaust flue gases quicker and slowing the rate of flow of cold gaseous nitrogen helps prevent the exhaust flue gases cooling down below the desired temperature, e.g. -40°C. Flow rate may be controlled by flow sensors in the cold gaseous nitrogen pumping system. The size of the heat exchange chiller labyrinth is typically designed to match the known maximum gas flow rate obtained from the exhaust flue during functional operation of the engine, boiler or coal-fired power station, so that the thermodynamic heat fluxes of the two temperature regimes are synchronised to accommodate from the known temperature of the gases upon leaving the original chimney design until exiting the heat exchange chiller labyrinth system. Typically, this may result in a temperature drop from between 50°C and 90°C to between -10°C and -40°C, ideally at least -30°C, or preferably at least -40°C.|The main function of chilling the exhaust flue gases is to prepare the gases for phase change. The heat exchange chiller labyrinth itself does not initiate the phase change - it changes the temperature of the gases but not the pressure. As such, the exhaust flue gases are typically cooled to a temperature of 40°C and remain in gaseous state at the point of leaving the primary heat exchanger. As the cooled exhaust flue gases leave the primary heat exchanger, the external surface of the transfer conduits that deliver cooled exhaust flue gases through the apparatus are typically insulated to ensure that the gases remain at their cooled temperature throughout their transitionary passage to formation of primarily solid carbon dioxide and secondarily liquid carbon dioxide.|Upon leaving the heat exchange chiller labyrinth, the cooled exhaust flue gas is typically delivered via transfer conduit(s) to a primary compressor. The primary compressor may compress the exhaust flue gases from approximately 10 KPa to approximately 1 MPa. After primary stage compression, exhaust flue gases may be partially warmed as a result of a reduction in their volume during the compression process. Exhaust flue gases may then be chilled back to about -10°C in a secondary heat exchanger. The compressed cooled exhaust flue gas may then be compressed by a secondary compressor to compress the compressed cooled exhaust flue gas from approximately 1 MPa to 10 MPa. Compressed cooled exhaust flue gases may then be chilled back to -10°C via exposure to the same secondary heat exchanger or a tertiary heat exchanger.|Compressed cooled exhaust flue gases typically contain multiphase flow of gaseous nitrogen, as well as chilled gaseous carbon dioxide. Other majority contaminants from coal-fired power station may have previously been removed using a flue gas desulphurisation cleaning process for removal of SOx, prior to delivery of the exhaust flue gas to the primary heat exchanger, thus ensuring that most of the gases in the apparatus comprise gaseous nitrogen and carbon dioxide. This cold gas mixture may be maintained within the system by means of placement of cryogenic non-return check valves in unidirectional flow. Check valves may help to prevent thermal bridging and maintain states of matter. Optionally, adjacent and strategically placed heat exchangers and/or maintenance compressors may be present to ensure that during transit of the exhaust flue gases through the apparatus, the temperature and pressure of the gas is maintained.|The compressed cooled exhaust flue gas is delivered to a throttling valve. The throttling valve acts to change unilateral liquid flow into turbulent flow. In the throttling valve there is typically an adiabatic drop due to the pressure drop with increased gas velocity. Simultaneously, upon ejection of the compressed cooled exhaust flue gas from the throttling valve, the tubular aperture may be significantly increased, e.g. at least 50-fold, so that the cross-sectional area of the compressed cooled exhaust flue gas before the throttling valve is significantly smaller than the cross-sectional area, e.g. 1/50 of the cross-sectional area, of the venting tube after the throttling valve. Simultaneously, the exit from the throttling valve may extend in a tubular cone orientation as the output end of the contents of throttling valve of the compressed cooled exhaust flue gas extend into the larger aperture holding chamber. The tubular cone extension on the output side of the throttling valve may act to create cyclonic turbulent flow and a sudden drop in pressure, with a simultaneous drop in temperature. This typically creates the phase change formation from gaseous cold carbon dioxide into a deposition phase transition, or reverse sublimation process into solid carbon dioxide 'snow' at a temperature below -78°C and mixed with cold gaseous nitrogen. The cold gaseous nitrogen may be vented, collected and pumped for reverse passage through the primary and/or secondary heat exchangers. The holding tank is typically designed to accommodate the volumetric space required for the input of solid carbon dioxide 'snow', so that its accumulation can readily be melted from solid carbon dioxide 'snow' into liquid carbon dioxide. The entire cooled zone from the primary heat exchanger through to the carbon dioxide collection vessel may be insulated to prevent heat influx from the external environment. The liquid carbon dioxide product may be stored using conventional cryogenic pressure vessel equipment of either tank or bulk storage systems, and transported to pertinent markets worldwide. Alternatively, hydraulic pressing may be used as a functional methodology to change the form of solid crystalline carbon dioxide snow into compressed carbon dioxide ice, or dry ice.|The apparatus may comprise a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue. The purpose of the gas bypass system is to act as a regulatory control mechanism, coupling to the exhaust flue and preceding placement of the primary heat exchanger described herein. The gas bypass system simultaneously avoids unwanted back pressure on the engine or boiler, allowing smooth, continuous and uninterrupted flow of exhaust flue gases from the engine or boiler, thereby ensuring that the regulatory control feedback mechanism for the temperature and pressure of the engine or boiler is functional. The exhaust flue gas bypass system may be constructed as a partitioned parallel exhaust chamber with a warmer than ambient temperature internal gaseous flow control mechanism. The secondary partitioned parallel exhaust chamber may have a modified heat and pressure take-off ensuring that exhaust flue modifications do not compromise or have any effects on the designed operations and efficiency of the engine or boiler by means of a unidirectional gas flow valve flap. | Family Number|(99263641)|99263641|Advantages / Prev. Drawbacks|(GB2615109 A)|Moreover, BECCS is prohibitively expensive at a cost of between $80-200/tonne of carbon dioxide gas removal, and biomass co-fired with coal reduces the efficiency of electricity generation. | | Chemical engineering | F23J-015/02|F23J-015/06|F23J-2215/50|F25J-001/00/27|F25J-001/00/4|F25J-001/02/01|F25J-003/06/7|F25J-2205/20|F25J-2210/70|F25J-2220/82|F25J-2230/04|F25J-2230/08|F25J-2230/30|Y02C-020/40 | F23J-015/02|F23J-015/06|F23J-2215/50|F25J-001/00/27|F25J-001/00/4|F25J-001/02/01|F25J-003/06/7|F25J-2205/20|F25J-2210/70|F25J-2220/82|F25J-2230/04|F25J-2230/08|F25J-2230/30|Y02C-020/40 | F25J-001/00|F25J-003/06 | F25J-001/00|F25J-003/06 | WO202162130|US20200309451|US20110296870 | WO202162130 93403262 WHO=Examiner SELF=N|US20200309451 90836177 WHO=Examiner SELF=N|US20110296870 44375978 WHO=Examiner SELF=N | WO202162130; US20200309451; US20110296870 | LAPSED | (GB2615109)|LAPSED | DEAD | (GB2615109)|DEAD | (GB2615109)|LEGAL DETAILS FOR GB2615109|Actual or expected expiration date=2024-06-12|Legal state=DEAD|Status=LAPSED|Event publication date=2022-01-28|Event code=GB/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=GB GB202201121|Application date=2022-01-28|Standardized application number=2022GB-0001121|Event publication date=2022-03-16|Event code=GB/D0|Event indicator=Pos|Event group=Examination events|Patent application filed|Publication country=GB|Publication number=GB202201121|Publication stage code=D0|Publication date=2022-03-16|Standardized publication number=GB202201121|Event publication date=2023-08-02|Event code=GB/A|Event group=Examination events|Published Application|Publication country=GB|Publication number=GB2615109|Publication stage code=A|Publication date=2023-08-02|Standardized publication number=GB2615109|Event publication date=2024-06-12|Event code=GB/WAP|Event indicator=Neg|Event group=Event indicating Not In Force|Application withdrawn, taken to be withdrawn or refused ** after publication under section 16(1) | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=BjeEns4sQtGxVFF8qwZ7nBX4n5EyVake66kX6Irr/smw0ZQBgTMhTs9Ry4MrhQjLALkMBz8hwaI=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=GB0000000002864938&ekey=2390&xpn=GB2615109&kind=A | http://www.ipo.gov.uk/p-ipsum/Case/PublicationNumber/GB2615109 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=yrF0oKa2gzI1zTc2PWcWRHfDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | GB | (GB2615109)|NAME=Matthew Pearce|NAME=Ray Middleton | (GB2615109)|4 | 1 | 1 | (GB2615109)|Number of Claims: NCL=21||(GB202201121)|Gazette date: GAZDATE=2022-03-16| | (GB2615109)|Patent|(GB202201121)|Patent | Titre: (GB2615109)|Extraction device Résumé: (GB2615109)|The invention relates to an apparatus for the extraction of solid and/or liquid carbon dioxide from exhaust flue gas, comprising a primary heat exchanger 10, which connects to a first heat exchanger 20, which cools the flue gas, and a storage tank 36, comprising a throttle valve 32 and a storage capacity. In some embodiments, there may be multiple heat exchangers, or gaseous nitrogen may be transferred from the storage tank for use in the heat exchanger. Autre: (GB2615109)|1. An apparatus for extracting solid and/or liquid carbon dioxide from exhaust flue gas, the apparatus comprising:|a) a primary heat exchanger for receiving and cooling the exhaust flue gas;|b) a primary compressor in fluid communication with the primary heat exchanger for receiving and compressing cooled exhaust flue gas from the primary heat exchanger; and|c) a carbon dioxide collection vessel in fluid communication with the primary compressor, wherein the carbon dioxide collection vessel comprises:|(i) a throttling valve for receiving compressed cooled exhaust flue gas from the primary compressor; and|(ii) a holding tank for containing solid and/or liquid carbon dioxide.|2. The apparatus of claim 1 further comprising one or more secondary heat exchangers for receiving and cooling compressed cooled exhaust flue gas from the primary compressor prior to passage of the compressed cooled exhaust flue gas to the carbon dioxide collection vessel.|3. The apparatus of claim 1 or claim 2, wherein the carbon dioxide collection vessel further comprises an outlet for gaseous nitrogen, wherein the outlet is in fluid communication with the primary heat exchanger and/or the outlet is in fluid communication with one or more of the secondary heat exchangers.|4. The apparatus of any preceding claim further comprising means for connecting in fluid communication the primary heat exchanger and the exhaust flue.|5. The apparatus of any preceding claim further comprising a gas bypass system for venting excess exhaust flue gas, wherein the gas bypass system is situated between the primary heat exchanger and the exhaust flue.|6. The apparatus of any preceding claim, wherein the primary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel.|7. The apparatus of claim 6, wherein the array of conduits forms a labyrinth chamber for receiving the exhaust flue gas.|8. The apparatus of any of claims 2-7, wherein the secondary heat exchanger comprises an array of conduits for receiving gaseous nitrogen from the carbon dioxide collection vessel.|9. The apparatus of claim 8, wherein the array of conduits forms a labyrinth chamber for receiving the compressed cooled exhaust flue gas.|10. The apparatus of any preceding claim further comprising an impeller for propelling the exhaust flue gas into the primary heat exchanger.|11. The apparatus of any preceding claim further comprising one or more impellers for propelling the compressed cooled exhaust flue gas into one or more of the one or more secondary heat exchangers.|12. The apparatus of any preceding claim further comprising a secondary compressor for receiving and compressing compressed cooled exhaust flue gas from the primary compressor.|13. The apparatus of any preceding claim, wherein one or more of the one or more secondary heat exchangers is situated between the primary compressor and the secondary compressor.|14. The apparatus of any preceding claim, wherein one or more of the one or more secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|15. The apparatus of any preceding claim, wherein: (a) one or more of the secondary heat exchangers is situated between the primary compressor and the secondary compressor; and (b) one or more of the secondary heat exchangers is situated between the secondary compressor and the carbon dioxide collection vessel.|16. The apparatus of any preceding claim, wherein the apparatus comprises one or more valves for maintaining unidirectional flow of exhaust flue gas.|17. A method for producing solid or liquid carbon dioxide from exhaust flue gas, the method comprising:|a) delivering exhaust flue gas to a primary heat exchanger to provide cooled exhaust flue gas;|b) compressing the cooled exhaust flue gas to provide compressed cooled exhaust flue gas, and optionally delivering the compressed cooled exhaust flue gas to a secondary heat exchanger; and|c) throttling the compressed cooled exhaust flue gas through a throttling valve to provide solid and/or liquid carbon dioxide.|18. The method of claim 17, wherein the method further comprises separating gaseous nitrogen from the solid and/or liquid carbon dioxide and supplying the separated gaseous nitrogen to the primary and/or secondary heat exchanger.|19. The method of claim 17 or claim 18, wherein the cooling comprises reducing the temperature of the gas to less than -10°C.|20. The method of any of claims 17-19, wherein the compressing comprises compressing the gas to at least 1 M Pa.|21. The method of any of claims 17-20, wherein the method further comprises converting solid carbon dioxide to carbon dioxide ice by hydraulic pressing. | 25 | Abstract | gpt-4o-mini | no | The article focuses on an extraction device for carbon dioxide from exhaust flue gas, without any mention of biomass energy production or integrated BECCS systems. | |||||||||||||||||||||||||||||
| 29 | US63/155,572P|WOUS2022/018484|US18/241,522 | WOUS2022/018484|EP22763957|KR10-2023-7032426|US18/241,522|CN202280032298|JP2023553989 | EP4376984|KR10-2024-0157528|US20240269605|CN118201696|EP4376984|JP2024512355|WO2022/187336 | 101683925 | WO2022/187336 A1 2022-09-09 [WO2022187336]|EP4376984 A4 2025-08-27 [EP4376984]|EP4376984 A1 2024-06-05 [EP4376984]|KR10-2024-0157528 A 2024-11-01 [KR20240157528]|US20240269605 A1 2024-08-15 [US20240269605]|CN118201696 A 2024-06-14 [CN118201696]|JP2024512355 A 2024-03-19 [JP2024512355] | 2021-03-02|2022-03-02|2023-09-01 | 2022-03-02|2022-03-02|2022-03-02|2022-03-02|2022-03-02|2022-03-02 | 2025-08-27|2024-11-01|2024-08-15|2024-06-14|2024-06-05|2024-03-19|2022-09-09 | (EP4376984)|2042-03-02|(US20240269605)|2042-03-02|(WO2022/187336)|2024-09-02|(JP2024512355)|2025-10-15|(CN118201696)|2042-03-02|(KR10-2024-0157528)|2025-09-18 | (EP4376984)|Systems and methods for enhanced weathering and calcining for co2 removal from air | (EP4376984)|Embodiments described herein relate to systems and methods of CO2 uptake. In one aspect, a method includes applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2. The method further includes sequestering and/or utilizing the gas stream, feeding the stream of the carbonation medium to a carbonation station, contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream, during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours, and feeding the carbon-containing stream to the calciner. In some embodiments, adding the water stream is via misting and/or spraying. | COLUMBIA UNIVERSITY|UNIVERSITY OF BRITISH COLUMBIA|UNIVERSITY OF PENNSYLVANIA | (EP4376984)|The Trustees Of Columbia University In The City Of New York|The University of British Columbia|The Trustees of The University of Pennsylvania|(EP4376984)|The Trustees Of Columbia University In The City Of New York ([US])|The University of British Columbia ([CA])|The Trustees of The University of Pennsylvania ([US])|(US20240269605)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK ([US])|(WO2022/187336)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK ([US])|THE UNIVERSITY OF BRITISH COLUMBIA ([CA])|THE TRUSTEES OF THE UNIVERSITY OF PENNSYLVANIA ([US])|(JP2024512355)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK|UNIVERSITY OF BRITISH COLUMBIA|TRUSTEES OF THE UNIV OF PENNSYLVANIA|(CN118201696)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK ([US])|THE UNIV. OF BRITISH COLUMBIA|THE TRUSTEES OF THE UNIVERSITY OF PENNSYLVANIA|(KR10-2024-0157528)|THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK ([US])|THE UNIVERSITY OF BRITISH COLUMBIA ([CA])|THE TRUSTEES OF THE UNIVERSITY OF PENNSYLVANIA ([US]) | MORTIMER THOMAS|KELEMEN PETER BOUSHALL|MCGILLIS WADE|WILCOX JENNIFER|MCQUEEN NOAH|DIPPLE GREG | (EP4376984)|MORTIMER, Thomas|KELEMEN, Peter, Boushall|MCGILLIS, Wade|WILCOX, Jennifer|MCQUEEN, Noah|DIPPLE, Greg|(EP4376984)|MORTIMER, Thomas|KELEMEN, Peter, Boushall|MCGILLIS, Wade|WILCOX, Jennifer|MCQUEEN, Noah|DIPPLE, Greg | (EP4376984)|Sayettat, Julien Christian;Strato-IP ([FR])|Reg. Nb: 101676761|(WO2022/187336)|GANGEMI, Anthony, P. ([US])|(JP2024512355)|MINAMI AOYAMA PATENT AND TRADEMARK ATTORNEYS|Reg. Nb: 110003339|(CN118201696)|FAN YUNFEI;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC|Reg. Nb: 31100|WANG YING;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC|Reg. Nb: 31100|(KR10-2024-0157528)|CHOI, DUG-KYU | (US20240269605)|In some embodiments, the air separation unit 170 can allow for more efficient combustion in the calciner 120 as the air separation unit 170 can remove contaminants and inert materials from the air prior to feeding to the calciner 120 .|Magnesium is also an attractive option, as there are large deposits of magnesium-rich minerals throughout the world.|This can be an advantageous layout, as it minimizes the distance carbonation medium and the carbon-containing streams travel for processing between the process units.|CO2 removal from air is more difficult than CO2 capture from flue gas.|The National Academies Report on Negative Emissions Technologies from 2019 concluded that none of these methods, individually, can reach the required goal, so an ensemble of methods should be used.|These solutions are often expensive, and they occasionally employ designer materials that may be difficult to produce.| | (US20240269605)|1. A method, comprising: applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2; at least one of sequestering or utilizing the gas stream; feeding the stream of the carbonation medium to a carbonation station; contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream; during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours; and feeding the carbon-containing stream to the calciner.|16. A method, comprising: applying heat to a calciner to decompose a carbon-containing stream into a gas stream and a stream of a carbonation medium, the gas stream including CO2; at least one of sequestering or utilizing the gas stream; feeding the stream of the carbonation medium to a carbonation station; contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream; during the contacting, spraying and/or misting a water stream to the carbonation medium at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium; and feeding the carbon-containing stream to the calciner.|23. A method, comprising: decomposing a carbon-containing stream into a gas stream and a stream of a carbonation medium in a calciner, the gas stream including CO2, the carbonation medium including at least one of MgCO3, sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, nesquehonite, or hydromagnesite; sequestering the gas stream; feeding the stream of the carbonation medium to a carbonation station; contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream; during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium; and feeding the carbon-containing stream to the calciner.| | (US20240269605)|Embodiments described herein relate to systems and methods of CO2 uptake.|Some embodiments of the present disclosure are directed to CO2 uptake from air during weathering.| | (US20240269605)|AIR(100,25)|CO2 REMOVAL(100,9)|CALCINATION(100,7)|CARBONATION STREAM(100,6)|ENHANCED WEATHERING(100,3)|CARBONATION STATION(96,36)|CARBONATION MEDIUM(84,93)|CARBONATION CONTACTOR(70,3)|CARBONATION(61,121)|GAS STREAM(55,53)|CALCINER(54,88)|CARBONATION MEDIUM GRAM(54,8)|CARBONATION MEDIUM STREAM(46,10)|CO2 UPTAKE(43,22)|CARBON DECOMPOSITION(42,6)|NATIONAL ACADEMY REPORT(39,1)|HYDROMAGNESITE(31,5)|NESQUEHONITE(30,5)|CO2(29,53)|NEGATIVE EMISSION(29,4)|MAGNESIUM RICH MINERAL(28,1)|DISTANCE CARBONATION MEDIUM(24,1)|LAYOUT(23,1)|STREAM TRAVEL(23,1)|HEAT APPLICATION(22,7)|SPRAYING(22,5)|CALCIUM BICARBONATE(22,4)|CARBONATION SHEET(22,2)|CONTAMINANT(21,1)|NATIONAL ACADEMY(21,1)|SODIUM BICARBONATE(19,4)|CARBONATION MEDIUM SHEET(19,2)|CALCIUM CARBONATE(18,5)|CARBONATION IMMEDIATE PROXIMITY(18,5)|BALL MILL CRUSHER(18,4)|MGCO3(17,15)|OXYGEN STREAM(17,6)|SILICON CARBONATE(17,4)|DOLOMITE(16,4)|WATER STREAM(15,28)|CARBONATION GRAM(15,6)|SODIUM CARBONATE(15,6)|COMBUSTION(15,3)|CALCIUM SILICATE(14,3)|MAGNESIUM SILICATE(14,3)|POTASSIUM BICARBONATE(14,3)|CO2 MITIGATION DIVERSE PORTFOLIO(13,1)|PETRI DISH(12,5)|MAGNESIUM HYDROXIDE(12,3)|DESIGNER MATERIAL(12,1)|LARGE DEPOSIT(12,1)|METHOD ENSEMBLE(12,1)|AMBIENT AIR(11,32)|SPRAYER(11,18)|POTASSIUM CARBONATE(11,4)|SILICON DIOXIDE(11,3)|CO2 TON(10,6)|CONE CRUSHER(10,4)|OXY FIRED CALCINER(10,4)|SODIUM HYDROXIDE(10,4)|CARBONATION MEDIUM TON(10,3)|POTASSIUM OXIDE(9,3)|ADSORBENT MATERIAL(9,1)|INERT MATERIAL(9,1)|AIR SEPARATION(8,18)|MAGNESIUM OXIDE(8,5)|IMPACT CRUSHER(8,4)|MAGNESIUM CALCIUM CARBONATE(8,4)|HYDRATION STATION(8,3)|CARBONATION MEDIUM IMMEDIATE PROXIMITY(8,2)|FLUE GAS(8,2)|ALTERED PERIDOTITE PROPORTION(8,1)|CALCINING THOROUGHNESS(8,1)|CARBONATION CONVEYANCE(8,1)|CARBONATION PLOT VICINITY(8,1)|CO2 UPTAKE VARIABILITY(8,1)|EXPERIMENT EVALUATED CO2 UPTAKE(8,1)|GLOBAL MGCO3 RESERVE(8,1)|HINDERING CO2 UPTAKE(8,1)|OCEAN CO2 UPTAKE(8,1)|REPLENISHING SPENT MGO(8,1)|CALCIUM OXIDE(7,5)|SEQUESTRATION SPACE(7,4)|CARBONATION MEDIUM STREAM CM(7,3)|SODIUM OXIDE(7,3)|CARBONATION STATION ILLUSTRATION(7,2)|HUMID ENCLOSURE(7,2)|AUTHORITATIVE ORGANIZATION(7,1)|CARBONATION AFFINITY(7,1)|CLUSTERED CARBONATION(7,1)|MINED CARBONATION(7,1)|TERRESTRIAL BIOSPHERE(7,1)|UNDERGROUND SEQUESTRATION(7,1)|CACO3(6,14)|CO2 UPTAKE RATE(6,3)|MGO POWDER(6,3)|CARBON MINERALIZATION(6,2)|CARBONATION MEDIUM POWDER(6,2)|GRINDING STATION(6,2)|CAO TON(6,1)|CARBONATION LAYOUT(6,1)|CARBONATION MEDIUM HYDRATION(6,1)|CAUSTIC MAGNESIA(6,1)|CO2 FLUX ESTIMATE(6,1)|LIMESTONE MT(6,1)|LIMESTONE RESERVE(6,1)|MAKEUP FEEDSTOCK(6,1)|MEASURING HEADSPACE CO2(6,1)|MGCO3 FEEDSTOCK(6,1)|MINE TAILING(6,1)|MISTING PLOT(6,1)|NONCONTIGUOUS PLOT(6,1)|OCEAN FERTILIZATION(6,1)|PREMIER MAGNESIA(6,1)|SOLAR CALCINER(6,1)|UNLIMITED RESOURCE(6,1)|UNLISTED ITEM(6,1)|PEBBLE(5,4)|RENEWABLE ELECTRICITY(5,4)|SEA(5,4)|TARGET COMPOUND(5,4)|GAS ANALYZER(5,3)|CALCINATION CYCLE(5,2)|CO2 UPTAKE DATA(5,2)|NONLINEARITY(5,2)|RECYCLED CARBON(5,2)|SOLID CARBONATE MINERAL(5,2)|STIRRING IMPLEMENT(5,2)|ADSORB CO2(5,1)|AGRICULTURAL SOILS CARBON CONTENT(5,1)|ANNUAL US PRODUCTION(5,1)|CALCINATION RESIDUE(5,1)|CALCIUM CAUSTIC RECOVERY LOOP(5,1)|CALCIUM SORBENT(5,1)|CAO FULL AGGLOMERATION(5,1)|CAO LOOPING(5,1)|CARBONATED MEDIA(5,1)|CARBONATION CONVERSION(5,1)|CARBONATION MEDIUM PLOT(5,1)|CO2 CONTACTOR(5,1)|CO2 CONTRIBUTION(5,1)|CO2 DISSOLUTION(5,1)|CO2 REMOVAL ENGINEERED ROUTE(5,1)|FLUIDIZED BED CALCINER(5,1)|FUTURE CO2 EMISSION(5,1)|GENERALIZED NATURAL WEATHERING REACTION(5,1)|GLOBAL RELIANCE(5,1)|GROWING CONSENSUS(5,1)|HUMAN SUSTAINABILITY(5,1)|HYBRID CALCINER(5,1)|HYDRATED MG CARBONATE(5,1)|KOH SORBENT(5,1)|LI COR INSTRUMENT CHAMBER(5,1)|LIMESTONE PRIMARY CONSTITUENT(5,1)|MGO PRODUCTION BRAND(5,1)|MGO SUPPLIER(5,1)|MINERAL CARBONATION REACTION(5,1)|NONARABLE LAND(5,1)|OPTIMISTIC COST ESTIMATE(5,1)|PLURAL REFERENT(5,1)|ROCK MINING(5,1)|ROTARY KILN CALCINER(5,1)|SOLD UNDERGROUND(5,1)|STIRRING CARBONATION MEDIUM(5,1)|TECHNOLOGY FOCUS(5,1)|TRANSPORTING CARBONATION MEDIUM(5,1)|UPTAKE PLOT(5,1)|AVERAGE PARTICLE SIZE(4,10)|TRAY(4,6)|CONVEYER(4,4)|MATERIAL CO2 UPTAKE(4,3)|WATER DELIVERY(4,3)|AIR VELOCITY(4,2)|BYPRODUCT(4,2)|CO2 REACTION(4,2)|AMBIENT WEATHERING(4,1)|AMERICAN PHYSICAL SOCIETY(4,1)|CAO SAMPLE(4,1)|CAPTURED CO2(4,1)|CARBONATE BEVERAGE(4,1)|CARBONATION CYCLE(4,1)|CARBONATION MEDIUM CONVERSION(4,1)|CARBONATION MEDIUM MOISTURE CONTENT(4,1)|CARBONATION THIN SHEET(4,1)|CARBONATION WIDTH DIMENSION(4,1)|CATASTROPHIC IMPACT(4,1)|CENTRAL REGENERATION FACILITY(4,1)|CO2 ADSORPTION(4,1)|CO2 GT(4,1)|CO2 STORAGE OPPORTUNITY(4,1)|CO2 UPTAKE CAPACITY(4,1)|DEPOSIT LIME(4,1)|EXCLUSIVITY TERM(4,1)|FEEDSTOCK TRANSPORT(4,1)|FINE MIST(4,1)|GRAFTED AMINE(4,1)|GRID ELECTRICITY(4,1)|HEAVY CO2 EXHAUST(4,1)|HYDRATED CARBONATE(4,1)|HYDROUS MG CARBONATE MINERAL(4,1)|HYPOTHETICAL MGO ENERGY BALANCE(4,1)|LI COR SOIL(4,1)|MATURATION DATE(4,1)|MEASURED CO2 UPTAKE(4,1)|MGCO3 CALCINATION TEMPERATURE(4,1)|MGO REACTANT(4,1)|NATURAL ACCELERATION(4,1)|OCEANIC PH(4,1)|OXIDE REACTANT(4,1)|PERIDOTITE HEATING(4,1)|SEQUESTERED GAS STREAM(4,1)|TARGETED ROCK(4,1)|DIVALENT METAL CATION(3,3)|GLOBAL WARMING(3,3)|LARGE ROCK(3,3)|MINED MATERIAL(3,3)|BIOENERGY(3,2)|CARBONATION MEDIUM CONTACT(3,2)|CEMENT(3,2)|CONDENSATION SPACE(3,2)|COST ESTIMATION(3,2)|DECLINE(3,2)|METAL CARBONATE(3,2)|MODEL CURVE(3,2)|PHOTOVOLTAICS(3,2)|RECYCLING WATER(3,2)|ULTRAMAFIC ROCK(3,2)|WATER RECYCLED STREAM(3,2)|ADDING BIOMASS(3,1)|ALKALINITY ADDITION(3,1)|AQUEOUS CALCIUM LOOPING(3,1)|CALCIUM HYDROXIDE CONSUMPTION(3,1)|CAO LOSS(3,1)|CARBON REMEDIATION COMPONENT(3,1)|CAVITY ENHANCED ABSORPTION SPECTROSCOPY(3,1)|CO2 DIFFUSION(3,1)|CO2 RICH FUEL(3,1)|COMBUSTION MEDIUM(3,1)|CONTINUING EXPERIMENT(3,1)|DAILY STIRRING(3,1)|DECAY OBSERVATION(3,1)|ELECTRIC FIRED CALCINER(3,1)|ELECTRIC KILN(3,1)|ENERGY INVESTMENT(3,1)|ENHANCING ABSORPTION SPECTROSCOPY(3,1)|ENSEMBLE COST(3,1)|ENTERPRISE USER(3,1)|EXCLUSION LIMIT(3,1)|EXPONENTIAL FIT(3,1)|FINE GRAINED MGO(3,1)|FOG(3,1)|FUEL COMBUSTION(3,1)|GAS FLOWMETER(3,1)|GEOLOGIC TIMESCALE(3,1)|GEOLOGICAL TIMESCALE(3,1)|GEOMETRIC RELATIONSHIP(3,1)|GRINDING MEDIA(3,1)|HYDRATED MAGNESIUM CARBONATE(3,1)|HYDRATED SODIUM CARBONATE(3,1)|INTERMEDIATE STATION(3,1)|LOOPING COST(3,1)|MAXIMIZE GROUND(3,1)|MGO SAMPLE(3,1)|OVAL PATTERN(3,1)|OXYGEN INTRODUCTION(3,1)|PLANET REGION(3,1)|PRIMARY COMPONENT(3,1)|PURITY CO2 CONDITION(3,1)|REMAINING REACTANT(3,1)|SINGULAR FEATURE(3,1)|SOUTHERN REGION(3,1)|STACKED COLUMN(3,1)|TERM ORDINARY MEANING(3,1)|UPTAKE PERFORMANCE(3,1)|VALUABLE CO2 REMOVAL(3,1)|VOL CO2(3,1)|ELECTRICAL RESISTANCE HEATING(2,7)|ACRYLONITRILE(2,1)|ADOPTION(2,1)|AFFORESTATION(2,1)|AGRICULTURE(2,1)|AQUEOUS POTASSIUM HYDROXIDE(2,1)|BIOPOLYMER(2,1)|BRUCITE(2,1)|CALCINING TEMPERATURE(2,1)|CALCITE(2,1)|CALCIUM BEARING MINERAL(2,1)|CAPTURE CONTROL ENVIRONMENT(2,1)|CARBON CAPTURE FACILITY COMPONENT(2,1)|CARBON CAPTURE FACILITY 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MEDIA(3,1)|HEAVY CO2 EXHAUST(3,1)|HYDRATED CARBONATE(3,1)|HYDRATED MAGNESIUM CARBONATE(3,1)|HYDRATED SODIUM CARBONATE(3,1)|HYDROUS MG CARBONATE MINERAL(3,1)|HYPOTHETICAL MGO ENERGY BALANCE(3,1)|INTERMEDIATE STATION(3,1)|LI COR SOIL(3,1)|LOOPING COST(3,1)|MATURATION DATE(3,1)|MAXIMIZE GROUND(3,1)|MEASURED CO2 UPTAKE(3,1)|MGCCB CALCINATION TEMPERATURE(3,1)|MGO REACTANT(3,1)|MGO SAMPLE(3,1)|NON CONTI GUOUS PLOT(3,1)|OCEANIC PH(3,1)|OVAL PATTERN(3,1)|OXIDE REACTANT(3,1)|OXYGEN INTRODUCTION(3,1)|PERIDOTITE HEATING(3,1)|PLANET REGION(3,1)|PRIMARY COMPONENT(3,1)|PURITY CO2 CONDITION(3,1)|REMAINING REACTANT(3,1)|SEQUESTERED GAS STREAM(3,1)|SINGULAR FEATURE(3,1)|SOUTHERN REGION(3,1)|STACKED COLUMN(3,1)|TARGETED ROCK(3,1)|TERM ORDINARY MEANING(3,1)|UPTAKE PERFORMANCE(3,1)|VALUABLE CO2 REMOVAL(3,1)|VOL CO2(3,1)|WEATHERING CONDITION(3,1)|DIVALENT METAL CATION(2,3)|GLOBAL WARMING(2,3)|LARGE ROCK(2,3)|MINED MATERIAL(2,3)|CEMENT(2,2)|METAL 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HYDROXIDE(100,6)|CARBON DECOMPOSITION(100,6)|MAGNESIUM CALCIUM CARBONATE(100,6)|MAGNESIUM OXIDE(100,6)|POTASSIUM CARBONATE(100,6)|SILICON CARBONATE(100,6)|SODIUM CARBONATE(100,6)|CALCINATION(100,5)|DROMITE(100,5)|POTASSIUM HYDROXIDE(100,5)|SODIUM HYDROXIDE(100,5)|CALCIUM SILICATE(100,4)|CARBONATED CHLORINATION STATION(100,4)|MAGNESIUM HYDROXIDE(100,4)|MAGNESIUM SILICATE(100,4)|OXYGEN(100,4)|POTASSIUM OXIDE(100,4)|REMOVING CO2(100,4)|SILICON DIOXIDE(100,4)|SODIUM OXIDE(100,4)|BALL MILL PULVERIZER(100,3)|CARBONIZATION MEDIUM(100,3)|CONE PULVERIZER(100,3)|IMPACT PULVERIZER(100,3)|ADSORBENT MATERIAL(100,2)|AIR VELOCITY(100,2)|BALL MILL(100,2)|ENHANCED WEATHERING(100,2)|GRINDING STATION(100,2)|PROXIMITY(100,2)|CARBONATED MEDIUM GRAM(100,1)|CONE GRINDER(100,1)|GRIND CARBONATED MEDIUM(100,1)|GRINDER(100,1)|IMPACT GRINDER(100,1)|PURITY(100,1)|CARBONATION CONTACTOR(45,3)|INTERGOVERNMENTAL COMMISSION(37,1)|CARBONATION STATION(30,16)|CARBONATION MEDIUM GRAM(21,4)|CARBONATION MEDIUM SHEET(21,2)|CO2 UPTAKE(19,20)|CAPTURING CO2(17,2)|POWDERED CARBONATION MEDIUM(16,2)|BALL MILL CRUSHER(15,1)|SPRAYING(14,5)|CAPTURING CARBON DIOXIDE(14,1)|LAYOUT(14,1)|ACID CHLORINATED MEDIUM STREAM(13,1)|MINERAL LARGE SEDIMENT(13,1)|FURNACE(10,2)|SPRAYER(9,18)|LARGE SEDIMENT(9,1)|HYDRATION STATION(8,8)|GLOBAL WARMING(8,3)|OXYGEN CONTENT(8,2)|CARBONATED MEDIUM SURFACE(8,1)|CONE CRUSHER(8,1)|IMPACT CRUSHER(8,1)|CO2 TON(7,6)|PETRI DISH(7,5)|WATER DELIVERY(7,3)|CARBONATION IMMEDIATE VICINITY(7,2)|EXHAUST GAS(6,1)|HEAT APPLICATION(6,1)|RISER REACTOR CALCINATION FURNACE(6,1)|INSULATION SPACE(5,12)|AVERAGE PARTICLE DIAMETER(5,10)|CO2 UPTAKE RATE(5,5)|CRUSHING STATION(5,4)|NATURAL WEATHERING(5,4)|HOSE(5,3)|CARBONATION GRAM(5,2)|CARBONATION MEDIUM IMMEDIATE VICINITY(5,2)|CLIMATE CHANGE(5,2)|CAO PERFECT AGGREGATION(5,1)|CARBONATED CHLORINATED STATION(5,1)|CO2 UPTAKE VARIABILITY(5,1)|ELECTRICAL POWER(5,1)|GLOBAL MGCO3 RESERVE(5,1)|HYBRID CALCINATION FURNACE(5,1)|MOISTURE CONTENT 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CARBONATED CHLORIDE(4,1)|PREMIER MAGNESIA(4,1)|ROCK WEATHERING(4,1)|ROTARY KILN CALCINATION FURNACE(4,1)|SUBSTANCE CARBONATION(4,1)|TERRESTRIAL BIOSPHERE(4,1)|TRANSITIONAL CLAUSE(4,1)|ULTRAPOWERFUL ROCK(4,1)|UNARABLE LAND(4,1)|UNLISTED ITEM(4,1)|VIRTUALLY INFINITE RESOURCE(4,1)|EXPERIMENT(3,5)|GRINDING(3,5)|CONDENSATION SPACE(3,4)|RENEWABLE ELECTRICITY(3,4)|TARGET COMPOUND(3,4)|CARBONATED MEDIUM SHEET(3,2)|CARBONIC CHLORIDE STATION(3,2)|CO2 REACTION(3,2)|CRUSHING MEDIUM(3,2)|GEOLOGICAL TIMESCALE(3,2)|MGO POWDER(3,2)|NEGATIVE EMISSION(3,2)|POWDER CO2 UPTAKE DATA(3,2)|RECYCLED CARBON(3,2)|BAKING FURNACE(3,1)|CALCINATED CARBONATE(3,1)|CALCIUM CAUSTIC RECOVERY LOOP(3,1)|CARBONATED MEDIUM AFFINITY(3,1)|CARBONATED MEDIUM PLOT(3,1)|CARBONATION MEDIA(3,1)|CARBONATION MEDIUM TRANSPORTATION(3,1)|CARBONIZATION CONVERSION(3,1)|CO2 ADSORPTION(3,1)|CO2 CONTACTOR(3,1)|CO2 CONTRIBUTION(3,1)|CO2 DISSOLUTION(3,1)|DAC ESTIMATED COST(3,1)|DISCONTINUOUS PLOT(3,1)|ELECTRIC CALCINING FURNACE(3,1)|ENGINEERED PATHWAY(3,1)|FUTURE CO2 EMISSION(3,1)|GLOBAL DEPENDANCE(3,1)|GROWING CONSENSUS(3,1)|HUMAN SUSTAINABILITY(3,1)|KOH ADSORBENT(3,1)|LI COR INSTRUMENT CHAMBER(3,1)|MGO SUPPLIER(3,1)|MINERAL CARBONIZATION REACTION(3,1)|OPTIMISTIC COST ESTIMATE(3,1)|OXY CALCINATION FURNACE(3,1)|OXY CALCINING FURNACE(3,1)|PERIDOTITE RICH(3,1)|ROCK CALCINATION(3,1)|ROCK MINING(3,1)|SOLD UNDERGROUND(3,1)|ELECTRICAL RESISTANCE HEATING(2,8)|TRAY(2,6)|CONVEYER(2,4)|ADDITIVE(2,2)|BIOENERGY(2,2)|CEMENT(2,2)|CHIMNEY(2,2)|CO2 AIR(2,2)|COST ESTIMATION(2,2)|GAS ANALYZER(2,2)|METAL CARBONATE(2,2)|MODEL CURVE(2,2)|RECYCLING WATER(2,2)|WET HOUSING(2,2)|9VOL CO2(2,1)|ACTION SIMULTANEOUS EXECUTION(2,1)|ADDING BIOMASS(2,1)|AMERICAN PHYSICAL SOCIETY(2,1)|ARBITRARY INTERMEDIATE STATION(2,1)|BURNING(2,1)|CALCINATION RESIDUE(2,1)|CALCIUM BINDER(2,1)|CAO LOOP(2,1)|CAO LOSS(2,1)|CAO SAMPLE(2,1)|CAPTURED CO2(2,1)|CARBON REMEDIATION(2,1)|CARBONATE DRINK(2,1)|CARBONATE SALT(2,1)|CARBONATED CHLORIDE MODE(2,1)|CARBONATED CHLORIDE STATION ARRANGEMENT(2,1)|CARBONATED CHLORIDE WIDTH DIMENSION(2,1)|CARBONATION CYCLE(2,1)|CARBONATION MEDIUM CONVERSION(2,1)|CARBONATION MEDIUM POWDER(2,1)|CARBONATION REACTION(2,1)|CENTRAL REGENERATION FACILITY(2,1)|CO2 CAPTURE(2,1)|CO2 DIFFUSION(2,1)|CO2 ISOLATION(2,1)|CO2 STORAGE OPPORTUNITY(2,1)|COMBUSTION MEDIUM(2,1)|COMPLEX DAC(2,1)|CONCURRENT EXECUTION(2,1)|CONE MILL(2,1)|DAILY AGITATION(2,1)|ELECTRICAL KILN(2,1)|ELLIPTICAL PATTERN(2,1)|ENERGY INVESTMENT(2,1)|ENHANCING ABSORPTION SPECTROSCOPY(2,1)|ENTERPRISE USER(2,1)|EXCLUSION LIMIT(2,1)|EXECUTION PARTICULAR ORDER(2,1)|EXPAND PLOT(2,1)|EXPONENTIAL FIT(2,1)|FAST VARIABLE(2,1)|FINE MIST(2,1)|FUEL COMBUSTION(2,1)|GAS FLOWMETER(2,1)|GEOMETRIC RELATIONSHIP(2,1)|GRADUAL DECREASE(2,1)|GRAFTED AMINE(2,1)|GT CO2(2,1)|HEAVY CO2 EXHAUST(2,1)|HYDRATE MG(2,1)|HYDRATED MAGNESIUM CARBONATE(2,1)|HYPERSOFTENING(2,1)|INACTIVE SUBSTANCE(2,1)|LEXICAL DEFINITION SENSE(2,1)|LI COR SOIL(2,1)|LIMESTONE COMPONENT(2,1)|MARINE CALCIFICATION(2,1)|MAXIMIZE 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SOCIETY(6,1)|VIRTUALLY UNLIMITED RESOURCE(6,1)|ADDITION RATE(5,5)|CARBONATION BLOCK(5,5)|CONTAINMENT(5,4)|CARBON MINERALIZATION(5,2)|CARBONATED MEDIA STREAM CM(5,2)|CARBONATION MASS(5,2)|CAO RECYCLING(5,1)|CAO TON(5,1)|HYPER MAFIC ROCK(5,1)|LIMESTONE RESOURCE(5,1)|MANTLE OLIVINE(5,1)|MARINE ALKALINITY(5,1)|MARINE FERTILIZATION(5,1)|OCEAN FERTILIZATION(5,1)|PREMIER MAGNESIA(5,1)|SOLAR CALCINER(5,1)|TREATING CARBONATION MEDIA(5,1)|TRAY(4,7)|FEEDSTOCK(4,4)|PEBBLE(4,4)|RECOVERING WATER(4,4)|WEIGHT PERCENT(4,4)|COST ESTIMATION(4,3)|GAS ANALYZER(4,3)|HEADSPACE(4,3)|RESERVE(4,3)|STRATEGY(4,3)|GEOLOGICAL TIMESCALE(4,2)|GRINDING MEDIA(4,2)|HYDRATED MAGNESIUM CARBONATE(4,2)|MGO POWDER(4,2)|NONLINEARITY(4,2)|RECOVERING CARBON(4,2)|SEQUESTRATION SPACE(4,2)|SOLID CARBONATE MINERAL(4,2)|STIRRING TOOL(4,2)|AGRICULTURAL LAND(4,1)|ALTERED OLIVINE(4,1)|CALCIUM ADSORBENT(4,1)|CALCIUM CAUSTIC RECOVERY LOOP(4,1)|CARBONATION MEDIA SHEET(4,1)|CARBONATION MEDIUM VICINITY(4,1)|FLUIDIZED BED 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CRUSHER(17,6)|SPRAYING(17,3)|MAGNESIUM SILICATE(16,4)|GRINDING STATION(16,3)|IMPACT CRUSHER(15,6)|POTASSIUM CARBONATE(15,6)|CALCIUM SILICATE(15,4)|MOISTURE CONTENT RANGE(15,2)|REMOVING CO2(15,2)|WATER STREAM(14,28)|HEAT APPLICATION(14,6)|MAGNESIUM HYDROXIDE(14,4)|POTASSIUM HYDROXIDE(13,5)|AMBIENT AIR(12,32)|CALCIUM HYDROXIDE(12,6)|SODIUM HYDROXIDE(12,5)|SILICON DIOXIDE(12,4)|OXYGEN STREAM(11,4)|POTASSIUM OXIDE(11,4)|GLOBAL WARMING(11,3)|OXYGEN CONTENT(11,2)|CO2 TON(10,7)|PETRI DISH(10,5)|MAGNESIUM OXIDE(9,6)|HYDRATION STATION(9,5)|CARBONATION MEDIUM TON(9,3)|FOG(9,2)|RELATIVE HUMIDITY(8,16)|CALCIUM OXIDE(8,6)|SODIUM OXIDE(8,4)|CARBONATION MEDIUM HYDRATION(8,2)|AIR STREAM(7,10)|HOSE(7,3)|CARBONATION MEDIUM IMMEDIATE VICINITY(7,2)|FLUE GAS(7,2)|SUPERBASIC ROCK(7,2)|CARBONATION IMMEDIATE VICINITY(7,1)|CARBONATION MEDIA RECYCLING(7,1)|CARBONATION PLOT VICINITY(7,1)|ATOMIZER(6,6)|HIGH MAGNESIUM CALCIUM CARBONATE(6,4)|CARBONATION MEDIUM COMPARTMENT(6,2)|CARBONATION STATION ILLUSTRATION(6,2)|HUMID ENCLOSURE(6,2)|BRUCITE CO2 ABSORPTION(6,1)|CLUSTERED CARBONATION(6,1)|CO2 ABSORPTION VARIABILITY(6,1)|HEADSPACE CO2 MEASUREMENT(6,1)|MGO CO2 UPTAKE(6,1)|MINED CARBONATION(6,1)|SOLAR FIRED FURNACE(6,1)|TERRESTRIAL BIOSPHERE(6,1)|AIR SEPARATION(5,18)|EXPERIMENT(5,5)|GAS ANALYZER(5,3)|GAS STREAM CO2(5,3)|TECHNOLOGICAL INNOVATION(5,3)|AGITATION TOOL(5,2)|CARBON MINERALIZATION(5,2)|CARBONATION MEDIUM POWDER(5,2)|CARBONATION MEDIUM STREAM CM(5,2)|MGO POWDER(5,2)|AGITATING CARBONATION MEDIUM(5,1)|CALCINATION INTEGRITY(5,1)|CAO TON(5,1)|CARBONATION LAYOUT(5,1)|CARBONATION MEDIUM AFFINITY(5,1)|CAUSTIC MAGNESIA(5,1)|CO2 MITIGATION(5,1)|ELECTROFIRED FURNACE(5,1)|FEEDSTOCK TRANSPORTATION(5,1)|LIMESTONE 4MT(5,1)|LIMESTONE RESERVE(5,1)|MANTLE OLIVINE(5,1)|MARINE CO2 ABSORPTION(5,1)|MGCO3 FEEDSTOCK(5,1)|MGCO3 RESERVE(5,1)|MGO SAMPLE CO2 ABSORPTION(5,1)|NONCONTINUOUS PLOT(5,1)|OCEAN FERTILIZATION(5,1)|PREMIER MAGNESIA(5,1)|AVERAGE PARTICLE SIZE(4,10)|CONVEYER(4,4)|RENEWABLE ELECTRICITY(4,4)|TARGET COMPOUND(4,4)|COMPONENT LIST(4,3)|PEBBLE(4,3)|CO2 REACTION(4,2)|GEOLOGICAL TIMESCALE(4,2)|NONLINEARITY(4,2)|OXYGEN FIRED FURNACE(4,2)|RECYCLED CARBON(4,2)|SOLID CARBONATE MINERAL(4,2)|WIND SPEED(4,2)|AMBIENT WEATHERING(4,1)|AMERICAN PHYSICAL SOCIETY(4,1)|CACO3 CALCINATION TEMPERATURE(4,1)|CALCINATION RESIDUE(4,1)|CALCINED CARBONATE(4,1)|CALCIUM ADSORBENT(4,1)|CALCIUM CAUSTIC RECOVERY LOOP(4,1)|CAO LOOPING(4,1)|CAO SAMPLE(4,1)|CARBONATED MEDIA(4,1)|CARBONATION CONVERSION(4,1)|CARBONATION CYCLE(4,1)|CARBONATION MEDIA SHEET(4,1)|CARBONATION MEDIA STREAM CM(4,1)|CARBONATION MEDIUM CONVERSION(4,1)|CARBONATION MEDIUM MOISTURE CONTENT(4,1)|CARBONATION PLUS(4,1)|CARBONATION SHEET(4,1)|CARBONATION THIN SHEET(4,1)|CENTRAL REGENERATION FACILITY(4,1)|CO2 ADSORPTION(4,1)|CO2 CONTACTOR(4,1)|CO2 CONTRIBUTION(4,1)|CO2 FLUX(4,1)|CO2 GT(4,1)|CO2 RICH FUEL(4,1)|CO2 STORAGE OPPORTUNITY(4,1)|CO2 UPTAKE GRAPHICAL REPRESENTATION(4,1)|ENGINEERED PATHWAY(4,1)|EXPONENTIATION RATE LAW(4,1)|FARMLAND SOIL(4,1)|FINE MIST(4,1)|FUTURE CO2 EMISSION(4,1)|GENERALIZED NATURAL WEATHERING REACTION(4,1)|GEOMETRY TOLERANCE(4,1)|GRAFT AMINE(4,1)|GRID ELECTRICITY(4,1)|HAZE GRAPH(4,1)|HUMAN SUSTAINABILITY(4,1)|HYBRID CALCINER(4,1)|HYDRATED MG CARBONATE(4,1)|HYDROUS MG CARBONATE MINERAL(4,1)|INFINITE RESOURCE(4,1)|KOH ADSORBENT(4,1)|MATURATION DURATION(4,1)|MAXIMIZE CO2(4,1)|MGCO3 CALCINATION TEMPERATURE(4,1)|MGO PRODUCTION BRAND(4,1)|MGO REACTANT(4,1)|MGO SUPPLIER(4,1)|MINE TAILING(4,1)|MINERAL CARBONATION REACTION(4,1)|MODIFIED PERSIMMON ARM(4,1)|NONARABLE LAND(4,1)|OLIVINE CANCER(4,1)|OPTIMISTIC COST ESTIMATE(4,1)|OXIDE REACTANT(4,1)|OXYGEN CALCINATION(4,1)|PURITY CO2(4,1)|ROCK MINING(4,1)|ROTARY KILN CALCINER(4,1)|SOIL FLUX(4,1)|SYSTEM IMPLEMENT(4,1)|UNDERGROUND ISOLATION(4,1)|TRAY(3,5)|WEIGHT FRACTION SEC(3,4)|WIDTH DIMENSION(3,4)|BIOENERGY(3,2)|CALCINING TEMPERATURE(3,2)|CHIMNEY(3,2)|CO2 ABSORPTION DATA(3,2)|CONDENSATION SPACE(3,2)|GRINDING MEDIUM(3,2)|MODEL CURVE(3,2)|PORTFOLIO(3,2)|PULVERIZATION(3,2)|RECYCLING WATER(3,2)|ABSORPTION PERFORMANCE(3,1)|ADDING BIOMASS(3,1)|AGITATOR ROD(3,1)|ALKALINITY ADDITION(3,1)|CALCINATION CYCLE(3,1)|CAO ACCOUNT(3,1)|CAO LOSS(3,1)|CAO REACTION(3,1)|CARBON CLEANUP COMPONENT(3,1)|CARBONATION LOCATION(3,1)|CAVITY ENHANCED ABSORPTION SPECTROSCOPY(3,1)|CO2 COLLECTION(3,1)|CO2 DIFFUSION(3,1)|CO2 RICH GAS(3,1)|CO2 UPTAKE RATE(3,1)|COMBUSTION MEDIUM(3,1)|ELECTRIC KILN(3,1)|ELLIPTICAL PATTERN(3,1)|ENERGY INVESTMENT(3,1)|ENHANCING ABSORPTION SPECTROSCOPY(3,1)|ENTERPRISE USER(3,1)|EXPONENTIAL FIT(3,1)|FINE MGO(3,1)|FUEL COMBUSTION(3,1)|GEOMETRIC RELATIONSHIP(3,1)|HYDRATED MAGNESIUM CARBONATE(3,1)|HYDRATED SODIUM CARBONATE(3,1)|HYPOTHETICAL MGO ROOFING(3,1)|INTERMEDIATE STATION(3,1)|ITEM SEPARATION(3,1)|LI COR EQUIPMENT CHAMBER(3,1)|LIMESTONE MAJOR COMPONENT(3,1)|MARINE PH(3,1)|MAXIMIZE GROUND(3,1)|NATURAL ACCELERATION(3,1)|NEBULIZER(3,1)|OXYGEN BURNING FURNACE(3,1)|REACTION PROGRESSION(3,1)|REMAINING REACTANT(3,1)|STACKED COLUMN(3,1)|TECHNICAL FOCUS(3,1)|TRADEMARK OFFICE(3,1)|WEATHERING ACTION(3,1)|ELECTRICAL RESISTANCE HEATING(2,8)|CONTACTOR SET(2,3)|DIVALENT METAL CATION(2,3)|INSULATION SPACE(2,3)|LARGE ROCK(2,3)|MINED MATERIAL(2,3)|METAL CARBONATE(2,2)|ABSORBING CARBON DIOXIDE(2,1)|ABSORPTIVITY(2,1)|ACRYLONITRILE(2,1)|AFFORESTATION(2,1)|AGRICULTURE(2,1)|AMBIENT AIR CO2 ABSORBANCE(2,1)|ANNUAL OUTPUT(2,1)|AQUEOUS CALCIUM(2,1)|AQUEOUS POTASSIUM HYDROXIDE(2,1)|BINDING COMPONENT(2,1)|BIOPOLYMER(2,1)|CALCITE(2,1)|CALCIUM HYDROXIDE GRAPH(2,1)|CAO TOTAL AGGREGATION DATA(2,1)|CAPTURE CONTROL ENVIRONMENT(2,1)|CARBON CAPTURE FACILITY ILLUSTRATION(2,1)|CARBON COLLECTION FACILITY COMPONENT(2,1)|CARBON CONTENT(2,1)|CARBONATED BEVERAGE(2,1)|CARBONATION HUMIDITY LEVEL(2,1)|CARBONATION PLOT NUMBER(2,1)|CIRCULAR PATTERN(2,1)|CIRCULATION(2,1)|CM SCALE(2,1)|CO2 COST(2,1)|CO2 SCALE(2,1)|CO2 SEQUESTRATION(2,1)|COMPONENT IDENTIFICATION(2,1)|COMPRESSOR(2,1)|CONSENSUS(2,1)|CONTAMINANT(2,1)|COST ESTIMATION(2,1)|CUSTOMIZATION(2,1)|CYCLE SUCCESSION(2,1)|DATABASE CONFIGURATION(2,1)|DECOMPOSITION(2,1)|DECREASE OBSERVATION(2,1)|DEHYDRATOR(2,1)| | (US20240269605)|1. A method, comprising:| applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2;| at least one of sequestering or utilizing the gas stream;| feeding the stream of the carbonation medium to a carbonation station;| contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream;| during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours; and| feeding the carbon-containing stream to the calciner.|2. The method of claim 1, wherein adding the water stream is via misting and/or spraying.|3. The method of claim 1, wherein adding the water is at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium.|4. The method of claim 1, wherein the carbonation medium is maintained at a moisture content between about 3 wt % and about 50 wt %.|5. The method of claim 1, further comprising:| grinding an adsorbent material to form the carbonation medium in a powder via at least one of a ball mill crusher, impact crushers, or a cone crusher.|6. The method of claim 1, wherein the carbonation medium includes at least one of magnesium oxide, magnesium silicates, silicon dioxide, calcium oxide, calcium hydroxide, calcium silicates, sodium oxide, sodium hydroxide, potassium oxide, potassium hydroxide, or magnesium hydroxide.|7. (canceled)|8. The method of claim 1, further comprising:| condensing an amount of water from the gas stream; and| feeding the amount of water to the water stream.|9. (canceled)|10. The method of claim 1, further comprising:| processing an air stream via an air separation unit to produce an oxygen stream, the oxygen stream having a purity of at least about 95%; and| feeding the oxygen stream to the calciner.|11. The method of claim 1, wherein the carbonation medium has an average particle size of less than about 75 μm.|12. The method of claim 1, wherein the carbonation station includes a plurality of carbonation contactors, each carbonation contactor of the carbonation contactors including a sheet of the carbonation medium, the sheet of the carbonation medium having a thickness between about 0.5 mm and about 10 mm.|13. The method of claim 1, wherein applying the heat to the calciner is via electric resistance heating powered by electricity.|14. The method of claim 1, further comprising:| monitoring a relative humidity, temperature, and air velocity levels of ambient air in close proximity to the carbonation medium during the contacting.|15. The method of claim 1, further comprising:| hydrating the carbonation medium prior to feeding the carbonation medium to the carbonation station.|16. A method, comprising:| applying heat to a calciner to decompose a carbon-containing stream into a gas stream and a stream of a carbonation medium, the gas stream including CO2;| at least one of sequestering or utilizing the gas stream;| feeding the stream of the carbonation medium to a carbonation station;| contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream;| during the contacting, spraying and/or misting a water stream to the carbonation medium at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium; and| feeding the carbon-containing stream to the calciner.|17. The method of claim 16, wherein the gas stream includes at least about 95% CO2 by volume.|18. The method of claim 16, further comprising:| grinding an adsorbent material to form the carbonation medium into a powder.|19. The method of claim 16, wherein the adsorbent material includes at least one of magnesium oxide, magnesium silicate, silicon dioxide, calcium oxide, calcium hydroxide, calcium silicates, sodium oxide, sodium hydroxide, potassium oxide, potassium hydroxide, or magnesium hydroxide.|20. The method of claim 16, wherein the carbon-containing stream includes at least one of MgCO3, dolomite (high magnesium calcium carbonate), sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, potassium carbonate, potassium bicarbonate, nesquehonite, or hydromagnesite.|21. The method of claim 16, further comprising:| condensing an amount of water from the gas stream; and| recycling the amount of water by feeding the amount of water to the water stream.|22. (canceled)|23. A method, comprising:| decomposing a carbon-containing stream into a gas stream and a stream of a carbonation medium in a calciner, the gas stream including CO2, the carbonation medium including at least one of MgCO3, sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, nesquehonite, or hydromagnesite;| sequestering the gas stream;| feeding the stream of the carbonation medium to a carbonation station;| contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream;| during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium; and| feeding the carbon-containing stream to the calciner.|24. (canceled)|25. The method of claim 23, wherein the carbon-containing stream includes at least one of MgCO3, dolomite (high magnesium calcium carbonate), sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, potassium carbonate, potassium bicarbonate, nesquehonite, or hydromagnesite.|26. The method of claim 23, further comprising:| applying heat to the calciner via electric resistance heating powered by electricity.|27. The method of claim 23, further comprising:| condensing an amount of water from the gas stream; and| recycling the amount of water by feeding the amount of water to the water stream.|28. (canceled)|29. (canceled)|30. (canceled)|31. (canceled)|32. (canceled)|33. (canceled)|34. (canceled)|35. (canceled)|36. (canceled) | (US20240269605)|RELATED APPLICATIONS|[0001] This application is a continuation of International Patent Application No. PCT/US2022/018484, filed Mar. 2, 2022, which claims priority and benefit of U.S. Provisional Application No. 63/155,572, filed Mar. 2, 2021 and titled “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference herein in its entirety.|(US20240269605)|TECHNICAL FIELD|[0002] Embodiments described herein relate systems and methods for uptake of carbon dioxide (CO2) from ambient air.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|SUMMARY|[0004] Embodiments described herein relate to systems and methods of CO2 uptake. In one aspect, a method includes applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2. The method further includes sequestering and/or utilizing the gas stream, feeding the stream of the carbonation medium to a carbonation station, contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs or reacts with CO2 to form the carbon-containing stream, during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours, and feeding the carbon-containing stream to the calciner. In some embodiments, adding the water stream is via misting and/or spraying. In some embodiments, the water is added at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium. In some embodiments, the carbonation medium is maintained at a moisture content between about 3 wt % and about 50 wt %. In some embodiments, the method can further include grinding a sorbent material to form the carbonation medium in a powder via a ball mill crusher, an impact crusher, and/or a cone crusher.|(US20240269605)|BRIEF DESCRIPTION OF THE DRAWINGS|[0005] FIG. 1 is a block diagram of a method of CO2 capture from ambient air, according to an embodiment.|[0006] FIG. 2 is a block diagram of a carbon capture facility, according to an embodiment.|[0007] FIG. 3 is an illustration of a carbon capture facility, according to an embodiment.|[0008] FIG. 4 is an illustration of a carbonation station, according to an embodiment.|[0009] FIG. 5 is an illustration of a carbonation station, according to an embodiment.|[0010] FIG. 6 is a plot of CO2 uptake of different materials over a period of 10 days.|[0011] FIG. 7 is a plot of CO2 uptake of different materials over a period of 16 days.|[0012] FIG. 8 is a plot of CO2 uptake of different materials over a period of 16 days.|[0013] FIG. 9 is a plot of consumption of calcium hydroxide (Ca(OH)2) over a period of 2 days.|[0014] FIG. 10 is a plot of uptake rate versus time for varying magnesium oxide material suppliers.|[0015] FIG. 11 is a plot of misting amount versus uptake rate as a function of material type.|[0016] FIG. 12 is a visual representation of material and energy balances in a carbon capture facility.|(US20240269605)|DETAILED DESCRIPTION|[0017] Some embodiments of the present disclosure are directed to CO2 uptake from air during weathering. The uptake can be on time scales of months to years, achieving valuable CO2 removal from air while lowering the looping costs. Embodiments described herein can relate to methods for using material including metal carbonates as a feedstock for carbon capture and removal. Heating of material yields CO2 gas and solid metal oxides and metal hydroxides from the carbonates. These metal oxide and metal hydroxide products can be layered thinly in an outdoor area and subjected to weathering over a series of months or years, during which the metal oxides and metal hydroxides absorb CO2 from the air to generate additional metal carbonates, other hydrated magnesium carbonates, etc. The cycle can then be repeated, with the carbonates being heated to release CO2 into a controlled capture environment. The resulting reactive oxides and/or hydroxides can then be layered again for weathering, and the captured CO2 can be bottled and sold or stored underground.