GB2625646A - Process for producing hydrogen - Google Patents
Process for producing hydrogen Download PDFInfo
- Publication number
- GB2625646A GB2625646A GB2319222.2A GB202319222A GB2625646A GB 2625646 A GB2625646 A GB 2625646A GB 202319222 A GB202319222 A GB 202319222A GB 2625646 A GB2625646 A GB 2625646A
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- GB
- United Kingdom
- Prior art keywords
- gas
- stream
- steam
- hydrogen
- unit
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Pending
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- 238000000034 method Methods 0.000 title claims abstract description 133
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 title claims abstract description 127
- 229910052739 hydrogen Inorganic materials 0.000 title claims abstract description 106
- 239000001257 hydrogen Substances 0.000 title claims abstract description 106
- 239000007789 gas Substances 0.000 claims abstract description 215
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract description 158
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 88
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 88
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract description 79
- 239000001569 carbon dioxide Substances 0.000 claims abstract description 79
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 49
- 238000011144 upstream manufacturing Methods 0.000 claims abstract description 44
- 239000002737 fuel gas Substances 0.000 claims abstract description 38
- 238000002407 reforming Methods 0.000 claims abstract description 35
- 238000000746 purification Methods 0.000 claims abstract description 33
- 238000000926 separation method Methods 0.000 claims abstract description 29
- 239000000126 substance Substances 0.000 claims abstract description 18
- 238000004519 manufacturing process Methods 0.000 claims abstract description 14
- 238000000629 steam reforming Methods 0.000 claims description 35
- 239000000203 mixture Substances 0.000 claims description 33
- 239000008246 gaseous mixture Substances 0.000 claims description 26
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 22
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 claims description 19
- 229910052799 carbon Inorganic materials 0.000 claims description 19
- 238000001816 cooling Methods 0.000 claims description 15
- 238000001179 sorption measurement Methods 0.000 claims description 7
- 239000003054 catalyst Substances 0.000 description 31
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 31
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 19
- 239000000446 fuel Substances 0.000 description 14
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical class [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 description 13
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 13
- 239000007788 liquid Substances 0.000 description 13
- 239000001301 oxygen Substances 0.000 description 13
- 229910052760 oxygen Inorganic materials 0.000 description 13
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 12
- 229910002091 carbon monoxide Inorganic materials 0.000 description 11
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 description 10
- 238000006243 chemical reaction Methods 0.000 description 10
- 239000003463 adsorbent Substances 0.000 description 9
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 7
- 238000002453 autothermal reforming Methods 0.000 description 7
- 238000010438 heat treatment Methods 0.000 description 7
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 6
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 6
- 239000002250 absorbent Substances 0.000 description 6
- 230000002745 absorbent Effects 0.000 description 6
- 229910052759 nickel Inorganic materials 0.000 description 6
- -1 magnesium aluminate Chemical class 0.000 description 5
- 239000000463 material Substances 0.000 description 5
- XLOMVQKBTHCTTD-UHFFFAOYSA-N Zinc monoxide Chemical compound [Zn]=O XLOMVQKBTHCTTD-UHFFFAOYSA-N 0.000 description 4
- MCMNRKCIXSYSNV-UHFFFAOYSA-N Zirconium dioxide Chemical compound O=[Zr]=O MCMNRKCIXSYSNV-UHFFFAOYSA-N 0.000 description 4
- 229910021529 ammonia Inorganic materials 0.000 description 4
- 238000002485 combustion reaction Methods 0.000 description 4
- 150000002431 hydrogen Chemical class 0.000 description 4
- 230000000153 supplemental effect Effects 0.000 description 4
- 239000002918 waste heat Substances 0.000 description 4
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 3
- 150000001412 amines Chemical class 0.000 description 3
- 230000006835 compression Effects 0.000 description 3
- 238000007906 compression Methods 0.000 description 3
- 239000000356 contaminant Substances 0.000 description 3
- 230000005611 electricity Effects 0.000 description 3
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 3
- 229910052757 nitrogen Inorganic materials 0.000 description 3
- 239000000376 reactant Substances 0.000 description 3
- 238000003786 synthesis reaction Methods 0.000 description 3
- XKRFYHLGVUSROY-UHFFFAOYSA-N Argon Chemical compound [Ar] XKRFYHLGVUSROY-UHFFFAOYSA-N 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 description 2
- GWEVSGVZZGPLCZ-UHFFFAOYSA-N Titan oxide Chemical compound O=[Ti]=O GWEVSGVZZGPLCZ-UHFFFAOYSA-N 0.000 description 2
- 238000010521 absorption reaction Methods 0.000 description 2
- 230000015572 biosynthetic process Effects 0.000 description 2
- XFWJKVMFIVXPKK-UHFFFAOYSA-N calcium;oxido(oxo)alumane Chemical compound [Ca+2].[O-][Al]=O.[O-][Al]=O XFWJKVMFIVXPKK-UHFFFAOYSA-N 0.000 description 2
- 229910002090 carbon oxide Inorganic materials 0.000 description 2
- 239000002826 coolant Substances 0.000 description 2
- 229910001385 heavy metal Inorganic materials 0.000 description 2
- LELOWRISYMNNSU-UHFFFAOYSA-N hydrogen cyanide Chemical compound N#C LELOWRISYMNNSU-UHFFFAOYSA-N 0.000 description 2
- 239000011261 inert gas Substances 0.000 description 2
- 238000002347 injection Methods 0.000 description 2
- 239000007924 injection Substances 0.000 description 2
- 229910052749 magnesium Inorganic materials 0.000 description 2
- 239000011777 magnesium Substances 0.000 description 2
- 229910052751 metal Inorganic materials 0.000 description 2
- 239000002184 metal Substances 0.000 description 2
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical compound OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 description 2
- 238000002156 mixing Methods 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 229910000069 nitrogen hydride Inorganic materials 0.000 description 2
- 239000008188 pellet Substances 0.000 description 2
- 239000010970 precious metal Substances 0.000 description 2
- 238000011084 recovery Methods 0.000 description 2
- 238000003860 storage Methods 0.000 description 2
- 239000013589 supplement Substances 0.000 description 2
- 239000011787 zinc oxide Substances 0.000 description 2
- RYGMFSIKBFXOCR-UHFFFAOYSA-N Copper Chemical compound [Cu] RYGMFSIKBFXOCR-UHFFFAOYSA-N 0.000 description 1
- 239000005751 Copper oxide Substances 0.000 description 1
- MYMOFIZGZYHOMD-UHFFFAOYSA-N Dioxygen Chemical compound O=O MYMOFIZGZYHOMD-UHFFFAOYSA-N 0.000 description 1
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 1
- 229910003294 NiMo Inorganic materials 0.000 description 1
- KJTLSVCANCCWHF-UHFFFAOYSA-N Ruthenium Chemical compound [Ru] KJTLSVCANCCWHF-UHFFFAOYSA-N 0.000 description 1
- 229910021536 Zeolite Inorganic materials 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 229910052786 argon Inorganic materials 0.000 description 1
- 229910052785 arsenic Inorganic materials 0.000 description 1
- RQNWIZPPADIBDY-UHFFFAOYSA-N arsenic atom Chemical compound [As] RQNWIZPPADIBDY-UHFFFAOYSA-N 0.000 description 1
- 238000009835 boiling Methods 0.000 description 1
- 230000003197 catalytic effect Effects 0.000 description 1
- 238000004517 catalytic hydrocracking Methods 0.000 description 1
- 239000000919 ceramic Substances 0.000 description 1
- 238000001311 chemical methods and process Methods 0.000 description 1
- 239000007795 chemical reaction product Substances 0.000 description 1
- 230000000052 comparative effect Effects 0.000 description 1
- BWFPGXWASODCHM-UHFFFAOYSA-N copper monosulfide Chemical compound [Cu]=S BWFPGXWASODCHM-UHFFFAOYSA-N 0.000 description 1
- 229910000431 copper oxide Inorganic materials 0.000 description 1
- VODBHXZOIQDDST-UHFFFAOYSA-N copper zinc oxygen(2-) Chemical compound [O--].[O--].[Cu++].[Zn++] VODBHXZOIQDDST-UHFFFAOYSA-N 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 239000002274 desiccant Substances 0.000 description 1
- 230000006866 deterioration Effects 0.000 description 1
- 238000010790 dilution Methods 0.000 description 1
- 239000012895 dilution Substances 0.000 description 1
- HNPSIPDUKPIQMN-UHFFFAOYSA-N dioxosilane;oxo(oxoalumanyloxy)alumane Chemical compound O=[Si]=O.O=[Al]O[Al]=O HNPSIPDUKPIQMN-UHFFFAOYSA-N 0.000 description 1
- 229910001882 dioxygen Inorganic materials 0.000 description 1
- 238000001035 drying Methods 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 239000003546 flue gas Substances 0.000 description 1
- 239000008236 heating water Substances 0.000 description 1
- 125000004435 hydrogen atom Chemical group [H]* 0.000 description 1
- SZVJSHCCFOBDDC-UHFFFAOYSA-N iron(II,III) oxide Inorganic materials O=[Fe]O[Fe]O[Fe]=O SZVJSHCCFOBDDC-UHFFFAOYSA-N 0.000 description 1
- 239000003915 liquefied petroleum gas Substances 0.000 description 1
- 239000012528 membrane Substances 0.000 description 1
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 description 1
- 229910052753 mercury Inorganic materials 0.000 description 1
- 239000003209 petroleum derivative Substances 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 238000010926 purge Methods 0.000 description 1
- 230000008929 regeneration Effects 0.000 description 1
- 238000011069 regeneration method Methods 0.000 description 1
- 229910052703 rhodium Inorganic materials 0.000 description 1
- 239000010948 rhodium Substances 0.000 description 1
- MHOVAHRLVXNVSD-UHFFFAOYSA-N rhodium atom Chemical compound [Rh] MHOVAHRLVXNVSD-UHFFFAOYSA-N 0.000 description 1
