WO2024063808A1 - Procédé de production d'un produit d'hydrogène ayant une intensité de carbone réduite - Google Patents
Procédé de production d'un produit d'hydrogène ayant une intensité de carbone réduite Download PDFInfo
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- WO2024063808A1 WO2024063808A1 PCT/US2023/016819 US2023016819W WO2024063808A1 WO 2024063808 A1 WO2024063808 A1 WO 2024063808A1 US 2023016819 W US2023016819 W US 2023016819W WO 2024063808 A1 WO2024063808 A1 WO 2024063808A1
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- power plant
- biomass power
- hydrogen
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- product
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- 238000000034 method Methods 0.000 title claims abstract description 193
- 239000001257 hydrogen Substances 0.000 title claims abstract description 184
- 229910052739 hydrogen Inorganic materials 0.000 title claims abstract description 184
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 title claims abstract description 170
- 229910052799 carbon Inorganic materials 0.000 title claims abstract description 145
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 title claims abstract description 144
- 230000008569 process Effects 0.000 title claims abstract description 100
- 239000002028 Biomass Substances 0.000 claims abstract description 208
- 238000004519 manufacturing process Methods 0.000 claims abstract description 80
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 49
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 49
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 44
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims abstract description 32
- 239000003546 flue gas Substances 0.000 claims abstract description 28
- 238000002407 reforming Methods 0.000 claims abstract description 26
- 238000012545 processing Methods 0.000 claims abstract description 16
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims description 162
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 claims description 134
- 239000000047 product Substances 0.000 claims description 93
- 229910002092 carbon dioxide Inorganic materials 0.000 claims description 83
- 239000007789 gas Substances 0.000 claims description 74
- 239000001569 carbon dioxide Substances 0.000 claims description 69
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 66
- 229910021529 ammonia Inorganic materials 0.000 claims description 53
- 238000006243 chemical reaction Methods 0.000 claims description 36
- 238000002485 combustion reaction Methods 0.000 claims description 33
- 230000015572 biosynthetic process Effects 0.000 claims description 26
- 238000003786 synthesis reaction Methods 0.000 claims description 26
- 230000005611 electricity Effects 0.000 claims description 25
- 238000002453 autothermal reforming Methods 0.000 claims description 24
- 239000003345 natural gas Substances 0.000 claims description 24
- 238000000629 steam reforming Methods 0.000 claims description 23
- 238000000746 purification Methods 0.000 claims description 21
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 21
- 238000002309 gasification Methods 0.000 claims description 18
- 238000007906 compression Methods 0.000 claims description 17
- 230000006835 compression Effects 0.000 claims description 17
- 150000002431 hydrogen Chemical class 0.000 claims description 16
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 14
- 239000002737 fuel gas Substances 0.000 claims description 14
- 229910000069 nitrogen hydride Inorganic materials 0.000 claims description 14
- 239000010813 municipal solid waste Substances 0.000 claims description 12
- 238000000926 separation method Methods 0.000 claims description 10
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 claims description 9
- 239000001301 oxygen Substances 0.000 claims description 9
- 229910052760 oxygen Inorganic materials 0.000 claims description 9
- 239000013067 intermediate product Substances 0.000 claims description 8
- 239000000446 fuel Substances 0.000 claims description 7
- 229910052757 nitrogen Inorganic materials 0.000 claims description 7
- 239000002699 waste material Substances 0.000 claims description 7
- 238000010276 construction Methods 0.000 claims description 6
- 239000010794 food waste Substances 0.000 claims description 6
- 239000002803 fossil fuel Substances 0.000 claims description 6
- 238000012994 industrial processing Methods 0.000 claims description 6
- 101100098973 Mus musculus Cct5 gene Proteins 0.000 claims description 5
- 239000002154 agricultural waste Substances 0.000 claims description 5
- 238000005057 refrigeration Methods 0.000 claims description 4
- 150000001412 amines Chemical class 0.000 description 21
- 238000010438 heat treatment Methods 0.000 description 12
- 238000001991 steam methane reforming Methods 0.000 description 11
- 238000005516 engineering process Methods 0.000 description 10
- 238000010795 Steam Flooding Methods 0.000 description 8
- 238000010586 diagram Methods 0.000 description 7
- 230000007935 neutral effect Effects 0.000 description 7
- 238000011144 upstream manufacturing Methods 0.000 description 7
- 230000009919 sequestration Effects 0.000 description 6
- 229910002091 carbon monoxide Inorganic materials 0.000 description 5
- 239000007788 liquid Substances 0.000 description 5
- 238000011084 recovery Methods 0.000 description 5
- 230000000035 biogenic effect Effects 0.000 description 4
- 230000008929 regeneration Effects 0.000 description 4
- 238000011069 regeneration method Methods 0.000 description 4
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- 230000008901 benefit Effects 0.000 description 3
- 239000005431 greenhouse gas Substances 0.000 description 3
- 238000007254 oxidation reaction Methods 0.000 description 3
- 230000009467 reduction Effects 0.000 description 3
- 238000006722 reduction reaction Methods 0.000 description 3
- MYMOFIZGZYHOMD-UHFFFAOYSA-N Dioxygen Chemical compound O=O MYMOFIZGZYHOMD-UHFFFAOYSA-N 0.000 description 2
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 2
- 238000010521 absorption reaction Methods 0.000 description 2
- 239000003054 catalyst Substances 0.000 description 2
- 230000003197 catalytic effect Effects 0.000 description 2
- ZZUFCTLCJUWOSV-UHFFFAOYSA-N furosemide Chemical compound C1=C(Cl)C(S(=O)(=O)N)=CC(C(O)=O)=C1NCC1=CC=CO1 ZZUFCTLCJUWOSV-UHFFFAOYSA-N 0.000 description 2
- 125000004435 hydrogen atom Chemical group [H]* 0.000 description 2
- 230000008676 import Effects 0.000 description 2
- 239000012528 membrane Substances 0.000 description 2
- 230000003647 oxidation Effects 0.000 description 2
- -1 propane and butanes) Chemical compound 0.000 description 2
- 238000010977 unit operation Methods 0.000 description 2
- MKKVKFWHNPAATH-UHFFFAOYSA-N [C].N Chemical compound [C].N MKKVKFWHNPAATH-UHFFFAOYSA-N 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 235000013844 butane Nutrition 0.000 description 1
- 150000001721 carbon Chemical class 0.000 description 1
- 239000000969 carrier Substances 0.000 description 1
- 238000010531 catalytic reduction reaction Methods 0.000 description 1
- 239000000356 contaminant Substances 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 239000000498 cooling water Substances 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000005868 electrolysis reaction Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
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- 238000010348 incorporation Methods 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
- 239000007924 injection Substances 0.000 description 1
- VUZPPFZMUPKLLV-UHFFFAOYSA-N methane;hydrate Chemical compound C.O VUZPPFZMUPKLLV-UHFFFAOYSA-N 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical class CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 1
- 230000036284 oxygen consumption Effects 0.000 description 1
- 239000001294 propane Substances 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 238000000197 pyrolysis Methods 0.000 description 1
- 238000003908 quality control method Methods 0.000 description 1
- 238000004064 recycling Methods 0.000 description 1