|[0018] Negative Emission Technologies (NET's), also known as carbon dioxide removal (CDR) technologies, encompass a broad range of strategies for CO2 removal from air. Some methods employed include bioenergy, afforestation, direct air capture and ocean fertilization. Energy efficiency is important for adoption and implementation of either of these strategies. NETs should be carbon negative if they are to be adopted on a large scale. In other words, methods of CO2 removal from air should extract more carbon from the atmosphere than they emit in the process. Efficiency of carbon removal has only recently become a technological focus.|[0019] The contribution of CO2 to global warming is well documented. Recently, carbon capture methods have been developed for point-of-release carbon capture (e.g., at the smokestack or near the exhaust port). Previous approaches included CO2 capture from flue gas and other concentrated sources, in smokestacks or reactors, on time scales of minutes to days. Such systems often rely on faster reaction times and higher energy investments, e.g., application of high heat and/or pressure. These solutions are often expensive, and they occasionally employ designer materials that may be difficult to produce. Costs of $100/ton of CO2 produced are optimistic cost estimates for direct air capture, but realistic for point source capture where CO2 is more concentrated.|[0020] The Intergovernmental Panel on Climate Change, (IPCC) and other authoritative organizations, have determined that CO2 removal from air is necessary to hold global warming to less than 2° C. CO2 removal from air is more difficult than CO2 capture from flue gas. Current technology involves “direct air capture” machines (DAC) that remove CO2 from air at a cost at or above $600/ton CO2. The reaction of CO2 with certain calcium and magnesium oxides has been widely recognized for many years as a form of rock weathering and subsequent carbon sink. Natural weathering removes vast quantities of CO2 and this could be adapted to help offset some of the emissions being produced worldwide. Enhanced carbon capture through reaction of CO2 with ultramafic rock is one NET that can be scaled up to alleviate impacts of climate change.|[0021] Enhanced weathering dates back to 1990, when Walter Seifritz proposed a process based on natural weathering. In natural weathering, alkaline-containing minerals are carbonated on geologic timescales (i.e., millions of years). The generalized natural weathering reaction is described below:|where Me represents a divalent metal cation.|[0022] Cations can include magnesium (Mg2+) and calcium (Ca2+), where suitable feedstocks include minerals, such as olivine and serpentine, as well as industrial byproducts, such as mine tailings and fly ash. Since the natural weathering reaction occurs on geological timescales, various process conditions, pretreatment methods, extraction mechanisms, and other strategies can expedite process kinetics as a form of CO2 sequestration.|[0023] Several CO2 capture systems have been explored. The American Physical Society, in a 2011 study, evaluated a system where CO2 is absorbed by sodium hydroxide (NaOH) and subsequently reacted with calcium hydroxide (Ca(OH)2) to produce solid calcium carbonate (CaCO3). The CaCO3 is then calcined in an oxy-fired calciner to release the CO2. Keith et al. propose a continuous looping process including an aqueous potassium hydroxide (KOH) sorbent coupled with a calcium caustic recovery loop. The KOH sorbent reacts with CO2 in the air to produce potassium carbonate (K2CO3). The K2CO3 then reacts with Ca(OH)2, produced from CaCO3, to reproduce the KOH and CaCO3. These types of aqueous calcium looping systems have been primarily evaluated using calcium-based sorbents in aqueous conditions (in the form of Ca(OH)2). Additionally, Renforth and Kruger proposed an ocean liming process which deposits lime (produced from calcined carbonate materials) into the ocean to react with carbonic acid currently in the ocean. The process increases oceanic pH and leads to the dissolution of more CO2 into the ocean water, reducing the atmospheric concentration of CO2. Additional systems utilizing mineral carbonation reactions have looked at various forms of carbon mineralization as a method to capture CO2 from more concentrated point sources, such as power plants.|[0024] In the aforementioned processes, calcium-bearing minerals are often used as the source of alkalinity to capture CO2. However, the calcination temperature of MgCO3 is lower than that of CaCO3, theoretically leading to a lower associated energy cost. Magnesium is also an attractive option, as there are large deposits of magnesium-rich minerals throughout the world. The IPCC and other organizations concluded that, even with optimally fast implementation of carbon-free electrical generation and other innovations, global warming would exceed 2° C. by 2100 unless about 10 billion tons of CO2 are removed from the atmosphere until 2050 increasing to 20 billion tons by 2100. In turn, there is consensus that warming beyond 2° C. is likely to have catastrophic impacts on human sustainability. Options for negative emissions that can grow to scales of about 1 billion tons of CO2 per year include increasing the carbon content of agricultural soils, reforestation, adding alkalinity to the oceans, adding biomass in the oceans, and various engineered routes of CO2 removal from air (e.g., direct air capture (DAC). The National Academies Report on Negative Emissions Technologies from 2019 concluded that none of these methods, individually, can reach the required goal, so an ensemble of methods should be used. While it seems unclear how the cost of such an ensemble will be supported, there does seem to be a growing consensus (including most national governments worldwide) that carbon capture and carbon removal will be an important component of carbon remediation.|[0025] Limestone is mined for use as crushed rock for many purposes, for use as a fertilizer, and for use in both cement and steel production. However, limestone reserves and resources are essentially unlimited from a practical point of view. Magnesite (MgCO3) is mined primarily for production of Mg metal, used in alloys. Targeted rock is used in many other industries: limestone for cement, MgCO3 for refractory, agriculture, and other uses. Global MgCO3 reserves are estimated to be 7 or 8 billion tons.|[0026] Regarding the mechanisms for material handling (e.g., loading and unloading vast amounts of carbonated media), much of the material handling infrastructure already developed in the industrial and agricultural fields can be leveraged. Some embodiments described herein include the use of electric kilns and photovoltaics. Photovoltaics laid out between plots of carbonation medium can give about 30 times more space to spread out the plots of carbonation medium.|[0027] Methods described herein can use geological materials rich in magnesium, calcium, and/or sodium. A techno-economic analysis (TEA) of an exemplary embodiment based on use of MgCO3 was produced. Mg-carbonate was calcined, at temperatures as low as 600° C. Produced CO2 (from air and from CH4 combustion in an oxy-fired calciner) is stored or sold. Produced, fine-grained MgO is distributed over the land surface for weathering. The TEA assumes a layer 10 cm thick and daily stirring, with no cm- to mm-scale passivation, for >90% carbonated in a year (based on data on CO2 uptake in brucite, Mg(OH)2). More recent data indicate that >90% carbonation can be attained in six months. Newly carbonated material is calcined, newly produced CO2 is stored or sold, and newly produced MgO is redistributed for the next stage of weathering. This looping process combines processes so that cost estimates may be relatively robust compared to those for more complex DAC methods. Cost is estimated to be $48 to $159/ton CO2 net-removed from air. The cost of produced CO2, including CO2 captured from combustion, is estimated to be $24 to $79/ton. These costs are comparable to estimated costs for other DAC methods. In fact, the estimated cost for MgO looping may currently be the lowest peer-reviewed cost estimate for DAC.|[0028] Limestone includes about 56 wt % CaO. After calcining, CaO generally reacts rapidly with air to form Ca(OH)2. Carbonation of this material via reaction with ambient air removes about 0.78 tons of CO2 per ton of initial CaO, or 0.44 tons of CO2 per ton of limestone per carbonation+calcination cycle. Results from exemplary embodiments have achieved an average Ca(OH)2 carbonation rate of about 6E-7/s (mass fraction Ca(OH)2 consumed per second by reaction with CO2 from ambient air to produce CaCO3). In turn, if this rate is constant, it will lead to 50% carbonation in about two weeks, 75% in about a month, 90% carbonation in 1.5 months, and 95% in about two months. In some embodiments, taking the 75% value, there would be 12 calcination cycles per year, removing 3.75 tons of CO2 from air per ton of limestone in the first year, assuming 1% loss of CaO per cycle. After ten years, the process would remove about 23 tons of CO2 from air per initial ton of limestone. In this calculation, to remove 1 Gt of CO2 from air per year for ten years would utilize one-time mining and processing 43.4 Mt of limestone. This is about 1.5 times more than current annual US production (32 Mt/year).|[0029] In some embodiments, systems described herein can be implemented where renewable energy capabilities overlap with CO2 storage opportunities globally. This presents opportunities to co-locate with energy and CO2 storage, specifically in the southern region of the US. It is estimated that, at an industry standard cost of $30/ton for feedstock transport, it will cost about $800,000 per year to transport the makeup feedstock for operation of a 1 Mt/year power plant. Moreover, if limestone (including CaCO3) is used and calcium oxide (CaO) is produced from CaCO3, CaO is regionally ubiquitous and effectively an unlimited resource.|[0030] In some embodiments, MgCO3 can be used as a feedstock. In some embodiments, the MgCO3 feedstock can be produced by initial weathering of quarried, ground mantle peridotite, rich in MgO. Mg(OH)2 often makes up a small portion of many peridotites. Mg(OH)2 reacts rapidly with CO2 in air to form MgCO3 in weathering conditions. Heating of peridotites including the mineral serpentine increases the rate at which serpentine reacts atmospheric CO2 to form MgCO3. Thus, after one or two heating cycles, a significant proportion of altered peridotite would be transformed to caustic magnesia. In some embodiments, CaCO3 or dolomite (high magnesium calcium carbonate) can be used as feedstock.|[0031] Some exemplary embodiments of replenished metal oxides and hydroxides include CaO and Ca(OH)2 from CaCO3, Na2O and NaOH from sodium carbonates and hydrated sodium carbonates, Mg(OH)2 and MgO from MgCO3 and hydrated Mg carbonates, and combinations thereof. Because CaCO3 is a primary constituent of limestone, looping of CaO and CaCO3 can greatly expand available feedstock and therefore the capacity for processes described herein to remove CO2 from air.|[0032] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions. In some embodiments, carbonation plots can include a composition that sequesters a target compound.|[0033] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0034] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0035] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0036] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0037] As used herein, the term “about” and “approximately” generally mean plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0038] FIG. 1 is a block diagram of a method 10 of CO2 capture from ambient air, according to an embodiment. As shown, the method 10 includes contacting a carbonation medium with ambient air at a carbonation station to form carbon-containing stream at step 11, adding a water stream to the carbonation medium at step 12, feeding the carbon-containing stream to a calciner at step 13, applying heat to the calciner to decompose the carbon-containing stream to a gas stream and the carbonation medium stream at step 14, sequestering and/or utilizing the gas stream at step 15, and feeding the carbonation medium stream to the carbonation station at step 16, where the process repeats again from step 11. The method 10 optionally includes processing an air stream to produce an oxygen stream and feeding the oxygen stream to the calciner at step 17, condensing and/or recycling water from the sequestered gas stream at step 18, grinding sorbent material to form the carbonation medium at step 19, and/or hydrating the carbonation medium stream at step 21.|[0039] Step 11 includes contacting the carbonation medium with ambient air at a carbonation station to from a carbon-containing stream. The carbonation medium adsorbs or reacts with carbon dioxide from the ambient air. The carbonation medium and the carbon dioxide react chemically to form the carbon-containing stream. In some embodiments, the carbonation medium can be from mined rocks. In some embodiments, the carbonation medium can be recycled (e.g., from the calciner). In some embodiments, the carbonation medium can include magnesium oxide, magnesium silicates, silicon dioxide, calcium oxide, calcium hydroxide, calcium silicates, sodium oxide, sodium hydroxide, potassium oxide, potassium hydroxide, and/or magnesium hydroxide|[0040] In some embodiments, the carbonation medium can be incorporated into one or more carbonation plots. In some embodiments, the carbonation medium can be in the form of a powder. In some embodiments, the carbonation medium can be in the form of pebbles or large rocks. In some embodiments, the carbonation medium can have an average particle size of at least about 10 μm, at least about 20 μm, at least about 30 μm, at least about 40 μm, at least about 50 μm, at least about 60 μm, at least about 70 μm, at least about 80 μm, at least about 90 μm, at least about 100 μm, at least about 200 μm, at least about 300 μm, at least about 400 μm, at least about 500 μm, at least about 600 μm, at least about 700 μm, at least about 800 μm, at least about 900 μm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, or at least about 4 cm. In some embodiments, the carbonation medium can have an average particle size of no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, no more than about 1 mm, no more than about 900 μm, no more than about 800 μm, no more than about 700 μm, no more than about 600 μm, no more than about 500 μm, no more than about 400 μm, no more than about 300 μm, no more than about 200 μm, no more than about 100 μm, no more than about 90 μm, no more than about 80 μm, no more than about 70 μm, no more than about 60 μm, no more than about 50 μm, no more than about 40 μm, no more than about 30 μm, or no more than about 20 μm.|[0041] Combinations of the above-referenced particle sizes are also possible (e.g., at least about 10 μm and no more than about 5 cm or at least about 100 μm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can have an average particle size of about 10 μm, about 20 μm, about 30 μm, about 40 μm, about 50 μm, about 60 μm, about 70 μm, about 80 μm, about 90 μm, about 100 μm, about 200 μm, about 300 μm, about 400 μm, about 500 μm, about 600 μm, about 700 μm, about 800 μm, about 900 μm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, at least about 2 cm, about 3 cm, about 4 cm, or about 5 cm.|[0042] In some embodiments, the carbonation medium can be stationed at the carbonation station to contact the ambient air for at least about 1 hour, at least about 5 hours, at least about 10 hours, at least about 1 day, at least about 2 days, at least about 3 days, at least about 4 days, at least about 5 days, at least about 6 days, at least about 1 week, at least about 2 weeks, at least about 3 weeks, at least about 1 month, at least about 2 months, at least about 3 months, at least about 4 months, at least about 5 months, at least about 6 months, at least about 7 months, at least about 8 months, at least about 9 months, at least about 10 months, at least about 11 months, at least about 1 year, or at least about 1.5 years. In some embodiments, the carbonation medium can be stationed at the carbonation station to contact the ambient air for no more than about 2 years, no more than about 1.5 years, no more than about 1 year, no more than about 11 months, no more than about 10 months, no more than about 10 months, no more than about 9 months, no more than about 8 months, no more than about 7 months, no more than about 6 months, no more than about 5 months, no more than about 4 months, no more than about 3 months, no more than about 2 months, no more than about 1 month, no more than about 3 weeks, no more than about 2 weeks, no more than about 1 week, no more than about 6 days, no more than about 5 days, no more than about 4 days, no more than about 3 days, no more than about 2 days, no more than about 1 day, no more than about 10 hours, or no more than about 5 days.|[0043] Combinations of the above-referenced residence times of the carbonation medium at the carbonation station are also possible (e.g., at least 1 hour and no more than about 2 years or at least about 1 week and no more than about 3 months), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be stationed at the carbonation station to contact the ambient air for about 1 hour, about 5 hours, about 10 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 1 week, about 2 weeks, about 3 weeks, about 1 month, about 2 months, about 3 months, about 4 months, about 5 months, about 6 months, about 7 months, about 8 months, about 9 months, about 10 months, about 11 months, about 1 year, about 1.5 years, or about 2 years.|[0044] In some embodiments, the carbonation medium can achieve at least about 50% conversion, at least about 55% conversion, at least about 60% conversion, at least about 65% conversion, at least about 70% conversion, at least about 75% conversion, at least about 80% conversion, at least about 85% conversion, at least about 90% conversion, or at least about 95% conversion during its residence time. In some embodiments, the carbon medium can achieve no more than about 99% conversion, no more than about 95% conversion, no more than about 90% conversion, no more than about 85% conversion, no more than about 80% conversion, no more than about 75% conversion, no more than about 70% conversion, no more than about 65% conversion, no more than about 60% conversion, or no more than about 55% conversion during its residence time. Combinations of the above-referenced conversion rates are also possible (e.g., at least about 50% and no more than about 99% or at least about 60% and no more than about 80%), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can achieve about 50% conversion, about 55% conversion, about 60% conversion, about 65% conversion, about 70% conversion, about 75% conversion, about 80% conversion, about 85% conversion, about 90% conversion, about 95% conversion, or about 99% conversion during its residence time. In some embodiments, conversion of the carbonation medium by the CO2 can be at a rate of about 1E-7, about 2E-7, about 3E-7, about 4E-7, about 5E-7, about 6E-7, about 7E-7, about 8E-7, about 9E-7, about 9E-7, about 1E-6, about 2E-6, about 3E-6, about 4E-6, about 5E-6, about 6E-6, about 7E-6, about 8E-6, about 9E-6, or about 1E-5 mass fraction per second, inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be stirred or mixed during carbonation. In some embodiments, the carbonation medium can be stirred at intervals of about 6 hours, about 12 hours, about 18 hours, about a day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 1 week, about 2 weeks, about 3 weeks, or about 4 weeks, inclusive of all values and ranges therebetween.|[0045] In some embodiments, the carbonation medium can be cycled seasonally. For example, the carbonation medium can be exposed to the ambient air at the carbonation station during the summer and spring and processed and/or stored elsewhere during the fall and winter. In some embodiments, a first portion of the carbonation medium can contact the ambient air at the carbonation station while a second portion of the carbonation medium is processed in the calciner and the second portion can contact the ambient air at the carbonation station while the first portion of the carbonation medium is processed in the calciner.|[0046] At step 12, a water stream is added to the carbonation medium. The moisture content of the carbonation medium can aid in maximizing the amount of CO2 adsorbed from the ambient air. In some embodiments, step 12 can occur concurrently with step 11. In other words, the water stream is added to the carbonation medium while the carbonation medium is contacting the ambient air at the carbonation station. In some embodiments, step 12 can be fully concurrent with step 11. In some embodiments, step 12 can be partially concurrent with step 11. In some embodiments, steps 11 and 12 can be executed multiple times before proceeding to feeding the carbon containing stream to the calciner at step 13. In other words, the carbonation medium can be contacted with ambient air and water can be added to the carbonation medium multiple times before feeding the carbon-containing stream to the calciner. In some embodiments, the water stream can be added to the carbonation medium in the form of misting and/or spraying. In some embodiments, the water stream can be added via a hose, a pipe, a tube, or any combination thereof. In some embodiments, the water stream can be added in the form of steam.|[0047] In some embodiments, the water stream can be added at time intervals. In some embodiments, the water stream addition interval (i.e., the amount of time from the start of one water stream addition to the next water stream addition) can be at least about 30 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 6 hours, at least about 7 hours, at least about 8 hours, at least about 9 hours, at least about 10 hours, at least about 12 hours, at least about 18 hours, at least about 24 hours, at least about 30 hours, at least about 36 hours, at least about 42 hours, at least about 48 hours, at least about 54 hours, at least about 60 hours, or at least about 66 hours. In some embodiments, the water stream addition interval can be no more than about 72 hours, no more than about 66 hours, no more than about 60 hours, no more than about 54 hours, no more than about 48 hours, no more than about 42 hours, no more than about 36 hours, no more than about 30 hours, no more than about 24 hours, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 9 hours, no more than about 8 hours, no more than about 7 hours, no more than about 6 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, or no more than about 1 hour.|[0048] Combinations of the above-referenced intervals between water stream additions are also possible (e.g., at least about 30 minutes and no more than about 72 hours or at least about 3 hours and no more than about 24 hours), inclusive of all values and ranges therebetween. In some embodiments, the water stream addition interval (i.e., the amount of time from the start of one water stream addition to the next water stream addition) can be about 30 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 6 hours, about 7 hours, about 8 hours, about 9 hours, about 10 hours, about 12 hours, about 18 hours, about 24 hours, about 30 hours, about 36 hours, about 42 hours, about 48 hours, about 54 hours, about 60 hours, about 66 hours, or about 72 hours.|[0049] In some embodiments, each addition of a water stream can be at a rate of at least about 0.01, at least about 0.02, at least about 0.03, at least about 0.04, at least about 0.05, at least about 0.06, at least about 0.07, at least about 0.08, at least about 0.09, at least about 0.1, at least about 0.15, at least about 0.2, at least about 0.25, at least about 0.3, at least about 0.35, at least about 0.4, or at least about 0.45 mL of water per gram of carbonation medium. In some embodiments, each water stream can be added at a rate of no more than about 0.5, no more than about 0.45, no more than about 0.4, no more than about 0.35, no more than about 0.3, no more than about 0.25, no more than about 0.2, no more than about 0.15, no more than about 0.1, no more than about 0.09, no more than about 0.08, no more than about 0.07, no more than about 0.06, no more than about 0.05, no more than about 0.04, no more than about 0.03, or no more than about 0.02 mL of water per gram of carbonation medium.|[0050] Combinations of the above-referenced rates of water addition are also possible (e.g., at 0.01 mL and no more than about 0.5 mL of water per gram of carbonation medium or at least about 0.1 and no more than about 0.3 mL of water per gram of carbonation medium), inclusive of all values and ranges therebetween. In some embodiments, each addition of a water stream can be at a rate of about 0.01, about 0.02, about 0.03, about 0.04, about 0.05, about 0.06, about 0.07, about 0.08, about 0.09, about 0.1, about 0.15, about 0.2, about 0.25, about 0.3, about 0.35, about 0.4, about 0.45 mL, or about 0.5 mL of water per gram of carbonation medium.|[0051] In some embodiments, the carbonation medium can be maintained at a moisture level of at least about 3 wt %, at least about 4 wt %, at least about 5 wt %, at least about 6 wt %, at least about 7 wt %, at least about 8 wt %, at least about 9 wt %, at least about 10 wt %, at least about 15 wt %, at least about 20 wt %, at least about 25 wt %, at least about 30 wt %, at least about 35 wt %, at least about 40 wt %, or at least about 45 wt %. In some embodiments, the carbonation medium can be maintained at a moisture level of no more than about 50 wt %, no more than about 45 wt %, no more than about 40 wt %, no more than about 35 wt %, no more than about 30 wt %, no more than about 25 wt %, no more than about 20 wt %, no more than about 15 wt %, no more than about 10 wt %, no more than about 9 wt %, no more than about 8 wt %, no more than about 7 wt %, no more than about 6 wt %, no more than about 5 wt %, or no more than about 4 wt %. Combinations of the above-referenced moisture contents are also possible (e.g., at least about 3 wt % and no more than about 50 wt % or at least about 10 wt % and no more than about 40 wt %), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be maintained at a moisture level of about 3 wt %, about 4 wt %, about 5 wt %, about 6 wt %, about 7 wt %, about 8 wt %, about 9 wt %, about 10 wt %, about 15 wt %, about 20 wt %, about 25 wt %, about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, or about 50 wt %.|[0052] In some embodiments, the method 10 can include monitoring relative humidity, temperature, and/or air velocity levels of the ambient air in close proximity (e.g., within about 100 m, within about 50 m, within about 10 m, within about 5 m, within about 1 m) to the carbonation station during the contacting of the carbonation medium with the ambient air|[0053] In some embodiments, the water stream can be added continuously (e.g., in a continuous fine mist). In some embodiments, the water stream can be added at a rate of at least about 0.01, at least about 0.02, at least about 0.03, at least about 0.04, at least about 0.05, at least about 0.06, at least about 0.07, at least about 0.08, at least about 0.09, at least about 0.1, at least about 0.2, at least about 0.3, at least about 0.4, at least about 0.5, at least about 0.6, at least about 0.7, at least about 0.8, at least about 0.9, at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, or at least about 9 mL of water per gram of carbonation medium per day. In some embodiments, the water stream can be added at a rate of no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, no more than about 2, no more than about 1, no more than about 0.9, no more than about 0.8, no more than about 0.7, no more than about 0.6, no more than about 0.5, no more than about 0.4, no more than about 0.3, no more than about 0.2, no more than about 0.1, no more than about 0.09, no more than about 0.08, no more than about 0.07, no more than about 0.06, no more than about 0.05, no more than about 0.04, no more than about 0.03, or no more than about 0.02 mL of water per gram of carbonation medium per day.|[0054] Combinations of the above-referenced water stream addition rates are also possible (e.g., at least about 0.01 and no more than about 10 ml of water per gram of carbonation medium per day or at least about 0.5 and no more than about 2 mL of water per gram of carbonation medium per day), inclusive of all values and ranges therebetween. In some embodiments, the water stream can be added at a rate of about 0.01, at least about 0.02, at least about 0.03, at least about 0.04, at least about 0.05, at least about 0.06, at least about 0.07, at least about 0.08, at least about 0.09, at least about 0.1, at least about 0.2, at least about 0.3, at least about 0.4, at least about 0.5, at least about 0.6, at least about 0.7, at least about 0.8, at least about 0.9, at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, about 9, or about 10 ml of water per gram of carbonation medium per day.|[0055] In some embodiments, the water stream can be added to the carbonation medium 12 to maintain a desired level of relative humidity in the immediate proximity of the carbonation medium (e.g., the volume within 10 m, within 5 m, or within 1 m of the carbonation medium). In some embodiments, step 12 can include maintaining the relative humidity in the immediate proximity of the carbonation medium at a level of at least about 5%, at least about 10%, at least about 15%, at least about 20%, at least about 25%, at least about 30%, at least about 35%, at least about 40%, at least about 45%, at least about 50%, at least about 55%, at least about 60%, at least about 65%, at least about 70%, at least about 75%, at least about 80%, at least about 85%, at least about 90%, or at least about 95%. In some embodiments, step 12 can include maintaining the relative humidity in the immediate proximity of the carbonation medium at a level of no more than about 100%, no more than about 95%, no more than about 90%, no more than about 85%, no more than about 80%, no more than about 75%, no more than about 70%, no more than about 65%, no more than about 60%, no more than about 55%, no more than about 50%, no more than about 45%, no more than about 40%, no more than about 35%, no more than about 30%, no more than about 25%, no more than about 20%, no more than about 15%, or no more than about 10%. Combinations of the above-referenced values of relative humidity in the immediate proximity of the carbonation medium are also possible (e.g., at least about 5% and no more than about 70% or at least about 20% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, step 12 can include maintaining the relative humidity in the immediate proximity of the carbonation medium at a level of about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, or about 100%.|[0056] Without wishing to be bound by theory, it is not anticipated that a large amount of water is physically adsorbed on the surface of the carbonation medium. Instead, the presence of water drives the conversion of the carbonation medium (e.g., oxides and/or hydroxides) while in reaction with CO2. In some embodiments, Mg(OH)2 can form hydrated carbonates, such as hydromagnesite, lansfordite, nesquehonite, and/or MgCO3. The decomposition of metastable, hydrous Mg-carbonate minerals occurs at lower temperatures than MgCO3, but can likely convert to MgCO3 rather than MgO under high purity CO2 conditions in a calciner, as described below.|[0057] After the carbonation medium has contacted the ambient air to adsorb the CO2 from the air, the carbonation medium becomes the carbon-containing stream. The carbon-containing stream is fed to the calciner at step 13. In some embodiments, the carbon-containing stream can include MgCO3, dolomite (high magnesium calcium carbonate), sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, potassium carbonate, potassium bicarbonate, nesquehonite, and/or hydromagnesite. In some embodiments, the carbon-containing stream can include dunite, calcite, wollastonite, and/or pyroxines.|[0058] In some embodiments, the carbon-containing stream can include a powder. In some embodiments, the carbon-containing stream can be in the form of pebbles or large rocks. In some embodiments, the carbon-containing stream can have an average particle size of at least about 5 μm, at least about 10 μm, at least about 20 μm, at least about 30 μm, at least about 40 μm, at least about 50 μm, at least about 60 μm, at least about 70 μm, at least about 80 μm, at least about 90 μm, at least about 100 μm, at least about 200 μm, at least about 300 μm, at least about 400 μm, at least about 500 μm, at least about 600 μm, at least about 700 μm, at least about 800 μm, at least about 900 μm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, or at least about 4 cm. In some embodiments, the carbon-containing stream can have an average particle size of no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, no more than about 1 mm, no more than about 900 μm, no more than about 800 μm, no more than about 700 μm, no more than about 600 μm, no more than about 500 μm, no more than about 400 μm, no more than about 300 μm, no more than about 200 μm, no more than about 100 μm, no more than about 90 μm, no more than about 80 μm, no more than about 70 μm, no more than about 60 μm, no more than about 50 μm, no more than about 40 μm, no more than about 30 μm, no more than about 20 μm, or no more than about 10 μm.|[0059] Combinations of the above-referenced particle sizes are also possible (e.g., at least about 10 μm and no more than about 5 cm or at least about 100 μm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbon-containing stream can have an average particle size of about 5 μm, about 10 μm, about 20 μm, about 30 μm, about 40 μm, about 50 μm, about 60 μm, about 70 μm, about 80 μm, about 90 μm, about 100 μm, about 200 μm, about 300 μm, about 400 μm, about 500 μm, about 600 μm, about 700 μm, about 800 μm, about 900 μm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, at least about 2 cm, about 3 cm, about 4 cm, or about 5 cm.|[0060] At step 14, heat is applied to the calciner to decompose the carbon-containing stream to a gas stream and a carbonation medium stream. In some embodiments, the heat applied to the calciner can be via electric resistance heating. In some embodiments, the electric resistance heating can be powered by renewable electricity. In some embodiments, the renewable electricity can be supplied by wind power, solar power, geothermal power, nuclear energy, or any other suitable renewable energy source or combinations thereof. In some embodiments, the calciner can be sufficiently hot (e.g., from solar radiation), such that additional heat need not be supplied at step 14. In some embodiments, in the calciner, the carbon-containing stream can be calcined according to the following reaction.|where Me represents a divalent metal cation.|[0061] The gas stream includes CO2. In some embodiments, the gas stream can have a composition that includes at least about 80 vol %, at least about 85 vol %, at least about 90 vol %, at least about 91 vol %, at least about 92 vol %, at least about 93 vol %, at least about 94 vol %, at least about 95 vol %, at least about 96 vol %, at least about 97 vol %, at least about 98 vol %, at least about 99 vol %, at least about 99.1 vol %, at least about 99.2 vol %, at least about 99.3 vol %, at least about 99.4 vol %, at least about 99.5 vol %, at least about 99.6 vol %, at least about 99.7 vol %, at least about 99.8 vol %, or at least about 99.9 vol % CO2.|[0062] The gas stream formed from the calcining is sequestered and/or utilized at step 15. In some embodiments, the gas stream can be sequestered at a sequestration space (e.g., an underground sequestration space). In some embodiments, the gas stream can be used as a CO2-rich fuel. In some embodiments, the gas stream can be fed to a greenhouse to facilitate plant growth. In some embodiments, the gas stream can be fed to an environment where a controlled dosage of CO2-rich gas is used to facilitate tree or plant growth. In some embodiments, the gas stream can be subjected to further processing to increase the CO2 content. In some embodiments, CO2 from the gas stream can be used to cure concrete. In some embodiments, CO2 from the gas stream can be used as a feedstock for chemicals (e.g., ethanol). In some embodiments, CO2 from the gas stream can be used to carbonate beverages. In some embodiments, CO2 from the gas stream can be used for enhanced oil recovery. In some embodiments, the processing can include condensation of water. In some embodiments, the gas stream can be compressed into gas storage. In some embodiments, the compressed gas stream can be direct injected in a co-located facility. In some embodiments, the compressed gas stream can be transported to a location where it can be sequestered. In some embodiments, a portion of the gas stream can be sequestered while a portion of the gas stream can be utilized.|[0063] Step 16 includes feeding the carbonation medium stream to the carbonation station. The carbonation medium is a product of the calcining and is fed to the carbonation station. In some embodiments, the carbonation medium stream fed to the carbonation station can include at least a portion of recycled material. In some embodiments, the carbonation medium can be grinded prior to feeding to the carbonation station. The process then starts again at step 11, where the carbonation medium contacts the ambient air. In some embodiments, the carbonation medium can be transported from the calciner to the carbonation station via a conveyor or a series of conveyors. In some embodiments, the calciner can be at a higher elevation than the carbonation station, such that gravity can assist the conveyance of the carbonation medium to the carbonation station. In some embodiments, with recycling of carbonation medium, ultramafic rocks can become increasingly divided into materials such as MgCO3, minor CaCO3, and SiO2 after each weathering step, and the calcining residue can become richer and richer in MgO and CaO, and thus more reactive and useful as feedstock for successive cycles.|[0064] Step 17 is an optional precursor to step 13 and/or step 14 and includes processing an air stream to produce an oxygen stream and feeding the oxygen stream to the calciner. Introducing oxygen to the calciner can improve the quality and thoroughness of the calcining. In some embodiments, the processing can be via an air separation unit. In some embodiments, the oxygen stream can include at least about 80 vol %, at least about 85 vol %, at least about 90 vol %, at least about 91 vol %, at least about 92 vol %, at least about 93 vol %, at least about 94 vol %, at least about 95 vol %, at least about 96 vol %, at least about 97 vol %, at least about 98 vol %, at least about 99 vol %, at least about 99.1 vol %, at least about 99.2 vol %, at least about 99.3 vol %, at least about 99.4 vol %, at least about 99.5 vol %, at least about 99.6 vol %, at least about 99.7 vol %, at least about 99.8 vol %, or at least about 99.9 vol % O2. In some embodiments, the feeding of the oxygen stream into the calciner can occur at least partially concurrently to feeding the carbon-containing stream into the calciner at step 13. In some embodiments, the feeding of the oxygen stream into the calciner can occur at least partially concurrently to applying heat to the calciner at step 14.|[0065] Step 18 is an optional post-processing step that can be applied to the gas stream captured at step 15. Step 18 includes condensing and/or recycling water from the gas stream. Water in the gas stream is not desired for purposes of sequestering and storage or for use as a fuel. By removing the water from the gas stream, the purity of the gas stream (in terms of CO2 content) increases and therefore the gas stream can have a wider range of possible storage locations or uses. In some embodiments, water capture from the gas stream can be recycled and fed to the carbonation station (i.e., added to the water stream from step 12).|[0066] Step 19 is optional and includes grinding sorbent material to form the carbonation medium. In some embodiments, the sorbent material can include a mined material. In some embodiments, the sorbent material can be recycled (e.g., from the calciner). Grinding the sorbent material can reduce the particle size and improve adsorption of CO2 per unit mass. In some embodiments, the grinding can be via a ball mill crusher, an impact crusher, a cone crusher, or any other suitable grinding device or combinations thereof.|[0067] Step 21 is optional and includes hydrating the carbonation medium stream. The carbonation medium can be hydrated prior to feeding the carbonation medium to the carbonation station. In some embodiments, carbonation medium from the calciner (or mined carbonation medium) can be hydrated at the hydration station to form a hydroxide, in accordance with the following reaction.|where Me represents a divalent metal cation.|[0068] Hydrating the carbonation medium can improve the affinity of the carbonation medium to capture CO2. For example, the reaction between Ca(OH)2 and CO2 can have lower activation energy than the reaction between CaO and CO2. The residence time of a carbonation medium including hydroxides at the carbonation station can be less than the residence time of a carbonation medium without hydroxides. Hydration of the carbonation medium can allow for recovery of heat from the hydration reaction, as the reaction is exothermic. In some embodiments, the hydration can be achieved by passing the carbonation medium through a humid enclosure (e.g., with at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, or about 100% relative humidity, inclusive of all values and ranges therebetween). In some embodiments, the hydration can be achieved by misting water onto the carbonation medium (e.g., via one or more sprayers). In some embodiments, the hydration can be achieved by placing the carbonation medium in a water bath.|[0069] FIG. 2 is a block diagram of a carbon capture facility 100, according to an embodiment. As shown, the carbon capture facility includes a carbonation station 110 and a calciner 120. The carbon capture facility 100 optionally includes a sequestration space 130, a grinding station 140, a hydration station 150, a condensation space 160, and an air separation unit 170. In use, a carbonation medium adsorbs and reacts chemically with CO2 in ambient air at the carbonation station 110 to form a carbon-containing stream. The carbon-containing stream is fed to the calciner 120, where the carbon-containing stream is calcined to form a gas stream and a stream of carbonation medium. The gas stream can be subjected to further processing in the condensation space 160 and stored in the sequestration space 130. The grinding station 140 can grind carbonation medium and/or carbon-containing medium and feed to the carbonation station 110 and/or the calciner 120. The hydration station 150 can optionally process the carbon-containing stream prior to feeding the carbon-containing stream to the calciner 120. The air separation unit 170 can process an air stream, prior to feeding the air stream to the calciner. The carbon capture facility 100 utilizes alkalinity to sequester a target compound (e.g., CO2). In some embodiments, the carbon capture can be via reaction between the target compound and a carbonation medium. In some embodiments, the reaction can be a carbonation reaction.|[0070] The carbonation station 110 is a location where the carbonation medium contacts the ambient air and adsorbs and reacts with the CO2 to become the carbon-containing stream. The carbonation station 110 includes CO2 contactors. Some of the contactors described herein can be the same or substantially similar to those described in International Patent Publication WO2020/263910 (“the '910 publication”), filed Jun. 24, 2020, titled, “System and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. The carbonation station 110 includes one or more water delivery devices to keep the moisture levels of the carbonation medium and/or localized humidity levels at the desired levels. In some embodiments, the water delivery devices can include one or more sprayers, hoses, mats, misters, sprinklers, or any other suitable water delivery device or combinations thereof. In some embodiments, the carbonation station 110 can include a plurality of carbonation plots positioned to expose the carbonation medium to ambient conditions. In some embodiments, one or more of the carbonation plots can be placed in the vicinity of facilities with heavy CO2 exhaust. In some embodiments, the carbonation plots can include sheets of carbonation medium in powder form. In some embodiments, the carbonation plots can be arranged in stacked columns. In some embodiments, the carbonation station 110 can include a temperature sensor, a humidity sensor, and/or a gas flowmeter to measure the movement of ambient air in the vicinity of the carbonation plots. In some embodiments, the carbonation station 110 can be located outdoors. In some embodiments, the carbonation station can include a stirring implement for stirring the carbonation medium. In some embodiments, the stirring implement can include a mixing bar, a stirring rod, an impeller, and/or any other suitable device for stirring.|[0071] In some embodiments, the carbonation station 110 can be maintained at a relative humidity in the immediate proximity of the carbonation medium at a level of at least about 5%, at least about 10%, at least about 15%, at least about 20%, at least about 25%, at least about 30%, at least about 35%, at least about 40%, at least about 45%, at least about 50%, at least about 55%, at least about 60%, at least about 65%, at least about 70%, at least about 75%, at least about 80%, at least about 85%, at least about 90%, or at least about 95%. In some embodiments, the carbonation station 110 can be maintained at a relative humidity in the immediate proximity of the carbonation medium at a level of no more than about 100%, no more than about 95%, no more than about 90%, no more than about 85%, no more than about 80%, no more than about 75%, no more than about 70%, no more than about 65%, no more than about 60%, no more than about 55%, no more than about 50%, no more than about 45%, no more than about 40%, no more than about 35%, no more than about 30%, no more than about 25%, no more than about 20%, no more than about 15%, or no more than about 10%. Combinations of the above-referenced values of relative humidity at the carbonation station 110 are also possible (e.g., at least about 5% and no more than about 70% or at least about 20% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, carbonation station 110 can be maintained at about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, or about 100% relative humidity.|[0072] The calciner 120 receives the carbon-containing stream from the carbonation station 110. In some embodiments, the calciner 120 can include a total flow calciner, a fluidized bed calciner, a rotary kiln calciner, a riser reactor-calciner, a separated tertiary air flow calciner, a hybrid calciner, or any other suitable calciner or combinations thereof. In some embodiments, the calciner 120 can include an oxy-fired calciner, an electric-fired calciner, a solar calciner, a “carbon-free” calciner. In some embodiments, the calciner 120 can use recycled waste heat from other processes. In some embodiments, the calciner 120 can be physically coupled to a power source. In some embodiments, the calciner 120 can be heated via electric resistance heating. In some embodiments, the electric resistance heating can be powered by grid electricity. In some embodiments, the electric resistance heating can be powered by renewable electricity. In some embodiments, the renewable electricity can be supplied by wind power, solar power, geothermal power, nuclear power, or any other suitable renewable energy source or combinations thereof. In some embodiments, the calciner 120 can include a valve and gate system for controlling inputs and outputs. In some embodiments, the calciner 120 can have a calcination efficiency of at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 96%, at least about 97%, at least about 98%, or at least about 99%, inclusive of all values and ranges therebetween.|[0073] In some embodiments, the calciner 120 can include an oxy-fired calciner and can be operationally coupled to the air separation unit 170 and a condenser (e.g., in the condensation space 160). The air separation unit 170 can ensure pure or substantially pure oxygen is fed to the calciner 120. The condenser can condense water from the gaseous stream leaving the calciner 120. This can allow for the capture of CO2 produced from fuel combustion. The complete combustion reaction can proceed in accordance with the following reaction, using methane as an exemplary combustion medium.|[0074] The sequestration space 130 is optional and is fluidically coupled to the calciner 120. The sequestration space 130 receives the gas stream from the calciner 120. In some embodiments, the condensation space 160 can receive liquid from the gas stream before or concurrently to when the sequestration space 130 receives the gas stream from the calciner 120. In some embodiments, a condenser is used to increase the purity of the gas stream and remove water from the gas stream. The water can be received in the condensation space 160. The water can be utilized in the process or sold as a byproduct. In some embodiments, the carbon capture facility 100 can include other post-processing equipment (not shown) to process the gas stream when it exits the calciner 120. In some embodiments, the carbon capture facility 100 can include a dehydrator and/or a compressor.