- 229910052707 ruthenium Inorganic materials 0.000 description 1
- 230000009919 sequestration Effects 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 239000010457 zeolite Substances 0.000 description 1
Classifications
-
- 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
- C01B3/382—Multi-step processes
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/46—Removing components of defined structure
- B01D53/62—Carbon oxides
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/34—Chemical or biological purification of waste gases
- B01D53/74—General processes for purification of waste gases; Apparatus or devices specially adapted therefor
- B01D53/77—Liquid phase processes
- B01D53/78—Liquid phase processes with gas-liquid contact
-
- 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
- C01B3/384—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 the catalyst being continuously externally heated
-
- 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
- C01B3/48—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 followed by reaction of water vapour with carbon monoxide
-
- 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
- C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
- C01B3/508—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by selective and reversible uptake by an appropriate medium, i.e. the uptake being based on physical or chemical sorption phenomena or on reversible chemical reactions
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2256/00—Main component in the product gas stream after treatment
- B01D2256/16—Hydrogen
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2257/00—Components to be removed
- B01D2257/50—Carbon oxides
- B01D2257/504—Carbon dioxide
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1475—Removing carbon dioxide
-
- 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
-
- 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
- C01B2203/0415—Purification by absorption in liquids
-
- 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
- C01B2203/042—Purification by adsorption on solids
- C01B2203/043—Regenerative adsorption process in two or more beds, one for adsorption, the other for regeneration
-
- 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
- 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
- C01B2203/0811—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel
- C01B2203/0827—Methods of heating the process for making hydrogen or synthesis gas by combustion of fuel at least part of the fuel being a recycle stream
-
- 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
- C01B2203/1258—Pre-treatment of the feed
- C01B2203/1264—Catalytic pre-treatment of the feed
- C01B2203/127—Catalytic desulfurisation
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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
- C01B2203/14—Details of the flowsheet
- C01B2203/142—At least two reforming, decomposition or partial oxidation steps in series
-
- 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
- C01B2203/14—Details of the flowsheet
- C01B2203/142—At least two reforming, decomposition or partial oxidation steps in series
- C01B2203/143—Three or more reforming, decomposition or partial oxidation steps in series
-
- 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
- C01B2203/14—Details of the flowsheet
- C01B2203/146—At least two purification steps in series
-
- 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
- C01B2203/14—Details of the flowsheet
- C01B2203/148—Details of the flowsheet involving a recycle stream to the feed of the process for making hydrogen or synthesis gas
Landscapes
- Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Organic Chemistry (AREA)
- Engineering & Computer Science (AREA)
- Health & Medical Sciences (AREA)
- Combustion & Propulsion (AREA)
- Inorganic Chemistry (AREA)
- General Health & Medical Sciences (AREA)
- Environmental & Geological Engineering (AREA)
- Biomedical Technology (AREA)
- Analytical Chemistry (AREA)
- General Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Hydrogen, Water And Hydrids (AREA)
Abstract
The invention relates to process for the production of hydrogen comprising the steps of: hydrodesulphurisation 203, reforming in a reforming section comprising a gas-heated reformer 207a and an autothermal reformer 207b, water-gas shift 210, carbon dioxide separation 212, and hydrogen purification 215. The hydrogen purification step produces a hydrocarbon-containing off-gas stream 217 is split: a portion is used as a fuel gas stream 218 which is fed to one or more fired heaters used to heat one or more process streams within the process, the remainder 219 is compressed and split into a hydrodesulphurisation recycle stream 220 which is used in the hydrodesulphurisation unit, and a process recycle stream 221 which is returned to the process. The invention also relates to a chemical plant configured to carry out the process. The process recycle stream may be fed downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer.
Description
Process for producing hydrogen
Technical Field
This invention relates to processes for the conversion of hydrocarbons to hydrogen whilst minimising carbon dioxide production.
Background to the Invention
Processes for generating hydrogen are well-known and generally include a fired steam methane reformer combined with water-gas shift and carbon dioxide (CO2) removal. Such processes create significant volumes of carbon dioxide in flue gases at pressures unsuitable for efficient CO2 capture. There is a need for hydrogen production processes that generate lower levels of carbon dioxide effluent and enable more efficient CO2 capture.
In some processes a fired reformer is used to generate a synthesis gas. In a fired reformer fuel is combusted within a radiant box of the fired reformer to provide heat to drive the steam reforming reactions. For example, EP2103569A2 discloses a method for generating hydrogen and/or syngas in a production facility where little or no export steam is produced. Most or all of the steam produced from the waste heat from the process is used in the steam-hydrocarbon reformer. The flowsheet shown in Figure 1 of this reference includes a fired steam reformer (650), optional water-gas shift reactor (602), pressure swing adsorber (330). The pressure swing adsorber generates a residual gas (698) which is divided. A portion (630) is used as fuel in the fired steam reformer. Another portion is compressed and used as feedstock for the fired steam reformer, optionally after first being treated to hydrodesulfurization and/or pre-reforming.
In an alternative process an autothermal reformer is used instead of a fired steam reformer. For example, US2022/194789A1 describes in Figure 2 of this reference a flowsheet which comprises sequentially: a pre-reforming unit (140), an autothermal reformer (110), a high-temperature shift unit (115), a low-temperature shift unit (150), a water wash section (160), a CO2 removal section (170) and a hydrogen purification unit (125). The hydrogen purification unit generates a high purity H2 stream (8) and an off-gas stream (9). The off-gas stream may be fed to the feed side of the pre-reformer unit, and/or to the feed side of the ATR, and/or to the feed side of the shift section. The same arrangement appears in Figure 2 of W02022/038089A1.
Arrangements with a gas-heated reformer and an autothermal reformer are also known. In a known hydrogen plant including a gas-heated reformer, autothermal reformer, water-gas shift unit, carbon dioxide separation unit a purification unit, a stream containing unreacted hydrocarbons, often called an off gas, is separated from the hydrogen product in the purification unit. The off-gas can be used as fuel to provide a portion or all of the heat duty for the plant.
W02019/162236A1 describes a method of producing hydrogen comprising: receiving a feed gas comprising hydrocarbons; performing reforming processes so as to generate hydrogen in dependence on the feed gas; wherein the reforming processes comprise both a gas-heated reforming process and an autothermal reforming process; heat generated by the autothermal reforming process is supplied to the gas-heated reforming process; wherein the method is performed in a hydrogen plant that is integrated with one or more further processing plants, such as a methanol plant. In one embodiment syngas generated from the gas-heated reforming and autothermal reforming process is shifted in a water-gas shift unit, treated to remove carbon dioxide and then treated to produce a hydrogen stream and a rest gas stream containing remnants of CO, CH4, CO2 and H2. The rest gas may alternatively be referred to as a tail gas or a recycle gas. The rest gas may be utilized for fuel in fired heater(s) for the preheating of feed gases, or can be recycled to the gas-heated reformer or autothermal reformer for maximum carbon efficiency.
W02022/003312A1 describes a process for the production of hydrogen comprising the steps of: (i) subjecting a gaseous mixture comprising a hydrocarbon and steam, and having a steam to carbon ratio of at least 2.6:1, to steam reforming in a gas-heated reformer followed by autothermal reforming with an oxygen-rich gas in an autothermal reformer to generate a reformed gas mixture; (ii) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-enriched reformed gas; (Hi) cooling the hydrogen-enriched reformed gas and separating condensed water therefrom to provide a de-watered hydrogen-enriched reformed gas; (iv) passing the de-watered hydrogen-enriched reformed gas to a carbon dioxide separation unit to provide a carbon dioxide gas stream and a crude hydrogen gas stream, and (v) passing the crude hydrogen gas stream from the carbon dioxide removal unit to a purification unit to provide a purified hydrogen gas and a fuel gas, wherein the fuel gas is fed to one or more fired heaters used to heat one or more process streams within the process.