- 238000006057 reforming reaction Methods 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 239000002594 sorbent Substances 0.000 description 1
- 238000001179 sorption measurement Methods 0.000 description 1
- 150000003464 sulfur compounds Chemical class 0.000 description 1
- 238000012546 transfer Methods 0.000 description 1
- 238000010792 warming Methods 0.000 description 1
Classifications
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
- C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
- C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
- C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
- C01B3/38—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01C—AMMONIA; CYANOGEN; COMPOUNDS THEREOF
- C01C1/00—Ammonia; Compounds thereof
- C01C1/02—Preparation, purification or separation of ammonia
- C01C1/04—Preparation of ammonia by synthesis in the gas phase
- C01C1/0405—Preparation of ammonia by synthesis in the gas phase from N2 and H2 in presence of a catalyst
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
- C10J3/00—Production of combustible gases containing carbon monoxide from solid carbonaceous fuels
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/02—Processes for making hydrogen or synthesis gas
- C01B2203/0205—Processes for making hydrogen or synthesis gas containing a reforming step
- C01B2203/0227—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step
- C01B2203/0233—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step the reforming step being a steam reforming step
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/02—Processes for making hydrogen or synthesis gas
- C01B2203/0205—Processes for making hydrogen or synthesis gas containing a reforming step
- C01B2203/0227—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step
- C01B2203/0244—Processes for making hydrogen or synthesis gas containing a reforming step containing a catalytic reforming step the reforming step being an autothermal reforming step, e.g. secondary reforming processes
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/02—Processes for making hydrogen or synthesis gas
- C01B2203/0283—Processes for making hydrogen or synthesis gas containing a CO-shift step, i.e. a water gas shift step
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
- C01B2203/0465—Composition of the impurity
- C01B2203/0475—Composition of the impurity the impurity being carbon dioxide
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
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- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
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- C01B2203/068—Ammonia synthesis
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- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/08—Methods of heating or cooling
- C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
- C01B2203/0833—Heating by indirect heat exchange with hot fluids, other than combustion gases, product gases or non-combustive exothermic reaction product gases
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/08—Methods of heating or cooling
- C01B2203/0805—Methods of heating the process for making hydrogen or synthesis gas
- C01B2203/085—Methods of heating the process for making hydrogen or synthesis gas by electric heating
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- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
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- C01B2203/1205—Composition of the feed
- C01B2203/1211—Organic compounds or organic mixtures used in the process for making hydrogen or synthesis gas
- C01B2203/1235—Hydrocarbons
- C01B2203/1241—Natural gas or methane
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- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/12—Feeding the process for making hydrogen or synthesis gas
- C01B2203/1205—Composition of the feed
- C01B2203/1211—Organic compounds or organic mixtures used in the process for making hydrogen or synthesis gas
- C01B2203/1235—Hydrocarbons
- C01B2203/1247—Higher hydrocarbons
-
- C—CHEMISTRY; METALLURGY
- C01—INORGANIC CHEMISTRY
- C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
- C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
- C01B2203/80—Aspect of integrated processes for the production of hydrogen or synthesis gas not covered by groups C01B2203/02 - C01B2203/1695
- C01B2203/86—Carbon dioxide sequestration
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
- C10J2300/00—Details of gasification processes
- C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
- C10J2300/0913—Carbonaceous raw material
- C10J2300/0916—Biomass
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
- C10J2300/00—Details of gasification processes
- C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
- C10J2300/0953—Gasifying agents
- C10J2300/0956—Air or oxygen enriched air
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
- C10J2300/00—Details of gasification processes
- C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
- C10J2300/0953—Gasifying agents
- C10J2300/0959—Oxygen
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
- C10J2300/00—Details of gasification processes
- C10J2300/09—Details of the feed, e.g. feeding of spent catalyst, inert gas or halogens
- C10J2300/0953—Gasifying agents
- C10J2300/0973—Water
- C10J2300/0976—Water as steam
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10J—PRODUCTION OF PRODUCER GAS, WATER-GAS, SYNTHESIS GAS FROM SOLID CARBONACEOUS MATERIAL, OR MIXTURES CONTAINING THESE GASES; CARBURETTING AIR OR OTHER GASES
- C10J2300/00—Details of gasification processes
- C10J2300/16—Integration of gasification processes with another plant or parts within the plant
- C10J2300/1671—Integration of gasification processes with another plant or parts within the plant with the production of electricity
- C10J2300/1675—Integration of gasification processes with another plant or parts within the plant with the production of electricity making use of a steam turbine
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
- C10K3/00—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide
- C10K3/02—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment
- C10K3/04—Modifying the chemical composition of combustible gases containing carbon monoxide to produce an improved fuel, e.g. one of different calorific value, which may be free from carbon monoxide by catalytic treatment reducing the carbon monoxide content, e.g. water-gas shift [WGS]
Definitions
- the present invention relates to a method and process for producing hydrogen product having reduced carbon intensity. More specifically, the process includes a method for the production of hydrogen by autothermal reforming, steam methane reforming, or a combination of autothermal reforming and steam reforming of hydrocarbons, where the energy and/or process steam for hydrocarbon reforming, syngas conversion, and or carbon capture is provided by the combustion or gasification of various forms of biomass to reduce the carbon intensity of the hydrogen product.
- the process also includes a similar method for the production of reduced carbon intensity hydrogen derivatives, specifically ammonia, where the energy and/or process steam to produce the hydrogen derivative is generated from the combustion or gasification of various forms of biomass. In both methods, the biogenic carbon dioxide produced from the combustion or gasification of biomass is separated and removed in a carbon capture unit.
- Hydrogen is widely considered a strong alternative as a decarbonized energy carrier and storage medium to reduce the carbon footprint of many industries, transportation, services, etc.
- hydrocarbons most typically natural gas
- two approaches are utilized in industry for reforming: (1) steam reforming is the endothermic reaction of water with hydrocarbon to produce synthesis gas, with the carbon monoxide in the synthesis gas shifted to carbon dioxide and hydrogen using the water gas shift reaction; and (2) autothermal reforming combines the exothermic oxidation of hydrocarbon with the steam reforming reaction in a single unit.
- Most existing hydrogen production units are utilizing a steam methane reformer (SMR) design.