|[0075] In some embodiments, the sequestration space 130 can be co-located with the calciner 120. In some embodiments, the sequestration space 130 can be located underground. In some embodiments, the sequestration space 130 can be located immediately underneath the calciner 120. In some embodiments, the sequestration space 130 can be located a sufficient distance away from the calciner 120, such that CO2 is transported from the calciner 120 to the sequestration space 130 (e.g., via fans and pipes). In some embodiments, the sequestration space 130 can include sorbents to improve storage capacity. In some embodiments, the sorbents can include activated carbon, graphene, silica, acrylonitrile, phosphorene, carbon nanotubes, biopolymers, metal organic frameworks, zeolites, grafted amines, or any other suitable sorbent or combinations thereof. In some embodiments, the sequestration space 130 can be maintained at a pressure of about 1 bar (gauge), about 2 bar, about 3 bar, about 4 bar, about 5 bar, about 6 bar, about 7 bar, about 8 bar, about 9 bar, about 10 bar, about 15 bar, about 20 bar, about 25 bar, about 30 bar, about 35 bar, about 40 bar, about 45 bar, about 50 bar, about 55 bar, about 60 bar, about 65 bar, about 70 bar, about 75 bar, about 70 bar, about 75 bar, about 80 bar, about 85 bar, about 90 bar, about 95 bar, about 100 bar, about 150 bar, about 200 bar, about 250 bar, about 300 bar, about 350 bar, about 400 bar, about 450 bar, about 500 bar, about 550 bar, about 600 bar, about 650 bar, about 700 bar, about 750 bar, about 800 bar, about 850 bar, about 900 bar, about 950 bar, or about 1,000 bar, inclusive of all values and ranges therebetween.|[0076] The grinding station 140 is an optional component of the carbon capture facility 100 and includes grinding media for processing of the carbonation medium and/or the carbon-containing stream. In some embodiments, mined materials can be fed to the grinding station 140 to reduce the particle size of the mined materials, before feeding to the carbonation station 110 and/or the calciner 120. In some embodiments, the grinding media can include a ball mill crusher, an impact crusher, and/or a cone crusher.|[0077] The hydration station 150 is an optional intermediate station between the calciner 120 and the carbonation station 110. In some embodiments, carbonation medium from the calciner can be hydrated at the hydration station to form a hydroxide, as described above in step 21, with reference to FIG. 1. In some embodiments, the hydration station can include a water bath, one or more misting devices (e.g., water sprayers), a humid enclosure, or any combination thereof. In some embodiments, the hydration station 150 can be part of the carbonation station 110. In other words, the hydration and the carbonation can occur at the same location.|[0078] The air separation unit 170 is an optional component for improving air quality before feeding the air to the calciner 120. In some embodiments, the air separation unit 170 can increase the oxygen content in an air stream, before feeding the oxygen-rich air stream into the calciner 120. In some embodiments, the air separation unit 170 can include a condenser to remove water from the air. In some embodiments, the air separation unit 170 can produce a pure stream of oxygen to feed the calciner 120. In some embodiments, the air separation unit 170 can allow for more efficient combustion in the calciner 120 as the air separation unit 170 can remove contaminants and inert materials from the air prior to feeding to the calciner 120.|[0079] FIG. 3 is a block diagram of a carbon capture facility 200, according to an embodiment. As shown, the carbon capture facility 200 includes a carbonation station 210, a calciner 220, a sequestration space 230, a grinding station 240, a hydration station 250, a condensation space 260, and an air separation unit 270. In some embodiments, the carbonation station 210, the calciner 220, the sequestration space 230, the grinding station 240, the hydration station 250, the condensation space 260, and the air separation unit 270 can be the same or substantially similar to the carbonation station 110, the calciner 120, the sequestration space 130, the grinding station 140, the hydration station 150, the condensation space 160, and the air separation unit 170, as described above with reference to FIG. 2. Thus, certain aspects of the carbonation station 210, the calciner 220, the sequestration space 230, the grinding station 240, the hydration station 250, the condensation space 260, and the air separation unit 270 are not described in greater detail herein.|[0080] In use, a carbonation medium stream CMS is processed via the hydration station 250 prior to being fed to the carbonation station 210. After carbonation at the carbonation plot 210, a recycled carbon-containing stream CCS(R) is fed to the calciner 220. Meanwhile, an adsorbent material AM is fed to the grinding station 240 and grinded to become a new carbon-containing stream CCS(N). The new carbon-containing stream CCS(N) is fed to the calciner concurrently with the recycled carbon-containing stream CCS(R). Meanwhile, air is fed to the air separation unit 270 and a stream rich in O2 is fed from the air separation unit 270 to the calciner 220. After processing in the calciner 220, the carbon-containing streams CCS(R) and CCS(N) become a gas stream GS and the carbonation medium stream CMS. The carbonation medium stream CMS is fed back to the hydration station 250 while the gas stream GS is fed to the sequestration space 230. Between the calciner 220 and the sequestration space 230, the gas stream 230 is condensed and a recycled stream of water H2O(R) is captured in the condensation space 260. The recycled stream of water H2O(R) is fed to a sprayer 215. A new stream of water H2O(N) is also fed to the sprayer 215. The sprayer 215 sprays water on the carbonation station 210.|[0081] The carbonation station 210 includes the carbonation plots 211. In some embodiments, the carbonation plots 211 can be positioned and configured to expose the compositions in the carbonation plots to ambient weathering. The carbonation plots 211 can be placed in an environment configured to maximize the temperature at the surface of the composition of the carbonation plots 211. In some embodiments, the carbonation plots 211 can be positioned in a natural environment (e.g., grasslands, deserts, mountainsides). In some embodiments, the carbonation plots 211 can be clustered into a group. In some embodiments, the clustered carbonation plots 211 enable centralized implementation of other system components for more efficient operation of the carbon capture facility 200. In some embodiments, the carbonation plots 211 can be distributed throughout a region of the planet (e.g., non-arable land in the Western United States). In some embodiments, a plurality of carbonation plots 211 are distributed throughout the planet.|[0082] As shown, the carbonation station 210 includes nine carbonation plots 211. In some embodiments, the carbonation station 210 can include at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, at least about 900, at least about 1,000, at least about 1,500, at least about 2,000, at least about 2,500, at least about 3,000, at least about 3,500, at least about 4,000, at least about 4,500, at least about 5,000, at least about 5,500, at least about 6,000, at least about 6,500, at least about 7,000, at least about 7,500, at least about 8,000, at least about 8,500, at least about 9,000, at least about 9,500, at least about 10,000, at least about 11,000, at least about 12,000, at least about 13,000, at least about 14,000, at least about 15,000, at least about 16,000, at least about 17,000, at least about 18,000, at least about 19,000, at least about 20,000, at least about 25,000, at least about 30,000, at least about 35,000, at least about 40,000, at least about 45,000, at least about 50,000, at least about 55,000, at least about 60,000, or at least about 65,000 carbonation plots 211. In some embodiments, the carbonation station 210 can include no more than about 70,000, no more than about 65,000, no more than about 60,000, no more than about 55,000, no more than about 50,000, no more than about 45,000, no more than about 40,000, no more than about 35,000, no more than about 30,000, no more than about 25,000, no more than about 20,000, no more than about 19,000, no more than about 18,000, no more than about 17,000, no more than about 16,000, no more than about 15,000, no more than about 14,000, no more than about 13,000, no more than about 12,000, no more than about 11,000, no more than about 10,000, no more than about 9,500, no more than about 9,000, no more than about 8,500, no more than about 8,000, no more than about 7,500, no more than about 7,000, no more than about 6,500, no more than about 6,000, no more than about 5,500, no more than about 5,000, no more than about 4,500, no more than about 4,000, no more than about 3,500, no more than about 3,000, no more than about 2,500, no more than about 2,000, no more than about 1,500, no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, or no more than about 3 carbonation plots 211.|[0083] Combinations of the above-referenced numbers of carbonation plots in the carbonation station 210 are also possible (e.g., at least about 2 and no more than about 70,000 or at least about 500 and no more than about 5,000, inclusive of all values and ranges therebetween. In some embodiments, the carbonation station 210 can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, about 1,000, about 1,500, about 2,000, about 2,500, about 3,000, about 3,500, about 4,000, about 4,500, about 5,000, about 5,500, about 6,000, about 6,500, about 7,000, about 7,500, about 8,000, about 8,500, about 9,000, about 9,500, about 10,000, about 11,000, about 12,000, about 13,000, about 14,000, about 15,000, about 16,000, about 17,000, about 18,000, about 19,000, about 20,000. about 25,000, about 30,000. about 35,000, about 40,000, about 45,000, about 50,000, about 55,000, about 60,000, about 65,000, or about 70,000 carbonation plots 211.|[0084] In some embodiments, the carbonation plots 211 can include sheets of carbonation medium. In some embodiments, the carbonation plots 211 can have length and/or width dimensions of at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.1 m, at least about 1.2 m, at least about 1.3 m, at least about 1.3 m, at least about 1.4 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, at least about 4.5 m, at least about 5 m, at least about 5.5 m, at least about 6 m, at least about 6.5 m, at least about 7 m, at least about 7.5 m, at least about 8 m, at least about 8.5 m, at least about 9 m, or at least about 9.5 m. In some embodiments, the carbonation plots 211 can have length and/or width dimensions of no more than about 10 m, no more than about 9.5 m, no more than about 9 m, no more than about 8.5 m, no more than about 8 m, no more than about 7.5 m, no more than about 7 m, no more than about 6.5 m, no more than about 6 m, no more than about 5.5 m, no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.9 m, no more than about 1.8 m, no more than about 1.7 m, no more than about 1.6 m, no more than about 1.5 m, no more than about 1.4 m, no more than about 1.3 m, no more than about 1.2 m, no more than about 1.1 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, or no more than about 20 cm. Combinations of the above-referenced length and width dimensions of the carbonation plots 211 are also possible (e.g., at least about 10 cm and no more than about 10 m or at least about 50 cm and no more than about 5 m), inclusive of all values and ranges therebetween. In some embodiments, the carbonation plots 211 can have length and/or width dimensions of about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.1 m, about 1.2 m, about 1.3 m, about 1.4 m, about 1.5 m, about 1.6 m, about 1.7 m, about 1.8 m, about 1.9 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, about 5 m, about 5.5 m, about 6 m, about 6.5 m, about 7 m, about 7.5 m, about 8 m, about 8.5 m, about 9 m, about 9.5 m, or about 10 m.|[0085] In some embodiments, the carbonation plots 211 can include thin sheets of carbonation medium powder and/or pebbles. In some embodiments, the carbonation plots 211 can include sheets with thicknesses of at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm. In some embodiments, the carbonation plots 211 can include sheets with thicknesses of no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, or no more than about 2 mm. Combinations of the above-referenced sheet thicknesses are also possible (e.g., at least about 1 mm and no more than about 50 cm or at least about 5 mm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation plots 211 can include sheets with thicknesses of about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, or about 50 cm.|[0086] In some embodiments, each of the carbonation plots 211 can include at least about 1,000 tons, at least about 2,000 tons, at least about 3,000 tons, at least about 4,000 tons, at least about 5,000 tons, at least about 6,000 tons, at least about 7,000 tons, at least about 8,000 tons, at least about 9,000 tons, at least about 10,000 tons, at least about 20,000 tons, at least about 30,000 tons, at least about 40,000 tons, or at least about 50,000 tons of carbonation medium. In some embodiments, each of the carbonation plots 211 can include no more than about 60,000 tons, no more than about 50,000 tons, no more than about 40,000 tons, no more than about 30,000 tons, no more than about 20,000 tons, no more than about 10,000 tons, no more than about 9,000 tons, no more than about 8,000 tons, no more than about 7,000 tons, no more than about 6,000 tons, no more than about 5,000 tons, no more than about 4,000 tons, no more than about 3,000 tons, or no more than about 2,000 tons of carbonation medium. Combinations of the above-referenced amounts of carbonation medium are also possible (e.g., at least about 1,000 tons and no more than about 60,000 tons or at least about 5,000 tons and no more than about 40,000 tons), inclusive of all values and ranges therebetween. In some embodiments, each of the carbonation plots 211 can include about 1,000 tons, about 2,000 tons, about 3,000 tons, about 4,000 tons, about 5,000 tons, about 6,000 tons, about 7,000 tons, about 8,000 tons, about 9,000 tons, about 10,000 tons, about 20,000 tons, about 30,000 tons, about 40,000 tons, about 50,000 tons, or about 60,000 tons of carbonation medium.|[0087] In some embodiments, the thin sheets of carbonation medium of the carbonation plots 211 can be arranged in trays. In some embodiments, the trays can be stacked vertically. In some embodiments, each the carbonation plots 211 can include at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, at least about 900, at least about 1,000, at least about 1,500, at least about 2,000, at least about 2,500, at least about 3,000, at least about 3,500, at least about 4,000, or at least about 4,500 trays. In some embodiments, each of the carbonation plots 211 can include no more than about 5,000, no more than about 4,500, no more than about 4,000, no more than about 3,500, no more than about 3,000, no more than about 2,500, no more than about 2,000, no more than about 1,500, no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, or no more than about 2 trays. Combinations of the above-referenced numbers of trays in each of the carbonation plots 211 are also possible (e.g., at least about 1 and no more than about 5,000 or at least about 50 and no more than about 500), inclusive of all values and ranges therebetween. In some embodiments, the trays can be stacked vertically. In some embodiments, each the carbonation plots 211 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, about 1,000, about 1,500, about 2,000, about 2,500, about 3,000, about 3,500, about 4,000, about 4,500, or about 5,000 trays.|[0088] In some embodiments, the carbonation plots 211 can include a powder of carbonation medium. In some embodiments, the carbonation medium can be in the form of pebbles or large rocks. In some embodiments, the carbonation medium can have an average particle size of at least about 5 μm, at least about 10 μm, at least about 20 μm, at least about 30 μm, at least about 40 μm, at least about 50 μm, at least about 60 μm, at least about 70 μm, at least about 80 μm, at least about 90 μm, at least about 100 μm, at least about 200 μm, at least about 300 μm, at least about 400 μm, at least about 500 μm, at least about 600 μm, at least about 700 μm, at least about 800 μm, at least about 900 μm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, or at least about 4 cm. In some embodiments, the carbonation medium can have an average particle size of no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, no more than about 1 mm, no more than about 900 μm, no more than about 800 μm, no more than about 700 μm, no more than about 600 μm, no more than about 500 μm, no more than about 400 μm, no more than about 300 μm, no more than about 200 μm, no more than about 100 μm, no more than about 90 μm, no more than about 80 μm, no more than about 70 μm, no more than about 60 μm, no more than about 50 μm, no more than about 40 μm, no more than about 30 μm, no more than about 20 μm, or no more than about 10 μm.|[0089] Combinations of the above-referenced particle sizes are also possible (e.g., at least about 10 μm and no more than about 5 cm or at least about 100 μm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can have an average particle size of about 5 μm, about 10 μm, about 20 μm, about 30 μm, about 40 μm, about 50 μm, about 60 μm, about 70 μm, about 80 μm, about 90 μm, about 100 μm, about 200 μm, about 300 μm, about 400 μm, about 500 μm, about 600 μm, about 700 μm, about 800 μm, about 900 μm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, at least about 2 cm, about 3 cm, about 4 cm, or about 5 cm.|[0090] FIG. 4 shows a carbonation station 310, according to an embodiment. As shown, the carbonation station 310 includes carbonation plots 311 and a sprayer 315. In some embodiments, the carbonation station 310, the carbonation plots 311, and the sprayer 315 can be the same or substantially similar to the carbonation station 210, the carbonation plots 211, and the sprayer 215 as described above with reference to FIG. 3. Thus, certain aspects of the carbonation station 310, the carbonation plots 311, and the sprayer 315 are not described in greater detail herein. As shown, the sprayer 315 sprays water onto the carbonation plots 311 to maintain a desired moisture level in the carbonation station 310. In some embodiments, the sprayer 315 can mist continuously. In some embodiments, the sprayer 315 can spray at intervals. In some embodiments, the sprayer 315 can be stationary. In some embodiments, the sprayer 315 can move laterally from above the carbonation plots 311 to maximize the ground covered by the sprayer 315. In some embodiments, carbonation plots 311 can be placed above and below the sprayer 315 and the sprayer can spray upward and downward to deliver water to the carbonation plots 311.|[0091] FIG. 5 shows positioning of a carbonation station 410 surrounding a calciner 420 and a sequestration space 430. As shown, the carbonation station includes a plurality of carbonation plots 411. In some embodiments, the carbonation station 410, the carbonation plots 411, the calciner 420, and the sequestration space 430 can be the same or substantially similar to the carbonation station 210, the carbonation plots 211, the calciner 220, and the sequestration space 230, as described above with reference to FIG. 3. Thus, certain aspects of the carbonation plots 411, the calciner 420, and the sequestration space 430 are not described in greater detail herein.|[0092] FIG. 5 shows a layout of the carbonation station 410 with the carbonation plots 411 surrounding the calciner 420. This can be an advantageous layout, as it minimizes the distance carbonation medium and the carbon-containing streams travel for processing between the process units. In some embodiments, the carbonation plots 411 can be arranged in a circle pattern, an oval pattern, a square pattern, a rectangular pattern, or any other suitable pattern around the calciner 420, in order to minimize energy cost for transporting carbonation medium and carbon-containing streams. In some embodiments, multiple carbonation plots 411 can be staggered in maturation date, allowing them to feed into a central regeneration facility. Conveyors C surround the calciner 420, transporting material between the carbonation station 410 and the calciner 420. | (US20240269605)|RELATED APPLICATIONS|[0001] This application is a continuation of International Patent Application No. PCT/US2022/018484, filed Mar. 2, 2022, which claims priority and benefit of U.S. Provisional Application No. 63/155,572, filed Mar. 2, 2021 and titled “Systems and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference herein in its entirety.|(US20240269605)|TECHNICAL FIELD|[0002] Embodiments described herein relate systems and methods for uptake of carbon dioxide (CO2) from ambient air.|BACKGROUND|[0003] The atmospheric concentration of CO2 has reached 410 parts per million by volume (ppm), an increase of almost 20 ppm in the last 10 years. As current emission levels exceed 35 GtCO2/year, a diverse portfolio of CO2 mitigation technologies must be developed and strategically deployed to avoid a 2° C. increase in Earth's temperature by 2100. Due to global reliance on fossil fuels, this portfolio must include technologies that can remove current and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|SUMMARY|[0004] Embodiments described herein relate to systems and methods of CO2 uptake. In one aspect, a method includes applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2. The method further includes sequestering and/or utilizing the gas stream, feeding the stream of the carbonation medium to a carbonation station, contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs or reacts with CO2 to form the carbon-containing stream, during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours, and feeding the carbon-containing stream to the calciner. In some embodiments, adding the water stream is via misting and/or spraying. In some embodiments, the water is added at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium. In some embodiments, the carbonation medium is maintained at a moisture content between about 3 wt % and about 50 wt %. In some embodiments, the method can further include grinding a sorbent material to form the carbonation medium in a powder via a ball mill crusher, an impact crusher, and/or a cone crusher.|(US20240269605)|BRIEF DESCRIPTION OF THE DRAWINGS|[0005] FIG. 1 is a block diagram of a method of CO2 capture from ambient air, according to an embodiment.|[0006] FIG. 2 is a block diagram of a carbon capture facility, according to an embodiment.|[0007] FIG. 3 is an illustration of a carbon capture facility, according to an embodiment.|[0008] FIG. 4 is an illustration of a carbonation station, according to an embodiment.|[0009] FIG. 5 is an illustration of a carbonation station, according to an embodiment.|[0010] FIG. 6 is a plot of CO2 uptake of different materials over a period of 10 days.|[0011] FIG. 7 is a plot of CO2 uptake of different materials over a period of 16 days.|[0012] FIG. 8 is a plot of CO2 uptake of different materials over a period of 16 days.|[0013] FIG. 9 is a plot of consumption of calcium hydroxide (Ca(OH)2) over a period of 2 days.|[0014] FIG. 10 is a plot of uptake rate versus time for varying magnesium oxide material suppliers.|[0015] FIG. 11 is a plot of misting amount versus uptake rate as a function of material type.|[0016] FIG. 12 is a visual representation of material and energy balances in a carbon capture facility.|(US20240269605)|DETAILED DESCRIPTION|[0017] Some embodiments of the present disclosure are directed to CO2 uptake from air during weathering. The uptake can be on time scales of months to years, achieving valuable CO2 removal from air while lowering the looping costs. Embodiments described herein can relate to methods for using material including metal carbonates as a feedstock for carbon capture and removal. Heating of material yields CO2 gas and solid metal oxides and metal hydroxides from the carbonates. These metal oxide and metal hydroxide products can be layered thinly in an outdoor area and subjected to weathering over a series of months or years, during which the metal oxides and metal hydroxides absorb CO2 from the air to generate additional metal carbonates, other hydrated magnesium carbonates, etc. The cycle can then be repeated, with the carbonates being heated to release CO2 into a controlled capture environment. The resulting reactive oxides and/or hydroxides can then be layered again for weathering, and the captured CO2 can be bottled and sold or stored underground.|[0018] Negative Emission Technologies (NET's), also known as carbon dioxide removal (CDR) technologies, encompass a broad range of strategies for CO2 removal from air. Some methods employed include bioenergy, afforestation, direct air capture and ocean fertilization. Energy efficiency is important for adoption and implementation of either of these strategies. NETs should be carbon negative if they are to be adopted on a large scale. In other words, methods of CO2 removal from air should extract more carbon from the atmosphere than they emit in the process. Efficiency of carbon removal has only recently become a technological focus.|[0019] The contribution of CO2 to global warming is well documented. Recently, carbon capture methods have been developed for point-of-release carbon capture (e.g., at the smokestack or near the exhaust port). Previous approaches included CO2 capture from flue gas and other concentrated sources, in smokestacks or reactors, on time scales of minutes to days. Such systems often rely on faster reaction times and higher energy investments, e.g., application of high heat and/or pressure. These solutions are often expensive, and they occasionally employ designer materials that may be difficult to produce. Costs of $100/ton of CO2 produced are optimistic cost estimates for direct air capture, but realistic for point source capture where CO2 is more concentrated.|[0020] The Intergovernmental Panel on Climate Change, (IPCC) and other authoritative organizations, have determined that CO2 removal from air is necessary to hold global warming to less than 2° C. CO2 removal from air is more difficult than CO2 capture from flue gas. Current technology involves “direct air capture” machines (DAC) that remove CO2 from air at a cost at or above $600/ton CO2. The reaction of CO2 with certain calcium and magnesium oxides has been widely recognized for many years as a form of rock weathering and subsequent carbon sink. Natural weathering removes vast quantities of CO2 and this could be adapted to help offset some of the emissions being produced worldwide. Enhanced carbon capture through reaction of CO2 with ultramafic rock is one NET that can be scaled up to alleviate impacts of climate change.|[0021] Enhanced weathering dates back to 1990, when Walter Seifritz proposed a process based on natural weathering. In natural weathering, alkaline-containing minerals are carbonated on geologic timescales (i.e., millions of years). The generalized natural weathering reaction is described below:|where Me represents a divalent metal cation.|[0022] Cations can include magnesium (Mg2+) and calcium (Ca2+), where suitable feedstocks include minerals, such as olivine and serpentine, as well as industrial byproducts, such as mine tailings and fly ash. Since the natural weathering reaction occurs on geological timescales, various process conditions, pretreatment methods, extraction mechanisms, and other strategies can expedite process kinetics as a form of CO2 sequestration.|[0023] Several CO2 capture systems have been explored. The American Physical Society, in a 2011 study, evaluated a system where CO2 is absorbed by sodium hydroxide (NaOH) and subsequently reacted with calcium hydroxide (Ca(OH)2) to produce solid calcium carbonate (CaCO3). The CaCO3 is then calcined in an oxy-fired calciner to release the CO2. Keith et al. propose a continuous looping process including an aqueous potassium hydroxide (KOH) sorbent coupled with a calcium caustic recovery loop. The KOH sorbent reacts with CO2 in the air to produce potassium carbonate (K2CO3). The K2CO3 then reacts with Ca(OH)2, produced from CaCO3, to reproduce the KOH and CaCO3. These types of aqueous calcium looping systems have been primarily evaluated using calcium-based sorbents in aqueous conditions (in the form of Ca(OH)2). Additionally, Renforth and Kruger proposed an ocean liming process which deposits lime (produced from calcined carbonate materials) into the ocean to react with carbonic acid currently in the ocean. The process increases oceanic pH and leads to the dissolution of more CO2 into the ocean water, reducing the atmospheric concentration of CO2. Additional systems utilizing mineral carbonation reactions have looked at various forms of carbon mineralization as a method to capture CO2 from more concentrated point sources, such as power plants.|[0024] In the aforementioned processes, calcium-bearing minerals are often used as the source of alkalinity to capture CO2. However, the calcination temperature of MgCO3 is lower than that of CaCO3, theoretically leading to a lower associated energy cost. Magnesium is also an attractive option, as there are large deposits of magnesium-rich minerals throughout the world. The IPCC and other organizations concluded that, even with optimally fast implementation of carbon-free electrical generation and other innovations, global warming would exceed 2° C. by 2100 unless about 10 billion tons of CO2 are removed from the atmosphere until 2050 increasing to 20 billion tons by 2100. In turn, there is consensus that warming beyond 2° C. is likely to have catastrophic impacts on human sustainability. Options for negative emissions that can grow to scales of about 1 billion tons of CO2 per year include increasing the carbon content of agricultural soils, reforestation, adding alkalinity to the oceans, adding biomass in the oceans, and various engineered routes of CO2 removal from air (e.g., direct air capture (DAC). The National Academies Report on Negative Emissions Technologies from 2019 concluded that none of these methods, individually, can reach the required goal, so an ensemble of methods should be used. While it seems unclear how the cost of such an ensemble will be supported, there does seem to be a growing consensus (including most national governments worldwide) that carbon capture and carbon removal will be an important component of carbon remediation.|[0025] Limestone is mined for use as crushed rock for many purposes, for use as a fertilizer, and for use in both cement and steel production. However, limestone reserves and resources are essentially unlimited from a practical point of view. Magnesite (MgCO3) is mined primarily for production of Mg metal, used in alloys. Targeted rock is used in many other industries: limestone for cement, MgCO3 for refractory, agriculture, and other uses. Global MgCO3 reserves are estimated to be 7 or 8 billion tons.|[0026] Regarding the mechanisms for material handling (e.g., loading and unloading vast amounts of carbonated media), much of the material handling infrastructure already developed in the industrial and agricultural fields can be leveraged. Some embodiments described herein include the use of electric kilns and photovoltaics. Photovoltaics laid out between plots of carbonation medium can give about 30 times more space to spread out the plots of carbonation medium.|[0027] Methods described herein can use geological materials rich in magnesium, calcium, and/or sodium. A techno-economic analysis (TEA) of an exemplary embodiment based on use of MgCO3 was produced. Mg-carbonate was calcined, at temperatures as low as 600° C. Produced CO2 (from air and from CH4 combustion in an oxy-fired calciner) is stored or sold. Produced, fine-grained MgO is distributed over the land surface for weathering. The TEA assumes a layer 10 cm thick and daily stirring, with no cm- to mm-scale passivation, for >90% carbonated in a year (based on data on CO2 uptake in brucite, Mg(OH)2). More recent data indicate that >90% carbonation can be attained in six months. Newly carbonated material is calcined, newly produced CO2 is stored or sold, and newly produced MgO is redistributed for the next stage of weathering. This looping process combines processes so that cost estimates may be relatively robust compared to those for more complex DAC methods. Cost is estimated to be $48 to $159/ton CO2 net-removed from air. The cost of produced CO2, including CO2 captured from combustion, is estimated to be $24 to $79/ton. These costs are comparable to estimated costs for other DAC methods. In fact, the estimated cost for MgO looping may currently be the lowest peer-reviewed cost estimate for DAC.|[0028] Limestone includes about 56 wt % CaO. After calcining, CaO generally reacts rapidly with air to form Ca(OH)2. Carbonation of this material via reaction with ambient air removes about 0.78 tons of CO2 per ton of initial CaO, or 0.44 tons of CO2 per ton of limestone per carbonation+calcination cycle. Results from exemplary embodiments have achieved an average Ca(OH)2 carbonation rate of about 6E-7/s (mass fraction Ca(OH)2 consumed per second by reaction with CO2 from ambient air to produce CaCO3). In turn, if this rate is constant, it will lead to 50% carbonation in about two weeks, 75% in about a month, 90% carbonation in 1.5 months, and 95% in about two months. In some embodiments, taking the 75% value, there would be 12 calcination cycles per year, removing 3.75 tons of CO2 from air per ton of limestone in the first year, assuming 1% loss of CaO per cycle. After ten years, the process would remove about 23 tons of CO2 from air per initial ton of limestone. In this calculation, to remove 1 Gt of CO2 from air per year for ten years would utilize one-time mining and processing 43.4 Mt of limestone. This is about 1.5 times more than current annual US production (32 Mt/year).|[0029] In some embodiments, systems described herein can be implemented where renewable energy capabilities overlap with CO2 storage opportunities globally. This presents opportunities to co-locate with energy and CO2 storage, specifically in the southern region of the US. It is estimated that, at an industry standard cost of $30/ton for feedstock transport, it will cost about $800,000 per year to transport the makeup feedstock for operation of a 1 Mt/year power plant. Moreover, if limestone (including CaCO3) is used and calcium oxide (CaO) is produced from CaCO3, CaO is regionally ubiquitous and effectively an unlimited resource.|[0030] In some embodiments, MgCO3 can be used as a feedstock. In some embodiments, the MgCO3 feedstock can be produced by initial weathering of quarried, ground mantle peridotite, rich in MgO. Mg(OH)2 often makes up a small portion of many peridotites. Mg(OH)2 reacts rapidly with CO2 in air to form MgCO3 in weathering conditions. Heating of peridotites including the mineral serpentine increases the rate at which serpentine reacts atmospheric CO2 to form MgCO3. Thus, after one or two heating cycles, a significant proportion of altered peridotite would be transformed to caustic magnesia. In some embodiments, CaCO3 or dolomite (high magnesium calcium carbonate) can be used as feedstock.|[0031] Some exemplary embodiments of replenished metal oxides and hydroxides include CaO and Ca(OH)2 from CaCO3, Na2O and NaOH from sodium carbonates and hydrated sodium carbonates, Mg(OH)2 and MgO from MgCO3 and hydrated Mg carbonates, and combinations thereof. Because CaCO3 is a primary constituent of limestone, looping of CaO and CaCO3 can greatly expand available feedstock and therefore the capacity for processes described herein to remove CO2 from air.|[0032] As used herein, “carbonation plot,” includes single contiguous plots, as well as semi- or non-contiguous plots that are then grouped or processed together to effectively act as a single plot. In some embodiments, carbonation plots include a composition that sequesters a target compound (e.g., CO2). In some embodiments, carbonation plots are positioned and configured to expose the composition to ambient conditions. In some embodiments, carbonation plots can include a composition that sequesters a target compound.|[0033] As used herein, “stream” can refer to stream that includes solid, liquid, and/or gas. For example, a stream can include a solid in granular form conveyed on a conveyor device. A stream can also include a liquid and/or gas flowing through a pipe. A stream can include a solution.|[0034] As used in this specification, the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, the term “a member” is intended to mean a single member or a combination of members, “a material” is intended to mean one or more materials, or a combination thereof.|[0035] The term “substantially” when used in connection with “cylindrical,” “linear,” and/or other geometric relationships is intended to convey that the structure so defined is nominally cylindrical, linear or the like. As one example, a portion of a support member that is described as being “substantially linear” is intended to convey that, although linearity of the portion is desirable, some non-linearity can occur in a “substantially linear” portion. Such non-linearity can result from manufacturing tolerances, or other practical considerations (such as, for example, the pressure or force applied to the support member). Thus, a geometric construction modified by the term “substantially” includes such geometric properties within a tolerance of plus or minus 5% of the stated geometric construction. For example, a “substantially linear” portion is a portion that defines an axis or center line that is within plus or minus 5% of being linear.|[0036] As used herein, the term “set” and “plurality” can refer to multiple features or a singular feature with multiple parts. For example, when referring to a set of contactors, the set of contactors can be considered as one contactor with multiple portions, or the set of contactors can be considered as multiple, distinct contactors. Thus, a set of portions or a plurality of portions may include multiple portions that are either continuous or discontinuous from each other. A plurality of particles or a plurality of materials can also be fabricated from multiple items that are produced separately and are later joined together (e.g., via mixing, an adhesive, or any suitable method).|[0037] As used herein, the term “about” and “approximately” generally mean plus or minus 10% of the value stated, e.g., about 250 μm would include 225 μm to 275 μm, about 1,000 μm would include 900 μm to 1,100 μm.|[0038] FIG. 1 is a block diagram of a method 10 of CO2 capture from ambient air, according to an embodiment. As shown, the method 10 includes contacting a carbonation medium with ambient air at a carbonation station to form carbon-containing stream at step 11, adding a water stream to the carbonation medium at step 12, feeding the carbon-containing stream to a calciner at step 13, applying heat to the calciner to decompose the carbon-containing stream to a gas stream and the carbonation medium stream at step 14, sequestering and/or utilizing the gas stream at step 15, and feeding the carbonation medium stream to the carbonation station at step 16, where the process repeats again from step 11. The method 10 optionally includes processing an air stream to produce an oxygen stream and feeding the oxygen stream to the calciner at step 17, condensing and/or recycling water from the sequestered gas stream at step 18, grinding sorbent material to form the carbonation medium at step 19, and/or hydrating the carbonation medium stream at step 21.|[0039] Step 11 includes contacting the carbonation medium with ambient air at a carbonation station to from a carbon-containing stream. The carbonation medium adsorbs or reacts with carbon dioxide from the ambient air. The carbonation medium and the carbon dioxide react chemically to form the carbon-containing stream. In some embodiments, the carbonation medium can be from mined rocks. In some embodiments, the carbonation medium can be recycled (e.g., from the calciner). In some embodiments, the carbonation medium can include magnesium oxide, magnesium silicates, silicon dioxide, calcium oxide, calcium hydroxide, calcium silicates, sodium oxide, sodium hydroxide, potassium oxide, potassium hydroxide, and/or magnesium hydroxide|[0040] In some embodiments, the carbonation medium can be incorporated into one or more carbonation plots. In some embodiments, the carbonation medium can be in the form of a powder. In some embodiments, the carbonation medium can be in the form of pebbles or large rocks. In some embodiments, the carbonation medium can have an average particle size of at least about 10 μm, at least about 20 μm, at least about 30 μm, at least about 40 μm, at least about 50 μm, at least about 60 μm, at least about 70 μm, at least about 80 μm, at least about 90 μm, at least about 100 μm, at least about 200 μm, at least about 300 μm, at least about 400 μm, at least about 500 μm, at least about 600 μm, at least about 700 μm, at least about 800 μm, at least about 900 μm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, or at least about 4 cm. In some embodiments, the carbonation medium can have an average particle size of no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, no more than about 1 mm, no more than about 900 μm, no more than about 800 μm, no more than about 700 μm, no more than about 600 μm, no more than about 500 μm, no more than about 400 μm, no more than about 300 μm, no more than about 200 μm, no more than about 100 μm, no more than about 90 μm, no more than about 80 μm, no more than about 70 μm, no more than about 60 μm, no more than about 50 μm, no more than about 40 μm, no more than about 30 μm, or no more than about 20 μm.|[0041] Combinations of the above-referenced particle sizes are also possible (e.g., at least about 10 μm and no more than about 5 cm or at least about 100 μm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can have an average particle size of about 10 μm, about 20 μm, about 30 μm, about 40 μm, about 50 μm, about 60 μm, about 70 μm, about 80 μm, about 90 μm, about 100 μm, about 200 μm, about 300 μm, about 400 μm, about 500 μm, about 600 μm, about 700 μm, about 800 μm, about 900 μm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, at least about 2 cm, about 3 cm, about 4 cm, or about 5 cm.|[0042] In some embodiments, the carbonation medium can be stationed at the carbonation station to contact the ambient air for at least about 1 hour, at least about 5 hours, at least about 10 hours, at least about 1 day, at least about 2 days, at least about 3 days, at least about 4 days, at least about 5 days, at least about 6 days, at least about 1 week, at least about 2 weeks, at least about 3 weeks, at least about 1 month, at least about 2 months, at least about 3 months, at least about 4 months, at least about 5 months, at least about 6 months, at least about 7 months, at least about 8 months, at least about 9 months, at least about 10 months, at least about 11 months, at least about 1 year, or at least about 1.5 years. In some embodiments, the carbonation medium can be stationed at the carbonation station to contact the ambient air for no more than about 2 years, no more than about 1.5 years, no more than about 1 year, no more than about 11 months, no more than about 10 months, no more than about 10 months, no more than about 9 months, no more than about 8 months, no more than about 7 months, no more than about 6 months, no more than about 5 months, no more than about 4 months, no more than about 3 months, no more than about 2 months, no more than about 1 month, no more than about 3 weeks, no more than about 2 weeks, no more than about 1 week, no more than about 6 days, no more than about 5 days, no more than about 4 days, no more than about 3 days, no more than about 2 days, no more than about 1 day, no more than about 10 hours, or no more than about 5 days.|[0043] Combinations of the above-referenced residence times of the carbonation medium at the carbonation station are also possible (e.g., at least 1 hour and no more than about 2 years or at least about 1 week and no more than about 3 months), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be stationed at the carbonation station to contact the ambient air for about 1 hour, about 5 hours, about 10 hours, about 1 day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 1 week, about 2 weeks, about 3 weeks, about 1 month, about 2 months, about 3 months, about 4 months, about 5 months, about 6 months, about 7 months, about 8 months, about 9 months, about 10 months, about 11 months, about 1 year, about 1.5 years, or about 2 years.|[0044] In some embodiments, the carbonation medium can achieve at least about 50% conversion, at least about 55% conversion, at least about 60% conversion, at least about 65% conversion, at least about 70% conversion, at least about 75% conversion, at least about 80% conversion, at least about 85% conversion, at least about 90% conversion, or at least about 95% conversion during its residence time. In some embodiments, the carbon medium can achieve no more than about 99% conversion, no more than about 95% conversion, no more than about 90% conversion, no more than about 85% conversion, no more than about 80% conversion, no more than about 75% conversion, no more than about 70% conversion, no more than about 65% conversion, no more than about 60% conversion, or no more than about 55% conversion during its residence time. Combinations of the above-referenced conversion rates are also possible (e.g., at least about 50% and no more than about 99% or at least about 60% and no more than about 80%), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can achieve about 50% conversion, about 55% conversion, about 60% conversion, about 65% conversion, about 70% conversion, about 75% conversion, about 80% conversion, about 85% conversion, about 90% conversion, about 95% conversion, or about 99% conversion during its residence time. In some embodiments, conversion of the carbonation medium by the CO2 can be at a rate of about 1E-7, about 2E-7, about 3E-7, about 4E-7, about 5E-7, about 6E-7, about 7E-7, about 8E-7, about 9E-7, about 9E-7, about 1E-6, about 2E-6, about 3E-6, about 4E-6, about 5E-6, about 6E-6, about 7E-6, about 8E-6, about 9E-6, or about 1E-5 mass fraction per second, inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be stirred or mixed during carbonation. In some embodiments, the carbonation medium can be stirred at intervals of about 6 hours, about 12 hours, about 18 hours, about a day, about 2 days, about 3 days, about 4 days, about 5 days, about 6 days, about 1 week, about 2 weeks, about 3 weeks, or about 4 weeks, inclusive of all values and ranges therebetween.|[0045] In some embodiments, the carbonation medium can be cycled seasonally. For example, the carbonation medium can be exposed to the ambient air at the carbonation station during the summer and spring and processed and/or stored elsewhere during the fall and winter. In some embodiments, a first portion of the carbonation medium can contact the ambient air at the carbonation station while a second portion of the carbonation medium is processed in the calciner and the second portion can contact the ambient air at the carbonation station while the first portion of the carbonation medium is processed in the calciner.|[0046] At step 12, a water stream is added to the carbonation medium. The moisture content of the carbonation medium can aid in maximizing the amount of CO2 adsorbed from the ambient air. In some embodiments, step 12 can occur concurrently with step 11. In other words, the water stream is added to the carbonation medium while the carbonation medium is contacting the ambient air at the carbonation station. In some embodiments, step 12 can be fully concurrent with step 11. In some embodiments, step 12 can be partially concurrent with step 11. In some embodiments, steps 11 and 12 can be executed multiple times before proceeding to feeding the carbon containing stream to the calciner at step 13. In other words, the carbonation medium can be contacted with ambient air and water can be added to the carbonation medium multiple times before feeding the carbon-containing stream to the calciner. In some embodiments, the water stream can be added to the carbonation medium in the form of misting and/or spraying. In some embodiments, the water stream can be added via a hose, a pipe, a tube, or any combination thereof. In some embodiments, the water stream can be added in the form of steam.|[0047] In some embodiments, the water stream can be added at time intervals. In some embodiments, the water stream addition interval (i.e., the amount of time from the start of one water stream addition to the next water stream addition) can be at least about 30 minutes, at least about 1 hour, at least about 2 hours, at least about 3 hours, at least about 4 hours, at least about 5 hours, at least about 6 hours, at least about 7 hours, at least about 8 hours, at least about 9 hours, at least about 10 hours, at least about 12 hours, at least about 18 hours, at least about 24 hours, at least about 30 hours, at least about 36 hours, at least about 42 hours, at least about 48 hours, at least about 54 hours, at least about 60 hours, or at least about 66 hours. In some embodiments, the water stream addition interval can be no more than about 72 hours, no more than about 66 hours, no more than about 60 hours, no more than about 54 hours, no more than about 48 hours, no more than about 42 hours, no more than about 36 hours, no more than about 30 hours, no more than about 24 hours, no more than about 18 hours, no more than about 12 hours, no more than about 10 hours, no more than about 9 hours, no more than about 8 hours, no more than about 7 hours, no more than about 6 hours, no more than about 5 hours, no more than about 4 hours, no more than about 3 hours, no more than about 2 hours, or no more than about 1 hour.