While the above process has a good efficiency with a very high rate of carbon dioxide capture, there is a need for a hydrogen production process with an even higher yield of hydrogen per unit of hydrocarbon feed. The present invention addresses this problem.
Summary of the Invention
The inventors have improved the process described in W02022/003312A1 to increase the yield of H2 per unit of hydrocarbon feed. Accordingly, the invention provides a process for the production of hydrogen comprising the steps of: (i) passing a hydrogen stream and a feed stream comprising hydrocarbons to a hydrodesulphurisation unit and carrying out hydrodesulphurisation to produce a purified hydrocarbon stream; (ii) adding steam to the purified hydrocarbon stream to produce a gaseous mixture comprising hydrocarbons and steam; (iii) subjecting the gaseous mixture comprising hydrocarbons and steam to steam reforming in a reforming section comprising a gas-heated reformer and an autothermal reformer to generate a reformed gas mixture; (iv) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift unit to provide a hydrogen-enriched reformed gas; (v) cooling the hydrogen-enriched reformed gas and separating condensed water therefrom to provide a de-watered hydrogen-enriched reformed gas; (vi) passing the de-watered hydrogen-enriched reformed gas to a carbon dioxide separation unit to provide a carbon dioxide gas stream and a crude hydrogen gas stream; (vii) passing the crude hydrogen gas stream from the carbon dioxide removal unit to a purification unit to provide a purified hydrogen gas stream and a hydrocarbon-containing off-gas stream; (viii) splitting the off-gas stream into a fuel gas stream and a recycle stream, wherein the fuel gas stream is fed to one or more fired heaters used to heat one or more process streams within the process; (ix) compressing the recycle stream; (x) splitting the compressed recycle stream into a desulphurisation recycle stream and a process recycle stream; (xi) feeding the hydrodesulphurisation recycle stream to the desulphurisation unit; (xii) returning the process recycle stream to one or more locations selected from: (xii-a) downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer; (xii-d) downstream from the gas-heated reformer and upstream from the autothermal reformer; (xii-c) downstream from the autothermal reformer and upstream from the water-gas shift unit; (xii-d) downstream from the water-gas shift unit and upstream from the carbon dioxide separation unit; or (xii-e) downstream from the carbon dioxide separation unit and upstream from the purification unit.
One aspect in which the present process differs from the arrangement in W02022/003312A1 is that instead of using all of the off-gas from the purification unit as fuel gas for one or more fired heaters, the off-gas is split into two streams: a recycle stream and a fuel gas stream. The fuel gas stream is fed to one or more fired heaters used to heat one or more process streams within the process. The recycle stream, containing some unreacted hydrocarbons, is compressed and then split into a hydrodesulphurisation recycle stream which is used in the hydrodesulphurisation unit and a process recycle stream which is returned to the process in order to convert as much of the hydrocarbon as possible. The use of some of the recycle for hydrodesulphurisation replaces a pure hydrogen feed which would otherwise be sent to the hydrodesulphurisation unit and thereby improves overall efficiency. The use of a process recycle maximises the conversion of hydrogen and, where the recycle is returned upstream of the water-gas shift unit, maximises CO conversion and CO2 capture. Surprisingly, despite the added complexity of this arrangement, the total hydrogen efficiency of the process (H2 produced per unit of hydrocarbon feed) is increased. This is achieved without sacrificing the efficiency of CO2 capture, which can be 98% or higher in the process of the invention.
In a second aspect the invention relates to a chemical plant comprising: (i) a hydrodesulphurisation unit (203, 303, 403, 503) arranged to receive a hydrogen stream (202, 302, 402, 502) and a feed stream comprising hydrocarbons (201, 301, 401, 501) and carry out hydrodesulphurisation to produce a purified hydrocarbon stream; (ii) means to add steam (204, 304, 404, 504) to the purified hydrocarbon stream to produce a gaseous mixture comprising hydrocarbons and steam (205, 305, 405, 505); (iii) a reforming section (207, 307, 407, 507) comprising a gas-heated reformer (207a, 307a, 407a, 507a) and an autothermal reformer (207b, 307b, 407b, 507b), arranged to receive the gaseous mixture comprising hydrocarbons and steam, and to generate a reformed gas mixture (208, 308, 408, 508); (iv) a water-gas shift (210, 310, 410, 510) unit arranged to receive the reformed gas mixture, and to generate a hydrogen-enriched reformed gas (211, 311, 411, 511); (v) means for cooling the hydrogen-enriched reformed gas and separating condensed water therefrom to provide a de-watered hydrogen-enriched reformed gas; (vi) a carbon dioxide separation unit (212, 312, 412, 512) arranged to receive the de-watered hydrogen-enriched reformed gas, and to generate a carbon dioxide gas stream (213, 313, 413, 513) and a crude hydrogen gas stream (214, 314, 414, 514); (vii) a purification unit (215, 315, 415, 515) arranged to receive the crude hydrogen gas stream, and to generate a purified hydrogen gas stream (216, 316, 416, 516) and a hydrocarbon-containing off-gas stream (217, 317, 417, 517); (viii) means for splitting the off-gas stream into a fuel gas stream (218, 318, 418, 518) and a recycle stream (219, 319, 419, 519), and means for feeding the fuel gas stream to one or more fired heaters used to heat one or more process streams within the process; (ix) means for compressing the recycle stream; (x) means for splitting the compressed recycle stream into a hydrodesulphurisation recycle stream (220, 320, 420, 520) and a process recycle stream (221, 321, 421, 521); (xi) means for feeding the hydrodesulphurisation recycle stream to the hydrodesulphurisation unit; (xii) means for returning the process recycle stream to one or more locations selected from: (xii-a) downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer; (xii-d) downstream from the gas-heated reformer and upstream from the autothermal reformer; (xii-c) downstream from the autothermal reformer and upstream from the water-gas shift unit; (xii-d) downstream from the water-gas shift unit and upstream from the carbon dioxide separation unit; or (xii-e) downstream from the carbon dioxide separation unit and upstream from the purification unit.
The chemical plant may be built from scratch (e.g. a "grassroots" chemical plant). Alternatively, an existing chemical plant may be retrofitted with the necessary units and associated piping etc. to produce a chemical plant according to the invention.
The chemical plant is preferably a hydrogen plant, i.e. produces hydrogen as the end product.
Description of the Figures
Figure 1 is a simplified illustration of the process described in W02022/003312A1. A hydrocarbon stream (101) and a hydrogen stream (102) are fed to a desulphurisation unit (103). Steam (104) is added to the output from the desulphurisation unit to produce a stream (105) with a steam to carbon ratio of at least 2.6: 1 which is sent to a reforming section (107). The reforming section includes a gas-heated reformer (107a) and an autothermal reformer (107b). An oxygen-rich gas stream (106) is also fed to the autothermal reformer. Steam reforming reactions take place in gas-heated reformer and autothermal reformer. The hot gases exiting the autothermal reformer are used to provide heat for the endothermic steam reforming reactions taking place in the gas-heated reformer, by passing the hot gases through the shell-side of the gas-heated reformer. The reformed stream may optionally be mixed with additional steam (109) (not used in arrangement modelled) and sent to a water-gas shift unit (110) to generate a hydrogen-rich reformed gas (111). The hydrogen-rich reformed gas is fed to a carbon dioxide separation unit (112) where it is separated into a carbon dioxide gas stream (113) and a crude hydrogen gas stream (114). The crude hydrogen gas stream is sent to a purification unit (115) where it is separated into a purified hydrogen gas stream (116) and an off-gas stream (117). The off-gas stream is used as a fuel gas.
Figure 2 shows an arrangement according to the invention which is based on the arrangement shown in Figure 1. The off-gas stream (217) is split to produce a fuel gas stream (218) and a recycle stream (219). The recycle stream is compressed (not shown) and then split into a desulphurisation recycle stream (220) which is fed to the purification unit and a process recycle stream (221) which is reintroduced to the process downstream from the desulphurisation unit (203) and upstream from the gas-heated reformer (207a).
Figure 3 shows an arrangement according to the invention which is based on the arrangement shown in Figure 1. The off-gas stream (317) is split to produce a fuel gas stream (318) and a recycle stream (319). The recycle stream is compressed (not shown) and then split into a desulphurisation recycle stream (320) which is fed to the desulphurisation unit and a process recycle stream (321) which is reintroduced to the process downstream from the autothermal reformer (307b) and upstream from the water-gas shift unit (310).
Figure 4 shows an arrangement according to the invention which is based on the arrangement shown in Figure 1. The off-gas stream (417) is split to produce a fuel gas stream (418) and a recycle stream (419). The recycle stream is compressed (not shown) and then split into a desulphurisation recycle stream (420) which is fed to the desulphurisation unit and a process recycle stream (421) which is reintroduced to the process downstream from the water-gas shift unit (410) and upstream from the carbon dioxide separation unit (412).
