CA2773718C - Integrated enhanced oil recovery process - Google Patents
Integrated enhanced oil recovery process Download PDFInfo
- Publication number
- CA2773718C CA2773718C CA2773718A CA2773718A CA2773718C CA 2773718 C CA2773718 C CA 2773718C CA 2773718 A CA2773718 A CA 2773718A CA 2773718 A CA2773718 A CA 2773718A CA 2773718 C CA2773718 C CA 2773718C
- Authority
- CA
- Canada
- Prior art keywords
- stream
- hydrocarbon
- acid gas
- gas
- carbon dioxide
- 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.)
- Expired - Fee Related
Links
- 238000011084 recovery Methods 0.000 title claims abstract description 13
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract description 298
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 172
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract description 148
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 143
- 238000003786 synthesis reaction Methods 0.000 claims abstract description 141
- 238000000034 method Methods 0.000 claims abstract description 128
- 239000001569 carbon dioxide Substances 0.000 claims abstract description 110
- 230000008569 process Effects 0.000 claims abstract description 107
- 238000002309 gasification Methods 0.000 claims abstract description 23
- 239000007789 gas Substances 0.000 claims description 391
- 229930195733 hydrocarbon Natural products 0.000 claims description 199
- 150000002430 hydrocarbons Chemical class 0.000 claims description 199
- 239000002253 acid Substances 0.000 claims description 194
- 239000004215 Carbon black (E152) Substances 0.000 claims description 193
- 239000006096 absorbing agent Substances 0.000 claims description 118
- 239000001257 hydrogen Substances 0.000 claims description 75
- 229910052739 hydrogen Inorganic materials 0.000 claims description 75
- 239000012530 fluid Substances 0.000 claims description 73
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 claims description 62
- 238000004519 manufacturing process Methods 0.000 claims description 45
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 claims description 38
- 229910002091 carbon monoxide Inorganic materials 0.000 claims description 38
- 239000007788 liquid Substances 0.000 claims description 37
- 238000000926 separation method Methods 0.000 claims description 32
- 230000003197 catalytic effect Effects 0.000 claims description 24
- 238000004891 communication Methods 0.000 claims description 21
- 238000002347 injection Methods 0.000 claims description 16
- 239000007924 injection Substances 0.000 claims description 16
- 230000008929 regeneration Effects 0.000 claims description 16
- 238000011069 regeneration method Methods 0.000 claims description 16
- 150000002431 hydrogen Chemical class 0.000 claims description 13
- 239000003575 carbonaceous material Substances 0.000 claims description 10
- 230000003647 oxidation Effects 0.000 claims description 10
- 238000007254 oxidation reaction Methods 0.000 claims description 10
- 238000002453 autothermal reforming Methods 0.000 claims description 5
- 238000011143 downstream manufacturing Methods 0.000 claims description 3
- 238000001991 steam methane reforming Methods 0.000 claims description 3
- 238000002407 reforming Methods 0.000 abstract description 9
- 239000000047 product Substances 0.000 description 56
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 24
- 239000003921 oil Substances 0.000 description 23
- 235000019198 oils Nutrition 0.000 description 23
- 229910001868 water Inorganic materials 0.000 description 23
- 239000002028 Biomass Substances 0.000 description 21
- 238000006243 chemical reaction Methods 0.000 description 21
- 239000000356 contaminant Substances 0.000 description 21
- 239000002006 petroleum coke Substances 0.000 description 20
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 20
- 239000003245 coal Substances 0.000 description 19
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 19
- 239000007787 solid Substances 0.000 description 19
- 238000012545 processing Methods 0.000 description 18