|[0048] Combinations of the above-referenced intervals between water stream additions are also possible (e.g., at least about 30 minutes and no more than about 72 hours or at least about 3 hours and no more than about 24 hours), inclusive of all values and ranges therebetween. In some embodiments, the water stream addition interval (i.e., the amount of time from the start of one water stream addition to the next water stream addition) can be about 30 minutes, about 1 hour, about 2 hours, about 3 hours, about 4 hours, about 5 hours, about 6 hours, about 7 hours, about 8 hours, about 9 hours, about 10 hours, about 12 hours, about 18 hours, about 24 hours, about 30 hours, about 36 hours, about 42 hours, about 48 hours, about 54 hours, about 60 hours, about 66 hours, or about 72 hours.|[0049] In some embodiments, each addition of a water stream can be at a rate of at least about 0.01, at least about 0.02, at least about 0.03, at least about 0.04, at least about 0.05, at least about 0.06, at least about 0.07, at least about 0.08, at least about 0.09, at least about 0.1, at least about 0.15, at least about 0.2, at least about 0.25, at least about 0.3, at least about 0.35, at least about 0.4, or at least about 0.45 mL of water per gram of carbonation medium. In some embodiments, each water stream can be added at a rate of no more than about 0.5, no more than about 0.45, no more than about 0.4, no more than about 0.35, no more than about 0.3, no more than about 0.25, no more than about 0.2, no more than about 0.15, no more than about 0.1, no more than about 0.09, no more than about 0.08, no more than about 0.07, no more than about 0.06, no more than about 0.05, no more than about 0.04, no more than about 0.03, or no more than about 0.02 mL of water per gram of carbonation medium.|[0050] Combinations of the above-referenced rates of water addition are also possible (e.g., at 0.01 mL and no more than about 0.5 mL of water per gram of carbonation medium or at least about 0.1 and no more than about 0.3 mL of water per gram of carbonation medium), inclusive of all values and ranges therebetween. In some embodiments, each addition of a water stream can be at a rate of about 0.01, about 0.02, about 0.03, about 0.04, about 0.05, about 0.06, about 0.07, about 0.08, about 0.09, about 0.1, about 0.15, about 0.2, about 0.25, about 0.3, about 0.35, about 0.4, about 0.45 mL, or about 0.5 mL of water per gram of carbonation medium.|[0051] In some embodiments, the carbonation medium can be maintained at a moisture level of at least about 3 wt %, at least about 4 wt %, at least about 5 wt %, at least about 6 wt %, at least about 7 wt %, at least about 8 wt %, at least about 9 wt %, at least about 10 wt %, at least about 15 wt %, at least about 20 wt %, at least about 25 wt %, at least about 30 wt %, at least about 35 wt %, at least about 40 wt %, or at least about 45 wt %. In some embodiments, the carbonation medium can be maintained at a moisture level of no more than about 50 wt %, no more than about 45 wt %, no more than about 40 wt %, no more than about 35 wt %, no more than about 30 wt %, no more than about 25 wt %, no more than about 20 wt %, no more than about 15 wt %, no more than about 10 wt %, no more than about 9 wt %, no more than about 8 wt %, no more than about 7 wt %, no more than about 6 wt %, no more than about 5 wt %, or no more than about 4 wt %. Combinations of the above-referenced moisture contents are also possible (e.g., at least about 3 wt % and no more than about 50 wt % or at least about 10 wt % and no more than about 40 wt %), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can be maintained at a moisture level of about 3 wt %, about 4 wt %, about 5 wt %, about 6 wt %, about 7 wt %, about 8 wt %, about 9 wt %, about 10 wt %, about 15 wt %, about 20 wt %, about 25 wt %, about 30 wt %, about 35 wt %, about 40 wt %, about 45 wt %, or about 50 wt %.|[0052] In some embodiments, the method 10 can include monitoring relative humidity, temperature, and/or air velocity levels of the ambient air in close proximity (e.g., within about 100 m, within about 50 m, within about 10 m, within about 5 m, within about 1 m) to the carbonation station during the contacting of the carbonation medium with the ambient air|[0053] In some embodiments, the water stream can be added continuously (e.g., in a continuous fine mist). In some embodiments, the water stream can be added at a rate of at least about 0.01, at least about 0.02, at least about 0.03, at least about 0.04, at least about 0.05, at least about 0.06, at least about 0.07, at least about 0.08, at least about 0.09, at least about 0.1, at least about 0.2, at least about 0.3, at least about 0.4, at least about 0.5, at least about 0.6, at least about 0.7, at least about 0.8, at least about 0.9, at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, or at least about 9 mL of water per gram of carbonation medium per day. In some embodiments, the water stream can be added at a rate of no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, no more than about 2, no more than about 1, no more than about 0.9, no more than about 0.8, no more than about 0.7, no more than about 0.6, no more than about 0.5, no more than about 0.4, no more than about 0.3, no more than about 0.2, no more than about 0.1, no more than about 0.09, no more than about 0.08, no more than about 0.07, no more than about 0.06, no more than about 0.05, no more than about 0.04, no more than about 0.03, or no more than about 0.02 mL of water per gram of carbonation medium per day.|[0054] Combinations of the above-referenced water stream addition rates are also possible (e.g., at least about 0.01 and no more than about 10 ml of water per gram of carbonation medium per day or at least about 0.5 and no more than about 2 mL of water per gram of carbonation medium per day), inclusive of all values and ranges therebetween. In some embodiments, the water stream can be added at a rate of about 0.01, at least about 0.02, at least about 0.03, at least about 0.04, at least about 0.05, at least about 0.06, at least about 0.07, at least about 0.08, at least about 0.09, at least about 0.1, at least about 0.2, at least about 0.3, at least about 0.4, at least about 0.5, at least about 0.6, at least about 0.7, at least about 0.8, at least about 0.9, at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, about 9, or about 10 ml of water per gram of carbonation medium per day.|[0055] In some embodiments, the water stream can be added to the carbonation medium 12 to maintain a desired level of relative humidity in the immediate proximity of the carbonation medium (e.g., the volume within 10 m, within 5 m, or within 1 m of the carbonation medium). In some embodiments, step 12 can include maintaining the relative humidity in the immediate proximity of the carbonation medium at a level of at least about 5%, at least about 10%, at least about 15%, at least about 20%, at least about 25%, at least about 30%, at least about 35%, at least about 40%, at least about 45%, at least about 50%, at least about 55%, at least about 60%, at least about 65%, at least about 70%, at least about 75%, at least about 80%, at least about 85%, at least about 90%, or at least about 95%. In some embodiments, step 12 can include maintaining the relative humidity in the immediate proximity of the carbonation medium at a level of no more than about 100%, no more than about 95%, no more than about 90%, no more than about 85%, no more than about 80%, no more than about 75%, no more than about 70%, no more than about 65%, no more than about 60%, no more than about 55%, no more than about 50%, no more than about 45%, no more than about 40%, no more than about 35%, no more than about 30%, no more than about 25%, no more than about 20%, no more than about 15%, or no more than about 10%. Combinations of the above-referenced values of relative humidity in the immediate proximity of the carbonation medium are also possible (e.g., at least about 5% and no more than about 70% or at least about 20% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, step 12 can include maintaining the relative humidity in the immediate proximity of the carbonation medium at a level of about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, or about 100%.|[0056] Without wishing to be bound by theory, it is not anticipated that a large amount of water is physically adsorbed on the surface of the carbonation medium. Instead, the presence of water drives the conversion of the carbonation medium (e.g., oxides and/or hydroxides) while in reaction with CO2. In some embodiments, Mg(OH)2 can form hydrated carbonates, such as hydromagnesite, lansfordite, nesquehonite, and/or MgCO3. The decomposition of metastable, hydrous Mg-carbonate minerals occurs at lower temperatures than MgCO3, but can likely convert to MgCO3 rather than MgO under high purity CO2 conditions in a calciner, as described below.|[0057] After the carbonation medium has contacted the ambient air to adsorb the CO2 from the air, the carbonation medium becomes the carbon-containing stream. The carbon-containing stream is fed to the calciner at step 13. In some embodiments, the carbon-containing stream can include MgCO3, dolomite (high magnesium calcium carbonate), sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, potassium carbonate, potassium bicarbonate, nesquehonite, and/or hydromagnesite. In some embodiments, the carbon-containing stream can include dunite, calcite, wollastonite, and/or pyroxines.|[0058] In some embodiments, the carbon-containing stream can include a powder. In some embodiments, the carbon-containing stream can be in the form of pebbles or large rocks. In some embodiments, the carbon-containing stream can have an average particle size of at least about 5 μm, at least about 10 μm, at least about 20 μm, at least about 30 μm, at least about 40 μm, at least about 50 μm, at least about 60 μm, at least about 70 μm, at least about 80 μm, at least about 90 μm, at least about 100 μm, at least about 200 μm, at least about 300 μm, at least about 400 μm, at least about 500 μm, at least about 600 μm, at least about 700 μm, at least about 800 μm, at least about 900 μm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, or at least about 4 cm. In some embodiments, the carbon-containing stream can have an average particle size of no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, no more than about 1 mm, no more than about 900 μm, no more than about 800 μm, no more than about 700 μm, no more than about 600 μm, no more than about 500 μm, no more than about 400 μm, no more than about 300 μm, no more than about 200 μm, no more than about 100 μm, no more than about 90 μm, no more than about 80 μm, no more than about 70 μm, no more than about 60 μm, no more than about 50 μm, no more than about 40 μm, no more than about 30 μm, no more than about 20 μm, or no more than about 10 μm.|[0059] Combinations of the above-referenced particle sizes are also possible (e.g., at least about 10 μm and no more than about 5 cm or at least about 100 μm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbon-containing stream can have an average particle size of about 5 μm, about 10 μm, about 20 μm, about 30 μm, about 40 μm, about 50 μm, about 60 μm, about 70 μm, about 80 μm, about 90 μm, about 100 μm, about 200 μm, about 300 μm, about 400 μm, about 500 μm, about 600 μm, about 700 μm, about 800 μm, about 900 μm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, at least about 2 cm, about 3 cm, about 4 cm, or about 5 cm.|[0060] At step 14, heat is applied to the calciner to decompose the carbon-containing stream to a gas stream and a carbonation medium stream. In some embodiments, the heat applied to the calciner can be via electric resistance heating. In some embodiments, the electric resistance heating can be powered by renewable electricity. In some embodiments, the renewable electricity can be supplied by wind power, solar power, geothermal power, nuclear energy, or any other suitable renewable energy source or combinations thereof. In some embodiments, the calciner can be sufficiently hot (e.g., from solar radiation), such that additional heat need not be supplied at step 14. In some embodiments, in the calciner, the carbon-containing stream can be calcined according to the following reaction.|where Me represents a divalent metal cation.|[0061] The gas stream includes CO2. In some embodiments, the gas stream can have a composition that includes at least about 80 vol %, at least about 85 vol %, at least about 90 vol %, at least about 91 vol %, at least about 92 vol %, at least about 93 vol %, at least about 94 vol %, at least about 95 vol %, at least about 96 vol %, at least about 97 vol %, at least about 98 vol %, at least about 99 vol %, at least about 99.1 vol %, at least about 99.2 vol %, at least about 99.3 vol %, at least about 99.4 vol %, at least about 99.5 vol %, at least about 99.6 vol %, at least about 99.7 vol %, at least about 99.8 vol %, or at least about 99.9 vol % CO2.|[0062] The gas stream formed from the calcining is sequestered and/or utilized at step 15. In some embodiments, the gas stream can be sequestered at a sequestration space (e.g., an underground sequestration space). In some embodiments, the gas stream can be used as a CO2-rich fuel. In some embodiments, the gas stream can be fed to a greenhouse to facilitate plant growth. In some embodiments, the gas stream can be fed to an environment where a controlled dosage of CO2-rich gas is used to facilitate tree or plant growth. In some embodiments, the gas stream can be subjected to further processing to increase the CO2 content. In some embodiments, CO2 from the gas stream can be used to cure concrete. In some embodiments, CO2 from the gas stream can be used as a feedstock for chemicals (e.g., ethanol). In some embodiments, CO2 from the gas stream can be used to carbonate beverages. In some embodiments, CO2 from the gas stream can be used for enhanced oil recovery. In some embodiments, the processing can include condensation of water. In some embodiments, the gas stream can be compressed into gas storage. In some embodiments, the compressed gas stream can be direct injected in a co-located facility. In some embodiments, the compressed gas stream can be transported to a location where it can be sequestered. In some embodiments, a portion of the gas stream can be sequestered while a portion of the gas stream can be utilized.|[0063] Step 16 includes feeding the carbonation medium stream to the carbonation station. The carbonation medium is a product of the calcining and is fed to the carbonation station. In some embodiments, the carbonation medium stream fed to the carbonation station can include at least a portion of recycled material. In some embodiments, the carbonation medium can be grinded prior to feeding to the carbonation station. The process then starts again at step 11, where the carbonation medium contacts the ambient air. In some embodiments, the carbonation medium can be transported from the calciner to the carbonation station via a conveyor or a series of conveyors. In some embodiments, the calciner can be at a higher elevation than the carbonation station, such that gravity can assist the conveyance of the carbonation medium to the carbonation station. In some embodiments, with recycling of carbonation medium, ultramafic rocks can become increasingly divided into materials such as MgCO3, minor CaCO3, and SiO2 after each weathering step, and the calcining residue can become richer and richer in MgO and CaO, and thus more reactive and useful as feedstock for successive cycles.|[0064] Step 17 is an optional precursor to step 13 and/or step 14 and includes processing an air stream to produce an oxygen stream and feeding the oxygen stream to the calciner. Introducing oxygen to the calciner can improve the quality and thoroughness of the calcining. In some embodiments, the processing can be via an air separation unit. In some embodiments, the oxygen stream can include at least about 80 vol %, at least about 85 vol %, at least about 90 vol %, at least about 91 vol %, at least about 92 vol %, at least about 93 vol %, at least about 94 vol %, at least about 95 vol %, at least about 96 vol %, at least about 97 vol %, at least about 98 vol %, at least about 99 vol %, at least about 99.1 vol %, at least about 99.2 vol %, at least about 99.3 vol %, at least about 99.4 vol %, at least about 99.5 vol %, at least about 99.6 vol %, at least about 99.7 vol %, at least about 99.8 vol %, or at least about 99.9 vol % O2. In some embodiments, the feeding of the oxygen stream into the calciner can occur at least partially concurrently to feeding the carbon-containing stream into the calciner at step 13. In some embodiments, the feeding of the oxygen stream into the calciner can occur at least partially concurrently to applying heat to the calciner at step 14.|[0065] Step 18 is an optional post-processing step that can be applied to the gas stream captured at step 15. Step 18 includes condensing and/or recycling water from the gas stream. Water in the gas stream is not desired for purposes of sequestering and storage or for use as a fuel. By removing the water from the gas stream, the purity of the gas stream (in terms of CO2 content) increases and therefore the gas stream can have a wider range of possible storage locations or uses. In some embodiments, water capture from the gas stream can be recycled and fed to the carbonation station (i.e., added to the water stream from step 12).|[0066] Step 19 is optional and includes grinding sorbent material to form the carbonation medium. In some embodiments, the sorbent material can include a mined material. In some embodiments, the sorbent material can be recycled (e.g., from the calciner). Grinding the sorbent material can reduce the particle size and improve adsorption of CO2 per unit mass. In some embodiments, the grinding can be via a ball mill crusher, an impact crusher, a cone crusher, or any other suitable grinding device or combinations thereof.|[0067] Step 21 is optional and includes hydrating the carbonation medium stream. The carbonation medium can be hydrated prior to feeding the carbonation medium to the carbonation station. In some embodiments, carbonation medium from the calciner (or mined carbonation medium) can be hydrated at the hydration station to form a hydroxide, in accordance with the following reaction.|where Me represents a divalent metal cation.|[0068] Hydrating the carbonation medium can improve the affinity of the carbonation medium to capture CO2. For example, the reaction between Ca(OH)2 and CO2 can have lower activation energy than the reaction between CaO and CO2. The residence time of a carbonation medium including hydroxides at the carbonation station can be less than the residence time of a carbonation medium without hydroxides. Hydration of the carbonation medium can allow for recovery of heat from the hydration reaction, as the reaction is exothermic. In some embodiments, the hydration can be achieved by passing the carbonation medium through a humid enclosure (e.g., with at least about 50%, at least about 60%, at least about 70%, at least about 80%, at least about 90%, or about 100% relative humidity, inclusive of all values and ranges therebetween). In some embodiments, the hydration can be achieved by misting water onto the carbonation medium (e.g., via one or more sprayers). In some embodiments, the hydration can be achieved by placing the carbonation medium in a water bath.|[0069] FIG. 2 is a block diagram of a carbon capture facility 100, according to an embodiment. As shown, the carbon capture facility includes a carbonation station 110 and a calciner 120. The carbon capture facility 100 optionally includes a sequestration space 130, a grinding station 140, a hydration station 150, a condensation space 160, and an air separation unit 170. In use, a carbonation medium adsorbs and reacts chemically with CO2 in ambient air at the carbonation station 110 to form a carbon-containing stream. The carbon-containing stream is fed to the calciner 120, where the carbon-containing stream is calcined to form a gas stream and a stream of carbonation medium. The gas stream can be subjected to further processing in the condensation space 160 and stored in the sequestration space 130. The grinding station 140 can grind carbonation medium and/or carbon-containing medium and feed to the carbonation station 110 and/or the calciner 120. The hydration station 150 can optionally process the carbon-containing stream prior to feeding the carbon-containing stream to the calciner 120. The air separation unit 170 can process an air stream, prior to feeding the air stream to the calciner. The carbon capture facility 100 utilizes alkalinity to sequester a target compound (e.g., CO2). In some embodiments, the carbon capture can be via reaction between the target compound and a carbonation medium. In some embodiments, the reaction can be a carbonation reaction.|[0070] The carbonation station 110 is a location where the carbonation medium contacts the ambient air and adsorbs and reacts with the CO2 to become the carbon-containing stream. The carbonation station 110 includes CO2 contactors. Some of the contactors described herein can be the same or substantially similar to those described in International Patent Publication WO2020/263910 (“the '910 publication”), filed Jun. 24, 2020, titled, “System and Methods for Enhanced Weathering and Calcining for CO2 Removal from Air,” the disclosure of which is hereby incorporated by reference in its entirety. The carbonation station 110 includes one or more water delivery devices to keep the moisture levels of the carbonation medium and/or localized humidity levels at the desired levels. In some embodiments, the water delivery devices can include one or more sprayers, hoses, mats, misters, sprinklers, or any other suitable water delivery device or combinations thereof. In some embodiments, the carbonation station 110 can include a plurality of carbonation plots positioned to expose the carbonation medium to ambient conditions. In some embodiments, one or more of the carbonation plots can be placed in the vicinity of facilities with heavy CO2 exhaust. In some embodiments, the carbonation plots can include sheets of carbonation medium in powder form. In some embodiments, the carbonation plots can be arranged in stacked columns. In some embodiments, the carbonation station 110 can include a temperature sensor, a humidity sensor, and/or a gas flowmeter to measure the movement of ambient air in the vicinity of the carbonation plots. In some embodiments, the carbonation station 110 can be located outdoors. In some embodiments, the carbonation station can include a stirring implement for stirring the carbonation medium. In some embodiments, the stirring implement can include a mixing bar, a stirring rod, an impeller, and/or any other suitable device for stirring.|[0071] In some embodiments, the carbonation station 110 can be maintained at a relative humidity in the immediate proximity of the carbonation medium at a level of at least about 5%, at least about 10%, at least about 15%, at least about 20%, at least about 25%, at least about 30%, at least about 35%, at least about 40%, at least about 45%, at least about 50%, at least about 55%, at least about 60%, at least about 65%, at least about 70%, at least about 75%, at least about 80%, at least about 85%, at least about 90%, or at least about 95%. In some embodiments, the carbonation station 110 can be maintained at a relative humidity in the immediate proximity of the carbonation medium at a level of no more than about 100%, no more than about 95%, no more than about 90%, no more than about 85%, no more than about 80%, no more than about 75%, no more than about 70%, no more than about 65%, no more than about 60%, no more than about 55%, no more than about 50%, no more than about 45%, no more than about 40%, no more than about 35%, no more than about 30%, no more than about 25%, no more than about 20%, no more than about 15%, or no more than about 10%. Combinations of the above-referenced values of relative humidity at the carbonation station 110 are also possible (e.g., at least about 5% and no more than about 70% or at least about 20% and no more than about 40%), inclusive of all values and ranges therebetween. In some embodiments, carbonation station 110 can be maintained at about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, about 95%, or about 100% relative humidity.|[0072] The calciner 120 receives the carbon-containing stream from the carbonation station 110. In some embodiments, the calciner 120 can include a total flow calciner, a fluidized bed calciner, a rotary kiln calciner, a riser reactor-calciner, a separated tertiary air flow calciner, a hybrid calciner, or any other suitable calciner or combinations thereof. In some embodiments, the calciner 120 can include an oxy-fired calciner, an electric-fired calciner, a solar calciner, a “carbon-free” calciner. In some embodiments, the calciner 120 can use recycled waste heat from other processes. In some embodiments, the calciner 120 can be physically coupled to a power source. In some embodiments, the calciner 120 can be heated via electric resistance heating. In some embodiments, the electric resistance heating can be powered by grid electricity. In some embodiments, the electric resistance heating can be powered by renewable electricity. In some embodiments, the renewable electricity can be supplied by wind power, solar power, geothermal power, nuclear power, or any other suitable renewable energy source or combinations thereof. In some embodiments, the calciner 120 can include a valve and gate system for controlling inputs and outputs. In some embodiments, the calciner 120 can have a calcination efficiency of at least about 90%, at least about 91%, at least about 92%, at least about 93%, at least about 94%, at least about 95%, at least about 96%, at least about 97%, at least about 98%, or at least about 99%, inclusive of all values and ranges therebetween.|[0073] In some embodiments, the calciner 120 can include an oxy-fired calciner and can be operationally coupled to the air separation unit 170 and a condenser (e.g., in the condensation space 160). The air separation unit 170 can ensure pure or substantially pure oxygen is fed to the calciner 120. The condenser can condense water from the gaseous stream leaving the calciner 120. This can allow for the capture of CO2 produced from fuel combustion. The complete combustion reaction can proceed in accordance with the following reaction, using methane as an exemplary combustion medium.|[0074] The sequestration space 130 is optional and is fluidically coupled to the calciner 120. The sequestration space 130 receives the gas stream from the calciner 120. In some embodiments, the condensation space 160 can receive liquid from the gas stream before or concurrently to when the sequestration space 130 receives the gas stream from the calciner 120. In some embodiments, a condenser is used to increase the purity of the gas stream and remove water from the gas stream. The water can be received in the condensation space 160. The water can be utilized in the process or sold as a byproduct. In some embodiments, the carbon capture facility 100 can include other post-processing equipment (not shown) to process the gas stream when it exits the calciner 120. In some embodiments, the carbon capture facility 100 can include a dehydrator and/or a compressor.|[0075] In some embodiments, the sequestration space 130 can be co-located with the calciner 120. In some embodiments, the sequestration space 130 can be located underground. In some embodiments, the sequestration space 130 can be located immediately underneath the calciner 120. In some embodiments, the sequestration space 130 can be located a sufficient distance away from the calciner 120, such that CO2 is transported from the calciner 120 to the sequestration space 130 (e.g., via fans and pipes). In some embodiments, the sequestration space 130 can include sorbents to improve storage capacity. In some embodiments, the sorbents can include activated carbon, graphene, silica, acrylonitrile, phosphorene, carbon nanotubes, biopolymers, metal organic frameworks, zeolites, grafted amines, or any other suitable sorbent or combinations thereof. In some embodiments, the sequestration space 130 can be maintained at a pressure of about 1 bar (gauge), about 2 bar, about 3 bar, about 4 bar, about 5 bar, about 6 bar, about 7 bar, about 8 bar, about 9 bar, about 10 bar, about 15 bar, about 20 bar, about 25 bar, about 30 bar, about 35 bar, about 40 bar, about 45 bar, about 50 bar, about 55 bar, about 60 bar, about 65 bar, about 70 bar, about 75 bar, about 70 bar, about 75 bar, about 80 bar, about 85 bar, about 90 bar, about 95 bar, about 100 bar, about 150 bar, about 200 bar, about 250 bar, about 300 bar, about 350 bar, about 400 bar, about 450 bar, about 500 bar, about 550 bar, about 600 bar, about 650 bar, about 700 bar, about 750 bar, about 800 bar, about 850 bar, about 900 bar, about 950 bar, or about 1,000 bar, inclusive of all values and ranges therebetween.|[0076] The grinding station 140 is an optional component of the carbon capture facility 100 and includes grinding media for processing of the carbonation medium and/or the carbon-containing stream. In some embodiments, mined materials can be fed to the grinding station 140 to reduce the particle size of the mined materials, before feeding to the carbonation station 110 and/or the calciner 120. In some embodiments, the grinding media can include a ball mill crusher, an impact crusher, and/or a cone crusher.|[0077] The hydration station 150 is an optional intermediate station between the calciner 120 and the carbonation station 110. In some embodiments, carbonation medium from the calciner can be hydrated at the hydration station to form a hydroxide, as described above in step 21, with reference to FIG. 1. In some embodiments, the hydration station can include a water bath, one or more misting devices (e.g., water sprayers), a humid enclosure, or any combination thereof. In some embodiments, the hydration station 150 can be part of the carbonation station 110. In other words, the hydration and the carbonation can occur at the same location.|[0078] The air separation unit 170 is an optional component for improving air quality before feeding the air to the calciner 120. In some embodiments, the air separation unit 170 can increase the oxygen content in an air stream, before feeding the oxygen-rich air stream into the calciner 120. In some embodiments, the air separation unit 170 can include a condenser to remove water from the air. In some embodiments, the air separation unit 170 can produce a pure stream of oxygen to feed the calciner 120. In some embodiments, the air separation unit 170 can allow for more efficient combustion in the calciner 120 as the air separation unit 170 can remove contaminants and inert materials from the air prior to feeding to the calciner 120.|[0079] FIG. 3 is a block diagram of a carbon capture facility 200, according to an embodiment. As shown, the carbon capture facility 200 includes a carbonation station 210, a calciner 220, a sequestration space 230, a grinding station 240, a hydration station 250, a condensation space 260, and an air separation unit 270. In some embodiments, the carbonation station 210, the calciner 220, the sequestration space 230, the grinding station 240, the hydration station 250, the condensation space 260, and the air separation unit 270 can be the same or substantially similar to the carbonation station 110, the calciner 120, the sequestration space 130, the grinding station 140, the hydration station 150, the condensation space 160, and the air separation unit 170, as described above with reference to FIG. 2. Thus, certain aspects of the carbonation station 210, the calciner 220, the sequestration space 230, the grinding station 240, the hydration station 250, the condensation space 260, and the air separation unit 270 are not described in greater detail herein.|[0080] In use, a carbonation medium stream CMS is processed via the hydration station 250 prior to being fed to the carbonation station 210. After carbonation at the carbonation plot 210, a recycled carbon-containing stream CCS(R) is fed to the calciner 220. Meanwhile, an adsorbent material AM is fed to the grinding station 240 and grinded to become a new carbon-containing stream CCS(N). The new carbon-containing stream CCS(N) is fed to the calciner concurrently with the recycled carbon-containing stream CCS(R). Meanwhile, air is fed to the air separation unit 270 and a stream rich in O2 is fed from the air separation unit 270 to the calciner 220. After processing in the calciner 220, the carbon-containing streams CCS(R) and CCS(N) become a gas stream GS and the carbonation medium stream CMS. The carbonation medium stream CMS is fed back to the hydration station 250 while the gas stream GS is fed to the sequestration space 230. Between the calciner 220 and the sequestration space 230, the gas stream 230 is condensed and a recycled stream of water H2O(R) is captured in the condensation space 260. The recycled stream of water H2O(R) is fed to a sprayer 215. A new stream of water H2O(N) is also fed to the sprayer 215. The sprayer 215 sprays water on the carbonation station 210.|[0081] The carbonation station 210 includes the carbonation plots 211. In some embodiments, the carbonation plots 211 can be positioned and configured to expose the compositions in the carbonation plots to ambient weathering. The carbonation plots 211 can be placed in an environment configured to maximize the temperature at the surface of the composition of the carbonation plots 211. In some embodiments, the carbonation plots 211 can be positioned in a natural environment (e.g., grasslands, deserts, mountainsides). In some embodiments, the carbonation plots 211 can be clustered into a group. In some embodiments, the clustered carbonation plots 211 enable centralized implementation of other system components for more efficient operation of the carbon capture facility 200. In some embodiments, the carbonation plots 211 can be distributed throughout a region of the planet (e.g., non-arable land in the Western United States). In some embodiments, a plurality of carbonation plots 211 are distributed throughout the planet.|[0082] As shown, the carbonation station 210 includes nine carbonation plots 211. In some embodiments, the carbonation station 210 can include at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, at least about 900, at least about 1,000, at least about 1,500, at least about 2,000, at least about 2,500, at least about 3,000, at least about 3,500, at least about 4,000, at least about 4,500, at least about 5,000, at least about 5,500, at least about 6,000, at least about 6,500, at least about 7,000, at least about 7,500, at least about 8,000, at least about 8,500, at least about 9,000, at least about 9,500, at least about 10,000, at least about 11,000, at least about 12,000, at least about 13,000, at least about 14,000, at least about 15,000, at least about 16,000, at least about 17,000, at least about 18,000, at least about 19,000, at least about 20,000, at least about 25,000, at least about 30,000, at least about 35,000, at least about 40,000, at least about 45,000, at least about 50,000, at least about 55,000, at least about 60,000, or at least about 65,000 carbonation plots 211. In some embodiments, the carbonation station 210 can include no more than about 70,000, no more than about 65,000, no more than about 60,000, no more than about 55,000, no more than about 50,000, no more than about 45,000, no more than about 40,000, no more than about 35,000, no more than about 30,000, no more than about 25,000, no more than about 20,000, no more than about 19,000, no more than about 18,000, no more than about 17,000, no more than about 16,000, no more than about 15,000, no more than about 14,000, no more than about 13,000, no more than about 12,000, no more than about 11,000, no more than about 10,000, no more than about 9,500, no more than about 9,000, no more than about 8,500, no more than about 8,000, no more than about 7,500, no more than about 7,000, no more than about 6,500, no more than about 6,000, no more than about 5,500, no more than about 5,000, no more than about 4,500, no more than about 4,000, no more than about 3,500, no more than about 3,000, no more than about 2,500, no more than about 2,000, no more than about 1,500, no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, or no more than about 3 carbonation plots 211.|[0083] Combinations of the above-referenced numbers of carbonation plots in the carbonation station 210 are also possible (e.g., at least about 2 and no more than about 70,000 or at least about 500 and no more than about 5,000, inclusive of all values and ranges therebetween. In some embodiments, the carbonation station 210 can include about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, about 1,000, about 1,500, about 2,000, about 2,500, about 3,000, about 3,500, about 4,000, about 4,500, about 5,000, about 5,500, about 6,000, about 6,500, about 7,000, about 7,500, about 8,000, about 8,500, about 9,000, about 9,500, about 10,000, about 11,000, about 12,000, about 13,000, about 14,000, about 15,000, about 16,000, about 17,000, about 18,000, about 19,000, about 20,000. about 25,000, about 30,000. about 35,000, about 40,000, about 45,000, about 50,000, about 55,000, about 60,000, about 65,000, or about 70,000 carbonation plots 211.|[0084] In some embodiments, the carbonation plots 211 can include sheets of carbonation medium. In some embodiments, the carbonation plots 211 can have length and/or width dimensions of at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm, at least about 50 cm, at least about 60 cm, at least about 70 cm, at least about 80 cm, at least about 90 cm, at least about 1 m, at least about 1.1 m, at least about 1.2 m, at least about 1.3 m, at least about 1.3 m, at least about 1.4 m, at least about 1.5 m, at least about 2 m, at least about 2.5 m, at least about 3 m, at least about 3.5 m, at least about 4 m, at least about 4.5 m, at least about 5 m, at least about 5.5 m, at least about 6 m, at least about 6.5 m, at least about 7 m, at least about 7.5 m, at least about 8 m, at least about 8.5 m, at least about 9 m, or at least about 9.5 m. In some embodiments, the carbonation plots 211 can have length and/or width dimensions of no more than about 10 m, no more than about 9.5 m, no more than about 9 m, no more than about 8.5 m, no more than about 8 m, no more than about 7.5 m, no more than about 7 m, no more than about 6.5 m, no more than about 6 m, no more than about 5.5 m, no more than about 5 m, no more than about 4.5 m, no more than about 4 m, no more than about 3.5 m, no more than about 3 m, no more than about 2.5 m, no more than about 2 m, no more than about 1.9 m, no more than about 1.8 m, no more than about 1.7 m, no more than about 1.6 m, no more than about 1.5 m, no more than about 1.4 m, no more than about 1.3 m, no more than about 1.2 m, no more than about 1.1 m, no more than about 1 m, no more than about 90 cm, no more than about 80 cm, no more than about 70 cm, no more than about 60 cm, no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, or no more than about 20 cm. Combinations of the above-referenced length and width dimensions of the carbonation plots 211 are also possible (e.g., at least about 10 cm and no more than about 10 m or at least about 50 cm and no more than about 5 m), inclusive of all values and ranges therebetween. In some embodiments, the carbonation plots 211 can have length and/or width dimensions of about 10 cm, about 20 cm, about 30 cm, about 40 cm, about 50 cm, about 60 cm, about 70 cm, about 80 cm, about 90 cm, about 1 m, about 1.1 m, about 1.2 m, about 1.3 m, about 1.4 m, about 1.5 m, about 1.6 m, about 1.7 m, about 1.8 m, about 1.9 m, about 2 m, about 2.5 m, about 3 m, about 3.5 m, about 4 m, about 4.5 m, about 5 m, about 5.5 m, about 6 m, about 6.5 m, about 7 m, about 7.5 m, about 8 m, about 8.5 m, about 9 m, about 9.5 m, or about 10 m.|[0085] In some embodiments, the carbonation plots 211 can include thin sheets of carbonation medium powder and/or pebbles. In some embodiments, the carbonation plots 211 can include sheets with thicknesses of at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, at least about 4 cm, at least about 5 cm, at least about 6 cm, at least about 7 cm, at least about 8 cm, at least about 9 cm, at least about 10 cm, at least about 20 cm, at least about 30 cm, at least about 40 cm. In some embodiments, the carbonation plots 211 can include sheets with thicknesses of no more than about 50 cm, no more than about 40 cm, no more than about 30 cm, no more than about 20 cm, no more than about 10 cm, no more than about 9 cm, no more than about 8 cm, no more than about 7 cm, no more than about 6 cm, no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, or no more than about 2 mm. Combinations of the above-referenced sheet thicknesses are also possible (e.g., at least about 1 mm and no more than about 50 cm or at least about 5 mm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation plots 211 can include sheets with thicknesses of about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, about 2 cm, about 3 cm, about 4 cm, about 5 cm, about 6 cm, about 7 cm, about 8 cm, about 9 cm, about 10 cm, about 20 cm, about 30 cm, about 40 cm, or about 50 cm.|[0086] In some embodiments, each of the carbonation plots 211 can include at least about 1,000 tons, at least about 2,000 tons, at least about 3,000 tons, at least about 4,000 tons, at least about 5,000 tons, at least about 6,000 tons, at least about 7,000 tons, at least about 8,000 tons, at least about 9,000 tons, at least about 10,000 tons, at least about 20,000 tons, at least about 30,000 tons, at least about 40,000 tons, or at least about 50,000 tons of carbonation medium. In some embodiments, each of the carbonation plots 211 can include no more than about 60,000 tons, no more than about 50,000 tons, no more than about 40,000 tons, no more than about 30,000 tons, no more than about 20,000 tons, no more than about 10,000 tons, no more than about 9,000 tons, no more than about 8,000 tons, no more than about 7,000 tons, no more than about 6,000 tons, no more than about 5,000 tons, no more than about 4,000 tons, no more than about 3,000 tons, or no more than about 2,000 tons of carbonation medium. Combinations of the above-referenced amounts of carbonation medium are also possible (e.g., at least about 1,000 tons and no more than about 60,000 tons or at least about 5,000 tons and no more than about 40,000 tons), inclusive of all values and ranges therebetween. In some embodiments, each of the carbonation plots 211 can include about 1,000 tons, about 2,000 tons, about 3,000 tons, about 4,000 tons, about 5,000 tons, about 6,000 tons, about 7,000 tons, about 8,000 tons, about 9,000 tons, about 10,000 tons, about 20,000 tons, about 30,000 tons, about 40,000 tons, about 50,000 tons, or about 60,000 tons of carbonation medium.|[0087] In some embodiments, the thin sheets of carbonation medium of the carbonation plots 211 can be arranged in trays. In some embodiments, the trays can be stacked vertically. In some embodiments, each the carbonation plots 211 can include at least about 1, at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, at least about 7, at least about 8, at least about 9, at least about 10, at least about 20, at least about 30, at least about 40, at least about 50, at least about 60, at least about 70, at least about 80, at least about 90, at least about 100, at least about 200, at least about 300, at least about 400, at least about 500, at least about 600, at least about 700, at least about 800, at least about 900, at least about 1,000, at least about 1,500, at least about 2,000, at least about 2,500, at least about 3,000, at least about 3,500, at least about 4,000, or at least about 4,500 trays. In some embodiments, each of the carbonation plots 211 can include no more than about 5,000, no more than about 4,500, no more than about 4,000, no more than about 3,500, no more than about 3,000, no more than about 2,500, no more than about 2,000, no more than about 1,500, no more than about 1,000, no more than about 900, no more than about 800, no more than about 700, no more than about 600, no more than about 500, no more than about 400, no more than about 300, no more than about 200, no more than about 100, no more than about 90, no more than about 80, no more than about 70, no more than about 60, no more than about 50, no more than about 40, no more than about 30, no more than about 20, no more than about 10, no more than about 9, no more than about 8, no more than about 7, no more than about 6, no more than about 5, no more than about 4, no more than about 3, or no more than about 2 trays. Combinations of the above-referenced numbers of trays in each of the carbonation plots 211 are also possible (e.g., at least about 1 and no more than about 5,000 or at least about 50 and no more than about 500), inclusive of all values and ranges therebetween. In some embodiments, the trays can be stacked vertically. In some embodiments, each the carbonation plots 211 can include about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, about 9, about 10, about 20, about 30, about 40, about 50, about 60, about 70, about 80, about 90, about 100, about 200, about 300, about 400, about 500, about 600, about 700, about 800, about 900, about 1,000, about 1,500, about 2,000, about 2,500, about 3,000, about 3,500, about 4,000, about 4,500, or about 5,000 trays.|[0088] In some embodiments, the carbonation plots 211 can include a powder of carbonation medium. In some embodiments, the carbonation medium can be in the form of pebbles or large rocks. In some embodiments, the carbonation medium can have an average particle size of at least about 5 μm, at least about 10 μm, at least about 20 μm, at least about 30 μm, at least about 40 μm, at least about 50 μm, at least about 60 μm, at least about 70 μm, at least about 80 μm, at least about 90 μm, at least about 100 μm, at least about 200 μm, at least about 300 μm, at least about 400 μm, at least about 500 μm, at least about 600 μm, at least about 700 μm, at least about 800 μm, at least about 900 μm, at least about 1 mm, at least about 2 mm, at least about 3 mm, at least about 4 mm, at least about 5 mm, at least about 6 mm, at least about 7 mm, at least about 8 mm, at least about 9 mm, at least about 1 cm, at least about 2 cm, at least about 3 cm, or at least about 4 cm. In some embodiments, the carbonation medium can have an average particle size of no more than about 5 cm, no more than about 4 cm, no more than about 3 cm, no more than about 2 cm, no more than about 1 cm, no more than about 9 mm, no more than about 8 mm, no more than about 7 mm, no more than about 6 mm, no more than about 5 mm, no more than about 4 mm, no more than about 3 mm, no more than about 2 mm, no more than about 1 mm, no more than about 900 μm, no more than about 800 μm, no more than about 700 μm, no more than about 600 μm, no more than about 500 μm, no more than about 400 μm, no more than about 300 μm, no more than about 200 μm, no more than about 100 μm, no more than about 90 μm, no more than about 80 μm, no more than about 70 μm, no more than about 60 μm, no more than about 50 μm, no more than about 40 μm, no more than about 30 μm, no more than about 20 μm, or no more than about 10 μm.|[0089] Combinations of the above-referenced particle sizes are also possible (e.g., at least about 10 μm and no more than about 5 cm or at least about 100 μm and no more than about 1 cm), inclusive of all values and ranges therebetween. In some embodiments, the carbonation medium can have an average particle size of about 5 μm, about 10 μm, about 20 μm, about 30 μm, about 40 μm, about 50 μm, about 60 μm, about 70 μm, about 80 μm, about 90 μm, about 100 μm, about 200 μm, about 300 μm, about 400 μm, about 500 μm, about 600 μm, about 700 μm, about 800 μm, about 900 μm, about 1 mm, about 2 mm, about 3 mm, about 4 mm, about 5 mm, about 6 mm, about 7 mm, about 8 mm, about 9 mm, about 1 cm, at least about 2 cm, about 3 cm, about 4 cm, or about 5 cm.|[0090] FIG. 4 shows a carbonation station 310, according to an embodiment. As shown, the carbonation station 310 includes carbonation plots 311 and a sprayer 315. In some embodiments, the carbonation station 310, the carbonation plots 311, and the sprayer 315 can be the same or substantially similar to the carbonation station 210, the carbonation plots 211, and the sprayer 215 as described above with reference to FIG. 3. Thus, certain aspects of the carbonation station 310, the carbonation plots 311, and the sprayer 315 are not described in greater detail herein. As shown, the sprayer 315 sprays water onto the carbonation plots 311 to maintain a desired moisture level in the carbonation station 310. In some embodiments, the sprayer 315 can mist continuously. In some embodiments, the sprayer 315 can spray at intervals. In some embodiments, the sprayer 315 can be stationary. In some embodiments, the sprayer 315 can move laterally from above the carbonation plots 311 to maximize the ground covered by the sprayer 315. In some embodiments, carbonation plots 311 can be placed above and below the sprayer 315 and the sprayer can spray upward and downward to deliver water to the carbonation plots 311.