Figure 5 shows an arrangement according to the invention which is based on the arrangement shown in Figure 1. The off-gas stream (517) is split to produce a fuel gas stream (518) and a recycle stream (519). The recycle stream is compressed (not shown) and then split into a desulphurisation recycle stream (520) which is fed to the desulphurisation unit and a process recycle stream (521) which is reintroduced to the process downstream from the carbon dioxide separation unit (512) and upstream from the purification unit (515).
Detailed description of the Invention
Sub-headings are included for clarity purposes but are not intended to limit the invention.
Features concerning the arrangement of the chemical plant described in connection with the process also apply to the chemical plant according to the second aspect of the invention.
Treatment prior to gas-heated reformer The gaseous mixture fed to gas-heated reformer comprises hydrocarbons and steam. It is preferred that this mixture comprises 90 vol°/0 methane, based on the % of hydrocarbons present in the mixture and excluding any steam, such as 95 vol% methane. A hydrocarbon-containing feed is pre-treated upstream of the gas-heated reformer in order to remove contaminants, including at least a step of hydrodesulphurisation.
A wide variety of feeds may be used, such as natural gas, associated gas, LPG, petroleum distillate, diesel, naphtha or mixtures thereof, or hydrocarbon-containing off-gases from chemical processes, such as a refinery off-gas or a pm-reformed gas.
Hydrodesulphurisation Step (i) involves passing a hydrogen stream and a feed stream comprising hydrocarbons to a hydrodesulphurisation unit and carrying out hydrodesulphurisation to produce a purified hydrocarbon stream.
The feed stream may be compressed before or after hydrodesulphurisation, preferably before hydrodesulphurisation. The feed may be compressed to a pressure in the range 10-100 bar abs. The pressure of the feed stream may usefully govern the pressure throughout the process. The operating pressure is preferably in the range 15-50 bar abs, more preferably 25-50 bar abs as this provides an enhanced performance from the process.
The hydrodesulphurisation step is typically catalytic hydrodesulphurisation which may be achieved using known catalysts, such as CoMo or NiMo catalysts. This process generates hydrogen sulphide which is absorbed using a suitable hydrogen sulphide adsorbent, e.g. a zinc oxide adsorbent. An ultra-purification adsorbent may usefully be used downstream of the hydrogen sulphide adsorbent to further protect the steam reforming catalyst. Suitable, ultra-purification adsorbents may comprise copper-zinc oxide/alumina materials and copper-nickelzinc oxide/alumina materials. To facilitate hydrodesulphurisation and/or reduce the risk of carbon laydown in the reforming process, hydrogen is preferably added to the compressed hydrocarbon. The amount of hydrogen in the resulting mixed gas stream may be in the range 1-20% vol, but is preferably in the range 1-10% vol, more preferably in the range 1-5% vol on a dry gas basis. In a preferred embodiment, a portion of the desulphurisation recycle stream (as described below) may be mixed with the compressed hydrocarbon.
The hydrogen stream to the hydrodesulphurisation unit is provided at least in part by the hydrodesulphurisation recycle stream which is separated in step (x) as described below. Although additional hydrogen may be added to the hydrodesulphurisation stream, the hydrodesulphurisation recycle stream is preferably fed to the hydrodesulphurisation unit without addition of supplemental hydrogen in order to maximise the hydrogen yield. In the latter case the hydrogen stream and hydrodesulphurisation recycle stream are one and the same.
Compared to the arrangement described in W02022/003312A1, in which a portion of the crude hydrogen gas stream (from the carbon dioxide separation unit) or the purified hydrogen gas stream (from the purification unit) may be used to provide the hydrogen for desulfurisation, this arrangement uses a different, less hydrogen-rich feed. This helps to improve the yield of hydrogen per unit of hydrocarbon feed.
If the feed contains other contaminants, such as chloride or heavy metal contaminants, these may be removed, prior to reforming, either upstream or downstream of hydrodesulphurisation, using conventional adsorbents. Adsorbents suitable for chloride removal are known and include alkalised alumina materials. Similarly, adsorbents for heavy metals such as mercury or arsenic are known and include copper sulphide materials.
The feed may be pre-heated in one or more stages. It is preferably pre-heated after compression and before desulphurisation. Various hot gas sources are provided in the present process that may be used for this duty. For example, the feed may be heated in heat exchange with a shifted gas stream recovered from a water-gas shift stage, preferably a high-temperature shift stage. The desulphurised feed, also referred to herein equivalently as the purified hydrocarbon stream, may, for example, be heated in a fired heater fuelled by the fuel gas.
Steam addition Step (ii) involves adding steam to the purified hydrocarbon stream to produce a gaseous mixture comprising hydrocarbons and steam The steam introduction may be performed by direct injection of steam and/or by saturation of the purified hydrocarbon stream by contact with a stream of heated water. The steam added in step (ii) is preferably generated by combusting the fuel gas stream in the one or more fired heaters. In a preferred embodiment, the gaseous mixture comprising the hydrocarbon and steam is formed by directly mixing the purified hydrocarbon stream with steam, preferably steam generated in the one or more fired heaters and/or from cooling the reformed gas mixture with water.
The amount of steam introduced is sufficient to give a steam to carbon ratio (defined as the steam to hydrocarbon carbon ratio at the inlet to the gas-heated reformer) of between 2.0: 1 to 3.5: 1, such as 2.6: 1 to 3.5: 1. For the avoidance of doubt, a feed containing 75 mol% H20 and 25 mol% CH4 has a steam to carbon ratio of 3.0: 1, a feed containing 75 mol% H20, 23 mol% and 2 mol% has a steam to carbon ratio of 2.8: 1 and so on. Operating the reforming section at a steam to carbon ratio towards the lower end of the 2.0: 1 to 3.5: 1 range, for example between 2.0: 1 to 2.4: 1 has the advantage that the heating requirement and oxygen demand for the reforming stages is reduced and that the front-end equipment (e.g. fired heater, pre-reformer, and autothermal reformer) will be smaller and lower in cost, but typically will require further steam addition to the reformed gas mixture upstream of the water-gas shift unit. In one embodiment the steam to carbon ratio of the gaseous mixture comprising hydrocarbons and steam at the inlet to the gas-heated reformer in step (iii) from 2.0: 1 to 2.4: 1 and further steam is added to the reformed gas mixture upstream of the water-gas shift unit. Where the steam to carbon ratio is in the range 2.4: 1 to 3.5: 1, no further steam addition upstream of the water-gas shift unit is necessary, which may be useful in circumstances where steam addition to the reformed gas is impractical.
The gaseous mixture comprising hydrocarbon and steam is then desirably pre-heated prior to reforming. In a preferred embodiment, the gaseous mixture is heated by passing it through a fired heater fuelled by at least a portion of the fuel gas, in particular through the same fired heater used to pre-heat the hydrocarbon. Desirably, the mixed stream is heated to 400-500°C, preferably 420-460°C.
Pre-reforming The gaseous mixture fed to gas-heated reformer preferably comprises 90 vol% methane, based on the % of hydrocarbons present in the mixture and excluding any steam. Although not generally necessary for light gaseous hydrocarbons feedstocks, where hydrocarbon feedstocks contain higher hydrocarbons, it may be preferable in some instances to include a stage of adiabatic pre-reforming upstream of the gas-heated reformer. The gaseous mixture comprising the hydrocarbon and steam in these cases is first subjected to a step of adiabatic steam reforming in a pre-reformer vessel. In such a process, the gaseous mixture comprising the hydrocarbon and steam, typically at an inlet temperature in the range of 400-650°C, is passed adiabatically through a bed of a steam reforming catalyst, usually a steam reforming catalyst having a high nickel content, for example above 40% by weight. During such an adiabatic pre-reforming step, any hydrocarbons higher than methane react with steam to give a mixture of methane, carbon oxides and hydrogen. The use of such an adiabatic steam reforming step, commonly termed pre-reforming, can be desirable to ensure that the feed to the gas-heated reformer contains no hydrocarbons higher than methane and also contains some hydrogen.
Reforming section Following purification, and if necessary pre-reforming, the gaseous mixture comprising the hydrocarbon and steam is subjected to steam reforming in a reforming section comprising a gas-heated reformer and an autothermal reformer. The gas-heated reformer and autothermal reformer are arranged such that hot gases exiting the autothermal reformer are used to provide heat for the steam reforming reactions taking place in the gas-heated reformer. Any suitable arrangement may be used in the reforming section such as a series or parallel arrangement. In a series arrangement all of the gases exiting the gas-heated reformer are fed to the autothermal reformer, all of the hot gases existing the autothermal reformer are fed to the shell-side of the gas-heated reformer to provide heat for the steam reforming reactions. This arrangement is preferred for grassroots plants. In a parallel arrangement the gas-heated reformer arid autothermal reformer are each fed with their own feed containing hydrocarbon; the gases from the outlet of the gas-heated reformer and the gases from the outlet of the autothermal reformer are combined and fed to the shell-side of the gas-heated reformer to provide heat for the steam reforming reactions. This arrangement may be suitable in situations where an existing chemical plant containing a reforming section with one of a gas-heated reformer or an autothermal reformer is retrofitted to produce the plant described.