- SMR steam methane reformer
- One option is hydrocarbon reforming with carbon capture.
- the captured carbon dioxide may be sequestered in a geologic repository or permanently stored in a for-use application.
- Hydrogen carbon intensity may be evaluated using a life cycle analysis methodology such as Argonne National Laboratory’s Greenhouse Gases, Regulated Emissions, and Energy Use in Technologies Model (GREET).
- carbon intensity refers to a measure of the amount of equivalent carbon dioxide (CCLe emitted to produce a specified amount of a product, such as hydrogen or ammonia.
- CO2e is a common unit used to sum various greenhouse gases based on their global warming potential (GWP).
- Hydrogen carbon intensity is frequently rated in kilograms of equivalent carbon dioxide per kilogram of hydrogen (kg CCbe I kg H2). Ammonia carbon intensity is similarly measured in kg CO2e I kg NH3.
- Hydrogen production by hydrocarbon reforming is an endothermic process that requires both heat and energy, both of which contribute to the overall CO2e emissions of the hydrogen production process.
- Sources of CO2e emissions in the hydrogen production process comprise upstream emissions associated with the hydrocarbon feedstock (e.g. leakage from pipelines, energy emissions associated with processing, transportation, and compression of the hydrocarbon feedstock), emissions associated with the production of imported power or steam, and uncaptured CO2e emissions associated with the hydrogen reforming process (e.g. fired heater flue gases).
- the upstream emissions associated with the hydrocarbon feedstock are inherent to the process and can only be reduced, not fully eliminated, with lower carbon intensity feeds.
- the uncaptured CCLe emissions within the hydrogen plant battery limits can be reduced or eliminated with the use of carbon capture technology or modifications to heat transfer equipment such as utilizing hydrogen fired heaters to eliminate carbon dioxide in the flue gas.
- electricity and/or steam is imported to the facility.
- low or neutral carbon power solar, wind, hydro, or nuclear power
- the CChe emissions associated with the production of imported power or steam can be reduced or eliminated.
- the present invention is directed to a method for producing hydrogen product having a carbon intensity preferably less than about 1.0 kg CC e / kg H2, more preferably less than about 0.45 kg CChe / kg H2, and most preferably less than about 0.0 kg CChe / kg H2.
- the method includes the steps of (a) converting a hydrocarbon feedstock to a hydrogen product using a hydrocarbon reforming process; (b) providing at least some of the required energy for the hydrogen production process from a biomass power plant; and (c) processing one or more gas streams containing carbon dioxide from the biomass power plant and hydrogen reforming process in one or more carbon capture units to reduce CChe emissions.
- the method further includes providing at least some of the required energy for one or more carbon capture units from the biomass power plant.
- the method further includes providing substantially all of the required energy for the hydrogen production process from the biomass power plant.
- the energy produced from the biomass power plant may include: (a) electricity generated from work produced by a Rankine cycle, Brayton cycle, or integrated gasification combined cycle; (b) steam that can be used as process steam in the reforming and water gas shift reactions; (c) steam that can be used as thermal energy; and (d) steam that can be used to power a mechanical drive for one or more compressors, pumps, or other motors generating shaft torque.
- the energy produced from the biomass power plant may be generated by direct combustion or gasification of the biomass feedstock.
- the biomass feedstock comprises one or more renewably sourced fuels selected from woody biomass, municipal solid waste, sorted municipal solid waste, food waste, agricultural waste, landfill diversion, hurricane and construction debris, industrial processing biomass waste, renewable natural gas, or a combination thereof.
- the biomass feedstock may also include one or more co-fired fossil fuels.
- the hydrogen production process may also produce a tail gas from the hydrogen purification unit that is also co-fired with the biomass feedstock in the biomass power plant.
- the present invention is also directed to a hydrogen product produced according to the methods provided herein.
- the hydrogen product preferably has a carbon intensity less than about 1.0 kg CChe / kg H2, more preferably less than about 0.45 kg CC e / kg H2, and most preferably less than about 0.0 kg CChe / kg H2.
- the present invention is also directed to a method for producing ammonia product having a carbon intensity preferably less than about 1.0 kg CC e / kg NH3, more preferably less than about 0.5 kg CC e / kg NH3, and most preferably less than about 0.0 kg CC e / kg NH3.
- the method includes the steps of: (a) converting a hydrocarbon feedstock to a hydrogen intermediate product using a hydrocarbon reforming process; (b) converting the hydrogen intermediate product to an ammonia product using an ammonia synthesis process; (c) providing at least some of the required energy for the hydrogen production process and the ammonia synthesis process from a biomass power plant; and (d) processing one or more gas streams containing carbon dioxide from the biomass power plant and the hydrocarbon reforming process in one or more carbon capture units to reduce CChe emissions.
- the method further includes providing at least some of the required energy for the one or more carbon capture units from the biomass power plant.
- the method further includes providing substantially all of the required energy for the hydrocarbon reforming process from the biomass power plant.
- the method further includes providing substantially all of the required energy for the ammonia synthesis process from the biomass power plant.
- the present invention is also directed to an ammonia product produced according to the methods provided herein.
- the ammonia product preferably has a carbon intensity less than about 1.0 kg CChe I kg NH3, more preferably less than about 0.5 kg CChe / kg NH3, and most preferably less than about 0.0 kg C'CTe / kg NH3.
- FIG. 1 depicts a process flow diagram for the production of hydrogen, in which required energy is produced in a biomass power plant with carbon capture.
- FIG. 2 depicts a process flow diagram for the production of hydrogen utilizing steam methane reforming with post-combustion carbon capture, in which required energy is produced in a biomass power plant with carbon capture.
- FIG. 3 depicts a process flow diagram for the production of hydrogen utilizing steam methane reforming with syngas carbon capture and post-combustion carbon capture, in which required energy is produced in a biomass power plant with carbon capture.
- FIG. 4 depicts a process flow diagram for the production of hydrogen utilizing auto-thermal reforming, in which required energy is produced in a biomass power plant with carbon capture.
- FIG. 5 depicts a process flow diagram for the process of FIG. 4, in which tail gas/reject gas is sent to the biomass power plant for conversion to energy.
- FIG. 6 depicts a process flow diagram for the process of FIG. 4, in which tail gas/reject gas is combusted in a fired preheater upstream of the auto-thermal reformer.
- FIG. 7 depicts a process flow diagram for the production of the hydrogenderivative ammonia, in which required energy is produced in a biomass power plant with carbon capture.
- the present invention relates to a method and process for producing hydrogen in which the energy for the process is provided by the combustion or gasification of various forms of biomass to reduce the carbon intensity of the hydrogen product to less than 1.0 kg CChe / kg H2, more preferably less than 0.45 kg CChe I kg H2, and most preferably less than 0.0 kg CChe / kg H2.