|[0091] FIG. 5 shows positioning of a carbonation station 410 surrounding a calciner 420 and a sequestration space 430. As shown, the carbonation station includes a plurality of carbonation plots 411. In some embodiments, the carbonation station 410, the carbonation plots 411, the calciner 420, and the sequestration space 430 can be the same or substantially similar to the carbonation station 210, the carbonation plots 211, the calciner 220, and the sequestration space 230, as described above with reference to FIG. 3. Thus, certain aspects of the carbonation plots 411, the calciner 420, and the sequestration space 430 are not described in greater detail herein.|[0092] FIG. 5 shows a layout of the carbonation station 410 with the carbonation plots 411 surrounding the calciner 420. This can be an advantageous layout, as it minimizes the distance carbonation medium and the carbon-containing streams travel for processing between the process units. In some embodiments, the carbonation plots 411 can be arranged in a circle pattern, an oval pattern, a square pattern, a rectangular pattern, or any other suitable pattern around the calciner 420, in order to minimize energy cost for transporting carbonation medium and carbon-containing streams. In some embodiments, multiple carbonation plots 411 can be staggered in maturation date, allowing them to feed into a central regeneration facility. Conveyors C surround the calciner 420, transporting material between the carbonation station 410 and the calciner 420.|(US20240269605)|Examples|[0093] Example 1: 30 g of CaO and 30 g of Ca(OH)2 powders were placed in petri dishes and their CO2 uptake was measured over a period of 10 days. 1 gram of water was added to the CaO every 2 hours and 1 gram of water was added to the Ca(OH)2 every 2.4 hours. FIG. 6 shows the CO2 uptake data for these powders. The y-axis shows the CO2 weight fraction of each powder that is taken up per second. As shown, over a 10-day period, Ca(OH)2 starts with a higher uptake rate, and the two powders perform similarly starting around day 3. Both powders experience a reduction in CO2 uptake over the 10-day period, as more of the CaO and Ca(OH)2 are converted to CaCO3. The reduction in rate of uptake slows over time. The model curve was generated to fit to the full agglomeration of CaO and Ca(OH)2 data. The model curve indicates a starting uptake rate 1.2E-6 wt fraction/s acting on the declining amount of remaining reactant. If this rate is sustained, it can produce 75% carbonation in 14 days.|[0094] Example 2: 30 g of CaO and 30 g of Ca(OH)2 powders were placed in petri dishes and their CO2 uptake was measured over a period of 16 days. 1.5 grams of water were added to the CaO every 6 hours and 1.5 grams of water were added to the Ca(OH)2 every 6 hours. FIG. 7 shows the CO2 uptake data for these powders. The y-axis shows the CO2 weight fraction of each powder that is taken up per second. On average, the CaO takes up 6E-7 wt fraction/s and the Ca(OH)2 takes up 5.6E-7 wt fraction/s. The starting uptake rate for both powders is about 1.2E-6 wt fraction/s. If this rate is sustained, it can produce 75% carbonation in 14 days.|[0095] Example 3: 30 g of CaO and 30 g of Ca(OH)2 powders were placed in petri dishes and their CO2 uptake was measured over a period of 16 days. Water was added to different samples of CaO and Ca(OH)2. Water was added to CaO at rates of 0.5, 1, 1.5, and 2 grams per 6 hours. Water was added to Ca(OH)2 at a rate of 1.5 grams every 6 hours. Uptake rates are plotted in FIG. 8. The best uptake performance was observed in the powders in which 1.5 grams were added every 6 hours.|[0096] Example 4: Ca(OH)2 powder was placed in a petri dish and its uptake was measured over a period of two days. About 2 grams of water were added to the powder every 24 hours. FIG. 9 shows the uptake date of the powder over 2 days. The top trend line is a constant effective uptake rate (where the carbon dioxide per unit mass of material is consistent), while the bottom line is a decline in the consumption of Ca(OH)2 consistent with an exponential rate law. The results demonstrate that there is no observed decay in the effective uptake rate over the first two days.|[0097] Example 5: 50 g of MgO powder was placed in petri dishes for uptake of CO2 was tested over a period of about 75 days exposed to ambient air. The MgO production brands were Baymag, Premier, and Calix (three different samples). FIG. 10 shows CO2 uptake of each MgO sample and relative humidity in the environment. Water was added in amounts of 5-30 mL to each sample at various intervals. As shown, CO2 uptake increases significantly with each addition of water across all of the samples. FIG. 11 shows the effects of water addition on each of the samples. As shown, adding a small to moderate amount of water improves CO2 uptake, while adding too much water can oversaturate the powders, hindering CO2 uptake.|[0098] Example 6: FIG. 12 depicts material and energy balances of a hypothetical MgO looping process. FIG. 12 represents material and energy flows on a per plot basis. The system operates with many plots at the same time. However, since the plots are staggered in their maturation time, only one plot is processed at a time. The number of overall plots was determined to ensure continuous operation of the calciner unit to eliminate costs associated with repeated startup and shutdown.|[0099] Example 7: Li—COR soil flux instruments were used to determine the flux of CO2 to form solid carbonate minerals via reaction of air with MgO, CaO, and Ca(OH)2. By creating a time series of these fluxes, CO2 uptake change over time can be observed. CO2 concentration was measured in the headspace of the chamber of the Li—COR instrument. The Li—COR instrument was lowered onto a tube to create a seal, separating the chamber from the surrounding air. This allows the Li—COR instrument to pull gas from the headspace and circulate it into a gas analyzer unit. The gas analyzer uses optical feedback-cavity enhanced absorption spectroscopy (OF-CEAS) to determine the concentration of CO2 in the gas mixture. The gas analyzer then recirculates the gas back into the headspace of the chamber. Measuring headspace CO2 concentration versus time yields an estimate of CO2 flux from the air to form solid carbonate minerals. The flux values, initially reported in micromoles per square meter per second, can be converted to CO2 uptake rates in terms of mass fraction of the reactant consumed per second, or moles per cubic meter of reactant surface area per second.|[0100] A first set of experiments evaluated CO2 uptake into eight different layers of MgO powder, from 2 to 9 mm thick, using material obtained from Premier Magnesia. Eight different samples were shown to have similar rates of CO2 uptake per unit mass of MgO. Without wishing to be bound by theory, this can indicate that, in layer thicknesses up to 9 mm, CO2 diffusion into MgO powder does not limit reaction progress. Without wishing to be bound by theory, similar additional experiments indicate that, up to 3 cm, the layer thickness of MgO does not affect CO2 uptake rate per unit mass of MgO reactant. Similar experiments were repeated to test the variability of CO2 uptake across three different commercial MgO suppliers: Baymag, Calix, and Premier. There was no discernable rate difference between the materials from different suppliers.|[0101] Continued experiments under various conditions have yielded similar rates for CO2 uptake via reaction of ambient air with CaO, Ca(OH)2, and MgO (±Mg(OH)2). Some experiments have yielded nearly constant, observed rates that gradually decline from about 1.2E-6 and 4E-7 weight fraction of initial oxide material per second, over periods of about two weeks. Such values can potentially lead to 75% carbonation of the experimental starting material in 2-6 weeks. However, since the amount of oxide reactant remaining after days of reaction is diminished, the measured CO2 uptake diminishes over time, even if the actual rate is constant. Exponential fits can be used to determine the weight fraction of remaining oxide material that is consumed per second, yielding best fits (for several experiments with the fastest and least variable rates) in the range of about 1.2E-6 per second, constant over two weeks or more. This rate should produce 75% carbonation after two weeks of reaction.|[0102] Without wishing to be bound by theory, for the purpose of CO2 removal from air, alone, there does not appear to be a minimum particle size. However, the larger the particles that can obtain the desired CO2 uptake rate, the less likely those particles are to be lost to the environment. Additionally, material losses are combatted by keeping the material damp and thus less likely to be blown away or spilled. In the TEA, a substantial loss of oxide material in each cycle of carbonation and calcination was assumed. Steam treatment after calcination, as well as other activation methods, can regenerate MgO that has diminished CO2 uptake capacity. This can aid in replenishing spent MgO without extracting additional resources.|[0103] Various concepts may be embodied as one or more methods, of which at least one example has been provided. The acts performed as part of the method may be ordered in any suitable way. Accordingly, embodiments may be constructed in which acts are performed in an order different than illustrated, which may include performing some acts simultaneously, even though shown as sequential acts in illustrative embodiments. Put differently, it is to be understood that such features may not necessarily be limited to a particular order of execution, but rather, any number of threads, processes, services, servers, and/or the like that may execute serially, asynchronously, concurrently, in parallel, simultaneously, synchronously, and/or the like in a manner consistent with the disclosure. As such, some of these features may be mutually contradictory, in that they cannot be simultaneously present in a single embodiment. Similarly, some features are applicable to one aspect of the innovations, and inapplicable to others.|[0104] In addition, the disclosure may include other innovations not presently described. Applicant reserves all rights in such innovations, including the right to embodiment such innovations, file additional applications, continuations, continuations-in-part, divisionals, and/or the like thereof. As such, it should be understood that advantages, embodiments, examples, functional, features, logical, operational, organizational, structural, topological, and/or other aspects of the disclosure are not to be considered limitations on the disclosure as defined by the embodiments or limitations on equivalents to the embodiments. Depending on the particular desires and/or characteristics of an individual and/or enterprise user, database configuration and/or relational model, data type, data transmission and/or network framework, syntax structure, and/or the like, various embodiments of the technology disclosed herein may be implemented in a manner that enables a great deal of flexibility and customization as described herein.|[0105] All definitions, as defined and used herein, should be understood to control over dictionary definitions, definitions in documents incorporated by reference, and/or ordinary meanings of the defined terms.|[0106] As used herein, in particular embodiments, the terms “about” or “approximately” when preceding a numerical value indicates the value plus or minus a range of 10%. Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range is encompassed within the disclosure. That the upper and lower limits of these smaller ranges can independently be included in the smaller ranges is also encompassed within the disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the disclosure.|[0107] The indefinite articles “a” and “an,” as used herein in the specification and in the embodiments, unless clearly indicated to the contrary, should be understood to mean “at least one.”|[0108] The phrase “and/or,” as used herein in the specification and in the embodiments, should be understood to mean “either or both” of the elements so conjoined, i.e., elements that are conjunctively present in some cases and disjunctively present in other cases. Multiple elements listed with “and/or” should be construed in the same fashion, i.e., “one or more” of the elements so conjoined. Other elements may optionally be present other than the elements specifically identified by the “and/or” clause, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, a reference to “A and/or B”, when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A only (optionally including elements other than B); in another embodiment, to B only (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.|[0109] As used herein in the specification and in the embodiments, “or” should be understood to have the same meaning as “and/or” as defined above. For example, when separating items in a list, “or” or “and/or” shall be interpreted as being inclusive, i.e., the inclusion of at least one, but also including more than one, of a number or list of elements, and, optionally, additional unlisted items. Only terms clearly indicated to the contrary, such as “only one of” or “exactly one of,” or, when used in the embodiments, “consisting of,” will refer to the inclusion of exactly one element of a number or list of elements. In general, the term “or” as used herein shall only be interpreted as indicating exclusive alternatives (i.e., “one or the other but not both”) when preceded by terms of exclusivity, such as “either,” “one of,” “only one of,” or “exactly one of.” “Consisting essentially of,” when used in the embodiments, shall have its ordinary meaning as used in the field of patent law.|[0110] As used herein in the specification and in the embodiments, the phrase “at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements. This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase “at least one” refers, whether related or unrelated to those elements specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including elements other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other elements); etc.|[0111] In the embodiments, as well as in the specification above, all transitional phrases such as “comprising,” “including,” “carrying,” “having,” “containing,” “involving,” “holding,” “composed of,” and the like are to be understood to be open-ended, i.e., to mean including but not limited to. Only the transitional phrases “consisting of” and “consisting essentially of” shall be closed or semi-closed transitional phrases, respectively, as set forth in the United States Patent Office Manual of Patent Examining Procedures, Section 2111.03.|[0112] While specific embodiments of the present disclosure have been outlined above, many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, the embodiments set forth herein are intended to be illustrative, not limiting. Various changes may be made without departing from the spirit and scope of the disclosure. Where methods and steps described above indicate certain events occurring in a certain order, those of ordinary skill in the art having the benefit of this disclosure would recognize that the ordering of certain steps may be modified and such modification are in accordance with the variations of the invention. Additionally, certain of the steps may be performed concurrently in a parallel process when possible, as well as performed sequentially as described above. The embodiments have been particularly shown and described, but it will be understood that various changes in form and details may be made. | Family Number|(101683925)|101683925|Advantages / Prev. Drawbacks|(WO2022187336 A1)| (...) and future CO2 emissions from the atmosphere, some of which include the acceleration of natural processes such as the CO2 uptake of oceans and the terrestrial biosphere (soils, forests, minerals), bioenergy with carbon capture and storage (BECCS), and synthetic approaches using chemicals also known as direct air capture with storage (DACS) technologies.|(CN118201696 A)|( . . . ) eliminate CO _ 2 emissions in the current and future atmospheres , some of which include acceleration of natural processes such as CO _ 2 absorption by marine and terrestrial biospheres ( soil , forest , minerals ) , bioenergy carbon capture and storage ( BECCS ) , and synthetic methods using chemicals , also known as Direct Air Capture and Storage ( DACS ) technologies . | | Basic materials chemistry|Chemical engineering|Environmental technology|Materials, metallurgy | B01D-053/02/5|B01D-053/06|B01D-053/62|B01D-053/96|B01D-2251/304|B01D-2251/306|B01D-2251/402|B01D-2251/404|B01D-2257/504|B01D-2258/06|B01J-020/30/21|C01B-032/55|C10B-057/00/5|C10B-057/04|Y02C-020/40 | B01D-053/02/5|B01D-053/06|B01D-053/62|B01D-053/96|B01D-2251/304|B01D-2251/306|B01D-2251/402|B01D-2251/404|B01D-2257/504|B01D-2258/06|B01J-020/30/21|C01B-032/55|C10B-057/00/5|C10B-057/04|Y02C-020/40 | B01D-053/02|B01D-053/06|B01D-053/14|B01D-053/34|B01D-053/62|B01D-053/77|B01D-053/82|B01D-053/96|B01J-020/30|C01B-032/50|C01B-032/55|C10B-057/00|C10B-057/04 | B01D-053/02|B01D-053/06|B01D-053/14|B01D-053/34|B01D-053/62|B01D-053/77|B01D-053/82|B01D-053/96|B01J-020/30|C01B-032/50|C01B-032/55|C10B-057/00|C10B-057/04 | WO2025249453|WO2024211540|WO2024102926;WO2024102926|WO202512458|US20240159128|US12544734|WO202602422|US12465889|US12220661|US12357946|EP4670824|WO2024211540|US12521676|EP4444449;EP4444449;EP4444449|WO202411170|US12533623|US12172127 | WO2025249453 116894334 WHO=Examiner SELF=N CAT=Y|WO2024211540 111695406 WHO=Examiner SELF=N CAT=Y|WO2024102926 109703247 WHO=Examiner SELF=N CAT=X|WO202512458 113058353 WHO=Examiner SELF=N CAT=A|US20240159128 109703247 WHO=Examiner SELF=N CAT=102 CAT=103|US12544734 117681626 WHO=Applicant SELF=N|WO202602422 117255527 WHO=Applicant SELF=N|US12465889 94627895 WHO=Applicant SELF=N|US12220661 94627895 WHO=Applicant SELF=N|US12357946 94627895 WHO=Applicant SELF=N|EP4670824 117255527 WHO=Applicant SELF=N|WO2024211540 111695406 WHO=Applicant SELF=N|US12521676 107508821 WHO=Applicant SELF=N|EP4444449 110762463 WHO=Examiner SELF=N|WO202411170 108035748 WHO=Applicant SELF=N|US12533623 97699359 WHO=Applicant SELF=N|US12172127 94627895 WHO=Applicant SELF=N | WO2020263910|JP2009138186|US20200009527|US20200009527|US20140120017|US20140120017|US20130255257|US20130255257|US20110113957|US20110113957|US20060093540|US20060093540|US20080031801|US20080031801|WO2020263910|US10213730|US20170327421|US20150343373|US9719417|US20140161696|JP2013136012|JP2013081873|US20110286902|JP2010194530|JP2010527771 | WO2020263910 92128920 WHO=Examiner SELF=Y CAT=X|JP2009138186 1839578 WHO=Examiner SELF=N CAT=X|US20200009527 87237141 WHO=Examiner SELF=N CAT=A|US20200009527 87237141 WHO=Examiner SELF=N CAT=A|US20140120017 6810871 WHO=Examiner SELF=N CAT=A|US20140120017 6810871 WHO=Examiner SELF=N CAT=A|US20130255257 46102286 WHO=Examiner SELF=N CAT=A|US20130255257 46102286 WHO=Examiner SELF=N CAT=A|US20110113957 6810871 WHO=Examiner SELF=N CAT=A|US20110113957 6810871 WHO=Examiner SELF=N CAT=A|US20060093540 4131565 WHO=Examiner SELF=N CAT=A|US20060093540 4131565 WHO=Examiner SELF=N CAT=A|US20080031801 43690578 WHO=Examiner SELF=N CAT=A|US20080031801 43690578 WHO=Examiner SELF=N CAT=A|WO2020263910 92128920 WHO=Applicant SELF=Y|US10213730 83463380 WHO=Examiner SELF=N|US20170327421 77745618 WHO=Examiner SELF=N|US20150343373 71603095 WHO=Examiner SELF=N|US9719417 69549855 WHO=Examiner SELF=N|US20140161696 15080017 WHO=Examiner SELF=N|JP2013136012 45762562 WHO=Examiner SELF=N|JP2013081873 45385183 WHO=Examiner SELF=N|US20110286902 71289850 WHO=Examiner SELF=N|JP2010194530 33175342 WHO=Examiner SELF=N|JP2010527771 81911683 WHO=Examiner SELF=N | 国際公開第２０２０／２６３９１０号 | US20130255257; US20140120017; US20060093540; US20080031801; US20200009527; US20110113957|US20130255257; US20140120017; US20060093540; US20080031801; US20200009527; US20110113957; XP093039666; XP093012896; XP025715916; XP085866689; XP037126698; XP093294989; XP028837112; XP093295133||US10213730; US20170327421; US9719417; US20150343373; US20140161696; US20110286902||WO2020263910; JP2009138186; JP2010527771; JP2013081873; JP2013136012; JP2010194530; WO2020263910 | (EP4376984)|Search Report references [Examiner]|-MCQUEEN NOAH ET AL: "Ambient weathering of magnesium oxide for CO2 removal from air", NATURE COMMUNICATIONS, vol. 11, no. 1, 3 July 2020 (2020-07-03), XP093039666, Retrieved from the Internet <URL:https://www.nature.com/articles/s41467-020-16510-3.pdf> DOI: 10.1038/s41467-020-16510-3|-ABANADES J. CARLOS ET AL: "An air CO 2 capture system based on the passive carbonation of large Ca(OH) 2 structures", SUSTAINABLE ENERGY & FUELS, vol. 4, no. 7, 1 January 2020 (2020-01-01), pages 3409 - 3417, XP093012896, DOI: 10.1039/D0SE00094A|-NIKULSHINA V ET AL: "CO"2 capture from atmospheric air via consecutive CaO-carbonation and CaCO"3-calcination cycles in a fluidized-bed solar reactor", CHEMICAL ENGENEERING JOURNAL, ELSEVIER, AMSTERDAM, NL, vol. 146, no. 2, 1 February 2009 (2009-02-01), pages 244 - 248, XP025715916, ISSN: 1385-8947, [retrieved on 20080613], DOI: 10.1016/J.CEJ.2008.06.005|-ERANS MAR�A ET AL: "Carbonation of lime-based materials under ambient conditions for direct air capture", JOURNAL OF CLEANER PRODUCTION, ELSEVIER, AMSTERDAM, NL, vol. 242, 7 September 2019 (2019-09-07), XP085866689, ISSN: 0959-6526, [retrieved on 20190907], DOI: 10.1016/J.JCLEPRO.2019.118330|-SAMARI MOHAMMAD ET AL: "Direct capture of carbon dioxide from air via lime-based sorbents", MITIGATION AND ADAPTATION STRATEGIES FOR GLOBAL CHANGE, SPRINGER NETHERLANDS, DORDRECHT, vol. 25, no. 1, 21 February 2019 (2019-02-21), pages 25 - 41, XP037126698, ISSN: 1381-2386, [retrieved on 20190221], DOI: 10.1007/S11027-019-9845-0|-MORALES-FL�REZ V. ET AL: "Hydration and carbonation reactions of calcium oxide by weathering: Kinetics and changes in the nanostructure", CHEMICAL ENGENEERING JOURNAL, vol. 265, 1 April 2015 (2015-04-01), AMSTERDAM, NL, pages 194 - 200, XP093294989, ISSN: 1385-8947, Retrieved from the Internet <URL:https://www.sciencedirect.com/science/article/pii/S1385894714016763> DOI: 10.1016/j.cej.2014.12.062|-COPPOLA ANTONIO ET AL: "Reactivation by water hydration of the CO2capture capacity of a calcium looping sorbent", FUEL, IPC SIENCE AND TECHNOLOGY PRESS , GUILDFORD, GB, vol. 127, 30 September 2013 (2013-09-30), pages 109 - 115, XP028837112, ISSN: 0016-2361, DOI: 10.1016/J.FUEL.2013.09.059|-MANOVIC VASILIJE ET AL: "Spray Water Reactivation/Pelletization of Spent CaO-based Sorbent from Calcium Looping Cycles", ENVIRONMENTAL SCIENCE & TECHNOLOGY, vol. 46, no. 22, 1 November 2012 (2012-11-01), US, pages 12720 - 12725, XP093295133, ISSN: 0013-936X, Retrieved from the Internet <URL:https://pubs.acs.org/doi/pdf/10.1021/es303252j> DOI: 10.1021/es303252j|-See also references of WO 2022187336A1|||(WO2022/187336)|International Search Report [Examiner]|-See also references of EP 4376984A4|||| | PENDING | (EP4376984)|PENDING|(US20240269605)|PENDING|(WO2022/187336)|LAPSED|(JP2024512355)|LAPSED|(CN118201696)|PENDING|(KR10-2024-0157528)|REVOKED | ALIVE | (EP4376984)|ALIVE|(US20240269605)|ALIVE|(WO2022/187336)|DEAD|(JP2024512355)|DEAD|(CN118201696)|ALIVE|(KR10-2024-0157528)|DEAD | (EP4376984)|LEGAL DETAILS FOR EP4376984|Actual or expected expiration date=2042-03-02|Legal state=ALIVE|Status=PENDING|Event publication date=2022-03-02|Event code=EP/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=EP EP22763957|Application date=2022-03-02|Standardized application number=2022EP-0763957|Event publication date=2022-09-09|Event code=EP/STAAPCT|Event group=Examination events Entry into national phase|The international publication has 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of duration of protection|ADMINISTRATIVE TIME LIMIT EXTENSION REQUESTED|St27 status event code: U-3-3-T10-T11-OTH-X000 (AS PROVIDED BY THE NATIONAL OFFICE) | (EP4376984)|Contracting States: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, LI, RO, NL, TR|(WO2022/187336)|ARIPO: GH, RW, GM, LR, TZ, LS, SZ, MW, MZ, SD, UG, NA, ZM, BW, SL, KE, ZW|(WO2022/187336)|EAPO: RU, TJ, BY, AZ, TM, AM, KG, KZ|(WO2022/187336)|EPO: DE, NO, RS, BE, FI, PT, BG, DK, LT, LU, HR, LV, FR, HU, SE, MC, SI, SK, SM, GB, IE, MK, EE, CH, MT, IS, AL, GR, IT, ES, AT, CY, CZ, PL, RO, NL, TR|(WO2022/187336)|OAPI: ST, KM, CF, BF, CG, MR, CI, GN, BJ, CM, GQ, GW, TD, TG, NE, GA, SN, ML|(WO2022/187336)|National States: PT, HN, HR, HU, QA, ID, IL, AE, IN, AG, ZA, IR, IS, AL, IT, AM, AO, AT, ZM, AU, AZ, RO, ZW, BA, BB, RS, JM, RU, BG, JO, RW, BH, JP, BN, SA, BR, SC, SD, SE, SG, BW, BY, BZ, SK, SL, KE, KG, KH, CA, ST, KN, SV, CH, KP, SY, KR, CL, CN, CO, KW, CR, KZ, CU, TH, LA, TJ, CZ, LC, TM, TN, TR, LK, TT, DE, DJ, LR, TZ, DK, LS, DM, LU, DO, UA, LY, UG, MA, DZ, MD, ME, MG, EC, MK, US, EE, MN, EG, UZ, MW, MX, MY, MZ, VC, ES, NA, VN, NG, NI, NO, FI, NZ, GB, WS, GD, GE, OM, GH, GM, GT, PA, PE, PG, PH, PL | (EP4376984)|EP|(US20240269605)|US|(WO2022/187336)|CN; EP; US|(CN118201696)|CN | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=8TP/cX+h8x6US5wHcsfhAnmXtI+wKb3KNoC7YXsv59YWpPjZ1ShY4s3HTZ4K3xLA34T3rrXcRGc=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=US0000000022143786&ekey=2319&xpn=EP4376984&kind=A4 | https://register.epo.org/application?number=EP22763957 | https://permalink.orbit.com/RenderStaticFirstPage?XPN=TgYmpxU3tSH4%252BC%252F5M6pym3fDUqlXTJ5uwQdFuycu4uk%3D%26n%3D1&id=0&base=FAMPAT | US | (WO2022/187336)|US | (WO2022/187336)|NAME=THE TRUSTEES OF COLUMBIA UNIVERSITY IN THE CITY OF NEW YORK 412 Low Memorial Library 535 West 116th Street New York, NY 10027 , COUNTRY=US NAME=THE UNIVERSITY OF BRITISH COLUMBIA 103-6190 Agronomy Road Vancouver, V6T 1Z3 , COUNTRY=CA NAME=THE TRUSTEES OF THE UNIVERSITY OF PENNSYLVANIA 3160 Chestnut Street, Suite 200 Penn Center For Innovation Philadelphia, PA 19104 , COUNTRY=US | (EP4376984)|FR|(WO2022/187336)|US||| | (EP4376984)|NAME=Sayettat, Julien Christian;Strato-IP 63, Boulevard de Ménilmontant , CITY=75011 Paris , COUNTRY=FR , REG=101676761|(WO2022/187336)|NAME=GANGEMI, Anthony, P. Murtha Cullina LLP One Century Tower 9th Floor New Haven, CT 06510 , POSTCODE=06510 , COUNTRY=US|(JP2024512355)|NAME=MINAMI AOYAMA PATENT AND TRADEMARK ATTORNEYS , REG=110003339|(CN118201696)|NAME=FAN YUNFEI;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC , REG=31100NAME=WANG YING;SHANGHAI PATENT & TRADEMARK LAW OFFICE, LLC , REG=31100|(KR10-2024-0157528)|NAME=CHOI, DUG-KYU | |(EP4376984)|GB; US; US; US; US; CA|(US20240269605)|US; US; GB; US; US; CA|(WO2022/187336)|GB; US; US; US; US; CA||| | (EP4376984)|NAME=MORTIMER, Thomas|NAME=KELEMEN, Peter, Boushall|NAME=MCGILLIS, Wade|NAME=WILCOX, Jennifer|NAME=MCQUEEN, Noah|NAME=DIPPLE, Greg|(EP4376984)|NAME=MORTIMER, Thomas, CITY=Reading, RG67BP, COUNTRY=GB |NAME=KELEMEN, Peter, Boushall, CITY=Nyack, NY 10960, COUNTRY=US |NAME=MCGILLIS, Wade, CITY=New York, NY 10025, COUNTRY=US |NAME=WILCOX, Jennifer, CITY=Philadelphia, PA 19118, COUNTRY=US |NAME=MCQUEEN, Noah, CITY=Overland Park, KS 66212, COUNTRY=US |NAME=DIPPLE, Greg, CITY=Vancouver, British Columbia V6T 1Z4, COUNTRY=CA|(US20240269605)|NAME=KELEMEN Peter Boushall, CITY=Nyack, STATE=NY , COUNTRY=US |NAME=McGILLIS Wade, CITY=New York, STATE=NY , COUNTRY=US |NAME=MORTIMER Thomas, CITY=Reading, COUNTRY=GB |NAME=WILCOX Jennifer, CITY=Philadelphia, STATE=PA , COUNTRY=US |NAME=McQUEEN Noah, CITY=Overland Park, STATE=KS , COUNTRY=US |NAME=DIPPLE Greg, CITY=Vancouver, COUNTRY=CA|(WO2022/187336)|NAME=MORTIMER, Thomas 29 Talfourd Avenue Reading RG67BP, POSTCODE=RG67BP, COUNTRY=GB |NAME=KELEMEN, Peter, Boushall 2 Clinton Avenue Nyack, NY 10960, POSTCODE=10960, COUNTRY=US |NAME=MCGILLIS, Wade 255 West 108th Street, 6E New York, NY 10025, POSTCODE=10025, COUNTRY=US |NAME=WILCOX, Jennifer 8840 Towanda Street Philadelphia, PA 19118, POSTCODE=19118, COUNTRY=US |NAME=MCQUEEN, Noah 9007 West 106th Street Overland Park, KS 66212, POSTCODE=66212, COUNTRY=US |NAME=DIPPLE, Greg 2020-2207 Main Mall Vancouver, British Columbia V6T 1Z4, POSTCODE=1Z4, COUNTRY=CA|(JP2024512355)|NAME=Kelemen, Peter, Bowshall|NAME=McGillis, Wade|NAME=Wilcox, Jennifer|NAME=mcqueen, noah|NAME=Dipple, Greg|NAME=mortimer, thomas|(CN118201696)|NAME=BUCHER KELLERMAN PETER|NAME=WADE MCGILLIS|NAME=WILCOX JENNIFER|NAME=NOAH MCQUEEN|NAME=DIPPLE, GREG|NAME=MORTIMER THOMAS|(KR10-2024-0157528)|NAME=KELEMEN PETER BOUSHALL|NAME=MCGILLIS WADE|NAME=WILCOX JENNIFER|NAME=MCQUEEN NOAH|NAME=DIPPLE GREG|NAME=MORTIMER THOMAS | (WO2022/187336)|12|(KR10-2024-0157528)|12|(US20240269605)|12|(CN118201696)|12|(JP2024512355)|12 | 3 | 6 | (EP4376984)|WO2022/187336|(US20240269605)|WO2022/187336|(JP2024512355)|WO2022/187336|(CN118201696)|WO2022/187336|(KR10-2024-0157528)|WO2022/187336 | (US20240269605)|Number of Claims: NCL=36|Number of Drawings: NDR=12|Number of Figures: NFG=12|Independent Claim Number: ICL=1,16,23|Number of Independent Claims: NICL=3|Exemplary Claim Number: ECL=1||(WO2022/187336)|Number of Claims: NCL=36|Extended kind: EXTK=x||(JP2024512355)|Number of Claims: NCL=36|Request for examination: REQEXA=true||(CN118201696)|Number of Claims: NCL=36|Gazette date: GAZDATE=2024-06-14|Gazette number: GAZNUM=40-2402|Substantial examination effective date: 20240702|Number of Pages: NPAGES=37||(KR10-2024-0157528)|Number of Claims: NCL=36| | (US20240269605)|Continuation of: WOUS2022/018484 FDD=2022-03-02 [2022WO-US18484] PENDING|Provisional Appl: US63/155,572 FDD=2021-03-02 [2021US-63155572] | (EP4376984)|ENGLISH (ENG) | (EP4376984)|Patent|(KR20240157528)|Patent|(US20240269605)|Patent|(CN118201696)|Patent|(EP4376984)|Patent|(JP2024512355)|Patent|(WO2022187336)|Patent | Titre: (EP4376984)|Systems and methods for enhanced weathering and calcining for co2 removal from air Résumé: (EP4376984)|Embodiments described herein relate to systems and methods of CO2 uptake. In one aspect, a method includes applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2. The method further includes sequestering and/or utilizing the gas stream, feeding the stream of the carbonation medium to a carbonation station, contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream, during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours, and feeding the carbon-containing stream to the calciner. In some embodiments, adding the water stream is via misting and/or spraying. Autre: (US20240269605)|1. A method, comprising:| applying heat to a calciner to decompose a carbon-containing stream to a gas stream and a stream of a carbonation medium, the gas stream including CO2;| at least one of sequestering or utilizing the gas stream;| feeding the stream of the carbonation medium to a carbonation station;| contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream;| during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours; and| feeding the carbon-containing stream to the calciner.|2. The method of claim 1, wherein adding the water stream is via misting and/or spraying.|3. The method of claim 1, wherein adding the water is at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium.|4. The method of claim 1, wherein the carbonation medium is maintained at a moisture content between about 3 wt % and about 50 wt %.|5. The method of claim 1, further comprising:| grinding an adsorbent material to form the carbonation medium in a powder via at least one of a ball mill crusher, impact crushers, or a cone crusher.|6. The method of claim 1, wherein the carbonation medium includes at least one of magnesium oxide, magnesium silicates, silicon dioxide, calcium oxide, calcium hydroxide, calcium silicates, sodium oxide, sodium hydroxide, potassium oxide, potassium hydroxide, or magnesium hydroxide.|7. (canceled)|8. The method of claim 1, further comprising:| condensing an amount of water from the gas stream; and| feeding the amount of water to the water stream.|9. (canceled)|10. The method of claim 1, further comprising:| processing an air stream via an air separation unit to produce an oxygen stream, the oxygen stream having a purity of at least about 95%; and| feeding the oxygen stream to the calciner.|11. The method of claim 1, wherein the carbonation medium has an average particle size of less than about 75 μm.|12. The method of claim 1, wherein the carbonation station includes a plurality of carbonation contactors, each carbonation contactor of the carbonation contactors including a sheet of the carbonation medium, the sheet of the carbonation medium having a thickness between about 0.5 mm and about 10 mm.|13. The method of claim 1, wherein applying the heat to the calciner is via electric resistance heating powered by electricity.|14. The method of claim 1, further comprising:| monitoring a relative humidity, temperature, and air velocity levels of ambient air in close proximity to the carbonation medium during the contacting.|15. The method of claim 1, further comprising:| hydrating the carbonation medium prior to feeding the carbonation medium to the carbonation station.|16. A method, comprising:| applying heat to a calciner to decompose a carbon-containing stream into a gas stream and a stream of a carbonation medium, the gas stream including CO2;| at least one of sequestering or utilizing the gas stream;| feeding the stream of the carbonation medium to a carbonation station;| contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream;| during the contacting, spraying and/or misting a water stream to the carbonation medium at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium; and| feeding the carbon-containing stream to the calciner.|17. The method of claim 16, wherein the gas stream includes at least about 95% CO2 by volume.|18. The method of claim 16, further comprising:| grinding an adsorbent material to form the carbonation medium into a powder.|19. The method of claim 16, wherein the adsorbent material includes at least one of magnesium oxide, magnesium silicate, silicon dioxide, calcium oxide, calcium hydroxide, calcium silicates, sodium oxide, sodium hydroxide, potassium oxide, potassium hydroxide, or magnesium hydroxide.|20. The method of claim 16, wherein the carbon-containing stream includes at least one of MgCO3, dolomite (high magnesium calcium carbonate), sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, potassium carbonate, potassium bicarbonate, nesquehonite, or hydromagnesite.|21. The method of claim 16, further comprising:| condensing an amount of water from the gas stream; and| recycling the amount of water by feeding the amount of water to the water stream.|22. (canceled)|23. A method, comprising:| decomposing a carbon-containing stream into a gas stream and a stream of a carbonation medium in a calciner, the gas stream including CO2, the carbonation medium including at least one of MgCO3, sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, nesquehonite, or hydromagnesite;| sequestering the gas stream;| feeding the stream of the carbonation medium to a carbonation station;| contacting the carbonation medium with ambient air at the carbonation station, such that the carbonation medium adsorbs CO2 to form the carbon-containing stream;| during the contacting, adding a water stream to the carbonation medium at intervals of about 30 minutes to about 72 hours at a rate of between about 0.01 and about 0.5 mL of water per gram of carbonation medium; and| feeding the carbon-containing stream to the calciner.|24. (canceled)|25. The method of claim 23, wherein the carbon-containing stream includes at least one of MgCO3, dolomite (high magnesium calcium carbonate), sodium carbonate, sodium bicarbonate, silicon carbonate, calcium carbonate, calcium bicarbonate, potassium carbonate, potassium bicarbonate, nesquehonite, or hydromagnesite.|26. The method of claim 23, further comprising:| applying heat to the calciner via electric resistance heating powered by electricity.|27. The method of claim 23, further comprising:| condensing an amount of water from the gas stream; and| recycling the amount of water by feeding the amount of water to the water stream.|28. (canceled)|29. (canceled)|30. (canceled)|31. (canceled)|32. (canceled)|33. (canceled)|34. (canceled)|35. (canceled)|36. (canceled) | 23 | Abstract | gpt-4o-mini | no | The article focuses on CO2 removal from air through enhanced weathering and calcining, which does not involve biomass or energy production from biomass. | ||||||||||||||
| 30 | CN201710943918 | CN201710943918 | CN107569981 | 78459841 | CN107569981 A 2018-01-12 [CN107569981] | 2017-10-11 | 2017-10-11 | 2018-01-12 | (CN107569981)|2021-02-23 | (CN107569981)|Preparation technology of charcoal for coupling with flue gas carbon dioxide catching in coal-fired power plant | (CN107569981)|The invention discloses a preparation technology of charcoal for coupling with flue gas carbon dioxide catching in a coal-fired power plant. The technology is integrated with the techniques of charcoal preparation, gas membrane separation, carbonic acid molten salt fuel cells, and the like; the liquified natural gas is used for cooling the system in stages and then is used as an anode fuel of molten carbonate fuel cell; the enrichment for carbon dioxide is realized in the power generating process through the molten carbonate fuel cell; after the exhaust gas emitted from the anode is dewatered,a membrane component is used for separating carbon dioxide from the other gases and the trapping gas is utilized to supply energy to the oxygen enriching block of the membrane component; a pressurizing-cooling-pressurizing process is adopted in the carbon dioxide liquifying process and the total energy consumption in the liquifying process is reduced; the requirements for heat and cold energy inall the processes of the technology are effectively integrated through a heat exchanger and a natural gas heating device; in the charcoal preparation process, the heat of the gas emitted from the anode and cathode of the molten carbonate fuel cell under different temperatures is utilized to fix carbon and meanwhile the energy utilization efficiency of the system is increased. | YANG ZHENGSHAN | (CN107569981)|YANG ZHENGSHAN | YANG ZHENGSHAN | (CN107569981)|YANG ZHENGSHAN | (CN107569981)|The membrane separation method has the advantages of small occupied area, low energy consumption, no phase change and simple and convenient operation, and has wide application prospect, but because the flue gas pressure of a coal-fired power plant is small, the concentration of carbon dioxide in the flue gas is low, a compressor is required to provide a separation effect in actual operation, the energy consumption in the carbon dioxide capturing process is increased, and the method is a main factor which hinders the industrial application of the membrane separation method at present.|Therefore, it is necessary to research a process for capturing carbon dioxide in flue gas of a coal-fired power plant by using biological energy and carbon capture and storage technology (BECCS), and integrate low-temperature deep cooling, membrane separation and molten carbonate fuel cell technologies in combination with biochar preparation to reduce the energy consumption and the capturing difficulty of the process.| | (CN107569981)|1. A preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant is characterized by comprising the following steps: integrates the technologies of biochar preparation, gas membrane separation, low-temperature liquefaction, molten carbonate fuel cells and the like; mixing a molten carbonate fuel cell anode fuel source consisting of natural gas obtained by heating natural gas and liquefied natural gas which utilize finish cooling energy and natural gas from other sources with water vapor, carrying out catalytic reforming, and introducing the mixture into a molten carbonate fuel cell anode to carry out oxidation reaction; the flue gas of the coal-fired power plant is purified by an impurity removal device, then is mixed with the flue gas obtained by burning natural gas and fresh air according to a certain proportion, and is subjected to pressurization and heating to react at the cathode of a molten carbonate fuel cell; reacting flue gas discharged from an anode with oxygen-enriched air prepared from an oxygen-enriched plate block of a membrane component in a catalytic combustor according to a certain proportion, then introducing the reaction product into a biochar preparation device, cooling to a set temperature, introducing the reaction product into the biochar preparation device with a lower preparation temperature, performing staged cooling when the temperature is lower than 100 ℃ to realize primary separation of moisture in the flue gas, introducing gas after gas-liquid separation into the membrane component to perform gas component separation, compressing the gas by a multistage compressor, performing 2-stage cooling by a heat exchanger, further dehydrating and drying by using a 3A molecular sieve, cooling the gas to-54 ℃ by using an LNG (liquefied natural gas) heat exchanger to obtain liquid, and then pressurizing to a pressure required by set commercial use by a hydraulic pump; the flue gas discharged from the cathode of the molten carbonate fuel cell is heated by a catalytic burner, expanded to generate power, introduced into the biochar preparation equipment, and discharged into the atmosphere after being cooled to a certain temperature.| | (CN107569981)|The invention aims to provide a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant, which effectively integrates the technologies of biochar preparation, gas membrane separation, molten carbonate fuel cells and the like, and can effectively reduce the energy consumption of the carbon dioxide capture process and improve the carbon dioxide emission reduction effect.|The invention discloses a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant, which integrates the technologies of biochar preparation, gas membrane separation, molten carbonate fuel cell and the like; the liquefied natural gas is used for cooling the system in stages and then is used as anode fuel of the molten carbonate fuel cell, the enrichment of carbon dioxide is realized in the power generation process of the molten carbonate fuel cell, the carbon dioxide is separated from other gas components by a membrane module after the anode exhaust smoke is dehydrated, the trapped gas is used for providing energy for the membrane module oxygen-enriched plate block, and the total energy consumption in the liquefaction process of the carbon dioxide is reduced by using the processes of pressurization, cooling and pressurization; the heat exchanger and the natural gas heating device effectively integrate the requirements of each link in the process on heat and cold energy; in the biochar preparation step, the heat of different temperature sections of flue gas discharged by the anode and the cathode of the molten carbonate fuel cell is utilized, so that the energy utilization efficiency of the system is improved while carbon is fixed. Technical Field The invention relates to the technical field of flue gas treatment and biomass utilization, in particular to a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant.| | (CN107569981)|FLUE GAS(100,46)|METHANEDIONE(100,18)|COAL FIRED POWER PLANT(100,16)|METHANEDIONE ENRICHMENT(100,1)|MOLTEN CARBONATE FUEL CELL(90,19)|BIOCHAR(70,17)|CARBONATE FUEL CELL(68,19)|BIOCHAR PREPARATION EQUIPMENT(57,1)|METHANEDIONE CAPTURE(50,5)|MULTISTAGE COMPRESSOR(49,4)|STAGED COOLING(48,1)|MEMBRANE MODULE(46,13)|MEMBRANE COMPONENT(45,9)|CARBONATE FUEL CELL ANODE(45,5)|CATALYTIC BURNER(44,3)|ENERGY UTILIZATION(43,3)|ANODE(41,10)|MOISTURE PRIMARY SEPARATION(40,1)|PRESSURIZING(39,8)|CATHODE(39,6)|LIQUEFACTION(39,3)|GAS MEMBRANE SEPARATION(37,2)|REMOVING IMPURITY(36,2)|FUEL CELL ANODE(35,5)|REACTION PRODUCT(35,2)|COLD ENERGY(34,10)|ENRICHMENT MODULE(34,1)|FUEL CELL(33,19)|CATALYTIC REFORMING(33,1)|EXPANSION MACHINE(31,2)|PRIMARY SEPARATION(30,1)|DEHYDRATION(28,3)|POWER GENERATION(27,1)|CATALYTIC COMBUSTOR(26,8)|SMOKE(26,3)|STEAM HEATER(26,2)|GAS INTERCEPTION(26,1)|TRAPPED GAS(24,5)|ANODE REACTION(23,1)|GAS COMPONENT SEPARATION(23,1)|SMOKE CONSTITUENT SEPARATION(23,1)|COOLING ENERGY(22,2)|OXYGEN SEPARATION(22,1)|SEPARATION COEFFICIENT(21,2)|MEMBRANE COMPONENT OXYGEN(21,1)|OXYGEN ENRICHED AIR(20,5)|METHANEDIONE LIQUID(20,4)|GAS PERMEATION(20,3)|DEHYDRATION LINK TEMPERATURE(20,2)|NATURAL GAS(19,28)|TOTAL ENERGY CONSUMPTION(19,1)|HEAT EXCHANGER(18,28)|MOLECULAR SIEVE(18,2)|PREPARATION TEMPERATURE(17,3)|HYDRAULIC PUMP(16,2)|GAS COMPONENT(15,6)|OXYGEN ENRICHED PLATE BLOCK(15,3)|TURBINE(15,3)|TEMPERATURE SECTION(15,1)|LIQUEFIED NATURAL GAS(14,25)|FUEL REFORMING(12,3)|LIQUID PUMP(11,6)|OXIDATION REACTION(11,3)|GAS LIQUID SEPARATION(11,2)|METHANEDIONE LIQUEFACTION LINK(11,1)|GAS MIXER(10,8)|OXYGEN SOURCE(10,3)|BIOENERGY RESEARCH CATEGORY(10,1)|METHANEDIONE MEMBRANE CAPTURE(10,1)|RESOURCE COMPREHENSIVE UTILIZATION(10,1)|TOTAL ENERGY(10,1)|COMPRESSED AIR(9,3)|PLATE BLOCK(9,3)|SET COMMERCIAL(9,3)|LOW TEMPERATURE LIQUEFACTION(9,2)|ANODE FUEL PRETREATMENT(9,1)|GAS POTENTIAL ENERGY(9,1)|LIQUEFIED METHANEDIONE(9,1)|FRESH AIR(8,3)|MOLECULAR SIEVE DEHYDRATION(8,2)|CARRYING OUT CATALYTIC REFORMING(8,1)|COUPLING METHANEDIONE CAPTURE(8,1)|DEHYDRATED METHANEDIONE GAS(8,1)|METHANEDIONE DISCHARGE ACCOUNT(8,1)|METHANEDIONE PURITY(8,1)|PRECOMBUSTION CAPTURE(8,1)|EXPANDER(7,4)|ANOXIC ENVIRONMENT(7,1)|BIOMASS UTILIZATION(7,1)|COOL DEHYDRATION LINK(7,1)|EXTENSIVE UTILIZATION(7,1)|HYDROXYLAMINE ABSORPTION(7,1)|METHANEDIONE CAPTURE MODE(7,1)|MOLTEN CARBONATE FUEL(7,1)|STRAW COMBUSTION(7,1)|COMPRESSOR(6,3)|FLUE GAS IMPURITY TREATMENT(6,2)|GAS LIQUID SEPARATOR(5,6)|FLOW BACK(5,2)|ANAEROBIC ENVIRONMENT(5,1)|BIOCHAR PRODUCT PHYSICOCHEMICAL PROPERTY(5,1)|COOLING LIQUEFACTION(5,1)|ENERGY INTERNATIONAL DEPARTMENT(5,1)|GREENHOUSE GAS ABATEMENT(5,1)|MEMBRANE MODULE PERMEATION GAS(5,1)|MEMBRANE MODULE TRAPPED GAS(5,1)|METHANEDIONE MEMBRANE SEPARATION LINK(5,1)|TRANSPORTATION ACCOUNT(5,1)|CATALYTIC REFORMING REACTION(4,1)|CATHODE REACTION(4,1)|FLUID PRESSURIZATION(4,1)|GAS DEHYDRATION(4,1)| | (CN107569981)|1. A preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant is characterized by comprising the following steps: integrates the technologies of biochar preparation, gas membrane separation, low-temperature liquefaction, molten carbonate fuel cells and the like; mixing a molten carbonate fuel cell anode fuel source consisting of natural gas obtained by heating natural gas and liquefied natural gas which utilize finish cooling energy and natural gas from other sources with water vapor, carrying out catalytic reforming, and introducing the mixture into a molten carbonate fuel cell anode to carry out oxidation reaction; the flue gas of the coal-fired power plant is purified by an impurity removal device, then is mixed with the flue gas obtained by burning natural gas and fresh air according to a certain proportion, and is subjected to pressurization and heating to react at the cathode of a molten carbonate fuel cell; reacting flue gas discharged from an anode with oxygen-enriched air prepared from an oxygen-enriched plate block of a membrane component in a catalytic combustor according to a certain proportion, then introducing the reaction product into a biochar preparation device, cooling to a set temperature, introducing the reaction product into the biochar preparation device with a lower preparation temperature, performing staged cooling when the temperature is lower than 100 ℃ to realize primary separation of moisture in the flue gas, introducing gas after gas-liquid separation into the membrane component to perform gas component separation, compressing the gas by a multistage compressor, performing 2-stage cooling by a heat exchanger, further dehydrating and drying by using a 3A molecular sieve, cooling the gas to-54 ℃ by using an LNG (liquefied natural gas) heat exchanger to obtain liquid, and then pressurizing to a pressure required by set commercial use by a hydraulic pump; the flue gas discharged from the cathode of the molten carbonate fuel cell is heated by a catalytic burner, expanded to generate power, introduced into the biochar preparation equipment, and discharged into the atmosphere after being cooled to a certain temperature.|2. The process for preparing the carbon dioxide capture coupling biochar in the flue gas of the coal-fired power plant according to claim 1, which is characterized in that: the membrane component oxygen enrichment module integrates pressure potential energy of gas intercepted by the smoke component separation membrane component through the turbine expansion-compressor to provide power for compressed air, the compressed air is used for separating oxygen and nitrogen through the membrane component, the intercepted gas is mixed with smoke at the outlet of the end of the expansion machine and then used for generating power through the expansion machine, and oxygen-enriched air obtained from the side of the permeated gas provides an oxygen source for the catalytic combustor.|3. The process for preparing the carbon dioxide capture coupling biochar in the flue gas of the coal-fired power plant according to claim 1, which is characterized in that: the system integrates various heat exchangers and a natural gas heating device, fully integrates the requirements of cold quantity and heat quantity in the system, utilizes the cold energy of liquefied natural gas to cool high-purity carbon dioxide gas so as to promote the liquefaction of the carbon dioxide, further provides cold energy for a dehydration link, and improves the separation coefficient of the membrane component to the carbon dioxide while cooling; the carbon dioxide is pressurized to the set pressure, then is liquefied at low temperature, and is pressurized to the pressure required by commercial use through the liquid pump, so that the energy consumption in the process of directly pressurizing air to the pressure required by commercial use is reduced; the cold energy of the low-temperature carbon dioxide liquid is used for cooling the dehydration link, so that the temperature of the dehydration link is increased, and then the temperature is adjusted, so that the energy consumption of the system is reduced; condensed water is used as a dehydration link for cooling and then flows back to the steam heater to be used as a raw material for the anode reaction of the molten carbonate fuel cell, so that the energy utilization efficiency of the system is improved. | (CN107569981)|TECHNICAL FIELD|[0002] The invention relates to the technical field of flue gas treatment and biomass utilization, in particular to a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant.|BACKGROUND ART|[0004] Since the 21 st century, global warming and greenhouse effect have been increasingly promoted, and a large amount of fossil fuel is burned, resulting in an increase in the concentration of carbon dioxide in the atmosphere, which has been over 400ppm at present according to the international department of energy. The contribution rate of carbon dioxide in greenhouse gas reaches about 55%, wherein the carbon dioxide discharged after combustion of a coal-fired power plant accounts for about 40% of the total amount of carbon dioxide, the industrial carbon dioxide discharge accounts for about 25%, and the transportation accounts for about 20%. Bioenergy and carbon capture and storage technology (BECCS) is a very efficient greenhouse gas abatement technology, combining the use of Carbon Capture and Storage (CCS) and biomass, which can create negative carbon emissions, currently owned for practical operation in the united states, canada, and the netherlands, all involving ethanol production processes.|[0005] The current carbon dioxide capture modes of coal-fired power plants are as follows: pre-combustion capture, post-combustion capture and oxygen-enriched combustion. The technologies for trapping after combustion in a coal-fired power plant mainly comprise a solvent absorption method, an adsorption method, a membrane separation method, a low-temperature cryogenic separation method and the like, and at present, the alcohol amine absorption method is most widely applied, but the regeneration temperature of an absorbent is higher, the required energy consumption is higher, and equipment is corroded to a certain degree. The membrane separation method has the advantages of small occupied area, low energy consumption, no phase change and simple and convenient operation, and has wide application prospect, but because the flue gas pressure of a coal-fired power plant is small, the concentration of carbon dioxide in the flue gas is low, a compressor is required to provide a separation effect in actual operation, the energy consumption in the carbon dioxide capturing process is increased, and the method is a main factor which hinders the industrial application of the membrane separation method at present.|[0006] The biochar is a solid product generated by high-temperature thermal cracking of a biological organic material (biomass) in an anoxic or anaerobic environment, the product is rich in carbon elements, the biochar can be used as a raw material in environmental management at present, can be used as an environment improvement material, can be used as a biomass energy utilization mode to realize carbon fixation, reduces atmospheric emission, and can relieve the problem of atmospheric pollution caused by straw combustion in China. The preparation temperature conditions of the biochar have certain difference on the physicochemical properties of the biochar products, and the biochar prepared under different temperature conditions has different optimal utilization ways.|[0007] Some current research combines molten carbonate fuel cells with coal fired power plant flue gas carbon dioxide capture, but not with biomass utilization, and is not in line with the research category of bioenergy and carbon capture and storage technology (BECCS). The existing research technology operates relatively independently, biomass energy utilization and carbon dioxide membrane capture and storage (CCS) technology are rarely combined, and the organic combination of the two technologies can improve the comprehensive utilization of resources and energy and reduce unnecessary waste.|[0008] Therefore, it is necessary to research a process for capturing carbon dioxide in flue gas of a coal-fired power plant by using biological energy and carbon capture and storage technology (BECCS), and integrate low-temperature deep cooling, membrane separation and molten carbonate fuel cell technologies in combination with biochar preparation to reduce the energy consumption and the capturing difficulty of the process.|DISCLOSURE|[0009] Disclosure of Invention|[0010] The invention aims to provide a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant, which effectively integrates the technologies of biochar preparation, gas membrane separation, molten carbonate fuel cells and the like, and can effectively reduce the energy consumption of the carbon dioxide capture process and improve the carbon dioxide emission reduction effect.|[0011] The technical scheme provided by the invention is as follows:|[0012] a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant comprises the following steps:|[0013] the method comprises the following steps of purifying flue gas of a coal-fired power plant by an impurity removal device, mixing the purified flue gas with flue gas obtained by burning natural gas and fresh air according to a certain proportion, pressurizing and heating the mixture, conveying the mixture to a cathode of a molten carbonate fuel cell to perform a reduction reaction, heating the flue gas discharged by the cathode by a catalytic burner, performing expansion power generation, introducing the heated flue gas into a biochar preparation device, and discharging the heated flue gas into the atmosphere after the temperature is reduced to a set value; mixing a molten carbonate fuel cell anode fuel source consisting of natural gas obtained by heating natural gas and liquefied natural gas which utilize finish cooling energy and natural gas from other sources with water vapor, then introducing the mixture into a catalytic reforming reaction device, and then introducing the mixture into a molten carbonate fuel cell anode to perform oxidation reaction; reacting the smoke discharged from the anode with oxygen-enriched air prepared from an oxygen-enriched plate block of the membrane component in a catalytic combustor according to a certain proportion, and introducing the reacted gas into a biochar preparation device; after the temperature of the flue gas is reduced to a set temperature, the flue gas is introduced to next biochar preparation equipment with a lower preparation temperature, and after the temperature is lower than 100 ℃, primary dehydration and drying are realized in a gas-liquid separator through 3 stages of temperature reduction; gas after gas-liquid separation is introduced into a membrane module to separate gas components, the membrane module permeation gas is compressed by a multistage compressor, then is cooled by a heat exchanger in 2 stages, and then is further dehydrated and dried by using a 3A molecular sieve; the dehydrated and dried carbon dioxide gas flow is cooled through an LNG liquefied natural gas heat exchanger, and the gas is cooled to-54 ℃ to become liquid; the liquefied carbon dioxide is pressurized by a hydraulic pump to a pressure required for a set commercial use.|[0014] The membrane component oxygen-enriched plate provides energy for the air compression process by a turbine expansion-compressor through the pressure potential energy of trapped gas in the carbon dioxide membrane separation link, the compressed air is separated from oxygen and nitrogen through the air membrane separation process, the trapped gas is mixed with flue gas at the end outlet of an expander and then is subjected to power generation and pressure reduction to atmospheric pressure through the expander, and oxygen-enriched air in the permeated gas provides an oxygen source for the catalytic combustor.|[0015] The requirements of cold quantity and heat quantity in the system are fully integrated by utilizing the natural gas heating device and the plurality of heat exchangers; the cold energy of liquefied natural gas is utilized to firstly provide cold energy for cooling high-purity carbon dioxide gas to promote liquefaction of the carbon dioxide gas, then the cold energy is continuously provided for a gas-liquid separation link, the separation coefficient of a membrane component to the carbon dioxide is improved while the temperature is reduced, and the natural gas which finishes the cold energy is utilized as the anode fuel of the molten carbonate fuel cell; in the carbon dioxide liquefaction link, a process of pressurization, cooling liquefaction and pressurization is carried out, pressurization is carried out to a set pressure, then low-temperature liquefaction is carried out, and pressurization is carried out to a pressure required by commercial use through a liquid pump, the set pressure meets the requirement that the carbon dioxide is changed into liquid after the temperature of liquefied natural gas is reduced, and the specific value is adjusted according to different concentrations of the carbon dioxide under different operating conditions; the liquefaction process reduces the volume of the required pressurized fluid and reduces the energy consumption required for pressurization; the cold energy of the low-temperature carbon dioxide liquid is utilized to cool the dehydration link, the temperature of the dehydration link is raised while cold energy is provided for the dehydration link, and then the temperature of the liquid carbon dioxide is adjusted to a value required by commercial use, so that the energy consumption required by the system is reduced; condensed water is used for cooling the second dehydration link and then flows back to the water vapor heater to be used as a raw material of the anode of the molten carbonate fuel cell, so that the energy utilization efficiency of the system is improved.|DRAWINGS DESCRIPTION|[0017] The invention will be described in more detail below with reference to the following figures and specific embodiments:|[0018] FIG. 1 is a schematic structural diagram of an implementation of the process for preparing biochar by coupling carbon dioxide capture in flue gas of a coal-fired power plant.|[0019] FIG. 2 is a schematic diagram of the structure of an oxygen-enriched plate of the membrane module.|[0020] FIG. 3 is a schematic structural diagram of a natural gas combustion heating link.|[0021] Fig. 4 is a schematic diagram of the structure of the anode fuel supply link of the molten carbonate fuel cell.|[0022] Reference numerals in the drawings indicate:|[0023] 1. flue gas from coal fired power plants; 2. a flue gas impurity treatment device; 3. 6, 26, 33, gas mixer; 4. a steam heating device; 5. 31, an air compressor; 7. a fuel reforming reaction device; 8. a molten carbonate fuel cell; 9. 32, a natural gas heating device; 10. a catalytic combustor; 11. 28, an expander; 12. 13, a biochar preparation device; 14. 15, 16, 20, 21, 30, heat exchanger; 17. a gas-liquid separator; 18. 27, a membrane module; 19. a multistage compressor; 22. an LNG liquefied natural gas heat exchanger; 23. a liquid pump; 24. a liquefied natural gas source gas storage tank; 25. a turbo-expander-compressor; 29. 3A molecular sieve dehydration device.|INVENTION MODE|[0024] Detailed Description|[0025] In order to better illustrate the prior art solution of the present invention, the following detailed description will be given with reference to the accompanying drawings required in the description of the prior art solution.|[0026] Referring to fig. 1, the preparation process of the carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant comprises the following steps: the molten carbonate fuel cell anode fuel reaches a compressor 5 through S47, reaches a gas mixer 6 through S5 after being pressurized and heated by the compressor, high-temperature steam is conveyed into the gas mixer 6 through S4 by a steam heating device, and the gas reaches a fuel reforming reaction device 7 through S6 after being uniformly mixed; after the alkane in the fuel reacts with the water vapor and is converted into carbon monoxide and hydrogen, the flue gas reaches the anode of the molten carbonate fuel cell 8 through S7, oxidation reaction occurs at the anode to obtain flue gas enriched with carbon dioxide, and then the flue gas reaches the catalytic combustor 10 through S9.|[0027] Flue gas 1 of a coal-fired power plant is treated by a flue gas impurity treatment device 2, and the treated flue gas, fresh air, flue gas discharged from a natural gas heating device and flue gas reach a gas mixer through S1, S2 and S54 according to a certain proportion; the gas is uniformly mixed and then reaches a compressor 31 through S3, the gas is pressurized and heated and then is introduced into a natural gas heating device 9 through S55, the mixed flue gas is heated and then is connected with the cathode of a molten carbonate fuel cell 8 through S56, the mixed gas is heated and then reaches a catalytic combustor 10 through S8 after the cathode reaction is finished, and the heated mixed gas is connected with an expander 11 through S11; the flue gas is expanded to generate power, enters the biochar preparation device 13 through S12, and is discharged through S14.|[0028] Flue gas from the anode of the molten carbonate fuel cell 8 reacts with oxygen-enriched air S45 from an oxygen-enriched plate of a membrane component in the catalytic combustor 10, the flue gas is connected with a biochar preparation device 12 through S10 after the reaction is finished, the temperature of the flue gas is absorbed in the biochar preparation process, the flue gas is connected with a biochar preparation device 13 through S13 when the temperature is reduced to be close to S12, and the flue gas is further cooled and depressurized to a set temperature and then enters a first cooling and dehydrating link.|[0029] The flue gas discharged from the biochar preparation device 13 is sequentially cooled by heat exchangers 14, 15 and 16, and is finally connected with a gas-liquid separator 17 through S24; in the heat exchanger 14, the low-temperature source is provided by the low-temperature water which is heated by the heat exchanger 20 and then is connected with the S17 through the S30 after the water separated from the gas-liquid separator 17; in the heat exchanger 15, the low-temperature source is provided by low-temperature carbon dioxide liquid which is heated by liquid carbon dioxide from the liquid pump 23 through the heat exchanger 21 and then is connected with S19 through S35; in the heat exchanger 16, the low-temperature source is provided by the low-temperature natural gas which is obtained by connecting the liquefied natural gas in the liquefied natural gas storage tank 24 with the LNG liquefied natural gas heat exchanger through S36 and S23 after the liquefied natural gas is heated; liquid water is separated from the gas component in the gas-liquid separator 17.|[0030] The separated liquid water is connected with S32 through S26, heated through the heat exchanger 20, flows out of S30, is connected with S17, is cooled for the heat exchanger 14, is heated, flows out of S16 and returns to the steam heater 4.|[0031] The gas component in the gas-liquid separator 17 is connected with the feed gas of the membrane module 18 through S25; the trapped gas of the membrane module 18 is connected with S27, and the permeated gas is connected with S28; the flue gas in the S25 is separated through the membrane module 18 to obtain a gas component with the carbon dioxide purity higher than 95%, and then the gas component enters a second step of dehydration.|[0032] High-concentration carbon dioxide gas obtained from the permeate gas side of the membrane module 18 is connected with a multistage compressor 19 through S28, and the gas is connected with a heat exchanger 20 through S29 and then connected with a heat exchanger 21 through S31 after being compressed; the gas is cooled for 2 times, then is connected with a 3A molecular sieve dehydration device 29 through S34, and then enters a liquefaction link.|[0033] After the gas is dehydrated, the dehydrated gas reaches the LNG heat exchanger 22 through S48, the dehydrated carbon dioxide gas is cooled through the LNG heat exchanger 22 to obtain carbon dioxide liquid, and then the carbon dioxide liquid is connected with the liquid pump 23 through S37; in the LNG-LNG heat exchanger 22, the low-temperature natural gas from the LNG tank 24 is connected to the LNG-LNG heat exchanger 22 through S38, and after the temperature is raised, the low-temperature natural gas is connected to S23 through S36, and reaches the heat exchanger 16 to be further raised in temperature, and the raised natural gas can be used as anode fuel of molten carbonate fuel.|[0034] After being pressurized to a pressure condition required by a set commercial use in the liquid pump 23, the liquid carbon dioxide is connected with S33 through S39, then is heated in the heat exchanger 21, is connected with S19 through S35 after being heated, is further heated through the heat exchanger 15, and is connected with a product temperature adjusting link through S20 after being heated; to meet the temperature required for many commercial applications and to avoid the difference between the temperature and the set temperature due to the change of the operating conditions, the liquid carbon dioxide in S20 is adjusted to the set temperature by the heat exchanger 30 and finally goes to the commercial application stage by S49.|[0035] Referring to fig. 1, in fig. 2, the oxygen-enriched plate of the membrane module of the present invention comprises:|[0036] air is delivered to the compressor-side inlet of the turboexpander-compressor 25 via S41, compressed and then connected to the feed gas port of the membrane module 27 via S40; the gas-trapping side of the membrane module 27 is connected with S43, and the permeate gas is connected with S45; the retentate gas is connected to the mixer 26 via S43 and the permeate gas provides the oxygen source for the catalytic burner 10 via S45; the trapped gas from the membrane module 18 is connected with an inlet at the expander end of the turbine expansion-compressor 25 through S27, and is connected with the gas mixer 26 through S42 after the expansion pressure is reduced; after the gas is completely mixed, the gas is connected with the expansion machine 28 through S44, and after the pressure of the flue gas is reduced to the atmospheric pressure through the expansion machine 28, the flue gas is discharged through S46.|[0037] Referring to fig. 1, in fig. 3, the heating process using natural gas combustion according to the present invention includes:|[0038] the low-temperature flue gas is connected with a natural gas heating device through S50, and is discharged through S52 after being heated and warmed; the natural gas enters a natural gas heating device through S53, and is discharged through S51 after being combusted; the heat sources of the steam heating device 4, the natural gas heating device 9, the natural gas heating device 32 and the fuel reforming reaction device 7 in the process are all provided by natural gas combustion.|[0039] Referring to fig. 1, in fig. 4, the anode fuel supply segment of the molten carbonate fuel cell according to the present invention includes:|[0040] natural gas from S22 using low-temperature energy is connected with a gas mixer 33, liquefied natural gas is connected with a natural gas heating device 32 through S57, the natural gas is connected with the gas mixer 33 through S58 after being heated, natural gas from other sources is connected with the gas mixer 33 through S59, and the natural gas enters an anode fuel pretreatment link of the molten carbonate fuel cell through S47 after being mixed. | (CN107569981)|TECHNICAL FIELD|[0002] The invention relates to the technical field of flue gas treatment and biomass utilization, in particular to a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant.|BACKGROUND ART|[0004] Since the 21 st century, global warming and greenhouse effect have been increasingly promoted, and a large amount of fossil fuel is burned, resulting in an increase in the concentration of carbon dioxide in the atmosphere, which has been over 400ppm at present according to the international department of energy. The contribution rate of carbon dioxide in greenhouse gas reaches about 55%, wherein the carbon dioxide discharged after combustion of a coal-fired power plant accounts for about 40% of the total amount of carbon dioxide, the industrial carbon dioxide discharge accounts for about 25%, and the transportation accounts for about 20%. Bioenergy and carbon capture and storage technology (BECCS) is a very efficient greenhouse gas abatement technology, combining the use of Carbon Capture and Storage (CCS) and biomass, which can create negative carbon emissions, currently owned for practical operation in the united states, canada, and the netherlands, all involving ethanol production processes.|[0005] The current carbon dioxide capture modes of coal-fired power plants are as follows: pre-combustion capture, post-combustion capture and oxygen-enriched combustion. The technologies for trapping after combustion in a coal-fired power plant mainly comprise a solvent absorption method, an adsorption method, a membrane separation method, a low-temperature cryogenic separation method and the like, and at present, the alcohol amine absorption method is most widely applied, but the regeneration temperature of an absorbent is higher, the required energy consumption is higher, and equipment is corroded to a certain degree. The membrane separation method has the advantages of small occupied area, low energy consumption, no phase change and simple and convenient operation, and has wide application prospect, but because the flue gas pressure of a coal-fired power plant is small, the concentration of carbon dioxide in the flue gas is low, a compressor is required to provide a separation effect in actual operation, the energy consumption in the carbon dioxide capturing process is increased, and the method is a main factor which hinders the industrial application of the membrane separation method at present.|[0006] The biochar is a solid product generated by high-temperature thermal cracking of a biological organic material (biomass) in an anoxic or anaerobic environment, the product is rich in carbon elements, the biochar can be used as a raw material in environmental management at present, can be used as an environment improvement material, can be used as a biomass energy utilization mode to realize carbon fixation, reduces atmospheric emission, and can relieve the problem of atmospheric pollution caused by straw combustion in China. The preparation temperature conditions of the biochar have certain difference on the physicochemical properties of the biochar products, and the biochar prepared under different temperature conditions has different optimal utilization ways.|[0007] Some current research combines molten carbonate fuel cells with coal fired power plant flue gas carbon dioxide capture, but not with biomass utilization, and is not in line with the research category of bioenergy and carbon capture and storage technology (BECCS). The existing research technology operates relatively independently, biomass energy utilization and carbon dioxide membrane capture and storage (CCS) technology are rarely combined, and the organic combination of the two technologies can improve the comprehensive utilization of resources and energy and reduce unnecessary waste.|[0008] Therefore, it is necessary to research a process for capturing carbon dioxide in flue gas of a coal-fired power plant by using biological energy and carbon capture and storage technology (BECCS), and integrate low-temperature deep cooling, membrane separation and molten carbonate fuel cell technologies in combination with biochar preparation to reduce the energy consumption and the capturing difficulty of the process.|DISCLOSURE|[0009] Disclosure of Invention|[0010] The invention aims to provide a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant, which effectively integrates the technologies of biochar preparation, gas membrane separation, molten carbonate fuel cells and the like, and can effectively reduce the energy consumption of the carbon dioxide capture process and improve the carbon dioxide emission reduction effect.|[0011] The technical scheme provided by the invention is as follows:|[0012] a preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant comprises the following steps:|[0013] the method comprises the following steps of purifying flue gas of a coal-fired power plant by an impurity removal device, mixing the purified flue gas with flue gas obtained by burning natural gas and fresh air according to a certain proportion, pressurizing and heating the mixture, conveying the mixture to a cathode of a molten carbonate fuel cell to perform a reduction reaction, heating the flue gas discharged by the cathode by a catalytic burner, performing expansion power generation, introducing the heated flue gas into a biochar preparation device, and discharging the heated flue gas into the atmosphere after the temperature is reduced to a set value; mixing a molten carbonate fuel cell anode fuel source consisting of natural gas obtained by heating natural gas and liquefied natural gas which utilize finish cooling energy and natural gas from other sources with water vapor, then introducing the mixture into a catalytic reforming reaction device, and then introducing the mixture into a molten carbonate fuel cell anode to perform oxidation reaction; reacting the smoke discharged from the anode with oxygen-enriched air prepared from an oxygen-enriched plate block of the membrane component in a catalytic combustor according to a certain proportion, and introducing the reacted gas into a biochar preparation device; after the temperature of the flue gas is reduced to a set temperature, the flue gas is introduced to next biochar preparation equipment with a lower preparation temperature, and after the temperature is lower than 100 ℃, primary dehydration and drying are realized in a gas-liquid separator through 3 stages of temperature reduction; gas after gas-liquid separation is introduced into a membrane module to separate gas components, the membrane module permeation gas is compressed by a multistage compressor, then is cooled by a heat exchanger in 2 stages, and then is further dehydrated and dried by using a 3A molecular sieve; the dehydrated and dried carbon dioxide gas flow is cooled through an LNG liquefied natural gas heat exchanger, and the gas is cooled to-54 ℃ to become liquid; the liquefied carbon dioxide is pressurized by a hydraulic pump to a pressure required for a set commercial use.|[0014] The membrane component oxygen-enriched plate provides energy for the air compression process by a turbine expansion-compressor through the pressure potential energy of trapped gas in the carbon dioxide membrane separation link, the compressed air is separated from oxygen and nitrogen through the air membrane separation process, the trapped gas is mixed with flue gas at the end outlet of an expander and then is subjected to power generation and pressure reduction to atmospheric pressure through the expander, and oxygen-enriched air in the permeated gas provides an oxygen source for the catalytic combustor.|[0015] The requirements of cold quantity and heat quantity in the system are fully integrated by utilizing the natural gas heating device and the plurality of heat exchangers; the cold energy of liquefied natural gas is utilized to firstly provide cold energy for cooling high-purity carbon dioxide gas to promote liquefaction of the carbon dioxide gas, then the cold energy is continuously provided for a gas-liquid separation link, the separation coefficient of a membrane component to the carbon dioxide is improved while the temperature is reduced, and the natural gas which finishes the cold energy is utilized as the anode fuel of the molten carbonate fuel cell; in the carbon dioxide liquefaction link, a process of pressurization, cooling liquefaction and pressurization is carried out, pressurization is carried out to a set pressure, then low-temperature liquefaction is carried out, and pressurization is carried out to a pressure required by commercial use through a liquid pump, the set pressure meets the requirement that the carbon dioxide is changed into liquid after the temperature of liquefied natural gas is reduced, and the specific value is adjusted according to different concentrations of the carbon dioxide under different operating conditions; the liquefaction process reduces the volume of the required pressurized fluid and reduces the energy consumption required for pressurization; the cold energy of the low-temperature carbon dioxide liquid is utilized to cool the dehydration link, the temperature of the dehydration link is raised while cold energy is provided for the dehydration link, and then the temperature of the liquid carbon dioxide is adjusted to a value required by commercial use, so that the energy consumption required by the system is reduced; condensed water is used for cooling the second dehydration link and then flows back to the water vapor heater to be used as a raw material of the anode of the molten carbonate fuel cell, so that the energy utilization efficiency of the system is improved.|DRAWINGS DESCRIPTION|[0017] The invention will be described in more detail below with reference to the following figures and specific embodiments:|[0018] FIG. 1 is a schematic structural diagram of an implementation of the process for preparing biochar by coupling carbon dioxide capture in flue gas of a coal-fired power plant.|[0019] FIG. 2 is a schematic diagram of the structure of an oxygen-enriched plate of the membrane module.|[0020] FIG. 3 is a schematic structural diagram of a natural gas combustion heating link.|[0021] Fig. 4 is a schematic diagram of the structure of the anode fuel supply link of the molten carbonate fuel cell.|[0022] Reference numerals in the drawings indicate:|[0023] 1. flue gas from coal fired power plants; 2. a flue gas impurity treatment device; 3. 6, 26, 33, gas mixer; 4. a steam heating device; 5. 31, an air compressor; 7. a fuel reforming reaction device; 8. a molten carbonate fuel cell; 9. 32, a natural gas heating device; 10. a catalytic combustor; 11. 28, an expander; 12. 13, a biochar preparation device; 14. 15, 16, 20, 21, 30, heat exchanger; 17. a gas-liquid separator; 18. 27, a membrane module; 19. a multistage compressor; 22. an LNG liquefied natural gas heat exchanger; 23. a liquid pump; 24. a liquefied natural gas source gas storage tank; 25. a turbo-expander-compressor; 29. 3A molecular sieve dehydration device.|INVENTION MODE|[0024] Detailed Description|[0025] In order to better illustrate the prior art solution of the present invention, the following detailed description will be given with reference to the accompanying drawings required in the description of the prior art solution.|[0026] Referring to fig. 1, the preparation process of the carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant comprises the following steps: the molten carbonate fuel cell anode fuel reaches a compressor 5 through S47, reaches a gas mixer 6 through S5 after being pressurized and heated by the compressor, high-temperature steam is conveyed into the gas mixer 6 through S4 by a steam heating device, and the gas reaches a fuel reforming reaction device 7 through S6 after being uniformly mixed; after the alkane in the fuel reacts with the water vapor and is converted into carbon monoxide and hydrogen, the flue gas reaches the anode of the molten carbonate fuel cell 8 through S7, oxidation reaction occurs at the anode to obtain flue gas enriched with carbon dioxide, and then the flue gas reaches the catalytic combustor 10 through S9.|[0027] Flue gas 1 of a coal-fired power plant is treated by a flue gas impurity treatment device 2, and the treated flue gas, fresh air, flue gas discharged from a natural gas heating device and flue gas reach a gas mixer through S1, S2 and S54 according to a certain proportion; the gas is uniformly mixed and then reaches a compressor 31 through S3, the gas is pressurized and heated and then is introduced into a natural gas heating device 9 through S55, the mixed flue gas is heated and then is connected with the cathode of a molten carbonate fuel cell 8 through S56, the mixed gas is heated and then reaches a catalytic combustor 10 through S8 after the cathode reaction is finished, and the heated mixed gas is connected with an expander 11 through S11; the flue gas is expanded to generate power, enters the biochar preparation device 13 through S12, and is discharged through S14.|[0028] Flue gas from the anode of the molten carbonate fuel cell 8 reacts with oxygen-enriched air S45 from an oxygen-enriched plate of a membrane component in the catalytic combustor 10, the flue gas is connected with a biochar preparation device 12 through S10 after the reaction is finished, the temperature of the flue gas is absorbed in the biochar preparation process, the flue gas is connected with a biochar preparation device 13 through S13 when the temperature is reduced to be close to S12, and the flue gas is further cooled and depressurized to a set temperature and then enters a first cooling and dehydrating link.|[0029] The flue gas discharged from the biochar preparation device 13 is sequentially cooled by heat exchangers 14, 15 and 16, and is finally connected with a gas-liquid separator 17 through S24; in the heat exchanger 14, the low-temperature source is provided by the low-temperature water which is heated by the heat exchanger 20 and then is connected with the S17 through the S30 after the water separated from the gas-liquid separator 17; in the heat exchanger 15, the low-temperature source is provided by low-temperature carbon dioxide liquid which is heated by liquid carbon dioxide from the liquid pump 23 through the heat exchanger 21 and then is connected with S19 through S35; in the heat exchanger 16, the low-temperature source is provided by the low-temperature natural gas which is obtained by connecting the liquefied natural gas in the liquefied natural gas storage tank 24 with the LNG liquefied natural gas heat exchanger through S36 and S23 after the liquefied natural gas is heated; liquid water is separated from the gas component in the gas-liquid separator 17.|[0030] The separated liquid water is connected with S32 through S26, heated through the heat exchanger 20, flows out of S30, is connected with S17, is cooled for the heat exchanger 14, is heated, flows out of S16 and returns to the steam heater 4.|[0031] The gas component in the gas-liquid separator 17 is connected with the feed gas of the membrane module 18 through S25; the trapped gas of the membrane module 18 is connected with S27, and the permeated gas is connected with S28; the flue gas in the S25 is separated through the membrane module 18 to obtain a gas component with the carbon dioxide purity higher than 95%, and then the gas component enters a second step of dehydration.|[0032] High-concentration carbon dioxide gas obtained from the permeate gas side of the membrane module 18 is connected with a multistage compressor 19 through S28, and the gas is connected with a heat exchanger 20 through S29 and then connected with a heat exchanger 21 through S31 after being compressed; the gas is cooled for 2 times, then is connected with a 3A molecular sieve dehydration device 29 through S34, and then enters a liquefaction link.|[0033] After the gas is dehydrated, the dehydrated gas reaches the LNG heat exchanger 22 through S48, the dehydrated carbon dioxide gas is cooled through the LNG heat exchanger 22 to obtain carbon dioxide liquid, and then the carbon dioxide liquid is connected with the liquid pump 23 through S37; in the LNG-LNG heat exchanger 22, the low-temperature natural gas from the LNG tank 24 is connected to the LNG-LNG heat exchanger 22 through S38, and after the temperature is raised, the low-temperature natural gas is connected to S23 through S36, and reaches the heat exchanger 16 to be further raised in temperature, and the raised natural gas can be used as anode fuel of molten carbonate fuel.|[0034] After being pressurized to a pressure condition required by a set commercial use in the liquid pump 23, the liquid carbon dioxide is connected with S33 through S39, then is heated in the heat exchanger 21, is connected with S19 through S35 after being heated, is further heated through the heat exchanger 15, and is connected with a product temperature adjusting link through S20 after being heated; to meet the temperature required for many commercial applications and to avoid the difference between the temperature and the set temperature due to the change of the operating conditions, the liquid carbon dioxide in S20 is adjusted to the set temperature by the heat exchanger 30 and finally goes to the commercial application stage by S49.|[0035] Referring to fig. 1, in fig. 2, the oxygen-enriched plate of the membrane module of the present invention comprises:|[0036] air is delivered to the compressor-side inlet of the turboexpander-compressor 25 via S41, compressed and then connected to the feed gas port of the membrane module 27 via S40; the gas-trapping side of the membrane module 27 is connected with S43, and the permeate gas is connected with S45; the retentate gas is connected to the mixer 26 via S43 and the permeate gas provides the oxygen source for the catalytic burner 10 via S45; the trapped gas from the membrane module 18 is connected with an inlet at the expander end of the turbine expansion-compressor 25 through S27, and is connected with the gas mixer 26 through S42 after the expansion pressure is reduced; after the gas is completely mixed, the gas is connected with the expansion machine 28 through S44, and after the pressure of the flue gas is reduced to the atmospheric pressure through the expansion machine 28, the flue gas is discharged through S46.|[0037] Referring to fig. 1, in fig. 3, the heating process using natural gas combustion according to the present invention includes:|[0038] the low-temperature flue gas is connected with a natural gas heating device through S50, and is discharged through S52 after being heated and warmed; the natural gas enters a natural gas heating device through S53, and is discharged through S51 after being combusted; the heat sources of the steam heating device 4, the natural gas heating device 9, the natural gas heating device 32 and the fuel reforming reaction device 7 in the process are all provided by natural gas combustion.|[0039] Referring to fig. 1, in fig. 4, the anode fuel supply segment of the molten carbonate fuel cell according to the present invention includes:|[0040] natural gas from S22 using low-temperature energy is connected with a gas mixer 33, liquefied natural gas is connected with a natural gas heating device 32 through S57, the natural gas is connected with the gas mixer 33 through S58 after being heated, natural gas from other sources is connected with the gas mixer 33 through S59, and the natural gas enters an anode fuel pretreatment link of the molten carbonate fuel cell through S47 after being mixed. | Family Number|(78459841)|78459841|Advantages / Prev. Drawbacks|(CN107569981 A)|Therefore , it is necessary to research a process for capturing carbon dioxide in flue gas of a coal - fired power plant by using biological energy and carbon capture and storage technology ( BECCS ) , and integrate low - temperature deep cooling , membrane separation and molten carbonate fuel cell technologies in combination with biochar preparation to reduce the energy consumption and the capturing difficulty of the process . | | Environmental technology|Materials, metallurgy | Y02C-020/40|Y02P-020/10|Y02P-020/151 | Y02C-020/40|Y02P-020/10|Y02P-020/151 | B01D-053/22|B01D-053/26|B01D-053/32|C01B-032/05|C01B-032/50|C01B-032/55 | B01D-053/22|B01D-053/26|B01D-053/32|C01B-032/05|C01B-032/50|C01B-032/55 | CN116328510|CN116136213|CN115614761B|US20220203297|CN113140766B | CN116328510 103518653 WHO=Examiner SELF=N CAT=A|CN116136213 105007326 WHO=Examiner SELF=N CAT=A|CN115614761B 103505076 WHO=Examiner SELF=N|US20220203297 91335021 WHO=Examiner SELF=N|CN113140766B 95262940 WHO=Examiner SELF=N | CN107081045|CN104847424|CN106948888|CN106693842|CN106554831|CN106401749|CN205863298U|US20160251218|CN104919636|CN103628982|CN102660341|US20100266923|CN201244430U|US20020134236 | CN107081045 77045072 WHO=Examiner SELF=N CAT=Y CAT=A|CN104847424 70568819 WHO=Examiner SELF=N CAT=Y CAT=A|CN106948888 76772163 WHO=Examiner SELF=N CAT=A|CN106693842 76213134 WHO=Examiner SELF=N CAT=A|CN106554831 75814248 WHO=Examiner SELF=N CAT=A|CN106401749 75420295 WHO=Examiner SELF=N CAT=A|CN205863298U 75099766 WHO=Examiner SELF=N CAT=A|US20160251218 68723804 WHO=Examiner SELF=N CAT=A|CN104919636 67377833 WHO=Examiner SELF=N CAT=A|CN103628982 64945068 WHO=Examiner SELF=N CAT=A|CN102660341 7880824 WHO=Examiner SELF=N CAT=A|US20100266923 44295775 WHO=Examiner SELF=N CAT=A|CN201244430U 8460980 WHO=Examiner SELF=N CAT=A|US20020134236 43329326 WHO=Examiner SELF=N CAT=A | 王湛等: "《膜分离技术基础 第二版》", 31 August 2006, 化学工业出版社 (Cat. A) | US20020134236; CN201244430U; US20100266923; CN102660341; CN103628982; CN104919636; US20160251218; CN205863298U; CN106401749; CN106554831; CN106693842; CN106948888; CN104847424; CN107081045 | LAPSED | (CN107569981)|LAPSED | DEAD | (CN107569981)|DEAD | (CN107569981)|LEGAL DETAILS FOR CN107569981|Actual or expected expiration date=2021-02-23|Legal state=DEAD|Status=LAPSED|Event publication date=2017-10-11|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN201710943918|Application date=2017-10-11|Standardized application number=2017CN-0943918|Event publication date=2018-01-12|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN107569981|Publication stage code=A|Publication date=2018-01-12|Standardized publication number=CN107569981|Event publication date=2018-01-12|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2018-02-06|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|Event publication date=2021-02-23|Event code=CN/WD01|Event indicator=Neg|Event group=Event indicating Not In Force|Patent application deemed withdrawn after publication | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=tO7C931onjnyUOPXo/7jwlfn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000017264822&ekey=2021&xpn=CN107569981&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=5ba0Oqh08duKgsckjxineJNXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN107569981)|NAME=YANG ZHENGSHAN | (CN107569981)|4 | 1 | 1 | (CN107569981)|Number of Claims: NCL=3|Gazette date: GAZDATE=2018-01-12|Gazette number: GAZNUM=34-0202|Number of Pages: NPAGES=7| | (CN107569981)|CHINESE (CHI) | (CN107569981)|Patent | Titre: (CN107569981)|Preparation technology of charcoal for coupling with flue gas carbon dioxide catching in coal-fired power plant Résumé: (CN107569981)|The invention discloses a preparation technology of charcoal for coupling with flue gas carbon dioxide catching in a coal-fired power plant. The technology is integrated with the techniques of charcoal preparation, gas membrane separation, carbonic acid molten salt fuel cells, and the like; the liquified natural gas is used for cooling the system in stages and then is used as an anode fuel of molten carbonate fuel cell; the enrichment for carbon dioxide is realized in the power generating process through the molten carbonate fuel cell; after the exhaust gas emitted from the anode is dewatered,a membrane component is used for separating carbon dioxide from the other gases and the trapping gas is utilized to supply energy to the oxygen enriching block of the membrane component; a pressurizing-cooling-pressurizing process is adopted in the carbon dioxide liquifying process and the total energy consumption in the liquifying process is reduced; the requirements for heat and cold energy inall the processes of the technology are effectively integrated through a heat exchanger and a natural gas heating device; in the charcoal preparation process, the heat of the gas emitted from the anode and cathode of the molten carbonate fuel cell under different temperatures is utilized to fix carbon and meanwhile the energy utilization efficiency of the system is increased. Autre: (CN107569981)|1. A preparation process of carbon dioxide capture coupling biochar in flue gas of a coal-fired power plant is characterized by comprising the following steps: integrates the technologies of biochar preparation, gas membrane separation, low-temperature liquefaction, molten carbonate fuel cells and the like; mixing a molten carbonate fuel cell anode fuel source consisting of natural gas obtained by heating natural gas and liquefied natural gas which utilize finish cooling energy and natural gas from other sources with water vapor, carrying out catalytic reforming, and introducing the mixture into a molten carbonate fuel cell anode to carry out oxidation reaction; the flue gas of the coal-fired power plant is purified by an impurity removal device, then is mixed with the flue gas obtained by burning natural gas and fresh air according to a certain proportion, and is subjected to pressurization and heating to react at the cathode of a molten carbonate fuel cell; reacting flue gas discharged from an anode with oxygen-enriched air prepared from an oxygen-enriched plate block of a membrane component in a catalytic combustor according to a certain proportion, then introducing the reaction product into a biochar preparation device, cooling to a set temperature, introducing the reaction product into the biochar preparation device with a lower preparation temperature, performing staged cooling when the temperature is lower than 100 ℃ to realize primary separation of moisture in the flue gas, introducing gas after gas-liquid separation into the membrane component to perform gas component separation, compressing the gas by a multistage compressor, performing 2-stage cooling by a heat exchanger, further dehydrating and drying by using a 3A molecular sieve, cooling the gas to-54 ℃ by using an LNG (liquefied natural gas) heat exchanger to obtain liquid, and then pressurizing to a pressure required by set commercial use by a hydraulic pump; the flue gas discharged from the cathode of the molten carbonate fuel cell is heated by a catalytic burner, expanded to generate power, introduced into the biochar preparation equipment, and discharged into the atmosphere after being cooled to a certain temperature.|2. The process for preparing the carbon dioxide capture coupling biochar in the flue gas of the coal-fired power plant according to claim 1, which is characterized in that: the membrane component oxygen enrichment module integrates pressure potential energy of gas intercepted by the smoke component separation membrane component through the turbine expansion-compressor to provide power for compressed air, the compressed air is used for separating oxygen and nitrogen through the membrane component, the intercepted gas is mixed with smoke at the outlet of the end of the expansion machine and then used for generating power through the expansion machine, and oxygen-enriched air obtained from the side of the permeated gas provides an oxygen source for the catalytic combustor.|3. The process for preparing the carbon dioxide capture coupling biochar in the flue gas of the coal-fired power plant according to claim 1, which is characterized in that: the system integrates various heat exchangers and a natural gas heating device, fully integrates the requirements of cold quantity and heat quantity in the system, utilizes the cold energy of liquefied natural gas to cool high-purity carbon dioxide gas so as to promote the liquefaction of the carbon dioxide, further provides cold energy for a dehydration link, and improves the separation coefficient of the membrane component to the carbon dioxide while cooling; the carbon dioxide is pressurized to the set pressure, then is liquefied at low temperature, and is pressurized to the pressure required by commercial use through the liquid pump, so that the energy consumption in the process of directly pressurizing air to the pressure required by commercial use is reduced; the cold energy of the low-temperature carbon dioxide liquid is used for cooling the dehydration link, so that the temperature of the dehydration link is increased, and then the temperature is adjusted, so that the energy consumption of the system is reduced; condensed water is used as a dehydration link for cooling and then flows back to the steam heater to be used as a raw material for the anode reaction of the molten carbonate fuel cell, so that the energy utilization efficiency of the system is improved. | 30 | Abstract | gpt-4o-mini | no | The article focuses on charcoal preparation and CO₂ capture in a coal-fired power plant, which does not involve biomass energy production or the integration of biomass with carbon capture and storage. | |||||||||||||||||||||||||