In one type of gas-heated reformer, the catalyst is disposed in tubes extending between a pair of tube sheets through a heat exchange zone. Reactants are fed to a zone above the upper tube sheet and pass through the tubes and into a zone beneath the lower tube sheet. The heating medium is passed through the zone between the two tube sheets. Gas-heated reformers of this type are described in GB1578270 and W097/05947. Another type of gas-heated reformer that may be used is a double-tube gas-heated reformer as described in US4910228 wherein the reformer tubes each comprise an outer tube having a closed end and an inner tube disposed concentrically within the outer tube and communicating with the annular space between the inner and outer tubes at the closed end of the outer tube with the steam reforming catalyst disposed in said annular space. The external surface of the outer tubes is heated by the autothermally reformed gas. The reactant mixture is fed to the end of the outer tubes remote from said closed end so that the mixture passes through said annular space and undergoes steam reforming and then passes through the inner tube.
The compressed, pre-heated gaseous mixture comprising the hydrocarbon and steam is passed through the catalyst-filled tubes in the gas-heated reformer. During passage through the reforming catalyst, the endothermic steam reforming reaction takes place with the heat required for the reaction being supplied from the autothermally reformed gas flowing past the exterior surface of the tubes. The steam reforming catalyst used in the gas-heated reformer may comprise nickel supported on a particulate refractory support such as rings or multi-holed pellets of calcium aluminate, magnesium aluminate, alumina, titania, zirc,onia and the like. Alternatively, a combination of nickel and a precious metal, such as ruthenium or rhodium, may be used. In place of, or in addition to, the particulate steam reforming catalyst, the steam reforming catalyst may comprise one or more structured catalyst units, which may be in the form of metal or ceramic monoliths or folded metal structures on which a layer of nickel and/or precious metal steam reforming catalyst has been deposited. Such structured catalysts are described for example in W02012/103432A1 and W02013151885A1.
The temperature of the autothermally reformed gas used to heat the gas-heated reformer is preferably sufficient that the gas undergoing steam reforming leaves the catalyst tubes at a temperature in the range 600-850°C, preferably 650-750°C, more preferably 680-720°C. In the present invention the reformed gas, which comprises methane, hydrogen, steam and carbon oxides, is fed preferably without any dilution or heat exchange, directly to an autothermal reformer in which it is subjected to autothermal reforming, also termed secondary reforming. The steam reforming in the gas-heated reformer may be therefore termed primary reforming.
The autothermal reformer may comprise a burner disposed at the top of the reformer, to which the steam reformed gas and the oxygen-rich gas are fed, a combustion zone beneath the burner through which a flame extends, and a fixed bed of particulate steam reforming catalyst disposed below the combustion zone. In autothermal reforming, the heat for the endothermic steam reforming reactions is therefore provided by combustion of a portion of hydrocarbon in the feed gas. The steam reformed gas is typically fed to the top of the reformer and the oxygen-rich gas fed to the burner, mixing and combustion occur downstream of the burner generating a heated gas mixture the composition of which is brought to equilibrium as it passes through the steam reforming catalyst. The autothermal steam reforming catalyst may comprise nickel supported on a refractory support such as rings or pellets of calcium aluminate, magnesium aluminate, alumina, fitania, zirconia and the like. In a preferred embodiment, the autothermal steam reforming catalyst comprises a layer of a catalyst comprising Ni and/or Ru on zirconia over a bed of a Ni on alumina catalyst to reduce catalyst support volatilisation that can result in deterioration in performance of the autothermal reformer.
The oxygen-rich gas may comprise at least 50% vol 02 and may be an oxygen-enriched air mixture. However, in the present invention the oxygen-rich gas preferably comprises at least 90% vol 02, more preferably at least 95% vol 02, most preferably at least 98% vol 02, or at least 99% vol 02, e.g. a pure oxygen gas stream, which may be obtained using a vacuum pressure swing adsorption (VPSA) unit or an air separation unit (ASU). The ASU may be electrically driven and is desirably driven using renewable electricity to further improve the efficiency of the process and minimise CO2 emissions.
The amount of oxygen-rich gas added is preferably such that 40 to 60 moles of oxygen are added per 100 moles of carbon in the hydrocarbon fed to the process. Preferably the amount of oxygen added is such that the reformed gas leaves the catalyst in the autothermal reformer at a temperature in the range 800-1100°C, more preferably 900-1100°C, most preferably 970- 1070°C. In a preferred embodiment, a small purge of steam may be added to the oxygen-rich gas to protect against reverse flow if the plant trips.
The reformed gas produced by the autothermal reformer is used to provide the heat required for the primary steam reforming step by using it as the hot gas flowing past the tubes in the gas-heated reformer. During this heat exchange, the reformed gas cools by transferring heat to the gas undergoing steam reforming. Preferably the reformed gas cools by several hundred degrees Centigrade but it will leave the gas-heated reformer at a temperature somewhat above the temperature at which the gaseous mixture comprising hydrocarbon and steam mixture is fed to the gas-heated reformer. Preferably the reformed gas leaves the gas-heated reformer at a temperature in the range 450-650°C, more preferably 450-580°C.
It will be understood that the flow of gas in step (iii) is from the tube-side of the gas-heated reformer to the autothermal reformer, to the shell-side of the gas-heated reformer, then to the water-gas shift unit. The shell-side of the gas-heated reformer and subsequent downstream locations are "downstream of the autothermal reformer' as that term is used herein.
After leaving the reforming section (via the shell side of the gas-heated reformer), the reformed gas is then typically further cooled in one or more steps of heat exchange. Heat recovered during this cooling may be employed for reactants pre-heating and/or for heating water used to provide the steam employed in the steam reforming step. As described hereinafter, the recovered heat may additionally, or alternatively, be used in the carbon dioxide separation step. In a preferred embodiment, the reformed gas mixture exiting the shell side of the gas-heated reformer is used to heat water fed to a saturator.
Water-gas shift unit The reformed gas comprises hydrogen, carbon monoxide, carbon dioxide, steam, and a small amount of unreacted methane, and may also contain small amounts of inert gases such as nitrogen and argon. Preferably, the hydrogen content of the reformed gas is in the range 30-45% vol and the carbon monoxide content in the range 5-15% vol. In the present invention, the hydrogen content of the partially cooled reformed gas mixture is increased by subjecting it to one or more water-gas shift stages thereby producing a hydrogen-enriched reformed gas and at the same time converting carbon monoxide in the reformed gas to carbon dioxide. The reaction may be depicted as follows: CO + H20 <-> CO2 + H2 Because steam reforming is performed with an excess of steam it is generally not necessary to add steam to the reformed gas mixture recovered from the autothermal reformer to ensure sufficient steam is available for the water-gas shift reaction. However, supplemental steam may be added if desired.
The partially cooled reformed gas may be subjected in the water-gas shift unit to one or more water-gas shift stages to form a hydrogen-enriched reformed gas stream, or "shifted" gas stream. The one or more water-gas shift stages may include stages of high-temperature shift, medium-temperature shift, isothermal shift and low-temperature shift.
High-temperature shift is operated adiabatically in a shift vessel with inlet temperature in the range 300-400°C, preferably 320-360°C, over a bed of a reduced iron catalyst, such as chromiapromoted magnetite. Alternatively, a promoted zinc-aluminate catalyst may be used.
Medium-temperature shift and low-temperature shift stages may be performed using shift vessels containing supported copper-catalysts, particularly copper/zinc oxide/alumina compositions. In low-temperature shift, a gas containing carbon monoxide (preferably 6% vol CO on a dry basis) and steam (at a steam to total dry gas molar ratio in range 0.3 to 1.5) may be passed over the catalyst in an adiabatic fixed bed with an outlet temperature in the range 200 to 300°C. The outlet carbon monoxide content may be in the range 0.1 to 1.5%, especially under 0.5% vol on a dry basis if additional steam is added. Alternatively, in medium-temperature shift, the gas containing carbon monoxide and steam may be fed to the catalyst at an inlet temperature in the range 200 to 240°C although the inlet temperature may be as high as 280°C. The outlet temperature may be up to 300°C but may be as high as 360°C.