- 239000003054 catalyst Substances 0.000 description 16
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 14
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 14
- 239000000203 mixture Substances 0.000 description 14
- 239000003345 natural gas Substances 0.000 description 14
- 239000000463 material Substances 0.000 description 13
- 239000002956 ash Substances 0.000 description 10
- 238000005516 engineering process Methods 0.000 description 9
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 8
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 8
- 229910052799 carbon Inorganic materials 0.000 description 8
- 239000010881 fly ash Substances 0.000 description 8
- 239000010882 bottom ash Substances 0.000 description 7
- 239000010779 crude oil Substances 0.000 description 7
- 230000018044 dehydration Effects 0.000 description 7
- 238000006297 dehydration reaction Methods 0.000 description 7
- 229910052757 nitrogen Inorganic materials 0.000 description 7
- 239000000377 silicon dioxide Substances 0.000 description 7
- 239000007795 chemical reaction product Substances 0.000 description 6
- 239000003077 lignite Substances 0.000 description 6
- MWUXSHHQAYIFBG-UHFFFAOYSA-N nitrogen oxide Inorganic materials O=[N] MWUXSHHQAYIFBG-UHFFFAOYSA-N 0.000 description 6
- 241001465754 Metazoa Species 0.000 description 5
- 239000002802 bituminous coal Substances 0.000 description 5
- 239000003795 chemical substances by application Substances 0.000 description 5
- 239000003476 subbituminous coal Substances 0.000 description 5
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 description 4
- 241000196324 Embryophyta Species 0.000 description 4
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 4
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 4
- 239000001301 oxygen Substances 0.000 description 4
- 229910052760 oxygen Inorganic materials 0.000 description 4
- 239000002904 solvent Substances 0.000 description 4
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical class OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 3
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 3
- RHZUVFJBSILHOK-UHFFFAOYSA-N anthracen-1-ylmethanolate Chemical compound C1=CC=C2C=C3C(C[O-])=CC=CC3=CC2=C1 RHZUVFJBSILHOK-UHFFFAOYSA-N 0.000 description 3
- 239000003830 anthracite Substances 0.000 description 3
- 239000000571 coke Substances 0.000 description 3
- 238000002485 combustion reaction Methods 0.000 description 3
- UAOMVDZJSHZZME-UHFFFAOYSA-N diisopropylamine Chemical compound CC(C)NC(C)C UAOMVDZJSHZZME-UHFFFAOYSA-N 0.000 description 3
- 239000012528 membrane Substances 0.000 description 3
- 230000009919 sequestration Effects 0.000 description 3
- 239000002699 waste material Substances 0.000 description 3
- OTMSDBZUPAUEDD-UHFFFAOYSA-N Ethane Chemical compound CC OTMSDBZUPAUEDD-UHFFFAOYSA-N 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- UQSXHKLRYXJYBZ-UHFFFAOYSA-N Iron oxide Chemical compound [Fe]=O UQSXHKLRYXJYBZ-UHFFFAOYSA-N 0.000 description 2
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 2
- 240000008042 Zea mays Species 0.000 description 2
- 235000005824 Zea mays ssp. parviglumis Nutrition 0.000 description 2
- 235000002017 Zea mays subsp mays Nutrition 0.000 description 2
- XLOMVQKBTHCTTD-UHFFFAOYSA-N Zinc monoxide Chemical compound [Zn]=O XLOMVQKBTHCTTD-UHFFFAOYSA-N 0.000 description 2
- 229910021529 ammonia Inorganic materials 0.000 description 2
- -1 asphaltenes Substances 0.000 description 2
- 239000012267 brine Substances 0.000 description 2
- 239000001273 butane Substances 0.000 description 2
- 239000006227 byproduct Substances 0.000 description 2
- 239000000919 ceramic Substances 0.000 description 2
- 238000004939 coking Methods 0.000 description 2
- 230000006835 compression Effects 0.000 description 2
- 238000007906 compression Methods 0.000 description 2
- 238000010276 construction Methods 0.000 description 2
- 238000011109 contamination Methods 0.000 description 2