| 31 | CN201711055664 | CN201711055664 | CN107758664 | 78971083 | CN107758664 A 2018-03-06 [CN107758664] | 2017-11-01 | 2017-11-01 | 2018-03-06 | (CN107758664)|2020-10-13 | (CN107758664)|Process for capturing rubbish landfill gas carbon dioxide | (CN107758664)|The invention discloses a process for capturing rubbish landfill gas carbon dioxide. The process combines technologies of gas membrane separation, low temperature liquidation and the like, and a landfill gas decarburization oxygen enrichment section and a carbon dioxide capturing section after landfill gas combustion are effectively integrated; liquefied natural gas is used as a fuel in the landfill gas combustion process after cooling in stages of the system, so that the concentration and calorific value of landfill gas methane component are increased; oxygen-enriched air is used as purging gas of landfill gas decarburization oxygen enrichment membrane component, so that the oxygen content in the mixed gas after entrapment gas in a carbon dioxide capturing and backflow link is mixed withosmotic gas of a third-level membrane component is increased, a nitrogen component in flue gas after landfill gas is combusted is effectively reduced, and the energy consumption of the carbon oxide capturing section after landfill gas combustion is reduced; in the membrane component oxygen enrichment section, the pressure of feeding gas is increased by utilizing energy provided by a compressing turbine expander in the two sections; the requirements of each link for heat energy and cold energy in the process are integrated effectively by a heat exchanger, and the energy utilization rate is increased. | YANG ZHENGSHAN | (CN107758664)|YANG ZHENGSHAN | YANG ZHENGSHAN | (CN107758664)|YANG ZHENGSHAN | (CN107758664)|The membrane separation method has the advantages of small occupied area, low energy consumption, no phase change and simple and convenient operation, and has wide application prospect; the hybrid capture technology improves the comprehensive utilization of resources and energy by combining different capture technologies, can effectively make up the defects of a single technology, and is beneficial to promoting the development of biological energy and carbon capture and storage technology (BECCS). Therefore, it is necessary to research a mixed capturing technology to capture carbon dioxide in landfill gas, reduce the energy consumption and capturing difficulty of the process, improve the concentration and calorific value of methane components in the landfill gas, improve the utilization value of the landfill gas of the refuse landfill in a close or closed state, improve the service cycle of the landfill, and reduce the emission of greenhouse gases.| | (CN107758664)|1. A landfill gas carbon dioxide capture process is characterized in that: the technology of gas membrane separation, low-temperature liquefaction and the like is combined, and the landfill gas decarbonization oxygen-rich plate and the carbon dioxide capture plate after the landfill gas is combusted are effectively integrated together; in the landfill gas decarburization oxygen-enriched block, the landfill gas is subjected to purification treatment and then subjected to decarburization and oxygen enrichment through a countercurrent membrane module to obtain the landfill gas with higher methane equivalent concentration for combustion power generation, and purge gas is provided by air or oxygen-enriched air; the permeate gas is discharged from a permeate gas side of a countercurrent membrane component, is compressed by a compressor and then is cooled in stages, and then is separated from other gas components by a three-stage membrane separation link, the permeate gas of a first-stage membrane component and the permeate gas of a second-stage membrane component are mixed and then are introduced into the low-temperature cryogenic separation link, the permeate gas of the third-stage membrane component and the retentate gas of the membrane component after the low-temperature cryogenic separation are mixed and then are used as one of oxygen sources in the combustion process of landfill gas, the retentate gas of the first-stage membrane component and the retentate gas of the second-stage membrane component are respectively captured by the second-stage membrane component and the third-stage membrane component, the energy of the retentate gas of the third-stage membrane component is recovered and then discharged, the permeate gas is compressed by the multi-stage compressor and then is cooled in stages in the low-temperature cryogenic separation link, carrying out second liquefaction and separation, mixing the carbon dioxide liquid obtained by the two times of liquefaction, introducing the mixed liquid into a low-temperature liquid pump, increasing the pressure to the pressure required by commercial use, and cooling the system by utilizing the low-temperature energy of the system through a heat exchanger; the method comprises the steps that a carbon dioxide trapping block is formed after landfill gas is combusted, after two-stage cooling is conducted on combusted flue gas, gas-liquid separation and preliminary dehydration drying are conducted, gas components are separated through a membrane module, trapped gas energy is recovered and then discharged, the permeated gas and the permeated gas in the membrane module after low-temperature deep cooling are uniformly mixed and then enter a low-temperature deep cooling separation link, after pressurization of a multi-stage compressor, the two-stage cooling is conducted firstly, then, further dehydration drying is conducted through a molecular sieve, then, liquefaction of carbon dioxide is achieved through cold energy of liquefied natural gas, after gas-liquid separation, carbon dioxide liquid passes through a low-temperature liquid pump, the gas components are further trapped through the membrane module, and the trapped gas energy is recovered and then discharged; in the decarbonization and oxygen enrichment link of the landfill gas and after the landfill gas is combusted, the carbon dioxide capture block utilizes natural gas with cold energy as a supplementary component of methane in the landfill gas to be combusted together with the landfill gas.| | (CN107758664)|The invention aims to provide a landfill gas carbon dioxide capture process, which combines gas membrane separation and low-temperature liquefaction technologies, effectively integrates a landfill gas decarburization oxygen-rich plate and a carbon dioxide capture plate after combustion of landfill gas, and improves the greenhouse gas emission reduction effect.|The invention discloses a carbon dioxide trapping process for landfill gas, which combines the technologies of gas membrane separation, low-temperature liquefaction and the like, and effectively integrates a landfill gas decarburization oxygen-rich plate and a carbon dioxide trapping plate after the landfill gas is combusted; liquefied natural gas is used as fuel in the combustion process of landfill gas after the system is cooled by stages, and the concentration and the heat value of methane components in the landfill gas are improved; oxygen-enriched air is used as the purge gas of the landfill gas decarburization oxygen-enriched membrane module, so that the oxygen content in the gas after the trapped gas in the carbon dioxide trapping reflux link and the permeated gas of the third-stage membrane module are mixed is improved, the nitrogen component in the flue gas after the landfill gas is combusted can be effectively reduced, and the energy consumption of the carbon dioxide trapping plate block after the landfill gas is combusted is reduced; in the membrane component oxygen enrichment link, the pressure of the feed gas is increased by utilizing the energy provided by the compression turboexpander in the two plates; the heat exchanger effectively integrates the requirements of each link in the process on heat and cold energy, and improves the energy utilization efficiency. Technical Field The invention relates to the technical field of carbon dioxide capture and recovery, in particular to a carbon dioxide capture process for a landfill gas.|The invention relates to a landfill gas carbon dioxide capture process, which comprises a landfill gas decarburization oxygen-rich block, a landfill gas combustion link and a flue gas carbon dioxide capture block after combustion of landfill gas; in order to better illustrate the prior art solution of the present invention, the following detailed description will be given with reference to the accompanying drawings required in the description of the prior art solution.| | (CN107758664)|LANDFILL GAS(100,56)|LANDFILL GAS METHANEDIONE(100,5)|CAPTURE(100,1)|METHANEDIONE CAPTURE(100,1)|MULTISTAGE COMPRESSOR PRESSURIZATION(100,1)|METHANEDIONE TRAPPING REFLUX LINK(85,4)|METHANEDIONE LIQUEFACTION(81,1)|STAGE MEMBRANE COMPONENT(71,10)|COUNTERCURRENT MEMBRANE MODULE(69,1)|PRELIMINARY DEHYDRATION DRYING(68,1)|RETENTATE GAS(66,6)|MEMBRANE MODULE(64,40)|LANDFILL GAS DECARBURIZATION(63,15)|GAS PERMEATION(60,4)|OXYGEN ENRICHMENT(58,10)|MULTISTAGE COMPRESSOR(58,9)|STAGE MEMBRANE MODULE(56,13)|TRAPPING REFLUX LINK(54,4)|METHANEDIONE TRAPPING PLATE(54,3)|METHANEDIONE TRAPPING BACKFLOW LINK(52,2)|DEHYDRATION DRYING(52,1)|SEPARATION LINK(51,21)|ENRICHMENT LINK(51,8)|METHANEDIONE CAPTURE PLATE(50,1)|MEMBRANE MODULE DECARBURIZATION(49,5)|METHANEDIONE TRAPPING BLOCK(49,3)|OXYGEN ENRICHED MEMBRANE MODULE(47,1)|COMPRESSION TURBO EXPANDER(46,6)|RETENTATE GAS ENERGY(40,1)|COLD ENERGY(39,10)|COMPRESSION TURBINE EXPANDER(39,6)|ENERGY UTILIZATION(39,1)|MEMBRANE SEPARATION LINK(37,18)|MEMBRANE COMPONENT RETENTATE GAS(37,1)|COMPRESSOR(36,20)|LANDFILL GAS DECARBONIZATION(36,2)|METHANEDIONE CAPTURE BLOCK(36,2)|METHANEDIONE TRAPPING(36,1)|PURIFICATION TREATMENT(36,1)|METHANE COMPONENT(35,8)|TRAPPED GAS(34,18)|METHANEDIONE LIQUID(34,11)|OXYGEN ENRICHED AIR(32,19)|PRESSURIZATION COOLING DEHYDRATION LINK(32,2)|METHANEDIONE LIQUID PASS(32,1)|COMBUSTION(31,8)|COUNTERCURRENT MEMBRANE COMPONENT(31,3)|MEMBRANE COMPONENT OXYGEN(31,3)|GAS MEMBRANE SEPARATION(31,2)|OXYGEN CONTENT(31,1)|TRAPPED GAS ENERGY(31,1)|LANDFILL GAS COMBUSTION(30,13)|PURGE GAS(29,4)|DECARBONIZATION(28,2)|NITROGEN SEPARATION COEFFICIENT(27,4)|TRAPPING PLATE(27,4)|PERMEATION GAS(26,10)|METHANEDIONE TRAPPING PLATE BLOCK(26,6)|TRAPPING BLOCK(26,3)|CAPTURE PLATE(26,1)|PRESSURIZING(25,7)|DECARBURIZATION(24,3)|OXYGEN RICH PLATE(24,3)|MEMBRANE COMPONENT(23,5)|LIQUEFACTION(23,4)|MEMBRANE MODULE TRAPPED GAS(23,2)|COMPRESSOR COOLING(21,2)|EXPANDER ENERGY(21,2)|REFLUXING LINK(21,2)|MIXED LIQUID(21,1)|GAS COMPONENT(20,16)|GAS ENERGY(20,1)|TRAPPING(20,1)|METHANE EQUIVALENT CONCENTRATION(19,2)|NITROGEN COMPONENT(19,2)|STAGE MEMBRANE SEPARATION LINK(18,4)|AIR SURPLUS COEFFICIENT(18,2)|FLUE GAS DENITRATION TREATMENT(18,2)|LNG HEAT EXCHANGER(17,14)|METHANE EMISSION(17,9)|OXYGEN SOURCE(17,5)|PURGE GAS INLET(17,2)|LIQUID PASS(17,1)|FLUE GAS(16,39)|LIQUEFIED NATURAL GAS(16,21)|OXYGEN ENRICHED LINK(15,2)|OXYGEN ENRICHMENT BLOCK(15,2)|HEAT EXCHANGER(14,65)|CAPTURE BLOCK(14,6)|OXYGEN ENRICHED BLOCK(14,3)|COMPRESSOR TURBO EXPANDER(14,2)|COOLING CIRCULATION(14,2)|LOW TEMPERATURE LIQUEFACTION(14,2)|LIQUEFACTION TIME(14,1)|TRAPPING PLATE BLOCK(13,6)|LARGE METHANEDIONE SEPARATION COEFFICIENT(13,2)|FEED GAS(12,10)|MOLECULAR SIEVE(12,7)|ENERGY CONSUMPTION(12,2)|METHANE COMPONENT HEAT VALUE(12,1)|GAS LIQUID SEPARATION(11,7)|BLOWER(11,2)|MEMBRANE MATERIAL(10,4)|OXYGEN ENRICHED PLATE(10,2)|METHANEDIONE CAPTURING REFLUX LINK(10,1)|URBAN DOMESTIC GARBAGE(10,1)|LARGE OXYGEN(9,4)|COMMERCIAL AIR SEPARATION MEMBRANE(9,2)|EQUIVALENT CONCENTRATION(9,2)|GAS COMPONENT SITUATION(9,2)|NATURAL GAS(8,9)|FLUE GAS METHANEDIONE(8,4)|MEMBRANE RETENTATE GAS(8,2)|STEP EXPANSION(8,2)|ABSORBENT VOLATILIZATION(8,1)|METHANE GLOBAL EMISSION(8,1)|METHANEDIONE CONTRIBUTION(8,1)|SUPERCRITICAL METHANEDIONE FLUID(8,1)|TRAPPING METHANEDIONE(8,1)|PRELIMINARY EXPANSION(7,2)|ANAEROBIC FERMENTATION(7,1)|HEAT VALUE(7,1)|MEMBRANE MODULE OXYGEN ENRICHMENT(7,1)|LOW TEMPERATURE ENERGY(6,46)|GAS LIQUID SEPARATOR(6,11)|LOW TEMPERATURE CRYOGENIC SEPARATION(6,5)|LIQUID MIXER(6,4)|GARBAGE LANDFILL GAS COMBUSTION(6,1)|HYDROXYLAMINE ABSORPTION(6,1)|LANDFILL GAS COMBUSTION METHANEDIONE(6,1)|LANDFILL GAS DECARBURIZATION REQUIREMENT(6,1)|METHANE CONTRIBUTION(6,1)|METHANE TON(6,1)|METHANEDIONE INFLUENCE(6,1)|PRELIMINARY DEHYDRATION(6,1)|VACUUM PUMP(5,9)|COMPRESSOR END(5,3)|FLUE GAS PURIFICATION(5,3)|PRESSURE VALUE(5,2)|SYSTEM CIRCULATION(5,2)|BLOCK COUNTERCURRENT MEMBRANE MODULE(5,1)|GREENHOUSE GAS ABATEMENT(5,1)|INTERNATIONALLY RECOGNIZED CONDITION(5,1)|METHANE INFLUENCE(5,1)|METHANEDIONE EQUIVALENT(5,1)|METHANEDIONE MEMBRANE COMPONENT(5,1)|NATURAL BYPRODUCT(5,1)|LOW TEMPERATURE LIQUID PUMP(4,5)|SEPARATION(4,4)|GASEOUS COMPONENT(4,2)|LOW TEMPERATURE DEEP COOLING(4,2)|MUNICIPAL SOLID WASTE LANDFILL(4,2)|SWEEP GAS(4,2)|TEMPERATURE RISE(4,2)|AGGRAVATION(4,1)|CRYOGENIC LIQUID PUMP(4,1)|EXPANDER GAS(4,1)|GLOBAL WARMING INFLUENCE(4,1)|HEATED LIQUID METHANEDIONE(4,1)|INTERGOVERNMENT CLIMATE CHANGE COMMITTEE(4,1)|LANDFILL GAS PURIFICATION(4,1)|MEMBRANE MODULE GAS(4,1)|PRELIMINARY COOLING(4,1)|SOLVENT ABSORPTION(4,1)| | (CN107758664)|1. A landfill gas carbon dioxide capture process is characterized in that: the technology of gas membrane separation, low-temperature liquefaction and the like is combined, and the landfill gas decarbonization oxygen-rich plate and the carbon dioxide capture plate after the landfill gas is combusted are effectively integrated together; in the landfill gas decarburization oxygen-enriched block, the landfill gas is subjected to purification treatment and then subjected to decarburization and oxygen enrichment through a countercurrent membrane module to obtain the landfill gas with higher methane equivalent concentration for combustion power generation, and purge gas is provided by air or oxygen-enriched air; the permeate gas is discharged from a permeate gas side of a countercurrent membrane component, is compressed by a compressor and then is cooled in stages, and then is separated from other gas components by a three-stage membrane separation link, the permeate gas of a first-stage membrane component and the permeate gas of a second-stage membrane component are mixed and then are introduced into the low-temperature cryogenic separation link, the permeate gas of the third-stage membrane component and the retentate gas of the membrane component after the low-temperature cryogenic separation are mixed and then are used as one of oxygen sources in the combustion process of landfill gas, the retentate gas of the first-stage membrane component and the retentate gas of the second-stage membrane component are respectively captured by the second-stage membrane component and the third-stage membrane component, the energy of the retentate gas of the third-stage membrane component is recovered and then discharged, the permeate gas is compressed by the multi-stage compressor and then is cooled in stages in the low-temperature cryogenic separation link, carrying out second liquefaction and separation, mixing the carbon dioxide liquid obtained by the two times of liquefaction, introducing the mixed liquid into a low-temperature liquid pump, increasing the pressure to the pressure required by commercial use, and cooling the system by utilizing the low-temperature energy of the system through a heat exchanger; the method comprises the steps that a carbon dioxide trapping block is formed after landfill gas is combusted, after two-stage cooling is conducted on combusted flue gas, gas-liquid separation and preliminary dehydration drying are conducted, gas components are separated through a membrane module, trapped gas energy is recovered and then discharged, the permeated gas and the permeated gas in the membrane module after low-temperature deep cooling are uniformly mixed and then enter a low-temperature deep cooling separation link, after pressurization of a multi-stage compressor, the two-stage cooling is conducted firstly, then, further dehydration drying is conducted through a molecular sieve, then, liquefaction of carbon dioxide is achieved through cold energy of liquefied natural gas, after gas-liquid separation, carbon dioxide liquid passes through a low-temperature liquid pump, the gas components are further trapped through the membrane module, and the trapped gas energy is recovered and then discharged; in the decarbonization and oxygen enrichment link of the landfill gas and after the landfill gas is combusted, the carbon dioxide capture block utilizes natural gas with cold energy as a supplementary component of methane in the landfill gas to be combusted together with the landfill gas.|2. The landfill gas carbon dioxide capture process of claim 1, wherein: the landfill gas decarburization oxygen enrichment block can be divided into a membrane module decarburization oxygen enrichment link, a three-stage membrane separation link, a two-step low-temperature cryogenic separation link, a carbon dioxide capture reflux link and a membrane module oxygen enrichment link; in the membrane module decarburization oxygen enrichment link, landfill gas firstly passes through a purification device, the purge gas utilizes oxygen-enriched air in the membrane module oxygen enrichment link, according to the actual gas component situation, when the oxygen-enriched air is insufficient, air can be directly blown into a purge gas inlet of the membrane module through a blower, when the oxygen-enriched air is left, an oxygen source is provided for the landfill gas combustion link, and meanwhile, the amount of the oxygen-enriched air can be controlled by adjusting the pressure value range of a compressor port of a compression turbine expander; in the third-stage membrane separation link, the first and second-stage membrane modules use membrane materials with larger carbon dioxide separation coefficient, the third-stage membrane module uses a commercial air separation membrane, the membrane materials with larger oxygen and nitrogen separation coefficient capture the trapped gas of the first and second-stage membrane modules respectively, the trapped gas of the third-stage membrane module provides low-temperature energy for the second-stage cooling of the compressor after being recovered by the energy of the expander, and then the system circulating water can be continuously cooled or directly discharged through the heat exchanger; in the two-step low-temperature cryogenic separation link, the liquefied natural gas provides cold energy through an LNG heat exchanger, the liquefied natural gas is uniformly mixed and then cooled for the first-stage membrane module permeation gas in the three-stage membrane separation link, then the low-temperature energy is continuously provided for the first-stage cooling of a compressor, and then the low-temperature energy is used as fuel for the landfill gas combustion link to improve the concentration of methane components in the landfill gas; in the two-step low-temperature cryogenic separation link, the low-temperature energy of the carbon dioxide liquid is utilized to firstly cool the flue gas after the pressurization and the temperature rise in the second-step low-temperature cryogenic separation process and then provide the low-temperature energy for the second-step cooling process in the first-step low-temperature cryogenic separation process, and finally provide the low-temperature energy for the permeation gas of the second-stage membrane component in the three-step membrane separation link; in the membrane component oxygen enrichment link, air pressurized at the compressor end of a compression turbine expander is uniformly mixed with air pressurized in a carbon dioxide trapping plate block after landfill gas is combusted, an air separation membrane is used after heat exchange, a membrane component of a membrane material with a large oxygen and nitrogen separation coefficient obtains oxygen-enriched air in permeating gas, and trapped gas can provide low-temperature energy for system circulating water or high-temperature gas after expansion and cooling.|3. The landfill gas carbon dioxide capture process of claim 1, wherein:|the carbon dioxide trapping block after the landfill gas is combusted can be divided into a pressurizing and cooling dehydration link, a membrane separation link, a low-temperature cryogenic separation link and a carbon dioxide trapping reflux link; the low-temperature cryogenic separation link utilizes the cold energy of the liquefied natural gas to obtain lower-temperature natural gas, and the low-temperature energy of the gas is fully utilized to cool a compressor in the pressurization, cooling and dehydration link or cool circulating water cooled by the compressor; after the trapped gas in the membrane separation link is expanded and cooled, low-temperature energy is provided for the second-stage cooling of a compressor in the pressurization cooling dehydration link, and then the carbon dioxide liquid after the temperature of a heat exchanger after a vacuum pump in the membrane separation link is cooled; the trapped gas of the membrane module in the carbon dioxide trapping and refluxing link is firstly subjected to power supply by a compression turbine expander to the compressor end, then is subjected to one-step expansion cooling to provide low-temperature energy for cooling in the second stage of the low-temperature cryogenic separation link, and then can be used for cooling circulating water or high-temperature gas by a heat exchanger.|4. The landfill gas carbon dioxide capture process of claim 1, wherein:|in the landfill gas combustion link, liquefied natural gas which utilizes low-temperature energy in common air and landfill gas decarburization oxygen-enriched plates, permeation gas of a third-stage membrane module in a third-stage membrane separation link, trapped gas in a carbon dioxide trapping backflow link and oxygen-enriched air in part of membrane module oxygen-enriched links are used, and the liquefied natural gas which utilizes the low-temperature energy in the carbon dioxide trapping plates after the landfill gas combustion is proportioned according to a certain air surplus coefficient; flue gas discharged after the landfill gas mixed gas is combusted and generated is subjected to flue gas denitration treatment, then circulating water or low-temperature gas in a system is used for cooling the flue gas, and finally the flue gas is introduced into a carbon dioxide trapping plate block after the landfill gas is combusted. | (CN107758664)|TECHNICAL FIELD|[0002] The invention relates to the technical field of carbon dioxide capture and recovery, in particular to a carbon dioxide capture process for a landfill gas.|BACKGROUND ART|[0004] Since the industrial revolution, a large amount of fossil fuel is burned, resulting in an increase in the concentration of carbon dioxide in the atmosphere, resulting in global warming, and the greenhouse effect is becoming more and more severe. According to the fourth assessment report of the inter-government climate change committee (IPCC) of the united nations, it was shown that the carbon dioxide contribution accounted for about 63% and the methane contribution accounted for about 18% of the total warming effect of greenhouse gases, wherein the carbon dioxide equivalent per ton of methane was 25. In recent years, the emission of methane is increased sharply and is close to the most internationally recognized condition, the control of the emission of methane is the key for avoiding the aggravation of global warming influence, the methane is the key for rapidly slowing down the climate change, the carbon dioxide influence is long and long, the methane influence is faster, the emission of methane caused by human factors accounts for 60 percent of the global emission of methane, the emission of methane caused by agricultural production accounts for about one third of the emission of methane, and the emission of methane caused by fossil fuels is less than the emission of methane. This means that the control of methane emissions has a very important impact on climate change due to the life cycle of the methane present.|[0005] Landfill gas, which is a natural byproduct of the decomposition of organic matter in landfills, is composed of approximately 50% methane and approximately 50% carbon dioxide with small amounts of non-methane organic compounds, where municipal solid waste landfills are the third major source of man-made methane emissions in the united states, accounting for approximately 15.4% of the 2015 emissions. With the acceleration of the urbanization process in China, the integrated development speed of urban and rural areas is accelerated, the quantity of urban domestic garbage is gradually increased, many cities are in danger of enclosing the cities by the garbage, and although the garbage can be greatly reduced by burning the garbage, pollutants such as dioxin and the like are generated along with the garbage burning, so that the air is damaged. If the landfill gas generated by anaerobic fermentation of the municipal solid waste landfill is effectively controlled and utilized, the organic components of the garbage can be digested, and meanwhile, methane is used for preparing compressed natural gas and liquefied natural gas or combustion power generation is carried out, so that the pollution to the air is reduced, and the emission equivalent of greenhouse gases is reduced.|[0006] Bioenergy and carbon capture and storage technology (BECCS) is a very efficient greenhouse gas abatement technology that combines the use of Carbon Capture and Storage (CCS) and biomass, which can create negative carbon emissions. Since the content of the methane component in the landfill gas is higher than 40 percent and the content of the methane component in the landfill gas generated after the landfill site is close to the service life or is closed may be lower than 20 percent, the value of the landfill gas for combustion power generation or as a natural gas preparation source is realized by capturing carbon dioxide in the landfill gas and increasing the concentration of the methane component, which has important significance, and the contribution of the landfill gas directly discharged to the atmosphere at the stage to the greenhouse effect can be reduced.|[0007] The current technologies for capturing carbon dioxide mainly comprise a solvent absorption method, an adsorption method, a membrane separation method, a low-temperature cryogenic separation method and the like, and although the alcohol amine absorption method is most widely applied, the regeneration temperature of an absorbent is high, the required energy consumption is high, and the leakage or volatilization of a chemical absorbent can cause environmental pollution. The membrane separation method has the advantages of small occupied area, low energy consumption, no phase change and simple and convenient operation, and has wide application prospect; the hybrid capture technology improves the comprehensive utilization of resources and energy by combining different capture technologies, can effectively make up the defects of a single technology, and is beneficial to promoting the development of biological energy and carbon capture and storage technology (BECCS). Therefore, it is necessary to research a mixed capturing technology to capture carbon dioxide in landfill gas, reduce the energy consumption and capturing difficulty of the process, improve the concentration and calorific value of methane components in the landfill gas, improve the utilization value of the landfill gas of the refuse landfill in a close or closed state, improve the service cycle of the landfill, and reduce the emission of greenhouse gases.|DISCLOSURE|[0008] Disclosure of Invention|[0009] The invention aims to provide a landfill gas carbon dioxide capture process, which combines gas membrane separation and low-temperature liquefaction technologies, effectively integrates a landfill gas decarburization oxygen-rich plate and a carbon dioxide capture plate after combustion of landfill gas, and improves the greenhouse gas emission reduction effect.|[0010] The technical scheme provided by the invention is as follows:|[0011] a landfill gas carbon dioxide capture process comprises the following steps: in the landfill gas decarburization oxygen-enriched block, the landfill gas is subjected to decarburization and oxygen enrichment through a countercurrent membrane component after being purified, so that the equivalent concentration of methane in the landfill gas is improved and the landfill gas is used for combustion power generation; the sweep gas of the landfill gas decarburization oxygen-enriched countercurrent membrane component is provided by air or oxygen-enriched air; the method comprises the following steps that (1) after permeate gas is discharged from a permeate gas side of a countercurrent membrane assembly, the permeate gas is compressed by a compressor and then is cooled in stages, then the separation of carbon dioxide and other gas components is realized through a three-stage membrane separation link, the permeate gas of a first-stage membrane assembly and the permeate gas of a second-stage membrane assembly are mixed with the permeate gas of the membrane assembly after low-temperature cryogenic separation, the permeate gas and the retentate gas of the membrane assembly after low-temperature cryogenic separation are uniformly mixed and then enter the low-temperature cryogenic separation link, the permeate gas of a third-stage membrane assembly and the retentate gas of the membrane assembly after low-temperature cryogenic separation are mixed and then serve as one of oxygen sources in the combustion process of landfill gas, the; in the low-temperature cryogenic separation link, the carbon dioxide is compressed by a multi-stage compressor and then is cooled by stages, the first liquefaction of the carbon dioxide is realized by utilizing the cold energy of liquefied natural gas after dehydration and drying through a molecular sieve, the gas components after gas-liquid separation are pressurized and cooled and then are subjected to the second liquefaction and separation, the obtained carbon dioxide liquid after the two liquefaction is mixed and then is led into a low-temperature liquid pump, the pressure is increased to the pressure required by commercial use, and the system is cooled by utilizing the low-temperature energy of the carbon dioxide liquid through a heat exchanger; in a carbon dioxide trapping plate block after landfill gas combustion, firstly compressing combusted flue gas, carrying out two-stage cooling, carrying out gas-liquid separation and preliminary dehydration and drying, separating gas components through a membrane module, recovering energy of trapped gas and then discharging, uniformly mixing permeation gas and permeation gas in the membrane module subjected to low-temperature deep cooling, then entering a low-temperature deep cooling separation link, pressurizing through a multi-stage compressor, firstly carrying out two-stage cooling, then further dehydrating and drying through a molecular sieve, then liquefying carbon dioxide by utilizing cold energy of liquefied natural gas, after gas-liquid separation, allowing carbon dioxide liquid to pass through a low-temperature liquid pump, further trapping carbon dioxide through the membrane module for the gas components, and discharging after energy recovery of the trapped gas; in the decarbonization and oxygen enrichment link of the landfill gas and after the landfill gas is combusted, the carbon dioxide capture block utilizes natural gas with cold energy as a supplementary component of methane in the landfill gas to be combusted together with the landfill gas.|[0012] The landfill gas decarburization oxygen enrichment block can be divided into a membrane module decarburization oxygen enrichment link, a three-stage membrane separation link, a two-step low-temperature cryogenic separation link, a carbon dioxide capture reflux link and a membrane module oxygen enrichment link; in the membrane module decarburization oxygen enrichment link, landfill gas firstly passes through a purification device, the purge gas utilizes oxygen-enriched air in the membrane module oxygen enrichment link, according to the actual gas component situation, when the oxygen-enriched air is insufficient, air can be directly blown into a purge gas inlet of the membrane module through a blower, when the oxygen-enriched air is left, an oxygen source is provided for the landfill gas combustion link, and meanwhile, the amount of the oxygen-enriched air can be controlled by adjusting the pressure value range of a compressor port of a compression turbine expander; in the third-stage membrane separation link, the first and second-stage membrane modules use membrane materials with larger carbon dioxide separation coefficient, the third-stage membrane module uses a commercial air separation membrane, the membrane materials with larger oxygen and nitrogen separation coefficient capture the trapped gas of the first and second-stage membrane modules respectively, the trapped gas of the third-stage membrane module provides low-temperature energy for the second-stage cooling of the compressor after being recovered by the energy of the expander, and then the system circulating water can be continuously cooled or directly discharged through the heat exchanger; in the two-step low-temperature cryogenic separation link, the liquefied natural gas provides cold energy through an LNG heat exchanger, the liquefied natural gas is uniformly mixed and then cooled for the first-stage membrane module permeation gas in the three-stage membrane separation link, then the low-temperature energy is continuously provided for the first-stage cooling of a compressor, and then the low-temperature energy is used as fuel for the landfill gas combustion link to improve the concentration of methane components in the landfill gas; in the two-step low-temperature cryogenic separation link, the low-temperature energy of the carbon dioxide liquid is utilized to firstly cool the flue gas after the pressurization and the temperature rise in the second-step low-temperature cryogenic separation process and then provide the low-temperature energy for the second-step cooling process in the first-step low-temperature cryogenic separation process, and finally provide the low-temperature energy for the permeation gas of the second-stage membrane component in the three-step membrane separation link; in the membrane component oxygen enrichment link, air pressurized at the compressor end of a compression turbine expander is uniformly mixed with air pressurized in a carbon dioxide trapping plate block after landfill gas is combusted, an air separation membrane is used after heat exchange, a membrane component of a membrane material with a large oxygen and nitrogen separation coefficient obtains oxygen-enriched air in permeating gas, and trapped gas can provide low-temperature energy for system circulating water or high-temperature gas after expansion and cooling.|[0013] The carbon dioxide trapping block after the landfill gas is combusted can be divided into a pressurizing and cooling dehydration link, a membrane separation link, a low-temperature cryogenic separation link and a carbon dioxide trapping reflux link; the low-temperature cryogenic separation link utilizes the cold energy of the liquefied natural gas to obtain lower-temperature natural gas, and the low-temperature energy of the gas is fully utilized to cool a compressor in the pressurization, cooling and dehydration link or cool circulating water cooled by the compressor; after the trapped gas in the membrane separation link is expanded and cooled, low-temperature energy is provided for the second-stage cooling of a compressor in the pressurization cooling dehydration link, and then the carbon dioxide liquid after the temperature of a heat exchanger after a vacuum pump in the membrane separation link is cooled; the trapped gas of the membrane module in the carbon dioxide trapping and refluxing link is firstly subjected to power supply by a compression turbine expander to the compressor end, then is subjected to one-step expansion cooling to provide low-temperature energy for cooling in the second stage of the low-temperature cryogenic separation link, and then can be used for cooling circulating water or high-temperature gas by a heat exchanger.|[0014] In the landfill gas combustion link, liquefied natural gas which utilizes low-temperature energy in common air and landfill gas decarburization oxygen-enriched plates, permeation gas of a third-stage membrane module in a third-stage membrane separation link, trapped gas in a carbon dioxide trapping backflow link and oxygen-enriched air in part of membrane module oxygen-enriched links are used, and the liquefied natural gas which utilizes the low-temperature energy in the carbon dioxide trapping plates after the landfill gas combustion is proportioned according to a certain air surplus coefficient; flue gas discharged after the landfill gas mixed gas is combusted and generated is subjected to flue gas denitration treatment, then circulating water or low-temperature gas in a system is used for cooling the flue gas, and finally the flue gas is introduced into a carbon dioxide trapping plate block after the landfill gas is combusted.|DRAWINGS DESCRIPTION|[0016] The invention will be described in more detail below with reference to the following figures and specific embodiments:|[0017] FIG. 1 is a schematic diagram of a landfill gas decarburization oxygen-enriched block of the present invention.|[0018] Fig. 2 is a schematic view of a landfill gas combustion process.|[0019] FIG. 3 is a schematic diagram of a flue gas carbon dioxide capture block after combustion of landfill gas.|[0020] Reference numerals in the drawings indicate:|[0021] 1. a landfill gas purification device; 2. a counter-flow membrane module; 3. 19, 38, a compressor; 4. 5, 8, 11, 14, 15, 20, 23, 27, 33, 36, 39, 40, 45, 48, 49, 53, 58, 64, heat exchangers; 6. 9, 24, 31, 34, 42, 54, membrane modules; 7. 10, 43, a vacuum pump; 12. 27, 37, 46, 59, 60, gas mixer; 13. 47, a multi-stage compressor; 16. A 50, 3A molecular sieve drying device; 17. 21, 51, LNG heat exchanger; 18. 22, 41, 52, a gas-liquid separator; 25. 55, a compression turboexpander; 26. 32, 35, 44, 61, an expander; 28. 57, a liquefied natural gas storage tank; 29. a liquid mixer; 30. 56, a cryogenic liquid pump; 62. landfill gas mixed gas combustion power generation device; 63. a flue gas purification device.|INVENTION MODE|[0022] Detailed Description|[0023] The invention relates to a landfill gas carbon dioxide capture process, which comprises a landfill gas decarburization oxygen-rich block, a landfill gas combustion link and a flue gas carbon dioxide capture block after combustion of landfill gas; in order to better illustrate the prior art solution of the present invention, the following detailed description will be given with reference to the accompanying drawings required in the description of the prior art solution.|[0024] Referring to fig. 1, the landfill gas decarbonization oxygen-rich plate of the invention comprises: can be divided into a membrane module decarburization oxygen enrichment link, a three-stage membrane separation link, a two-step low-temperature cryogenic separation link, a carbon dioxide capture reflux link and a membrane module oxygen enrichment link.|[0025] The landfill gas enters the trapping system from S1, is purified by the landfill gas purifying device 1 and then is connected with the feed gas side of the counter-flow membrane module 2 through S2; in the counter-flow membrane module 2, high-concentration carbon dioxide in the feed gas permeates into the permeate gas through the membrane module, oxygen-enriched air or ordinary air from the permeate gas side of the membrane module 34 is connected with the purge gas side, the oxygen-enriched air can be connected with the S4 through S80 and conveyed into the membrane module 2, because the feed gas contains little oxygen component and little nitrogen component, nitrogen and oxygen components in the oxygen-enriched air can permeate into a channel on the feed gas side through the membrane module 2 and are finally discharged from a trapped gas side through S3, the oxygen-enriched air contains only trace carbon dioxide, and a channel on the feed gas side, through which carbon dioxide permeates into the permeate gas side, is finally discharged from the permeate side and enters a membrane separation link through S5.|[0026] The flue gas components are connected with a compressor 3 through S5, and the temperature of the flue gas is reduced in a heat exchanger 4 and a heat exchanger 5 through S6 and S7 in sequence after the flue gas is compressed; the low-temperature gas source in the heat exchanger 4 is low-temperature natural gas which is heated by the heat exchanger 8, and is discharged from S78 after being heated by the heat exchanger 4 and conveyed to a landfill gas combustion power generation link; the low-temperature energy of the heat exchanger 5 is provided by connecting the gas in the expander 32 with the heat exchanger through S19; the flue gas is cooled by a heat exchanger 5 and then is connected with a membrane module 6 through S8; the trapped gas side of the membrane module 6 is connected with the membrane module 9 through S12, the permeate gas side is connected with the vacuum pump 7 through S9, the concentration of carbon dioxide on the permeate gas side is improved through the membrane module 6, the permeate gas recovers the atmospheric pressure after being pumped by the vacuum pump 7, and then the permeate gas is connected with the heat exchanger 8 through S10; the temperature of the flue gas is raised in the heat exchanger 8 and then introduced into the gas mixer 12 through S11; the permeate side of the membrane module 9 is connected with the vacuum pump 10 through S13, and the retentate side is connected with the membrane module 31 through S16; after the trapped gas from the membrane module 6 reaches the module 9 through S12, carbon dioxide is enriched in the permeated gas, and reaches the vacuum pump 10 through S13, and the pressure is restored to atmospheric pressure and then connected to the heat exchanger 11 through S14; in the heat exchanger 14, the low-temperature energy is derived from the carbon dioxide low-temperature liquid heated by the heat exchanger, and after heat exchange, the carbon dioxide liquid is conveyed to the next stage of commercial application through S79; the permeation gas from the membrane module 9 is cooled by a heat exchanger 11 and then is introduced into a gas mixer 12 through S15; the membrane module 31 is connected with the gas mixer 37 through S17, the trapped gas is connected with the expander 32 through S18, and the trapped gas is expanded and cooled by the expander 32 and then provides low-temperature energy for the heat exchanger 5 through S19; the gas mixer 12 is formed by mixing a total of three gas sources, and the other gas source group is provided by the permeate gas of the membrane module 24 through S47; after being uniformly mixed, the gas enters a low-temperature cryogenic separation link through S20.|[0027] The uniformly mixed gas is connected with a multistage compressor 13 through S20, and the flue gas is pressurized, then is cooled in stages through heat exchangers 14 and 15 respectively, and then is connected with a 3A molecular sieve drying device 16 through S23; the high-temperature gas in the S21 in the heat exchanger 14 and the circulating water are subjected to heat exchange, and the flue gas is subjected to primary cooling and then is further cooled in the heat exchanger 15 through the S22; the low-temperature energy of the heat exchanger 15 comes from the heated liquid carbon dioxide in the heat exchanger 20, and the flue gas is connected with the 3A molecular sieve drying device 16 through S23 after being cooled for the second time; the flue gas is dried and then is connected with the LNG heat exchanger 12 through S24; the low-temperature energy of the LNG heat exchanger 12 is provided by connecting liquefied natural gas in a liquefied natural gas storage tank with the heat exchanger through S27, the liquefied natural gas is connected with the gas mixer 59 through S25 after being heated in the LNG heat exchanger 17, and the flue gas is connected with the gas-liquid separator 18 through S26 after being cooled; separating the liquid carbon dioxide from the gaseous component in the gas-liquid separator 18, wherein the liquid carbon dioxide is connected to the liquid mixer via S29 and the gaseous component is connected to the compressor 19 via S28; after the gas component is pressurized by a compressor 19, 2-step cooling operation is carried out; the heat exchanger 20 is connected through S30, the low-temperature energy of the carbon dioxide liquid in the low-temperature liquid pump 30 is utilized, and the heated low-temperature liquid is conveyed into the heat exchanger 15 to provide the low-temperature energy for the heat exchanger 15; the gas component primarily cooled by the heat exchanger 20 is connected with the LNG heat exchanger 21 through S31; in the LNG heat exchanger 21, the LNG in the LNG storage tank 28 provides low-temperature energy to the heat exchanger through S32, and is discharged through S33 after being heated and then connected to the gas mixer 59; in the gas mixer 59, the natural gas from S25 and S33 is uniformly mixed to provide low-temperature energy for the heat exchanger 8; the gas component is subjected to secondary temperature reduction through the LNG heat exchanger 21 and then reaches the gas-liquid separator 22 through S34 to undergo gas-liquid separation; in the gas-liquid separator 22, the liquid component is connected with the liquid mixer 29 through S39, and the gas component enters a carbon dioxide membrane component for capturing and refluxing through S35; the carbon dioxide liquid in S39 and S29 is uniformly mixed in the liquid mixer 29 and reaches the low-temperature liquid pump 30 through S40; the gas component separated by the gas-liquid separator 22 is connected with the heat exchanger 23 through S35, is heated by the heat exchanger 23 and then is connected with the feed gas side of the membrane module 24 through S36, and enters a carbon dioxide capture reflux link; in the heat exchanger 23, the gas component provides low temperature energy for cooling the circulating water in the system.|[0028] The permeate gas side of the membrane module 24 is connected to S37 and the retentate gas side is connected to S38; the trapped gas in the membrane module 24 reaches an expander-side inlet of the compression turboexpander 25 through S38, and provides kinetic energy for the compressor side through preliminary expansion; air enters a compressor side inlet of the compression turboexpander 25 through S46, is discharged from a compressor side outlet after being compressed, is uniformly mixed with air in S81 from a landfill gas combustion carbon dioxide capture block in a gas mixer 60 through S47, and is connected with a heat exchanger 33 through S82; the cooled gas is connected with the feed gas side of the oxygen-enriched membrane component 34 through S48 after being cooled by the heat exchanger 33; the permeate side of membrane module 34 is connected to the sweep gas side of membrane module 2 via S4, and the retentate side is connected to expander 35 via S49; the trapped gas from the membrane module 34 is expanded, connected with a heat exchanger 36 through S50 to provide low-temperature energy for the system, and finally discharged through S51; trapped gas in the membrane module 24 is subjected to preliminary expansion and pressure reduction through a compression turbo expander 25, then is connected with an expander 26 through S42, then reaches a heat exchanger 27 through S43 to provide low-temperature energy for the system, and then is connected with a gas mixer 37 through S44; the gases from S44 and S17 are mixed in the gas mixer 37 and delivered to the combustion section through S45.|[0029] Referring to fig. 1, in fig. 2, the landfill gas combustion section of the present invention includes: the method comprises the following steps that S45, gas comes from a gas mixer 37 of a landfill gas decarburization oxygen-rich block, S78 is natural gas which is obtained by utilizing low-temperature energy by the landfill gas decarburization oxygen-rich block, S69 is natural gas which is obtained by utilizing low-temperature energy by a flue gas carbon dioxide capture block after combustion of garbage landfill gas, S3 is landfill gas which is obtained by decarburization and oxygen enrichment by a landfill gas decarburization oxygen-rich block countercurrent membrane module 2, S84 is common air, S85 is oxygen-rich air which is used as an oxygen source in a landfill gas combustion process after meeting the requirements of the landfill gas decarburization oxygen-rich block, and the six gases are proportioned according to a certain air excess coefficient and are fully combusted in a landfill gas mixed gas combustion power generation device 62; the flue gas after burning of the landfill gas mixer is connected with a flue gas purification device 63 through S86; the flue gas is connected with the heat exchanger 64 through S87 after being purified, the flue gas is cooled by using circulating water or low-temperature gas in the system, and finally the flue gas enters the landfill gas through S77 to burn to form a flue gas carbon dioxide trapping plate.|[0030] Referring to fig. 1 and 2, in fig. 3, the flue gas carbon dioxide capture block after combustion of landfill gas of the invention comprises: a pressurizing and cooling dehydration link, a membrane separation link, a low-temperature deep-cooling separation link and a carbon dioxide trapping reflux link.