Whereas one or more adiabatic water-gas shift stages may be employed, such as a high-temperature shift stage, optionally followed by a low-temperature shift stage, the partially cooled reformed gas is preferably subjected to a stage of isothermal water-gas shift in a cooled shift vessel, optionally followed by one or more adiabatic medium-or low-temperature water-gas shift stages in un-cooled vessels as described above. Using an isothermal shift stage, i.e. with heat exchange in the shift converter such that the exothermic reaction in the catalyst bed occurs in contact with heat exchange surfaces that remove heat, offers the potential to use the reformed gas stream in a very efficient manner. Whereas the term "isothermal" is used to describe a cooled shift converter, there may be a small increase in temperature of the gas between inlet and outlet, so that the temperature of the hydrogen-enriched reformed gas stream at the exit of the isothermal shift converter may be between 1 and 25 degrees Celsius higher than the inlet temperature. The coolant conveniently may be water under pressure such that partial, or complete, boiling takes place. The water can be in tubes surrounded by catalyst or vice versa. The resulting steam can be used, for example, to drive a turbine, e.g. for electrical power, or to provide process steam for supply to the process. In a preferred embodiment, steam generated by the isothermal shift stage is used to supplement the steam addition to the gaseous mixture comprising a hydrocarbon and steam upstream of the gas-heated reformer. This improves the efficiency of the process and enables the relatively high steam to carbon ratio to be achieved at low cost.
Addition of an adiabatic medium-or low-temperature shift stage downstream of the isothermal shift stage offers the potential to increase the CO2 capture efficiency from the process to 98% or higher. However, we have found that excellent efficiency may be provided by a single isothermal shift converter.
Following the one or more shift stages, the hydrogen-enriched reformed gas is cooled to a temperature below the dew point so that the steam condenses. The liquid water condensate may then be separated using one or more, gas-liquid separators, which may have one or more further cooling stages between them. Any coolant may be used. Preferably, cooling of the hydrogen-enriched reformed gas stream is first carried out in heat exchange with the process condensate. As a result, a stream of heated water, which may be used to supply some or all of the steam required for reforming, is formed. Thus, in one embodiment condensate recovered from the hydrogen-enriched reformed gas is used to provide at least a portion of steam for the gas mixture fed to the steam reforming step in the gas-heated reformer. Because the condensate may contain ammonia, methanol, hydrogen cyanide and CO2, returning the condensate to form steam offers a useful way of returning hydrogen and carbon to the process.
One or more further stages of cooling are desirable. The cooling may be performed in heat exchange in one or more stages using demineralised water, air, or a combination of these. In a preferred embodiment, cooling is performed in heat exchange with one or more liquids in the CO2 separation unit. In a particularly preferred arrangement, the hydrogen-enriched reformed gas stream is cooled in heat exchange with condensate followed by cooling with CO2 reboiler liquid. The cooled shifted gas may then be fed to a first gas-liquid separator, the separated gas further cooled with water and/or air and fed to a second separator, before further cooling with water and/or air and feeding to a third separator. Two or three stages of condensate separation are preferred. Some or all of the condensate may be used to generate steam for the steam reforming. Any condensate not used to generate steam may be sent to water treatment as effluent.
Carbon dioxide separation unit The carbon dioxide separation stage may be performed using a physical wash system or a reactive wash system, preferably a reactive wash system, especially an amine wash system. The carbon dioxide may be separated by an acid gas recovery (AGR) process. In the AGR process, the de-watered hydrogen-enriched reformed gas stream (i.e. the de-watered shifted gas) is contacted with a stream of a suitable absorbent liquid, such as an amine, particularly methyl diethanolamine (MDEA) solution so that the carbon dioxide is absorbed by the liquid to give a laden absorbent liquid and a gas stream having a decreased content of carbon dioxide. The laden absorbent liquid is then regenerated by heating and/or reducing the pressure, to desorb the carbon dioxide and to give a regenerated absorbent liquid, which is then recycled to the carbon dioxide absorption stage. Alternatively, methanol or a glycol may be used to capture the carbon dioxide in a similar manner as the amine. In a preferred arrangement, at least part of the heating to regenerate the absorbent liquid is performed using steam generated in the one or more fired heaters. If the carbon dioxide separation step is operated as a single pressure process, i.e. essentially the same pressure is employed in the absorption and regeneration steps, only a little recompression of the recycled carbon dioxide will be required.
The recovered carbon dioxide, e.g. from the AGR, may be compressed and used for the manufacture of chemicals, sent to storage or sequestration, used in enhanced oil recovery (EOR) processes or used in the production of other chemicals. Compression may be accomplished using an electrically driven compressor powered by renewable electricity. In cases where the CO2 is to be compressed for storage, transportation or use in EOR processes. the CO2 may be dried to prevent liquid water present in trace amounts, from condensing. For example, the CO2 may be dried to a dew point -10°C by passing it through a bed of a suitable desiccant, such as a zeolite, or contacting it with a glycol in a glycol drying unit.
Upon the separation of the carbon dioxide, the process provides a crude hydrogen gas stream. The crude hydrogen stream may comprise 85-99% vol hydrogen, preferably 90-99% vol hydrogen, with the balance comprising methane, carbon monoxide, carbon dioxide and inert gases. Whereas this hydrogen gas stream is pure enough for many duties, in the present invention, the crude hydrogen gas stream is passed to a purification unit to provide a purified hydrogen gas and an off-gas, so that the fuel gas may be used in the process as an alternative to external fuel sources in order to minimise the CO2 emissions from the process.
Purification unit The role of the purification unit is to receive a crude hydrogen gas stream from the water-gas shift unit and separate it into a purified hydrogen gas stream and an off-gas stream. Any suitable purification unit may be used. Preferred examples include a membrane system, a temperature swing adsorption system, or a pressure swing adsorption system. Such systems are commercially available. The purification unit is preferably a pressure swing adsorption unit or a temperature swing adsorption unit. Such units comprise regenerable porous adsorbent materials that selectively trap gases other than hydrogen and thereby purify it. The purification unit produces a pure hydrogen stream preferably with a purity greater than 99.5% vol, more preferably greater than 99.9% vol, which may be compressed and used in downstream power or heating process, for example, by using it as fuel in a gas turbine (GT) or by injection into a domestic or industrial networked gas piping system. The pure hydrogen may also be used in a downstream chemical synthesis process. Thus, the pure hydrogen stream may be used to produce ammonia by reaction with nitrogen in an ammonia synthesis unit. Alternatively, the pure hydrogen may be used with a carbon dioxide-containing gas to manufacture methanol in a methanol production unit. Alternatively, the pure hydrogen may be used with a carbon-monoxide containing gas to synthesise hydrocarbons in a Fischer-Tropsch production unit. Any known ammonia, methanol or Fischer-Tropsch production technology may be used. Alternatively, the hydrogen may be used to upgrade hydrocarbons, e.g. by hydro-treating or hydro-cracking hydrocarbons in a hydrocarbon refinery, or in any other process where pure hydrogen may be used. Compression may again be accomplished using an electrically driven compressor powered by renewable electricity.
In the present invention the off-gas stream typically has a H2 content below 90 vol%, typically 70 to 90 vol%, such as 75 to 85 vol%. The off-gas typically has a hydrocarbons content typically of 2.5 to 7.5 vol%, such as 4 to 6 vol%. The off-gas has a higher hydrocarbons content and a lower hydrogen content than the off-gas in the arrangement described in W02022/003312A1 where stream (142) has a hydrogen content of 87.56 mol% and a methane content of 2.19 mol%.
Recycle The off-gas stream is split into a fuel gas stream and a recycle stream (step (viii)). The fuel gas stream is fed to one or more fired heaters used to heat one or more process streams within the process. The recycle stream is then compressed (step (ix)) and split into a hydrodesulphurisation recycle stream and a process recycle stream (step (x)). The hydrodesulphurisation recycle stream is fed to the hydrodesulphurisation unit (step (xi)) to provide hydrogen for the reactions taking place there. The process recycle stream is returned to one or more locations (step (xii)). The process recycle stream may be reintroduced to the process at various different locations (arrangements (xii-a) to (xii-e)).
The relative ratio of the mass flows of fuel gas: process recycle stream: hydrodesulfurisation recycle stream depends on several factors including the demand on the fired heater, the H2 demand for the dehydrodesulfurisation unit, and the H2 content of the hydrogen-containing off-gas stream. The proportion used as process recycle is determined by subtracting the fraction required for the fired heater duty, then subtracting the fraction required for the HDS duty. The remainder is sent for recycle.