- 235000005822 corn Nutrition 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 238000004821 distillation Methods 0.000 description 2
- 238000010981 drying operation Methods 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 239000000446 fuel Substances 0.000 description 2
- 238000010438 heat treatment Methods 0.000 description 2
- 230000010354 integration Effects 0.000 description 2
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 description 2
- 229910052753 mercury Inorganic materials 0.000 description 2
- 229910052751 metal Inorganic materials 0.000 description 2
- 239000002184 metal Substances 0.000 description 2
- 150000002739 metals Chemical class 0.000 description 2
- 239000002808 molecular sieve Substances 0.000 description 2
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical compound CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 2
- OFBQJSOFQDEBGM-UHFFFAOYSA-N n-pentane Natural products CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 2
- 239000003027 oil sand Substances 0.000 description 2
- 239000003208 petroleum Substances 0.000 description 2
- BWHMMNNQKKPAPP-UHFFFAOYSA-L potassium carbonate Chemical compound [K+].[K+].[O-]C([O-])=O BWHMMNNQKKPAPP-UHFFFAOYSA-L 0.000 description 2
- 238000010248 power generation Methods 0.000 description 2
- 239000001294 propane Substances 0.000 description 2
- QQONPFPTGQHPMA-UHFFFAOYSA-N propylene Natural products CC=C QQONPFPTGQHPMA-UHFFFAOYSA-N 0.000 description 2
- 125000004805 propylene group Chemical group [H]C([H])([H])C([H])([*:1])C([H])([H])[*:2] 0.000 description 2
- 239000000376 reactant Substances 0.000 description 2
- URGAHOPLAPQHLN-UHFFFAOYSA-N sodium aluminosilicate Chemical compound [Na+].[Al+3].[O-][Si]([O-])=O.[O-][Si]([O-])=O URGAHOPLAPQHLN-UHFFFAOYSA-N 0.000 description 2
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 2
- 238000000629 steam reforming Methods 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- 229910052717 sulfur Inorganic materials 0.000 description 2
- 239000011593 sulfur Substances 0.000 description 2
- 229910052815 sulfur oxide Inorganic materials 0.000 description 2
- 238000005979 thermal decomposition reaction Methods 0.000 description 2
- 229910052723 transition metal Inorganic materials 0.000 description 2
- 150000003624 transition metals Chemical class 0.000 description 2
- GIAFURWZWWWBQT-UHFFFAOYSA-N 2-(2-aminoethoxy)ethanol Chemical compound NCCOCCO GIAFURWZWWWBQT-UHFFFAOYSA-N 0.000 description 1
- HZAXFHJVJLSVMW-UHFFFAOYSA-N 2-Aminoethan-1-ol Chemical compound NCCO HZAXFHJVJLSVMW-UHFFFAOYSA-N 0.000 description 1
- 240000000559 Albizia odoratissima Species 0.000 description 1
- 235000011438 Albizia odoratissima Nutrition 0.000 description 1
- 241000609240 Ambelania acida Species 0.000 description 1
- 235000017166 Bambusa arundinacea Nutrition 0.000 description 1
- 235000017491 Bambusa tulda Nutrition 0.000 description 1
- QPLDLSVMHZLSFG-UHFFFAOYSA-N Copper oxide Chemical class [Cu]=O QPLDLSVMHZLSFG-UHFFFAOYSA-N 0.000 description 1
- 241000195493 Cryptophyta Species 0.000 description 1
- XTHFKEDIFFGKHM-UHFFFAOYSA-N Dimethoxyethane Chemical compound COCCOC XTHFKEDIFFGKHM-UHFFFAOYSA-N 0.000 description 1
- 240000003133 Elaeis guineensis Species 0.000 description 1
- 235000001950 Elaeis guineensis Nutrition 0.000 description 1
- 244000004281 Eucalyptus maculata Species 0.000 description 1
- 241000221089 Jatropha Species 0.000 description 1
- 240000004658 Medicago sativa Species 0.000 description 1
- 235000017587 Medicago sativa ssp. sativa Nutrition 0.000 description 1
- 240000003433 Miscanthus floridulus Species 0.000 description 1
- 240000007594 Oryza sativa Species 0.000 description 1
- 235000007164 Oryza sativa Nutrition 0.000 description 1
- 241001520808 Panicum virgatum Species 0.000 description 1
- 241000321453 Paranthias colonus Species 0.000 description 1
- 244000082204 Phyllostachys viridis Species 0.000 description 1
- 235000015334 Phyllostachys viridis Nutrition 0.000 description 1
- 241000219000 Populus Species 0.000 description 1