|[0031] The purified flue gas is connected with the compressor 38 through S77, and the flue gas is pressurized and then respectively connected with the heat exchangers 39 and 40 through S52 and S53 to carry out staged temperature reduction; in the heat exchanger 39, the low-temperature energy is provided by connecting the low-temperature natural gas heated in the LNG heat exchanger 51 with the heat exchanger 39 through S67; in the heat exchanger 40, the flue gas expanded and cooled by the expander 44 is connected with the heat exchanger through S59 to provide low-temperature energy for the heat exchanger; the flue gas reaches the gas-liquid separator 41 through S54 after being cooled, gas-liquid separation occurs in the gas-liquid separator 41, condensed water enters water circulation of the system through S58, and the obtained primarily dried gas component is connected with the feed gas side of the membrane module 42 through S55 and enters a membrane separation link.|[0032] The permeate side of the membrane module 42 is connected to a vacuum pump 43 via S56, and the retentate side is connected to an expander 44 via S57; the carbon dioxide is enriched in the permeation gas through the membrane module 42, and reaches the heat exchanger 45 through S60 after the atmospheric pressure is recovered through the suction effect of the vacuum pump 43; the heat exchanger 45 is cooled by the process of heating the carbon dioxide liquid, and is connected with the gas mixer 46 through S61 after being cooled; in the gas mixer 46, the gas from S61 and S72 is mixed uniformly and then is connected with a multi-stage compressor 47 through S62, and enters a low-temperature cryogenic separation link.|[0033] In the S62, the flue gas is compressed by a multi-stage compressor and then cooled by stages through heat exchangers 48 and 49; after the high-temperature gas in the multistage compressor 47 is connected with the heat exchanger 48 through S63, the circulating water in the system is used for preliminary cooling, and after cooling, the high-temperature gas is connected with the heat exchanger 49 through S64; the low-temperature energy of the heat exchanger 49 is provided by the expanded and cooled gas of the expander 55 through S74; the flue gas is cooled in stages and then is connected with a 3A molecular sieve drying device 50 through S65, and the dried gas is introduced into an LNG heat exchanger 51 through S66; the low-temperature energy of the LNG heat exchanger is provided by connecting the liquefied natural gas in the liquefied natural gas storage tank 57 with the LNG heat exchanger 51 through S69; the dried gas is cooled by an LNG heat exchanger 51 and then is connected with a gas-liquid separator 52 through a 68; in the gas-liquid separator 52, the liquid carbon dioxide is connected with the low-temperature liquid pump 56 through S75, is connected with the heat exchanger 45 through S76, provides low-temperature energy for the heat exchanger 45, is connected with the heat exchanger 58, provides heat for the gas coming from the expander 44 and heated by the heat exchanger 40, and reduces the temperature of the carbon dioxide liquid to about 31 ℃ to obtain supercritical carbon dioxide fluid; the gas components separated in the gas-liquid separator 52 are connected with the heat exchanger 53 through the S70, the heat exchanger 53 provides low-temperature energy for circulating water in the system, and the gas components are connected with the feed gas side of the membrane module 54 through the S71 after being heated by the heat exchanger 53 and enter a carbon dioxide capturing reflux link.|[0034] The permeate gas side of the membrane module 54 is connected with S72, the trapped gas side is connected with the compression turboexpander 55 through S73, the gas is connected with the expander 61 through S74 after being expanded and depressurized initially, and low-temperature energy is provided for the heat exchanger 49 through S84 after being expanded and cooled further; the inlet of the compressor port of the compressor turboexpander is connected with S83, the outlet of the compressor port of the compressor turboexpander is connected with S81, and air enters a membrane module oxygen enrichment link of the landfill gas decarburization oxygen enrichment plate block through S81 after being pressurized at the compressor end. | (CN107758664)|TECHNICAL FIELD|[0002] The invention relates to the technical field of carbon dioxide capture and recovery, in particular to a carbon dioxide capture process for a landfill gas.|BACKGROUND ART|[0004] Since the industrial revolution, a large amount of fossil fuel is burned, resulting in an increase in the concentration of carbon dioxide in the atmosphere, resulting in global warming, and the greenhouse effect is becoming more and more severe. According to the fourth assessment report of the inter-government climate change committee (IPCC) of the united nations, it was shown that the carbon dioxide contribution accounted for about 63% and the methane contribution accounted for about 18% of the total warming effect of greenhouse gases, wherein the carbon dioxide equivalent per ton of methane was 25. In recent years, the emission of methane is increased sharply and is close to the most internationally recognized condition, the control of the emission of methane is the key for avoiding the aggravation of global warming influence, the methane is the key for rapidly slowing down the climate change, the carbon dioxide influence is long and long, the methane influence is faster, the emission of methane caused by human factors accounts for 60 percent of the global emission of methane, the emission of methane caused by agricultural production accounts for about one third of the emission of methane, and the emission of methane caused by fossil fuels is less than the emission of methane. This means that the control of methane emissions has a very important impact on climate change due to the life cycle of the methane present.|[0005] Landfill gas, which is a natural byproduct of the decomposition of organic matter in landfills, is composed of approximately 50% methane and approximately 50% carbon dioxide with small amounts of non-methane organic compounds, where municipal solid waste landfills are the third major source of man-made methane emissions in the united states, accounting for approximately 15.4% of the 2015 emissions. With the acceleration of the urbanization process in China, the integrated development speed of urban and rural areas is accelerated, the quantity of urban domestic garbage is gradually increased, many cities are in danger of enclosing the cities by the garbage, and although the garbage can be greatly reduced by burning the garbage, pollutants such as dioxin and the like are generated along with the garbage burning, so that the air is damaged. If the landfill gas generated by anaerobic fermentation of the municipal solid waste landfill is effectively controlled and utilized, the organic components of the garbage can be digested, and meanwhile, methane is used for preparing compressed natural gas and liquefied natural gas or combustion power generation is carried out, so that the pollution to the air is reduced, and the emission equivalent of greenhouse gases is reduced.|[0006] Bioenergy and carbon capture and storage technology (BECCS) is a very efficient greenhouse gas abatement technology that combines the use of Carbon Capture and Storage (CCS) and biomass, which can create negative carbon emissions. Since the content of the methane component in the landfill gas is higher than 40 percent and the content of the methane component in the landfill gas generated after the landfill site is close to the service life or is closed may be lower than 20 percent, the value of the landfill gas for combustion power generation or as a natural gas preparation source is realized by capturing carbon dioxide in the landfill gas and increasing the concentration of the methane component, which has important significance, and the contribution of the landfill gas directly discharged to the atmosphere at the stage to the greenhouse effect can be reduced.|[0007] The current technologies for capturing carbon dioxide mainly comprise a solvent absorption method, an adsorption method, a membrane separation method, a low-temperature cryogenic separation method and the like, and although the alcohol amine absorption method is most widely applied, the regeneration temperature of an absorbent is high, the required energy consumption is high, and the leakage or volatilization of a chemical absorbent can cause environmental pollution. The membrane separation method has the advantages of small occupied area, low energy consumption, no phase change and simple and convenient operation, and has wide application prospect; the hybrid capture technology improves the comprehensive utilization of resources and energy by combining different capture technologies, can effectively make up the defects of a single technology, and is beneficial to promoting the development of biological energy and carbon capture and storage technology (BECCS). Therefore, it is necessary to research a mixed capturing technology to capture carbon dioxide in landfill gas, reduce the energy consumption and capturing difficulty of the process, improve the concentration and calorific value of methane components in the landfill gas, improve the utilization value of the landfill gas of the refuse landfill in a close or closed state, improve the service cycle of the landfill, and reduce the emission of greenhouse gases.|DISCLOSURE|[0008] Disclosure of Invention|[0009] The invention aims to provide a landfill gas carbon dioxide capture process, which combines gas membrane separation and low-temperature liquefaction technologies, effectively integrates a landfill gas decarburization oxygen-rich plate and a carbon dioxide capture plate after combustion of landfill gas, and improves the greenhouse gas emission reduction effect.|[0010] The technical scheme provided by the invention is as follows:|[0011] a landfill gas carbon dioxide capture process comprises the following steps: in the landfill gas decarburization oxygen-enriched block, the landfill gas is subjected to decarburization and oxygen enrichment through a countercurrent membrane component after being purified, so that the equivalent concentration of methane in the landfill gas is improved and the landfill gas is used for combustion power generation; the sweep gas of the landfill gas decarburization oxygen-enriched countercurrent membrane component is provided by air or oxygen-enriched air; the method comprises the following steps that (1) after permeate gas is discharged from a permeate gas side of a countercurrent membrane assembly, the permeate gas is compressed by a compressor and then is cooled in stages, then the separation of carbon dioxide and other gas components is realized through a three-stage membrane separation link, the permeate gas of a first-stage membrane assembly and the permeate gas of a second-stage membrane assembly are mixed with the permeate gas of the membrane assembly after low-temperature cryogenic separation, the permeate gas and the retentate gas of the membrane assembly after low-temperature cryogenic separation are uniformly mixed and then enter the low-temperature cryogenic separation link, the permeate gas of a third-stage membrane assembly and the retentate gas of the membrane assembly after low-temperature cryogenic separation are mixed and then serve as one of oxygen sources in the combustion process of landfill gas, the; in the low-temperature cryogenic separation link, the carbon dioxide is compressed by a multi-stage compressor and then is cooled by stages, the first liquefaction of the carbon dioxide is realized by utilizing the cold energy of liquefied natural gas after dehydration and drying through a molecular sieve, the gas components after gas-liquid separation are pressurized and cooled and then are subjected to the second liquefaction and separation, the obtained carbon dioxide liquid after the two liquefaction is mixed and then is led into a low-temperature liquid pump, the pressure is increased to the pressure required by commercial use, and the system is cooled by utilizing the low-temperature energy of the carbon dioxide liquid through a heat exchanger; in a carbon dioxide trapping plate block after landfill gas combustion, firstly compressing combusted flue gas, carrying out two-stage cooling, carrying out gas-liquid separation and preliminary dehydration and drying, separating gas components through a membrane module, recovering energy of trapped gas and then discharging, uniformly mixing permeation gas and permeation gas in the membrane module subjected to low-temperature deep cooling, then entering a low-temperature deep cooling separation link, pressurizing through a multi-stage compressor, firstly carrying out two-stage cooling, then further dehydrating and drying through a molecular sieve, then liquefying carbon dioxide by utilizing cold energy of liquefied natural gas, after gas-liquid separation, allowing carbon dioxide liquid to pass through a low-temperature liquid pump, further trapping carbon dioxide through the membrane module for the gas components, and discharging after energy recovery of the trapped gas; in the decarbonization and oxygen enrichment link of the landfill gas and after the landfill gas is combusted, the carbon dioxide capture block utilizes natural gas with cold energy as a supplementary component of methane in the landfill gas to be combusted together with the landfill gas.|[0012] The landfill gas decarburization oxygen enrichment block can be divided into a membrane module decarburization oxygen enrichment link, a three-stage membrane separation link, a two-step low-temperature cryogenic separation link, a carbon dioxide capture reflux link and a membrane module oxygen enrichment link; in the membrane module decarburization oxygen enrichment link, landfill gas firstly passes through a purification device, the purge gas utilizes oxygen-enriched air in the membrane module oxygen enrichment link, according to the actual gas component situation, when the oxygen-enriched air is insufficient, air can be directly blown into a purge gas inlet of the membrane module through a blower, when the oxygen-enriched air is left, an oxygen source is provided for the landfill gas combustion link, and meanwhile, the amount of the oxygen-enriched air can be controlled by adjusting the pressure value range of a compressor port of a compression turbine expander; in the third-stage membrane separation link, the first and second-stage membrane modules use membrane materials with larger carbon dioxide separation coefficient, the third-stage membrane module uses a commercial air separation membrane, the membrane materials with larger oxygen and nitrogen separation coefficient capture the trapped gas of the first and second-stage membrane modules respectively, the trapped gas of the third-stage membrane module provides low-temperature energy for the second-stage cooling of the compressor after being recovered by the energy of the expander, and then the system circulating water can be continuously cooled or directly discharged through the heat exchanger; in the two-step low-temperature cryogenic separation link, the liquefied natural gas provides cold energy through an LNG heat exchanger, the liquefied natural gas is uniformly mixed and then cooled for the first-stage membrane module permeation gas in the three-stage membrane separation link, then the low-temperature energy is continuously provided for the first-stage cooling of a compressor, and then the low-temperature energy is used as fuel for the landfill gas combustion link to improve the concentration of methane components in the landfill gas; in the two-step low-temperature cryogenic separation link, the low-temperature energy of the carbon dioxide liquid is utilized to firstly cool the flue gas after the pressurization and the temperature rise in the second-step low-temperature cryogenic separation process and then provide the low-temperature energy for the second-step cooling process in the first-step low-temperature cryogenic separation process, and finally provide the low-temperature energy for the permeation gas of the second-stage membrane component in the three-step membrane separation link; in the membrane component oxygen enrichment link, air pressurized at the compressor end of a compression turbine expander is uniformly mixed with air pressurized in a carbon dioxide trapping plate block after landfill gas is combusted, an air separation membrane is used after heat exchange, a membrane component of a membrane material with a large oxygen and nitrogen separation coefficient obtains oxygen-enriched air in permeating gas, and trapped gas can provide low-temperature energy for system circulating water or high-temperature gas after expansion and cooling.|[0013] The carbon dioxide trapping block after the landfill gas is combusted can be divided into a pressurizing and cooling dehydration link, a membrane separation link, a low-temperature cryogenic separation link and a carbon dioxide trapping reflux link; the low-temperature cryogenic separation link utilizes the cold energy of the liquefied natural gas to obtain lower-temperature natural gas, and the low-temperature energy of the gas is fully utilized to cool a compressor in the pressurization, cooling and dehydration link or cool circulating water cooled by the compressor; after the trapped gas in the membrane separation link is expanded and cooled, low-temperature energy is provided for the second-stage cooling of a compressor in the pressurization cooling dehydration link, and then the carbon dioxide liquid after the temperature of a heat exchanger after a vacuum pump in the membrane separation link is cooled; the trapped gas of the membrane module in the carbon dioxide trapping and refluxing link is firstly subjected to power supply by a compression turbine expander to the compressor end, then is subjected to one-step expansion cooling to provide low-temperature energy for cooling in the second stage of the low-temperature cryogenic separation link, and then can be used for cooling circulating water or high-temperature gas by a heat exchanger.|[0014] In the landfill gas combustion link, liquefied natural gas which utilizes low-temperature energy in common air and landfill gas decarburization oxygen-enriched plates, permeation gas of a third-stage membrane module in a third-stage membrane separation link, trapped gas in a carbon dioxide trapping backflow link and oxygen-enriched air in part of membrane module oxygen-enriched links are used, and the liquefied natural gas which utilizes the low-temperature energy in the carbon dioxide trapping plates after the landfill gas combustion is proportioned according to a certain air surplus coefficient; flue gas discharged after the landfill gas mixed gas is combusted and generated is subjected to flue gas denitration treatment, then circulating water or low-temperature gas in a system is used for cooling the flue gas, and finally the flue gas is introduced into a carbon dioxide trapping plate block after the landfill gas is combusted.|DRAWINGS DESCRIPTION|[0016] The invention will be described in more detail below with reference to the following figures and specific embodiments:|[0017] FIG. 1 is a schematic diagram of a landfill gas decarburization oxygen-enriched block of the present invention.|[0018] Fig. 2 is a schematic view of a landfill gas combustion process.|[0019] FIG. 3 is a schematic diagram of a flue gas carbon dioxide capture block after combustion of landfill gas.|[0020] Reference numerals in the drawings indicate:|[0021] 1. a landfill gas purification device; 2. a counter-flow membrane module; 3. 19, 38, a compressor; 4. 5, 8, 11, 14, 15, 20, 23, 27, 33, 36, 39, 40, 45, 48, 49, 53, 58, 64, heat exchangers; 6. 9, 24, 31, 34, 42, 54, membrane modules; 7. 10, 43, a vacuum pump; 12. 27, 37, 46, 59, 60, gas mixer; 13. 47, a multi-stage compressor; 16. A 50, 3A molecular sieve drying device; 17. 21, 51, LNG heat exchanger; 18. 22, 41, 52, a gas-liquid separator; 25. 55, a compression turboexpander; 26. 32, 35, 44, 61, an expander; 28. 57, a liquefied natural gas storage tank; 29. a liquid mixer; 30. 56, a cryogenic liquid pump; 62. landfill gas mixed gas combustion power generation device; 63. a flue gas purification device.|INVENTION MODE|[0022] Detailed Description|[0023] The invention relates to a landfill gas carbon dioxide capture process, which comprises a landfill gas decarburization oxygen-rich block, a landfill gas combustion link and a flue gas carbon dioxide capture block after combustion of landfill gas; in order to better illustrate the prior art solution of the present invention, the following detailed description will be given with reference to the accompanying drawings required in the description of the prior art solution.|[0024] Referring to fig. 1, the landfill gas decarbonization oxygen-rich plate of the invention comprises: can be divided into a membrane module decarburization oxygen enrichment link, a three-stage membrane separation link, a two-step low-temperature cryogenic separation link, a carbon dioxide capture reflux link and a membrane module oxygen enrichment link.|[0025] The landfill gas enters the trapping system from S1, is purified by the landfill gas purifying device 1 and then is connected with the feed gas side of the counter-flow membrane module 2 through S2; in the counter-flow membrane module 2, high-concentration carbon dioxide in the feed gas permeates into the permeate gas through the membrane module, oxygen-enriched air or ordinary air from the permeate gas side of the membrane module 34 is connected with the purge gas side, the oxygen-enriched air can be connected with the S4 through S80 and conveyed into the membrane module 2, because the feed gas contains little oxygen component and little nitrogen component, nitrogen and oxygen components in the oxygen-enriched air can permeate into a channel on the feed gas side through the membrane module 2 and are finally discharged from a trapped gas side through S3, the oxygen-enriched air contains only trace carbon dioxide, and a channel on the feed gas side, through which carbon dioxide permeates into the permeate gas side, is finally discharged from the permeate side and enters a membrane separation link through S5.|[0026] The flue gas components are connected with a compressor 3 through S5, and the temperature of the flue gas is reduced in a heat exchanger 4 and a heat exchanger 5 through S6 and S7 in sequence after the flue gas is compressed; the low-temperature gas source in the heat exchanger 4 is low-temperature natural gas which is heated by the heat exchanger 8, and is discharged from S78 after being heated by the heat exchanger 4 and conveyed to a landfill gas combustion power generation link; the low-temperature energy of the heat exchanger 5 is provided by connecting the gas in the expander 32 with the heat exchanger through S19; the flue gas is cooled by a heat exchanger 5 and then is connected with a membrane module 6 through S8; the trapped gas side of the membrane module 6 is connected with the membrane module 9 through S12, the permeate gas side is connected with the vacuum pump 7 through S9, the concentration of carbon dioxide on the permeate gas side is improved through the membrane module 6, the permeate gas recovers the atmospheric pressure after being pumped by the vacuum pump 7, and then the permeate gas is connected with the heat exchanger 8 through S10; the temperature of the flue gas is raised in the heat exchanger 8 and then introduced into the gas mixer 12 through S11; the permeate side of the membrane module 9 is connected with the vacuum pump 10 through S13, and the retentate side is connected with the membrane module 31 through S16; after the trapped gas from the membrane module 6 reaches the module 9 through S12, carbon dioxide is enriched in the permeated gas, and reaches the vacuum pump 10 through S13, and the pressure is restored to atmospheric pressure and then connected to the heat exchanger 11 through S14; in the heat exchanger 14, the low-temperature energy is derived from the carbon dioxide low-temperature liquid heated by the heat exchanger, and after heat exchange, the carbon dioxide liquid is conveyed to the next stage of commercial application through S79; the permeation gas from the membrane module 9 is cooled by a heat exchanger 11 and then is introduced into a gas mixer 12 through S15; the membrane module 31 is connected with the gas mixer 37 through S17, the trapped gas is connected with the expander 32 through S18, and the trapped gas is expanded and cooled by the expander 32 and then provides low-temperature energy for the heat exchanger 5 through S19; the gas mixer 12 is formed by mixing a total of three gas sources, and the other gas source group is provided by the permeate gas of the membrane module 24 through S47; after being uniformly mixed, the gas enters a low-temperature cryogenic separation link through S20.|[0027] The uniformly mixed gas is connected with a multistage compressor 13 through S20, and the flue gas is pressurized, then is cooled in stages through heat exchangers 14 and 15 respectively, and then is connected with a 3A molecular sieve drying device 16 through S23; the high-temperature gas in the S21 in the heat exchanger 14 and the circulating water are subjected to heat exchange, and the flue gas is subjected to primary cooling and then is further cooled in the heat exchanger 15 through the S22; the low-temperature energy of the heat exchanger 15 comes from the heated liquid carbon dioxide in the heat exchanger 20, and the flue gas is connected with the 3A molecular sieve drying device 16 through S23 after being cooled for the second time; the flue gas is dried and then is connected with the LNG heat exchanger 12 through S24; the low-temperature energy of the LNG heat exchanger 12 is provided by connecting liquefied natural gas in a liquefied natural gas storage tank with the heat exchanger through S27, the liquefied natural gas is connected with the gas mixer 59 through S25 after being heated in the LNG heat exchanger 17, and the flue gas is connected with the gas-liquid separator 18 through S26 after being cooled; separating the liquid carbon dioxide from the gaseous component in the gas-liquid separator 18, wherein the liquid carbon dioxide is connected to the liquid mixer via S29 and the gaseous component is connected to the compressor 19 via S28; after the gas component is pressurized by a compressor 19, 2-step cooling operation is carried out; the heat exchanger 20 is connected through S30, the low-temperature energy of the carbon dioxide liquid in the low-temperature liquid pump 30 is utilized, and the heated low-temperature liquid is conveyed into the heat exchanger 15 to provide the low-temperature energy for the heat exchanger 15; the gas component primarily cooled by the heat exchanger 20 is connected with the LNG heat exchanger 21 through S31; in the LNG heat exchanger 21, the LNG in the LNG storage tank 28 provides low-temperature energy to the heat exchanger through S32, and is discharged through S33 after being heated and then connected to the gas mixer 59; in the gas mixer 59, the natural gas from S25 and S33 is uniformly mixed to provide low-temperature energy for the heat exchanger 8; the gas component is subjected to secondary temperature reduction through the LNG heat exchanger 21 and then reaches the gas-liquid separator 22 through S34 to undergo gas-liquid separation; in the gas-liquid separator 22, the liquid component is connected with the liquid mixer 29 through S39, and the gas component enters a carbon dioxide membrane component for capturing and refluxing through S35; the carbon dioxide liquid in S39 and S29 is uniformly mixed in the liquid mixer 29 and reaches the low-temperature liquid pump 30 through S40; the gas component separated by the gas-liquid separator 22 is connected with the heat exchanger 23 through S35, is heated by the heat exchanger 23 and then is connected with the feed gas side of the membrane module 24 through S36, and enters a carbon dioxide capture reflux link; in the heat exchanger 23, the gas component provides low temperature energy for cooling the circulating water in the system.|[0028] The permeate gas side of the membrane module 24 is connected to S37 and the retentate gas side is connected to S38; the trapped gas in the membrane module 24 reaches an expander-side inlet of the compression turboexpander 25 through S38, and provides kinetic energy for the compressor side through preliminary expansion; air enters a compressor side inlet of the compression turboexpander 25 through S46, is discharged from a compressor side outlet after being compressed, is uniformly mixed with air in S81 from a landfill gas combustion carbon dioxide capture block in a gas mixer 60 through S47, and is connected with a heat exchanger 33 through S82; the cooled gas is connected with the feed gas side of the oxygen-enriched membrane component 34 through S48 after being cooled by the heat exchanger 33; the permeate side of membrane module 34 is connected to the sweep gas side of membrane module 2 via S4, and the retentate side is connected to expander 35 via S49; the trapped gas from the membrane module 34 is expanded, connected with a heat exchanger 36 through S50 to provide low-temperature energy for the system, and finally discharged through S51; trapped gas in the membrane module 24 is subjected to preliminary expansion and pressure reduction through a compression turbo expander 25, then is connected with an expander 26 through S42, then reaches a heat exchanger 27 through S43 to provide low-temperature energy for the system, and then is connected with a gas mixer 37 through S44; the gases from S44 and S17 are mixed in the gas mixer 37 and delivered to the combustion section through S45.|[0029] Referring to fig. 1, in fig. 2, the landfill gas combustion section of the present invention includes: the method comprises the following steps that S45, gas comes from a gas mixer 37 of a landfill gas decarburization oxygen-rich block, S78 is natural gas which is obtained by utilizing low-temperature energy by the landfill gas decarburization oxygen-rich block, S69 is natural gas which is obtained by utilizing low-temperature energy by a flue gas carbon dioxide capture block after combustion of garbage landfill gas, S3 is landfill gas which is obtained by decarburization and oxygen enrichment by a landfill gas decarburization oxygen-rich block countercurrent membrane module 2, S84 is common air, S85 is oxygen-rich air which is used as an oxygen source in a landfill gas combustion process after meeting the requirements of the landfill gas decarburization oxygen-rich block, and the six gases are proportioned according to a certain air excess coefficient and are fully combusted in a landfill gas mixed gas combustion power generation device 62; the flue gas after burning of the landfill gas mixer is connected with a flue gas purification device 63 through S86; the flue gas is connected with the heat exchanger 64 through S87 after being purified, the flue gas is cooled by using circulating water or low-temperature gas in the system, and finally the flue gas enters the landfill gas through S77 to burn to form a flue gas carbon dioxide trapping plate.|[0030] Referring to fig. 1 and 2, in fig. 3, the flue gas carbon dioxide capture block after combustion of landfill gas of the invention comprises: a pressurizing and cooling dehydration link, a membrane separation link, a low-temperature deep-cooling separation link and a carbon dioxide trapping reflux link.|[0031] The purified flue gas is connected with the compressor 38 through S77, and the flue gas is pressurized and then respectively connected with the heat exchangers 39 and 40 through S52 and S53 to carry out staged temperature reduction; in the heat exchanger 39, the low-temperature energy is provided by connecting the low-temperature natural gas heated in the LNG heat exchanger 51 with the heat exchanger 39 through S67; in the heat exchanger 40, the flue gas expanded and cooled by the expander 44 is connected with the heat exchanger through S59 to provide low-temperature energy for the heat exchanger; the flue gas reaches the gas-liquid separator 41 through S54 after being cooled, gas-liquid separation occurs in the gas-liquid separator 41, condensed water enters water circulation of the system through S58, and the obtained primarily dried gas component is connected with the feed gas side of the membrane module 42 through S55 and enters a membrane separation link.|[0032] The permeate side of the membrane module 42 is connected to a vacuum pump 43 via S56, and the retentate side is connected to an expander 44 via S57; the carbon dioxide is enriched in the permeation gas through the membrane module 42, and reaches the heat exchanger 45 through S60 after the atmospheric pressure is recovered through the suction effect of the vacuum pump 43; the heat exchanger 45 is cooled by the process of heating the carbon dioxide liquid, and is connected with the gas mixer 46 through S61 after being cooled; in the gas mixer 46, the gas from S61 and S72 is mixed uniformly and then is connected with a multi-stage compressor 47 through S62, and enters a low-temperature cryogenic separation link.|[0033] In the S62, the flue gas is compressed by a multi-stage compressor and then cooled by stages through heat exchangers 48 and 49; after the high-temperature gas in the multistage compressor 47 is connected with the heat exchanger 48 through S63, the circulating water in the system is used for preliminary cooling, and after cooling, the high-temperature gas is connected with the heat exchanger 49 through S64; the low-temperature energy of the heat exchanger 49 is provided by the expanded and cooled gas of the expander 55 through S74; the flue gas is cooled in stages and then is connected with a 3A molecular sieve drying device 50 through S65, and the dried gas is introduced into an LNG heat exchanger 51 through S66; the low-temperature energy of the LNG heat exchanger is provided by connecting the liquefied natural gas in the liquefied natural gas storage tank 57 with the LNG heat exchanger 51 through S69; the dried gas is cooled by an LNG heat exchanger 51 and then is connected with a gas-liquid separator 52 through a 68; in the gas-liquid separator 52, the liquid carbon dioxide is connected with the low-temperature liquid pump 56 through S75, is connected with the heat exchanger 45 through S76, provides low-temperature energy for the heat exchanger 45, is connected with the heat exchanger 58, provides heat for the gas coming from the expander 44 and heated by the heat exchanger 40, and reduces the temperature of the carbon dioxide liquid to about 31 ℃ to obtain supercritical carbon dioxide fluid; the gas components separated in the gas-liquid separator 52 are connected with the heat exchanger 53 through the S70, the heat exchanger 53 provides low-temperature energy for circulating water in the system, and the gas components are connected with the feed gas side of the membrane module 54 through the S71 after being heated by the heat exchanger 53 and enter a carbon dioxide capturing reflux link.|[0034] The permeate gas side of the membrane module 54 is connected with S72, the trapped gas side is connected with the compression turboexpander 55 through S73, the gas is connected with the expander 61 through S74 after being expanded and depressurized initially, and low-temperature energy is provided for the heat exchanger 49 through S84 after being expanded and cooled further; the inlet of the compressor port of the compressor turboexpander is connected with S83, the outlet of the compressor port of the compressor turboexpander is connected with S81, and air enters a membrane module oxygen enrichment link of the landfill gas decarburization oxygen enrichment plate block through S81 after being pressurized at the compressor end. | Family Number|(78971083)|78971083|Advantages / Prev. Drawbacks|(CN107758664 A)|( . . . ) of resources and energy by combining different capture technologies , can effectively make up the defects of a single technology , and is beneficial to promoting the development of biological energy and carbon capture and storage technology ( BECCS ) . | | Chemical engineering|Environmental technology|Materials, metallurgy | F23G-007/06|F23G-2209/14|F25J-003/08|F25J-2210/66|F25J-2210/70|Y02E-020/34|Y02P-020/10 | F23G-007/06|F23G-2209/14|F25J-003/08|F25J-2210/66|F25J-2210/70|Y02E-020/34|Y02P-020/10 | C01B-032/50|F23G-007/06|F25J-003/08 | C01B-032/50|F23G-007/06|F25J-003/08 | WO2024254510;WO2024254510|CN108256701B|US12377383|US12397260|US12403423|CN110080843B | WO2024254510 112571411 WHO=Examiner SELF=N CAT=X|CN108256701B 80498982 WHO=Examiner SELF=N CAT=A|US12377383 112571400 WHO=Applicant SELF=N|US12397260 112571400 WHO=Applicant SELF=N|US12403423 112571400 WHO=Applicant SELF=N|CN110080843B 85569490 WHO=Examiner SELF=N | CN107081045|CN106554838|CN101643209|US7909911 | CN107081045 77045072 WHO=Examiner SELF=N CAT=Y|CN106554838 75819624 WHO=Examiner SELF=N CAT=Y|CN101643209 6913729 WHO=Examiner SELF=N CAT=A|US7909911 14904623 WHO=Examiner SELF=N CAT=A | 吴满昌,等: "城市生活垃圾沼气的净化技术进展", 《现代化工》 (Cat. A) | CN101643209; US7909911; CN106554838; CN107081045 | LAPSED | (CN107758664)|LAPSED | DEAD | (CN107758664)|DEAD | (CN107758664)|LEGAL DETAILS FOR CN107758664|Actual or expected expiration date=2020-10-13|Legal state=DEAD|Status=LAPSED|Event publication date=2017-11-01|Event code=CN/APP|Event indicator=Pos|Event group=Examination events|Application details|Application country=CN CN201711055664|Application date=2017-11-01|Standardized application number=2017CN-1055664|Event publication date=2018-03-06|Event code=CN/A|Event group=Examination events|Published application|Publication country=CN|Publication number=CN107758664|Publication stage code=A|Publication date=2018-03-06|Standardized publication number=CN107758664|Event publication date=2018-03-06|Event code=CN/PB01|Event group=Examination events|Publication|Event publication date=2018-03-30|Event code=CN/SE01|Event group=Examination events|Entry into substantive examination|Event publication date=2020-10-13|Event code=CN/WD01|Event indicator=Neg|Event group=Event indicating Not In Force|Patent application deemed withdrawn after publication | https://www.orbit.com/GetPDF?gui=crypt&callingapp=EDOFF&key=tO7C931onjmHldRL1Fuic1fn1HwLNiulWeUrB63Jy+vtNjR6EE3+kEF+ZCnEgfSqFvdRXHLDESY=&n=1 | https://sobj.orbit.com/sobj/getMosaic?bdi=na&userid=ZIBNDZZF&key=CN0000000017768782&ekey=2218&xpn=CN107758664&kind=A | https://pss-system.cponline.cnipa.gov.cn/conventionalSearch | https://permalink.orbit.com/RenderStaticFirstPage?XPN=FG2hJKiyHv5vxDM4spJDI5NXe7dphUsu7KxJINoFg8I%3D%26n%3D1&id=0&base=FAMPAT | CN | (CN107758664)|NAME=YANG ZHENGSHAN | (CN107758664)|3 | 1 | 1 | (CN107758664)|Number of Claims: NCL=4|Gazette date: GAZDATE=2018-03-06|Gazette number: GAZNUM=34-1001|Number of Pages: NPAGES=12| | (CN107758664)|CHINESE (CHI) | (CN107758664)|Patent | Titre: (CN107758664)|Process for capturing rubbish landfill gas carbon dioxide Résumé: (CN107758664)|The invention discloses a process for capturing rubbish landfill gas carbon dioxide. The process combines technologies of gas membrane separation, low temperature liquidation and the like, and a landfill gas decarburization oxygen enrichment section and a carbon dioxide capturing section after landfill gas combustion are effectively integrated; liquefied natural gas is used as a fuel in the landfill gas combustion process after cooling in stages of the system, so that the concentration and calorific value of landfill gas methane component are increased; oxygen-enriched air is used as purging gas of landfill gas decarburization oxygen enrichment membrane component, so that the oxygen content in the mixed gas after entrapment gas in a carbon dioxide capturing and backflow link is mixed withosmotic gas of a third-level membrane component is increased, a nitrogen component in flue gas after landfill gas is combusted is effectively reduced, and the energy consumption of the carbon oxide capturing section after landfill gas combustion is reduced; in the membrane component oxygen enrichment section, the pressure of feeding gas is increased by utilizing energy provided by a compressing turbine expander in the two sections; the requirements of each link for heat energy and cold energy in the process are integrated effectively by a heat exchanger, and the energy utilization rate is increased. Autre: (CN107758664)|1. A landfill gas carbon dioxide capture process is characterized in that: the technology of gas membrane separation, low-temperature liquefaction and the like is combined, and the landfill gas decarbonization oxygen-rich plate and the carbon dioxide capture plate after the landfill gas is combusted are effectively integrated together; in the landfill gas decarburization oxygen-enriched block, the landfill gas is subjected to purification treatment and then subjected to decarburization and oxygen enrichment through a countercurrent membrane module to obtain the landfill gas with higher methane equivalent concentration for combustion power generation, and purge gas is provided by air or oxygen-enriched air; the permeate gas is discharged from a permeate gas side of a countercurrent membrane component, is compressed by a compressor and then is cooled in stages, and then is separated from other gas components by a three-stage membrane separation link, the permeate gas of a first-stage membrane component and the permeate gas of a second-stage membrane component are mixed and then are introduced into the low-temperature cryogenic separation link, the permeate gas of the third-stage membrane component and the retentate gas of the membrane component after the low-temperature cryogenic separation are mixed and then are used as one of oxygen sources in the combustion process of landfill gas, the retentate gas of the first-stage membrane component and the retentate gas of the second-stage membrane component are respectively captured by the second-stage membrane component and the third-stage membrane component, the energy of the retentate gas of the third-stage membrane component is recovered and then discharged, the permeate gas is compressed by the multi-stage compressor and then is cooled in stages in the low-temperature cryogenic separation link, carrying out second liquefaction and separation, mixing the carbon dioxide liquid obtained by the two times of liquefaction, introducing the mixed liquid into a low-temperature liquid pump, increasing the pressure to the pressure required by commercial use, and cooling the system by utilizing the low-temperature energy of the system through a heat exchanger; the method comprises the steps that a carbon dioxide trapping block is formed after landfill gas is combusted, after two-stage cooling is conducted on combusted flue gas, gas-liquid separation and preliminary dehydration drying are conducted, gas components are separated through a membrane module, trapped gas energy is recovered and then discharged, the permeated gas and the permeated gas in the membrane module after low-temperature deep cooling are uniformly mixed and then enter a low-temperature deep cooling separation link, after pressurization of a multi-stage compressor, the two-stage cooling is conducted firstly, then, further dehydration drying is conducted through a molecular sieve, then, liquefaction of carbon dioxide is achieved through cold energy of liquefied natural gas, after gas-liquid separation, carbon dioxide liquid passes through a low-temperature liquid pump, the gas components are further trapped through the membrane module, and the trapped gas energy is recovered and then discharged; in the decarbonization and oxygen enrichment link of the landfill gas and after the landfill gas is combusted, the carbon dioxide capture block utilizes natural gas with cold energy as a supplementary component of methane in the landfill gas to be combusted together with the landfill gas.|2. The landfill gas carbon dioxide capture process of claim 1, wherein: the landfill gas decarburization oxygen enrichment block can be divided into a membrane module decarburization oxygen enrichment link, a three-stage membrane separation link, a two-step low-temperature cryogenic separation link, a carbon dioxide capture reflux link and a membrane module oxygen enrichment link; in the membrane module decarburization oxygen enrichment link, landfill gas firstly passes through a purification device, the purge gas utilizes oxygen-enriched air in the membrane module oxygen enrichment link, according to the actual gas component situation, when the oxygen-enriched air is insufficient, air can be directly blown into a purge gas inlet of the membrane module through a blower, when the oxygen-enriched air is left, an oxygen source is provided for the landfill gas combustion link, and meanwhile, the amount of the oxygen-enriched air can be controlled by adjusting the pressure value range of a compressor port of a compression turbine expander; in the third-stage membrane separation link, the first and second-stage membrane modules use membrane materials with larger carbon dioxide separation coefficient, the third-stage membrane module uses a commercial air separation membrane, the membrane materials with larger oxygen and nitrogen separation coefficient capture the trapped gas of the first and second-stage membrane modules respectively, the trapped gas of the third-stage membrane module provides low-temperature energy for the second-stage cooling of the compressor after being recovered by the energy of the expander, and then the system circulating water can be continuously cooled or directly discharged through the heat exchanger; in the two-step low-temperature cryogenic separation link, the liquefied natural gas provides cold energy through an LNG heat exchanger, the liquefied natural gas is uniformly mixed and then cooled for the first-stage membrane module permeation gas in the three-stage membrane separation link, then the low-temperature energy is continuously provided for the first-stage cooling of a compressor, and then the low-temperature energy is used as fuel for the landfill gas combustion link to improve the concentration of methane components in the landfill gas; in the two-step low-temperature cryogenic separation link, the low-temperature energy of the carbon dioxide liquid is utilized to firstly cool the flue gas after the pressurization and the temperature rise in the second-step low-temperature cryogenic separation process and then provide the low-temperature energy for the second-step cooling process in the first-step low-temperature cryogenic separation process, and finally provide the low-temperature energy for the permeation gas of the second-stage membrane component in the three-step membrane separation link; in the membrane component oxygen enrichment link, air pressurized at the compressor end of a compression turbine expander is uniformly mixed with air pressurized in a carbon dioxide trapping plate block after landfill gas is combusted, an air separation membrane is used after heat exchange, a membrane component of a membrane material with a large oxygen and nitrogen separation coefficient obtains oxygen-enriched air in permeating gas, and trapped gas can provide low-temperature energy for system circulating water or high-temperature gas after expansion and cooling.|3. The landfill gas carbon dioxide capture process of claim 1, wherein:|the carbon dioxide trapping block after the landfill gas is combusted can be divided into a pressurizing and cooling dehydration link, a membrane separation link, a low-temperature cryogenic separation link and a carbon dioxide trapping reflux link; the low-temperature cryogenic separation link utilizes the cold energy of the liquefied natural gas to obtain lower-temperature natural gas, and the low-temperature energy of the gas is fully utilized to cool a compressor in the pressurization, cooling and dehydration link or cool circulating water cooled by the compressor; after the trapped gas in the membrane separation link is expanded and cooled, low-temperature energy is provided for the second-stage cooling of a compressor in the pressurization cooling dehydration link, and then the carbon dioxide liquid after the temperature of a heat exchanger after a vacuum pump in the membrane separation link is cooled; the trapped gas of the membrane module in the carbon dioxide trapping and refluxing link is firstly subjected to power supply by a compression turbine expander to the compressor end, then is subjected to one-step expansion cooling to provide low-temperature energy for cooling in the second stage of the low-temperature cryogenic separation link, and then can be used for cooling circulating water or high-temperature gas by a heat exchanger.|4. The landfill gas carbon dioxide capture process of claim 1, wherein:|in the landfill gas combustion link, liquefied natural gas which utilizes low-temperature energy in common air and landfill gas decarburization oxygen-enriched plates, permeation gas of a third-stage membrane module in a third-stage membrane separation link, trapped gas in a carbon dioxide trapping backflow link and oxygen-enriched air in part of membrane module oxygen-enriched links are used, and the liquefied natural gas which utilizes the low-temperature energy in the carbon dioxide trapping plates after the landfill gas combustion is proportioned according to a certain air surplus coefficient; flue gas discharged after the landfill gas mixed gas is combusted and generated is subjected to flue gas denitration treatment, then circulating water or low-temperature gas in a system is used for cooling the flue gas, and finally the flue gas is introduced into a carbon dioxide trapping plate block after the landfill gas is combusted. | 29 | Abstract | gpt-4o-mini | no | The article focuses on capturing carbon dioxide from landfill gas, which does not involve biomass energy production or the integration of biomass with carbon capture and storage. |
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