In a preferred embodiment the recycle stream is reintroduced to the process downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer (arrangement (xii-a)) or downstream from the gas-heated reformer and upstream from the autothermal reformer (arrangement (xii-b)). In connection with arrangement (xii-a) if a pre-reformer is present then the recycle stream is preferably reintroduced downstream from the pre-reformer and upstream from the gas-heated reformer. An advantage of these arrangements is that they provide another opportunity to convert residual hydrocarbons in the off-gas into hydrogen and therefore improve the hydrogen yield per unit of hydrocarbon. A further advantage of these arrangements is that they provide another opportunity to convert residual carbon monoxide in the off-gas into carbon dioxide, since it will have a further pass through the water-gas shift section. This reduces carbon monoxide emissions from the process. A yet further advantage of these arrangements is that they provide another opportunity to capture residual carbon dioxide in the off-gas, since it will have a further pass through the carbon dioxide separation unit. It will be appreciated that the feed to the gas-heated reformer or autothermal reformer is typically much hotter than the off-gas from the purification unit and the off-gas may need to be heated before reintroduction.
In one embodiment of arrangement (xii-a) the relative mass flows (e.g. in ton/h) of fuel gas: process recycle stream: hydrodesulfurisation recycle stream are 66 ± 3: 28 ± 3: 6 ± 3, where the sum of these values is 100. Preferably the relative mass flows of these streams is 66 ± 2: 28 ± 2: 6 ± 2, such as 66 ± 1: 28 ± 1: 6 ± 1.
In one embodiment the recycle stream is reintroduced to the process downstream from the autothermal reformer and upstream from the water-gas shift unit (arrangement (xii-c)). This arrangement provides an opportunity to reduce the carbon monoxide content of the off-gas.
In one the recycle stream is reintroduced to the process at a location which is downstream from the water-gas shift unit and upstream from the carbon dioxide removal unit (arrangement (xii-d)). This arrangement provides a further opportunity to separate hydrogen and unconverted hydrocarbons.
In one the recycle stream is reintroduced to the process at a location which is downstream from the carbon dioxide removal unit and upstream from the purification unit (arrangement (xii-e)). This arrangement provides a further opportunity to separate hydrogen and unconverted hydrocarbons.
It will be appreciated that more complicated arrangements are possible, e.g. where the recycle stream is introduced at two or more different locations out of the options specified. For simplicity of design it is preferred that the recycle is introduced at only a single location of (xii-a) to (xii-e), preferably (xii-a) or (xii-b).
The combination of steps as described herein provides sufficient fuel gas to heat the process streams used in the process without significant additional fuel during normal operation. The volume of supplemental fuel in the process is desirably kept to a minimum to maximise the CO2 capture efficiency. The amount of the supplemental fuel, e.g. natural gas, fed to the one or more fired heaters along with the fuel gas is preferably less than 5% vol of the total fuel provided, more preferably less than 3% vol of the total fuel provided, most preferably less than 2% of the total fuel provided.
In some circumstances, such as during start-up of the process, it may be necessary to supplement the fuel gas with a hydrocarbon fuel temporarily, but this should not materially reduce the efficiency of the process, and during normal operation the fuel gas recovered from the purification unit will be the main source of fuel provided to the one or more fired heaters.
In some embodiments, a single fired heater fuelled at least in part by the fuel gas is sufficient to heat the hydrocarbon, the reformed gas recovered from the pre-reforming stage upstream of the autothermal reforming stage, and water to generate at least part of the steam for the process.
Whereas all the process streams requiring heating may be heated in a single fired heater, in a preferred arrangement one fired heater is used for process gas streams containing hydrocarbon and/or hydrogen and another is used solely to boil water for steam generation. The latter may therefore also be described as a boiler. The fuel gas may therefore be divided between a first fired heater used to heat hydrocarbon-and/or hydrogen-containing streams and a second fired heater used to boil water to generate steam. Using two fired heaters in this way provides a number of distinct advantages; it allows for steam to be raised within the second fired heater and thereby used as part of the plant start-up; it allows steam to be generated in the second fired heater whilst the plant is being shut down and supplied to the plant during the shut-down process; it makes start-up easier as the first and second fired heaters can be operated independently and eliminates coils being heated in a no-flow regime; and separating the first fired heater allows nitrogen to be warmed up as part of the start-up procedure whilst the second fired heater is either being brought into service or is itself being started up. The fuel gas split to the first and second fired heaters may be in the ranges of 10-90% vol to 90-10% vol respectively but is preferably 6080% vol to the first fired heater and 40-20% vol to the second fired heater.
Steam generated in the second fired heater may be used to heat the CO2 absorbent liquid in the carbon dioxide separation unit. The second fired heater may also be used to superheat steam recovered from the steam drum coupled to a waste-heat boiler heated by the reformed gas. The waste-heat boiler preferably is also used to generate steam used to pre-heat the oxygen-rich gas and/or to provide process steam to be added upstream of the water-gas shift unit to maximise the conversion to hydrogen and carbon dioxide. A portion of the steam from the waste-heat boiler may also be passed to a steam expander to generate power.
Examples
Example 1 (Comparative) This example corresponds to the flowsheet depicted in Figure 1 of VV02022/003312A1. The steam to carbon ratio of the feed to the gas-heated reformer is 3.1: 1. Selected heat and mass balance calculations from the example modelled in W02022/003312A1 are shown in Table 1. A simplified version of the flowsheet is depicted in Figure 1.
Example 2 (According to invention) The flowsheet depicted in W02022/003312A1 was modified as follows. The steam to carbon ratio of the feed to the gas-heated reformer was 2.6: 1. The off-gas was split into a fuel gas stream and a recycle stream. The recycle stream was itself split into a process recycle stream (219) and a desulfurisation recycle stream (220). This example corresponds to the arrangement shown in Figure 2. Heat and mass balance calculations for selected streams are shown in Table 2. The relative mass flow of mass flow of fuel gas: process recycle stream: hydrodesulfurisation recycle stream in the example is 66: 28: 6.
Stream # in 10 12 48 70 126 130 132 140 142 Stream in Fig. 1 101 102 105 108 111 113 114 116 117 Temperature 40 94 440 240 40 1 49 10 40 (°C) Pressure (bare) 45.0 47.0 41.3 33.6 31.1 21.0 31.1 46.0 1.5 Mass flow (ton/h) 29.3 0.1 125.1 151.3 87.7 75.3 12.3 9.0 3.2 Composition (mol%) H20 - - 76.15 43.98 0.27 0.05 0.23 - 1.82 H2 100.00 0.47 38.89 73.89 0.21 98.43 100.00 87.56 CO - - 0.00 10.35 0.48 - 0.64 - 5.09 CO2 2.00 0.51 6.46 24.87 99.74 0.04 0.32 N2 0.89 - 0.21 0.18 0.27 - 0.36 - 2.82 CH4 89.00 20.75 0.14 0.21 0.28 2.19 C2H6 7.00 - 1.63 - - - - - -C3He 1.00 0.23 C41-110 0.10 - 0.02 - - - - - -C5H12 0.01 CH3OH - - 0.01 - 0.01 - - - -NH3 0.01 0.01 0.03
Table 1.
Stream in Fig. 201 220 205 208 211 214 216 219 218 Temperature 20 121 440 1020 258 40 45 121 40 (°C) Pressure 50.0 45.0 42.0 36.1 34.0 31.4 50.0 45.8 4.1 (bara) Mass flow 27.79 0.32 107.00 131.00 131.00 14.05 9.11 1.46 3.41 (ton/h) Composition (mol%) H20 0.32 71.25 39.03 27.90 0.24 0.32 1.80 H2 - 79.09 2.49 42.37 53.43 97.16 99.91 79.09 77.92 CO - 7.07 0.26 11.99 0.48 0.87 - 7.07 6.96 CO2 2.00 4.80 0.65 6.10 17.50 0.59 4.80 4.73 N2 0.89 2.59 0.31 0.20 0.20 0.36 0.05 2.59 2.55 Ar 0.53 0.02 0.05 0.05 0.09 0.03 0.53 0.52 CH4 89.00 5.54 22.88 0.25 0.37 0.68 0.00 5.54 5.46 C2E-16 7.00 - 1.79 - - - - - -C3H8 1.00 0.26 C4E-110 0.10 - 0.03 - - - - - -CH3OH 0.01 0.08 0.06 0.01 0.01 NH3 - 0.05 0.01 - 0.01 0.01 - 0.05 0.05
Table 2.