- the biogenic carbon dioxide produced from the combustion or gasification of biomass is separated and removed in a carbon capture unit.
- the electricity generated in the biomass power plant can equal, but does not have to equal, the total amount of electricity required for the hydrogen production plant.
- the biomass power plant can be sized to generate adequate electrical power to offset enough import grid power, and thereby achieve a targeted hydrogen carbon intensity.
- the biomass feed to the biomass power plant can be a variety of fuel mixes including but not limited to: woody biomass, municipal solid waste (MSW), sorted MSW, food waste, agriculture waste, landfill diversion, hurricane and construction debris, industrial processing biomass waste, and renewable natural gas.
- biomass feed to the biomass power plant can be a variety of fuel mixes including but not limited to: woody biomass, municipal solid waste (MSW), sorted MSW, food waste, agriculture waste, landfill diversion, hurricane and construction debris, industrial processing biomass waste, and renewable natural gas.
- fossil fuels including but not limited to natural gas and/or fuel gas (i.e. propane and butanes)
- propane and butanes can also be co-fired with the biomass as required or desired.
- the biomass power plant is selected from a Rankine cycle, or a Brayton cycle, or an integrated gasification combined cycle (IGCC) which consist of both a Rankine cycle and Brayton cycle.
- IGCC integrated gasification combined cycle
- the biomass power plant configuration comprises a Rankine cycle
- a biomass boiler produces heat from the direct combustion of biomass to generate steam for the Rankine cycle.
- the biomass boiler can either be a traditional air fired boiler or oxy-fired boiler using oxygen generated in an air separation unit (ASU) or otherwise supplied by a third-party.
- ASU air separation unit
- the gasification of biomass produces a syngas product, with or without steam generation, that is purified before being combusted in the Brayton cycle.
- the exhaust heat from the Brayton cycle can be used to generate steam for a Rankine cycle.
- biomass power plant 10 can be configured to directly combust the biomass feedstock 101 in a biomass boiler to generate steam.
- biomass power plant 10 can be configured as an IGCC power plant in which the biomass feedstock is gasified to create a syngas product with or without steam generation.
- the syngas can be combusted as fuel in a Brayton cycle gas turbine to generate electricity 103-ELEC.
- Steam 103-STM can also be generated with a heat recovery steam generator (HRSG) on the turbine exhaust. This steam can be used in a Rankine cycle to generate additional electricity 103-ELEC.
- HRSG heat recovery steam generator
- the generated steam from the biomass power plant can be sent to a steam turbine to produce electricity 103-ELEC.
- the steam 103-STM can also be sent directly to hydrogen plant 11, or can be extracted from the turbine and sent to hydrogen plant 11 depending on the steam pressure level requirements.
- This steam 103-STM can be used as process steam for the reforming and water gas shift reactions in hydrogen plant 11 or as thermal energy (such as process heating of an amine regenerator reboiler). Additional uses of this carbon negative energy (103-ELEC and 103-STM) within hydrogen plant 1 1 are discussed herein with respect to additional embodiments of the present invention.
- hydrocarbon feed 104 is reformed by either autothermal reforming, steam reforming, or a combination of autothermal reforming and steam reforming to produce low, neutral, and/or negative carbon intensity hydrogen product 105.
- autothermal reforming the required oxygen can be provided by an ASU, membrane, or other commercially available oxygen production technology, or can be provided at the plant fence line by a third-party supplier.
- hydrocarbon feed 104 includes but is not limited to fossil based natural gas, renewable natural gas, biogas, refinery off-gases, fuel gas, naphtha, and/or renewable naphtha.
- the low, neutral, and/or negative carbon intensity hydrogen product 105 can be utilized to produce low, neutral, and/or negative carbon intensity hydrogen derivatives and/or hydrogen carriers, including but not limited to ammonia.
- Carbon dioxide can be all or partially captured from the flue gas stream from the biomass power plant and from the syngas stream and/or flue gas stream from the hydrogen plant.
- the purified carbon dioxide streams 102 and 106 can be compressed and sent to geologic sequestration or can be used external to the process.
- Carbon dioxide captured in the biomass power plant and any flue gas streams in the hydrogen plant, from either a fired preheater, utility boiler, and/or reformer, can be compressed in a single CO2 compression unit 12.
- Biomass power plant 10 and hydrogen plant 11 can also have separate CO2 compression units, not shown.
- FIG. 2 illustrates a hydrogen production plant 11 utilizing steam methane reforming (SMR) with post-combustion carbon capture only.
- SMR steam methane reforming
- Carbon negative energy 103-ELEC and 103-STM which is generated in the biomass power plant 10, can be sent to hydrogen plant 11 for various uses as described below.
- Hydrocarbon feed 104 goes through the feed purification 20 to remove any sulfur compounds and other contaminants.
- the feed can also be compressed depending on the upstream operating pressure of the feed.
- energy from biomass power plant 10 can be supplied in the form of electricity 103-ELEC and/or steam 103-STM for driving the feed gas compressor.
- the purified feed is then sent to reformer 21.
- a pre-reformer may or may not be included as part of reformer 21 as would be understood by a person having ordinary skill in the art.
- the catalytic SMR reaction in which steam and hydrocarbons, mainly methane, are converted to syngas, which consists of carbon monoxide and hydrogen, takes place in reformer 21.
- Biomass power plant 10 can provide both electrical energy 103-ELEC for auxiliary equipment, instrumentation, and controls, and process steam 103-STM to reformer 21 for the SMR reaction.
- fuel gas is combusted in the presence of air in a fired heater outside the reformer tubes. The heat of combustion drives the endothermic, SMR reaction.
- the fuel gas preferably consists of one or more of natural gas, hydrogen, and/or tail gas/reject gas 208 from the hydrogen purification unit 26.
- the purified feed undergoing the SMR reaction passes through the reformer tubes packed with catalyst and exits the reformer as syngas 202.
- Flue gas 203 from the combustion of the fuel gas in the fired heater exits the reformer stack at low or atmospheric pressure.
- the heat of combustion in SMR flue gas 203 can be converted to make steam 204 from boiler feed water.
- Steam 204 can be sent to turbine 27 at biomass power plant 10 to generate additional electricity.
- steam 204 can be used elsewhere in hydrogen plant 11, or can be sent to a separate steam turbine located in hydrogen plant 11 to create additional electricity, or can be used external to the process (e.g. district heating).
- Flue gas 203 can be sent to a post-combustion capture (PCC) unit 22 where the carbon dioxide in the flue gas is separated into purified carbon dioxide 106-PCC using either cryogenic process or an amine-based solution.