- 235000019484 Rapeseed oil Nutrition 0.000 description 1
- 240000000111 Saccharum officinarum Species 0.000 description 1
- 235000007201 Saccharum officinarum Nutrition 0.000 description 1
- 241000124033 Salix Species 0.000 description 1
- 235000015503 Sorghum bicolor subsp. drummondii Nutrition 0.000 description 1
- 244000138286 Sorghum saccharatum Species 0.000 description 1
- 235000011684 Sorghum saccharatum Nutrition 0.000 description 1
- 244000062793 Sorghum vulgare Species 0.000 description 1
- 241000982035 Sparattosyce Species 0.000 description 1
- 244000170625 Sudangrass Species 0.000 description 1
- 241000219793 Trifolium Species 0.000 description 1
- WGLPBDUCMAPZCE-UHFFFAOYSA-N Trioxochromium Chemical compound O=[Cr](=O)=O WGLPBDUCMAPZCE-UHFFFAOYSA-N 0.000 description 1
- 241001464837 Viridiplantae Species 0.000 description 1
- 238000010521 absorption reaction Methods 0.000 description 1
- 230000032683 aging Effects 0.000 description 1
- 229910052783 alkali metal Inorganic materials 0.000 description 1
- 150000001340 alkali metals Chemical class 0.000 description 1
- 229910052784 alkaline earth metal Inorganic materials 0.000 description 1
- 150000001342 alkaline earth metals Chemical class 0.000 description 1
- 150000001413 amino acids Chemical class 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 239000012736 aqueous medium Substances 0.000 description 1
- 125000003118 aryl group Chemical group 0.000 description 1
- 239000010905 bagasse Substances 0.000 description 1
- 239000011425 bamboo Substances 0.000 description 1
- 239000010884 boiler slag Substances 0.000 description 1
- 238000009835 boiling Methods 0.000 description 1
- 235000019519 canola oil Nutrition 0.000 description 1
- 239000000828 canola oil Substances 0.000 description 1
- 238000003763 carbonization Methods 0.000 description 1
- 230000015556 catabolic process Effects 0.000 description 1
- 238000005119 centrifugation Methods 0.000 description 1
- 229910000423 chromium oxide Inorganic materials 0.000 description 1
- 238000005352 clarification Methods 0.000 description 1
- 239000000567 combustion gas Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 239000004035 construction material Substances 0.000 description 1
- 238000001816 cooling Methods 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 230000007812 deficiency Effects 0.000 description 1
- 238000006731 degradation reaction Methods 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- ZBCBWPMODOFKDW-UHFFFAOYSA-N diethanolamine Chemical compound OCCNCCO ZBCBWPMODOFKDW-UHFFFAOYSA-N 0.000 description 1
- 229940043279 diisopropylamine Drugs 0.000 description 1
- 238000001704 evaporation Methods 0.000 description 1
- 230000008020 evaporation Effects 0.000 description 1
- 239000003925 fat Substances 0.000 description 1
- 210000003608 fece Anatomy 0.000 description 1
- 230000008570 general process Effects 0.000 description 1
- 239000002515 guano Substances 0.000 description 1
- 239000013056 hazardous product Substances 0.000 description 1
- 229910001892 higher sulfur oxide Inorganic materials 0.000 description 1
- 239000010903 husk Substances 0.000 description 1
- 238000005984 hydrogenation reaction Methods 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 238000005470 impregnation Methods 0.000 description 1
- 150000002484 inorganic compounds Chemical class 0.000 description 1
- 229910010272 inorganic material Inorganic materials 0.000 description 1
- 229910052500 inorganic mineral Inorganic materials 0.000 description 1
- 244000144972 livestock Species 0.000 description 1
- 239000010871 livestock manure Substances 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical compound OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 description 1
- 235000019713 millet Nutrition 0.000 description 1
- 239000011707 mineral Substances 0.000 description 1
- 239000010813 municipal solid waste Substances 0.000 description 1
- 230000007935 neutral effect Effects 0.000 description 1
- 229910052759 nickel Inorganic materials 0.000 description 1