Claims (18)
- Claims 1. A process for the production of hydrogen comprising the steps of: (i) passing a hydrogen stream (220, 320, 420, 520) and a feed stream comprising hydrocarbons (201, 301, 401, 501) to a hydrodesulphurisation unit (203, 303, 403, 503) and carrying out hydrodesulphurisation to produce a purified hydrocarbon stream; (ii) adding steam (204, 304, 404, 504) to the purified hydrocarbon stream to produce a gaseous mixture comprising hydrocarbons and steam (205, 305, 405, 505); (iii) subjecting the gaseous mixture comprising hydrocarbons and steam to steam reforming in a reforming section (207, 307, 407, 507) comprising a gas-heated reformer (207a, 307a, 407a, 507a) and an autothermal reformer (207b, 307b, 407b, 507b) to generate a reformed gas mixture (208, 308, 408, 508); (iv) increasing the hydrogen content of the reformed gas mixture by subjecting it to one or more water-gas shift stages in a water-gas shift (210, 310, 410, 510) unit to provide a hydrogen-enriched reformed gas (211, 311, 411, 511); (v) cooling the hydrogen-enriched reformed gas and separating condensed water therefrom to provide a de-watered hydrogen-enriched reformed gas; (vi) passing the de-watered hydrogen-enriched reformed gas to a carbon dioxide separation unit (212, 312, 412, 512) to provide a carbon dioxide gas stream (213, 313, 413, 513) and a crude hydrogen gas stream (214, 314, 414, 514); (vii) passing the crude hydrogen gas stream from the carbon dioxide removal unit to a purification unit (215, 315, 415, 515) to provide a purified hydrogen gas stream (216, 316, 416, 516) and a hydrocarbon-containing off-gas stream (217, 317, 417, 517); (viii) splitting the off-gas stream into a fuel gas stream (218, 318, 418, 518) and a recycle stream (219, 319, 419, 519), wherein the fuel gas stream is fed to one or more fired heaters used to heat one or more process streams within the process; (ix) compressing the recycle stream; (x) splitting the compressed recycle stream into a hydrodesulphurisafion recycle stream (220, 320, 420, 520) and a process recycle stream (221, 321, 421, 521); (xi) feeding the hydrodesulphurisafion recycle stream to the hydrodesulphurisafion unit; (xii) returning the process recycle stream to one or more locations selected from: (xii-a) downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer; (xii-d) downstream from the gas-heated reformer and upstream from the autothermal reformer; (xii-c) downstream from the autothermal reformer and upstream from the water-gas shift unit; (xii-d) downstream from the water-gas shift unit and upstream from the carbon dioxide separation unit; or (xii-e) downstream from the carbon dioxide separation unit and upstream from the purification unit.
- 2. A process according to claim 1, wherein the steam to carbon ratio of the gaseous mixture comprising hydrocarbons and steam at the inlet to the gas-heated reformer in step (iii) is from 2.0: 1 to 3.5: 1.
- 3. A process according to claim 1, wherein the steam to carbon ratio of the gaseous mixture comprising hydrocarbons and steam at the inlet to the gas-heated reformer in step (iii) is from 2.6: Ito 3.5: I.
- 4. A process according to claim 1, wherein the steam to carbon ratio of the gaseous mixture comprising hydrocarbons and steam at the inlet to the gas-heated reformer in step (iii) is from 2.0: 1 to 2.4: 1 and wherein further steam is added to the reformed gas mixture upstream of the water-gas shift unit.
- 5. A process according to any of claims 1 to 4, wherein the recycle stream is returned to the process at location (xii-a).
- 6. A process according to any of claims 1 to 5, wherein the process recycle stream is returned to the process at a single location.
- 7. A process according to any of claims 1 to 6, wherein the gas-heated reformer and autothermal reformer are arranged in series.
- 8. A process according to any of claims 1 to 7, wherein the off-gas stream separated in step (vii) comprises 70 to 90 vol% hydrogen.
- 9. A process according to any of claims 1 to 8, wherein the off-gas stream separated in step (vii) comprises 2.5 to 7.5 vol% hydrocarbons.
- 10. A process according to any of claims 1 to 9, wherein the gaseous mixture comprising hydrocarbons and steam is formed by hydrocarbons with steam generated by the one or more Fred heaters and/or by cooling the reformed gas mixture with water.
- 11. A process according to any of claims 1 to 10, wherein the purification unit is a pressure swing adsorption unit or a temperature swing adsorption unit.
- 12. A process according to any of claims 1 toll, wherein the steam added in step (ii) is generated by combusting the fuel gas stream in said one or more fired heaters.
- 13. A chemical plant comprising: (i) a hydrodesulphurisation unit (203, 303, 403, 503) arranged to receive a hydrogen stream (202, 302, 402, 502) and a feed stream comprising hydrocarbons (201, 301, 401, 501) and carry out hydrodesulphurisation to produce a purified hydrocarbon stream; (ii) means to add steam (204, 304, 404, 504) to the purified hydrocarbon stream to produce a gaseous mixture comprising hydrocarbons and steam (205, 305, 405, 505); (iii) a reforming section (207, 307, 407, 507) comprising a gas-heated reformer (207a, 307a, 407a, 507a) and an autothermal reformer (207b, 307b, 407b, 507b), arranged to receive the gaseous mixture comprising hydrocarbons and steam, and to generate a reformed gas mixture (208, 308, 408, 508); (iv) a water-gas shift (210, 310, 410, 510) unit arranged to receive the reformed gas mixture, and to generate a hydrogen-enriched reformed gas (211, 311, 411, 511); (v) means for cooling the hydrogen-enriched reformed gas and separating condensed water therefrom to provide a de-watered hydrogen-enriched reformed gas; (vi) a carbon dioxide separation unit (212, 312, 412, 512) arranged to receive the de-watered hydrogen-enriched reformed gas, and to generate a carbon dioxide gas stream (213, 313, 413, 513) and a crude hydrogen gas stream (214, 314, 414, 514); (vii) a purification unit (215, 315, 415, 515) arranged to receive the crude hydrogen gas stream, and to generate a purified hydrogen gas stream (216, 316, 416, 516) and a hydrocarbon-containing off-gas stream (217, 317, 417, 517); (viii) means for splitting the off-gas stream into a fuel gas stream (218, 318, 418, 518) and a recycle stream (219, 319, 419, 519), and means for feeding the fuel gas stream to one or more fired heaters used to heat one or more process streams within the process; (ix) means for compressing the recycle stream; (x) means for splitting the compressed recycle stream into a hydrodesulphurisation recycle stream (220, 320, 420, 520) and a process recycle stream (221, 321, 421, 521); (xi) means for feeding the hydrodesulphurisation recycle stream to the hydrodesulphurisation unit; (xii) means for returning the process recycle stream to one or more locations selected from: (xii-a) downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer; (xii-d) downstream from the gas-heated reformer and upstream from the autothermal reformer; (xii-c) downstream from the autothermal reformer and upstream from the water-gas shift unit; (xii-d) downstream from the water-gas shift unit and upstream from the carbon dioxide separation unit; or (xii-e) downstream from the carbon dioxide separation unit and upstream from the purification unit.
- 14. A chemical plant according to claim 13, wherein the plant comprises a pre-reformer either upstream from the hydrodesulphurisation unit, or downstream from the hydrodesulphurisation unit and upstream from the gas-heated reformer.
- 15. A chemical plant according to claim 13 or claim 14 wherein the recycle stream is returned to the process at location (xii-a).
- 16. A chemical plant according to any of claims 13 to 15, wherein the process recycle stream is returned to the process at a single location.
- 17. A chemical plant according to any of claims 13 to 16, wherein the gas-heated reformer and autothermal reformer are arranged in series.
- 18. A chemical plant according to any of claims 13 to 17, wherein the steam added in step (ii) is generated by combusting the fuel gas stream in said one or more fired heaters.
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| US7988948B2 (en) * | 2008-03-17 | 2011-08-02 | Air Products And Chemicals, Inc. | Steam-hydrocarbon reforming method with limited steam export |
| WO2012103432A2 (en) | 2011-01-28 | 2012-08-02 | Catacel Corp. | Improved stackable structural reactors |
| JP6105042B2 (en) | 2012-04-02 | 2017-03-29 | ジョンソン、マッセイ、パブリック、リミテッド、カンパニーＪｏｈｎｓｏｎ Ｍａｔｔｈｅｙ Ｐｕｂｌｉｃ Ｌｉｍｉｔｅｄ Ｃｏｍｐａｎｙ | Wire standoffs for stackable structural reactors |
| GB2571136A (en) | 2018-02-20 | 2019-08-21 | Reinertsen New Energy As | Gas processing |
| GB202009969D0 (en) | 2020-06-30 | 2020-08-12 | Johnson Matthey Plc | Low-carbon hydrogen process |
| US11807532B2 (en) * | 2021-03-29 | 2023-11-07 | Uop Llc | Method of recovering a hydrogen enriched product and CO2 in a hydrogen production unit |
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| EP2103569A2 (en) * | 2008-03-17 | 2009-09-23 | Air Products and Chemicals, Inc. | Steam-hydrocarbon reforming method with limited steam export |
| US20220194789A1 (en) * | 2019-05-02 | 2022-06-23 | Haldor Topsøe A/S | Atr-based hydrogen process and plant |
| WO2022038089A1 (en) * | 2020-08-17 | 2022-02-24 | Haldor Topsøe A/S | Atr-based hydrogen process and plant |
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| GB202219362D0 (en) | 2023-02-01 |
| WO2024134158A1 (en) | 2024-06-27 |
| GB202319222D0 (en) | 2024-01-31 |
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