- the PCC unit 22 can receive carbon negative energy from biomass power plant 10 in three forms: (1) electrical power 103-ELEC which can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the amine regenerator reboiler (amine-based carbon capture); and (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- the PCC unit 22 can be combined (not shown) with the biomass power plant 10’ s PCC unit 29.
- CO2 compression 12 can use electrical energy 103-ELEC from biomass power plant 10 to power the motor for the CO2 compressor, power auxiliary equipment, instrumentation, and controls.
- steam 103-STM from biomass power plant 10 can be supplied directly to power the mechanical drive (e.g. turbines) for the CO2 compressor.
- Hydrogen plant 1 1 and biomass power plant 10 can alternatively have individual CO2 compression units (not shown) instead of the combined CO2 compression 12.
- Syngas 202 generated by the SMR is sent to the water-gas shift (WGS) reactor system 25 where carbon monoxide and water in the syngas 202 undergo a WGS reaction to form carbon dioxide and hydrogen in a single stream 206.
- Carbon negative energy can be supplied to the WGS in three forms: (1) electrical power 103-ELEC that can be used to provide power to pump and/or fan motors, including but not limited to the process condensate pumps, syngas air cooled heat exchangers, auxiliary equipment, instrumentation, and controls; (2) process steam 103-STM for use in the WGS reaction; or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps.
- hydrogen product purification unit 26 the carbon dioxide and/or methane is separated from the hydrogen to create a purified hydrogen product 105 that can be compressed for use.
- the hydrogen purification unit 26 consists of a pressure swing adsorption (PSA) system, but other alternative technologies known in the art, such as membranes, can also be utilized to achieve purified hydrogen product 105.
- PSA pressure swing adsorption
- the carbon dioxide in tail gas/reject gas 208 along with the carbon dioxide that is produced from combustion in the fired heater can also be captured in PCC unit 22.
- Biomass power plant 10 can provide both electrical energy 103-ELEC to power the motor for the hydrogen compressor, instrumentation, and controls.
- steam 103-STM from biomass power plant 10 can be supplied directly to power the mechanical drive (e.g. turbines) for the hydrogen compressor.
- the energy and/or steam from biomass power plant 10 is generated by combusting the biomass feedstock 101 in boiler 24.
- the heat from the combustion of biomass feedstock 101 can be used to produce steam 211 from boiler feed water 210 that can be used to generate electricity in steam turbine 27.
- steam 211 can also be sent directly to hydrogen plant 11 for use as thermal energy for process heating requirements and/or power the mechanical drive for pumps and compressors, and/or be used as process steam to either the SMR or WGS reactions.
- Flue gas 212 from boiler 24 is sent through air quality control system 28, where it passes through several emissions reduction technologies such as a pulse jet fabric filter, dry sorbent injection system, selective catalytic reduction (SCR), and carbon monoxide catalyst. These environmental train technologies are optional to treat flue gas 212 depending on the specific site needs, and would be well understood by a person having ordinary skill in the art.
- electricity 103-ELEC and steam 103-STM from biomass power plant can be generated by the gasification of the biomass feedstock.
- the gasification of the biomass in the presence of air, steam, or oxygen results in a syngas product consisting of mostly carbon monoxide and hydrogen. Any impurities produced in the syngas are removed in a syngas clean-up step.
- the syngas can be combusted in a gas turbine to produce electricity 103-ELEC.
- a HRSG can be included on the turbine exhaust to produce steam.
- This steam can be used to generate additional electricity in a steam turbine or can be sent directly to the hydrogen plant for use as thermal energy for process heating requirements and/or power the mechanical drive for pumps and compressors, and/or be used as process steam to either the SMR or WGS reactions.
- the exhaust from the HRSG can be sent to a postcombustion carbon capture unit to reduce COze emissions.
- the treated flue gas 213 is then sent to the PCC unit 29.
- the PCC technology employed for carbon capture can include a cryogenic process or an amine-based solution.
- the PCC unit 29 can receive carbon negative energy in three forms: (1) electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the amine regenerator reboiler (amine-based carbon capture); or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls
- Purified carbon dioxide 102 can be compressed in compression step 12 for geologic sequestration or can be used external to the process.
- CO2 compression step 12 can use electrical energy 103-ELEC from biomass power plant 10 to power the motor for the CO2 compressor, power auxiliary equipment, instrumentation, and controls.
- steam 103-STM from biomass power plant 10 can be supplied directly to power the mechanical drive (e.g. turbines) for the CO2 compressor.
- Energy from biomass power plant 10 can also be used in the balance of plant, offsites, and utility systems.
- the carbon negative energy can be in three forms: (1) electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the boiler feed water pumps cooling water pumps, cooling tower fans, compressors located in the air separation unit, auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the stripping steam for the deaerator or steam tracing; or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the boiler feed water pumps cooling water pumps, cooling tower fans, compressors located in the air separation unit, auxiliary equipment, instrumentation, and controls
- thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the stripping steam for the
- an SMR consists of a fired heater as described above; however, depending on the hydrogen reforming configuration an electrified steam methane reformer (eSMR) can also be utilized to convert the steam and hydrocarbon feed to syngas. Where the configuration includes an eSMR, it is well understood that no flue gas would be generated. In this configuration, the biomass power plant 10 can provide the electrical energy 103-ELEC directly to the reformer.
- eSMR electrified steam methane reformer
- the heat for the endothermic reaction could be provided by the direct combustion of biomass.
- the biogenic carbon dioxide in flue gas 203 can be sent to PCC unit 22.
- FIG. 3 illustrates a similar embodiment to FIG. 2 for an SMR having an additional unit operation, specifically syngas carbon capture unit 39.
- the hydrogen and carbon dioxide product 306 from the WGS reactor 25 can be sent to syngas carbon capture unit 39 where the carbon dioxide is separated using either a cryogenic process or an amine-based solution.
- Hydrogen stream 315 from syngas carbon capture unit 39 is sent to the purification unit 26, with product purification tail gas/reject gas 208, consisting of mostly of hydrogen, can be used for combustion in reformer 21.
- Captured carbon dioxide 106-SYN can be compressed in compression step 12 for geologic sequestration or can be used external to the process.
- Syngas carbon capture unit 39 can receive carbon negative energy from biomass power plant 10 in three forms: (1) electrical power 103-ELEC which can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the amine regenerator reboiler (amine-based carbon capture); or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- electrical power 103-ELEC which can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls
- thermal energy in the form of steam 103-STM for process heating requirements including but not limited to the amine regenerator reboiler (amine-based carbon capture)
- FIG. 4 illustrates the use of auto-thermal reforming (ATR) instead of steam methane reforming as shown in FIGS. 2 and 3. Similar to FIGS. 2 and 3, the hydrocarbon feed 104 goes through feed purification and compression 20.
- ATR auto-thermal reforming
- the purified feed is preheated and then reformed in reformer 41.