- 150000002825 nitriles Chemical class 0.000 description 1
- 239000007800 oxidant agent Substances 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 239000003415 peat Substances 0.000 description 1
- 235000020030 perry Nutrition 0.000 description 1
- 238000005504 petroleum refining Methods 0.000 description 1
- JTJMJGYZQZDUJJ-UHFFFAOYSA-N phencyclidine Chemical class C1CCCCN1C1(C=2C=CC=CC=2)CCCCC1 JTJMJGYZQZDUJJ-UHFFFAOYSA-N 0.000 description 1
- 229910000027 potassium carbonate Inorganic materials 0.000 description 1
- 239000010867 poultry litter Substances 0.000 description 1
- 239000000843 powder Substances 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000000717 retained effect Effects 0.000 description 1
- 235000009566 rice Nutrition 0.000 description 1
- 239000010865 sewage Substances 0.000 description 1
- 239000002002 slurry Substances 0.000 description 1
- 238000002791 soaking Methods 0.000 description 1
- 159000000000 sodium salts Chemical class 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 238000001179 sorption measurement Methods 0.000 description 1
- 239000010907 stover Substances 0.000 description 1
- 239000010902 straw Substances 0.000 description 1
- XTQHKBHJIVJGKJ-UHFFFAOYSA-N sulfur monoxide Chemical class S=O XTQHKBHJIVJGKJ-UHFFFAOYSA-N 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
- 231100000331 toxic Toxicity 0.000 description 1
- 230000002588 toxic effect Effects 0.000 description 1
- 229910000314 transition metal oxide Inorganic materials 0.000 description 1
- 238000010977 unit operation Methods 0.000 description 1
- 229910052720 vanadium Inorganic materials 0.000 description 1
- GPPXJZIENCGNKB-UHFFFAOYSA-N vanadium Chemical compound [V]#[V] GPPXJZIENCGNKB-UHFFFAOYSA-N 0.000 description 1
- 235000015112 vegetable and seed oil Nutrition 0.000 description 1
- 239000008158 vegetable oil Substances 0.000 description 1
- 238000013022 venting Methods 0.000 description 1
- 238000005406 washing Methods 0.000 description 1
- 239000002023 wood Substances 0.000 description 1
- 239000010925 yard waste Substances 0.000 description 1
- 239000011787 zinc oxide Substances 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/164—Injecting CO2 or carbonated water
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/40—Separation associated with re-injection of separated materials
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0204—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the feed stream
- F25J3/0223—H2/CO mixtures, i.e. synthesis gas; Water gas or shifted synthesis gas
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
- F25J3/0233—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of CnHm with 1 carbon atom or more
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
- F25J3/0252—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of hydrogen
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J3/00—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification
- F25J3/02—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream
- F25J3/0228—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream
- F25J3/0266—Processes or apparatus for separating the constituents of gaseous or liquefied gaseous mixtures involving the use of liquefaction or solidification by rectification, i.e. by continuous interchange of heat and material between a vapour stream and a liquid stream characterised by the separated product stream separation of carbon dioxide
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2205/00—Processes or apparatus using other separation and/or other processing means
- F25J2205/40—Processes or apparatus using other separation and/or other processing means using hybrid system, i.e. combining cryogenic and non-cryogenic separation techniques
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2205/00—Processes or apparatus using other separation and/or other processing means