- preheating the purified feed to reformer 41 including but not limited to a fired preheater and/or a gas heated reformer (GHR).
- GHR gas heated reformer
- the fuel gas to the fired preheater can consist of a combination of natural gas, fuel gas, and/or hydrogen.
- the purified feed is heated inside fired heater tubes. Flue gas 418 from the fired preheater exits the reformer stack at low or atmospheric pressure.
- a post-combustion carbon capture unit can also be included to capture the CO2 from the fired preheater flue gas 418.
- the heat of combustion of flue gas 418 can be converted to make steam 204) from boiler feed water.
- Steam 204 can be sent to the turbine 27 at biomass power plant 10 to generate additional electricity.
- steam 204 produced in reformer 41 can be used elsewhere in the hydrogen plant, or can be sent to a separate steam turbine located in hydrogen plant 11 to create additional electricity, or can be used external to the process (e.g. district heating).
- a GHR can be included upstream of reformer 41 to partially reform the feed to the ATR.
- a slip stream of the purified feed bypasses the fired preheater and can be sent directly to the GHR.
- An ATR differs from an SMR in how heat is supplied to the reforming reaction.
- An ATR is a combination of the endothermic steam methane reforming reaction and the exothermic partial oxidation (POX) reaction. The heat produced by the POX reaction is used in the steam methane reforming reaction to generate syngas.
- POX partial oxidation
- the hydrocarbons are partially oxidized, in the presence of high purity oxygen 403 to form syngas product 402. Both reactions occur inside the reactor.
- Biomass power plant 10 can provide both electrical energy 103-ELEC for auxiliary equipment, instrumentation, and controls, and process steam 103-STM to reformer 41 for the steam methane reforming reaction. Steam 417 for the steam methane reforming reaction can also be provided by utility boiler 49.
- the POX reaction requires high purity oxygen 403 which is supplied by the ASU 42.
- Carbon negative energy can be sent to ASU 42 as: (1) electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the liquid oxygen pumps, electric heater for temperature swing absorption (TSA) bed regeneration, auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the TSA bed regeneration; and/or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the liquid oxygen pumps, electric heater for temperature swing absorption (TSA) bed regeneration, auxiliary equipment, instrumentation, and controls
- TSA temperature swing absorption
- thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the TSA bed regeneration
- steam drive energy to power the mechanical drive
- Syngas 402 from reformer 41 is sent to WGS reaction unit 25, syngas carbon capture 39, and a hydrogen product purification unit 26, all of which are similar unit operations to the embodiments described in the third embodiment (FIG. 3).
- Tail gas/reject gas 208 from the hydrogen product purification unit 26 can be sent to utility boiler 49 to provide process steam 417 to ATR 41 and/or the WGS 25.
- the majority of the carbon dioxide and methane contained in tail gas/reject gas 208 has been removed in this embodiment because of the incorporation of the syngas carbon capture unit 39.
- flue gas 405 from utility boiler 49 can be sent to a PCC unit.
- tail gas/reject gas 208 can be recycled (208-RCYL) to the reformer 41 as feed.
- FIG. 5 illustrates a process flow that differs from FIG. 4 in the disposition of the hydrogen product purification tail gas/reject gas 208.
- tail gas/reject gas 208 is sent to boiler 24 in biomass power plant 10.
- the configuration of FIG. 5 reduces the overall equipment count and further integrates the two facilities 10 and 11.
- the concept of sending the hydrogen product purification tail gas/reject gas 208 to biomass plant boiler 24 can also optionally be applied to the embodiments of FIG. 2 or FIG. 3.
- FIG. 5 has the same preheating configurations as FIG. 4, including but not limited to a fired preheater and/or a GHR. Flue gas 418 from the fired preheater can either vent to atmosphere or be sent to a PCC unit depending on the desired carbon capture recovery. Where the configuration includes a standalone GHR, it is well understood that no flue gas would be generated.
- FIG. 6 illustrates a process flow that differs from FIGS. 4 and 5 in the disposition of hydrogen product purification tail gas/reject gas 208.
- Tail gas/reject gas 208 can be combusted in the fired preheater upstream of ATR 41.
- the fuel gas to the fired preheater can also consist of a combination of natural gas, hydrogen, and/or tail gas/reject gas 208 from the hydrogen purification unit 26.
- the flue gas 418 from the fired preheater can be sent to PCC unit 69.
- PCC unit 69 can either be a cryogenic process or an amine-based solution.
- PCC 69 can receive carbon negative energy in three forms: (1) electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the amine regenerator reboiler (amine-based carbon capture); or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the amine pumps (amine-based carbon capture), liquid carbon dioxide pumps (cryogenic carbon capture), auxiliary equipment, instrumentation, and controls
- thermal energy in the form of steam 103-STM for process heating requirements including but not limited to the amine regenerator reboiler (amine-based carbon capture)
- steam drive energy to power the mechanical drive
- the captured carbon dioxide stream 106-PCC can be compressed in compression unit 12 for geologic sequestration or for uses external to the process.
- FIG. 7 illustrates an embodiment in which carbon negative energy is supplied to the production of a hydrogen derivative, specifically ammonia.
- Ammonia product 705 is a low, neutral, and/or negative carbon intensity ammonia that can replace the traditional, carbon-intensive ammonia currently on the market.
- biomass power plant 10 can supply either electricity 103- ELEC and/or steam 103-STM to ammonia synthesis 71 and/or ASU 73 and/or CO2 compression unit 12.
- electricity 103-ELEC from biomass power plant 10 can be used to power the motor for compressors and/or pumps, power auxiliary equipment, instrumentation, and controls.
- steam 103-STM from biomass power plant 10 can be supplied directly to power the mechanical drive for compressors and/or pumps.
- the ammonia synthesis 71 does not produce any carbon dioxide, since hydrogen 704 and nitrogen 708 are the only feedstocks.
- Biomass power plant 10 can offset the CCFe emissions associated with the production of hydrogen and/or CCFe emissions associated with import grid power and/or CCFe emissions associated with nitrogen production.
- Carbon dioxide 102 produced from biomass power plant 10 can be compressed in compression unit 12 for geologic sequestration or can be used external to the process.
- Hydrogen 704 used for ammonia synthesis can be produced through the methods described in Figures 1 -6, and/or can be provided at the plant fence line by a third- party supplier.
- Nitrogen 708 used for ammonia synthesis can be generated in ASU 73 and/or can be provided at the plant fence line by a third-party supplier.
- ASU 73 can be combined with ASU 42 (FIGS. 4-6), which produces oxygen for ATR 41 (FIGS. 4-6).
- Carbon negative energy can be sent to ASU 73 as: (1) electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the liquid oxygen pumps, electric heater for temperature swing absorption (TS A) bed regeneration, auxiliary equipment, instrumentation, and controls; (2) thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the TSA bed regeneration; or (3) steam drive energy to power the mechanical drive (e.g. turbines) of the pumps and/or compressors.
- electrical power 103-ELEC that can be used to provide power to pump and/or compressor motors, including but not limited to the liquid oxygen pumps, electric heater for temperature swing absorption (TS A) bed regeneration, auxiliary equipment, instrumentation, and controls
- thermal energy in the form of steam 103-STM for process heating requirements, including but not limited to the TSA bed regeneration
- steam drive energy to
- Table 2 demonstrates the required energy produced from a biomass power plant with carbon capture to achieve a hydrogen product having desired low carbon intensity for a 300 MMSCFD hydrogen production facility: Table 2
- a hydrogen product having a carbon intensity of 1.0 kg CChe / kg H2 would require 13.73 MW from a biomass power plant with carbon capture, in accordance with certain teachings of the present invention.
- a hydrogen product having a carbon intensity of 0.45 kg CChe / kg H2 would require 18.10 MW from a biomass power plant with carbon capture, in accordance with certain teachings of the present invention.
- a hydrogen product having a carbon intensity of 0.0 kg CChe / kg H2 would require 21.68 MW from a biomass power plant with carbon capture, in accordance with certain teachings of the present invention.
- the present invention is directed to a method for producing hydrogen product having a carbon intensity preferably less than about 1.0 kg CChe / kg H2, more preferably less than about 0.45 kg CChe I kg H2, and most preferably less than about 0.0 kg CChe I kg H2.
- the method includes the steps of (a) converting a hydrocarbon feedstock to a hydrogen product using a hydrocarbon reforming process; (b) providing at least some of the required energy for the hydrogen production process from a biomass power plant; and (c) processing one or more flue gas streams from the biomass power plant in a carbon capture unit to reduce CChe emissions.
- the method further includes providing at least some of the required energy for the carbon capture unit from the biomass power plant.
- the method further includes providing substantially all of the required energy for the hydrogen production process from the biomass power plant.
- the energy produced from the biomass power plant may include: (a) electricity generated from work produced by a Rankine cycle, a Brayton cycle, or an IGCC; (b) steam that can be used as process steam in the reforming and water gas shift reactions; (c) steam that can be used as thermal energy; and (d) steam that can be used to power a mechanical drive for one or more compressors, pumps, or other motors generating shaft torque.
- the energy produced from the biomass power plant may be generated by direct combustion of the biomass feedstock, or by combustion of syngas produced from the gasification of the biomass feedstock.
- the biomass feedstock comprises one or more renewably sourced fuels selected from woody biomass, municipal solid waste, sorted municipal solid waste, food waste, agricultural waste, landfill diversion, hurricane and construction debris, industrial processing biomass waste, renewable natural gas, or a combination thereof.
- the biomass feedstock may also include one or more co-fired fossil fuels.
- the hydrogen production process may also produce a tail gas from the hydrogen purification unit that is also co-fired with the biomass feedstock in the biomass power plant.
- the present invention is directed to a method for producing hydrogen product having a carbon intensity preferably less than about 1.0 kg CCTe / kg H2, more preferably less than about 0.45 kg CCTe / kg H2, and most preferably less than about 0.0 kg CCTe / kg H2.
- the method includes the steps of (a) converting a hydrocarbon feedstock to a hydrogen product using a hydrocarbon reforming process; (b) providing at least some of the required energy for the hydrogen production process from a biomass power plant; and (c) processing one or more gas streams containing carbon dioxide from the biomass power plant and the hydrogen production process in one or more carbon capture units to reduce CO?e emissions.
- the energy produced from the biomass power plant may include: (a) electricity generated from work produced by a Rankine cycle, a Brayton cycle, or an IGCC; (b) steam that can be used as process steam in the reforming and water gas shift reactions; (c) steam that can be used as thermal energy; and (d) steam that can be used to power a mechanical drive for one or more compressors, pumps, or other motors generating shaft torque.
- the method further includes providing at least some of the required energy for the one or more carbon capture units from the biomass power plant.
- the method further includes providing substantially all of the required energy for the hydrogen production process from the biomass power plant.
- the hydrocarbon reforming process is selected from autothermal reforming, steam reforming, or a combination of autothermal reforming and steam reforming.
- the hydrocarbon feedstock is selected from natural gas, renewable natural gas, biogas, refinery off-gases, fuel gas, naphtha, renewable naphtha, or a combination thereof.
- the hydrogen production process comprises pressurizing the hydrocarbon feedstock, such as through compression (gas feed) or pumping (liquid feed), wherein at least some of the required energy for the feedstock pressurization is provided from the biomass power plant.
- a syngas product is produced, wherein at least some of the process steam for the steam reforming reaction is provided from the biomass power plant.
- the method further includes the step of converting the syngas product in a water gas shift reaction to a product comprising carbon dioxide and hydrogen, wherein at least some of the process steam for the water gas shift reaction is provided from the biomass power plant.
- the method further includes the step of processing the carbon dioxide/hydrogen product in a syngas carbon capture unit to create a purified carbon dioxide product and reduce CChe emissions, wherein at least some of the required energy for the syngas carbon capture unit is provided from the biomass power plant.
- the method further includes the step of pressurizing the purified carbon dioxide product, wherein at least some of the required energy for the carbon dioxide pressurization is provided from the biomass power plant.
- the method further includes the step of processing a flue gas stream in a post-combustion carbon capture unit to create a purified carbon dioxide product and reduce CCbe emissions, wherein at least some of the required energy for the postcombustion carbon capture unit is provided from the biomass power plant.
- the method further includes the step of pressurizing the purified carbon dioxide product from the post-combustion carbon capture unit, wherein at least some of the required energy for the carbon dioxide pressurization is provided from the biomass power plant.
- the method further includes the step of combusting as a tail gas from the hydrogen purification unit with the biomass feedstock in the biomass power plant.
- the method further includes the step of compressing the hydrogen product, wherein at least some of the required energy for the hydrogen product compression is provided from the biomass power plant.
- a hydrogen product produced according to the preceding embodiments is provided.
- the hydrogen product preferably has a carbon intensity less than about 1.0 kg CCbe I kg H2, more preferably less than about 0.45 kg CCbe / kg H2, and most preferably less than about 0.0 kg CCbe / kg H2.
- the present invention is directed to a method for producing ammonia product having a carbon intensity preferably less than about 1.0 kg CChe / kg NH3, more preferably less than about 0.5 kg CCbe / kg NH3, and most preferably less than about 0.0 kg CCbe / kg NH3.
- the method includes the steps of: (a) converting a hydrocarbon feedstock to a hydrogen intermediate product using a hydrocarbon reforming process; (b) converting the hydrogen intermediate product to an ammonia product using an ammonia synthesis process; (c) providing at least some of the required energy for the hydrogen production process and the ammonia synthesis process from a biomass power plant; and (d) processing one or more gas streams containing carbon dioxide from the biomass power plant and the hydrocarbon reforming process in one or more carbon capture units to reduce CCbe emissions.
- the method further includes providing at least some of the required energy for the one or more carbon capture units from the biomass power plant.
- the method further includes providing substantially all of the required energy for the one or more carbon capture units from the biomass power plant.
- the method further includes providing substantially all of the required energy for the hydrocarbon reforming process from the biomass power plant.
- the method further includes providing substantially all of the required energy for the ammonia synthesis process from the biomass power plant.
- the energy produced from the biomass power plant may include: (a) electricity generated from work produced by a Rankine cycle, Brayton cycle, or integrated gasification combined cycle; (b) steam that can be used as process steam in the reforming and water gas shift reactions; (c) steam that can be used as thermal energy; and (d) steam that can be used to power a mechanical drive for one or more compressors, pumps, or other motors generating shaft torque.
- the biomass feedstock for the biomass power plant comprises one or more renewably sourced fuels selected from woody biomass, municipal solid waste, sorted municipal solid waste, food waste, agricultural waste, landfill diversion, hurricane and construction debris, industrial processing biomass waste, renewable natural gas, or a combination thereof.
- the biomass feedstock may also include one or more co-fired fossil fuels.
- the hydrogen production process may also produce a tail gas from the hydrogen purification unit that is also co-fired with the biomass feedstock in the biomass power plant.
- the hydrocarbon reforming process is selected from autothermal reforming, steam reforming, or a combination of autothermal reforming and steam reforming.
- the hydrocarbon feedstock is selected from natural gas, renewable natural gas, biogas, refinery off-gases, fuel gas, naphtha, renewable naphtha, or a combination thereof.
- the ammonia synthesis process comprises a syngas compressor that compresses the hydrogen intermediate product and nitrogen to an ammonia converter, wherein at least some of the required energy for the syngas compressor is provided by the biomass power plant.
- the ammonia synthesis process comprises ammonia refrigeration, wherein at least some of the required energy for the ammonia refrigeration is provided from the biomass power plant.
- the ammonia synthesis process comprises ammonia product pressurization, wherein at least some of the required energy for the ammonia product pressurization is provided from the biomass power plant.
- the ammonia synthesis process comprises an air separation unit to provide high purity nitrogen to the ammonia synthesis process, wherein at least some of the required energy for the air separation unit is provided from the biomass power plant.
- the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein.
- the particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings therein. It is therefore evident that the particular embodiments disclosed above may be altered or modified and all such variations are considered within the scope and sprit of the present invention.
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Abstract
L'invention concerne une méthode de production d'un produit d'hydrogène ayant une faible intensité de carbone. La méthode comprend les étapes consistant à : (a) convertir une charge d'hydrocarbures en un produit d'hydrogène à l'aide d'un processus de reformage d'hydrocarbures ; (b) fournir au moins une partie de l'énergie requise pour le processus de production d'hydrogène à partir d'une centrale à biomasse ; et (c) traiter un ou plusieurs flux de gaz de combustion provenant de la centrale à biomasse dans une unité de capture de carbone pour réduire les émissions de CO2e. Le produit d'hydrogène a une intensité de carbone de préférence inférieure à environ 1,0 kg de CO2e / kg H2, plus préférablement inférieure à 0,45 kg CO2e / kg H2, et idéalement inférieure à 0,0 kg de CO2e / kg H2.
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EP23718913.9A EP4367058A1 (fr) | 2022-09-23 | 2023-03-30 | Procédé de production d'un produit d'hydrogène ayant une intensité de carbone réduite |
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US202263409331P | 2022-09-23 | 2022-09-23 | |
US63/409,331 | 2022-09-23 | ||
US18/117,606 US11952276B1 (en) | 2022-09-23 | 2023-03-06 | Process for producing hydrogen product having reduced carbon intensity |
US18/117,606 | 2023-03-06 | ||
US18/118,553 | 2023-03-07 | ||
US18/118,553 US11952274B1 (en) | 2022-09-23 | 2023-03-07 | Process for producing hydrogen product having reduced carbon intensity |
US18/118,887 US11952272B1 (en) | 2022-09-23 | 2023-03-08 | Process for producing hydrogen product having reduced carbon intensity |
US18/118,887 | 2023-03-08 |
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Citations (5)
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US20060207178A1 (en) * | 2003-02-06 | 2006-09-21 | Ztek Corporation | Renewable energy operated hydrogen reforming system |
WO2021110757A1 (fr) * | 2019-12-04 | 2021-06-10 | Haldor Topsøe A/S | Conversion de biogaz en gaz de synthèse pour la production d'hydrocarbures |
US20220119269A1 (en) * | 2019-01-15 | 2022-04-21 | Sabic Global Technologies B.V. | Use of renewable energy in ammonia synthesis |
FR3120317A1 (fr) * | 2021-03-05 | 2022-09-09 | L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude | Installation de production de biométhane et de gaz de synthèse à partir d’un flux de biogaz avec un moyen d’ajustement de la qualité du biogaz |
WO2022217365A1 (fr) * | 2021-04-15 | 2022-10-20 | Iogen Corporation | Procédé et système de production d'hydrogène renouvelable à faible intensité de carbone |
-
2023
- 2023-03-30 WO PCT/US2023/016819 patent/WO2024063808A1/fr unknown
- 2023-03-30 EP EP23718913.9A patent/EP4367058A1/fr active Pending
Patent Citations (5)
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US20060207178A1 (en) * | 2003-02-06 | 2006-09-21 | Ztek Corporation | Renewable energy operated hydrogen reforming system |
US20220119269A1 (en) * | 2019-01-15 | 2022-04-21 | Sabic Global Technologies B.V. | Use of renewable energy in ammonia synthesis |
WO2021110757A1 (fr) * | 2019-12-04 | 2021-06-10 | Haldor Topsøe A/S | Conversion de biogaz en gaz de synthèse pour la production d'hydrocarbures |
FR3120317A1 (fr) * | 2021-03-05 | 2022-09-09 | L'air Liquide Societe Anonyme Pour L'etude Et L'exploitation Des Procedes Georges Claude | Installation de production de biométhane et de gaz de synthèse à partir d’un flux de biogaz avec un moyen d’ajustement de la qualité du biogaz |
WO2022217365A1 (fr) * | 2021-04-15 | 2022-10-20 | Iogen Corporation | Procédé et système de production d'hydrogène renouvelable à faible intensité de carbone |
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