- F25J2205/50—Processes or apparatus using other separation and/or other processing means using absorption, i.e. with selective solvents or lean oil, heavier CnHm and including generally a regeneration step for the solvent or lean oil
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
- F25J2230/30—Compression of the feed stream
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2230/00—Processes or apparatus involving steps for increasing the pressure of gaseous process streams
- F25J2230/80—Processes or apparatus involving steps for increasing the pressure of gaseous process streams the fluid being carbon dioxide
-
- F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
- F25—REFRIGERATION OR COOLING; COMBINED HEATING AND REFRIGERATION SYSTEMS; HEAT PUMP SYSTEMS; MANUFACTURE OR STORAGE OF ICE; LIQUEFACTION SOLIDIFICATION OF GASES
- F25J—LIQUEFACTION, SOLIDIFICATION OR SEPARATION OF GASES OR GASEOUS OR LIQUEFIED GASEOUS MIXTURES BY PRESSURE AND COLD TREATMENT OR BY BRINGING THEM INTO THE SUPERCRITICAL STATE
- F25J2260/00—Coupling of processes or apparatus to other units; Integrated schemes
- F25J2260/80—Integration in an installation using carbon dioxide, e.g. for EOR, sequestration, refrigeration etc.
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
- Y02C20/00—Capture or disposal of greenhouse gases
- Y02C20/40—Capture or disposal of greenhouse gases of CO2
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P90/00—Enabling technologies with a potential contribution to greenhouse gas [GHG] emissions mitigation
- Y02P90/70—Combining sequestration of CO2 and exploitation of hydrocarbons by injecting CO2 or carbonated water in oil wells
Landscapes
- Engineering & Computer Science (AREA)
- Physics & Mathematics (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Engineering & Computer Science (AREA)
- Thermal Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Mechanical Engineering (AREA)
- Geochemistry & Mineralogy (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Gas Separation By Absorption (AREA)
- Hydrogen, Water And Hydrids (AREA)
- Industrial Gases (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
The present invention relates to an enhanced oil recovery process that is integrated with a synthesis gas generation process, such as gasification or methane reforming, involving combined capture and recycle of carbon dioxide from both processes.
Description
INTEGRATED ENHANCED OIL RECOVERY PROCESS
Field of the Invention [0001] The present invention relates to an enhanced oil recovery process that is integrated with a synthesis gas generation process, such as gasification or reforming, involving combined capture and recycle of carbon dioxide from both processes.
Background of the Invention [0002] In view of dwindling supplies of crude oil, enhanced oil recovery (EOR) techniques are receiving renewed attention.
Field of the Invention [0001] The present invention relates to an enhanced oil recovery process that is integrated with a synthesis gas generation process, such as gasification or reforming, involving combined capture and recycle of carbon dioxide from both processes.
Background of the Invention [0002] In view of dwindling supplies of crude oil, enhanced oil recovery (EOR) techniques are receiving renewed attention.
[0003] Typically, oil is produced using the natural pressure of an oil reservoir to drive the crude into the well bore from where it is brought to the surface with conventional pumps. After some period of production, the natural pressure of the oil reservoir decreases and production dwindles.
In the 1940s, producers incorporated secondary recovery by utilizing injected water, steam and/or natural gas to drive the crude to the well bore prior to pumping it to the surface.
In the 1940s, producers incorporated secondary recovery by utilizing injected water, steam and/or natural gas to drive the crude to the well bore prior to pumping it to the surface.
[0004] Once the easily extracted oil already has been recovered, producers may turn to tertiary or enhanced oil recovery (EOR) techniques. One known such EOR technique is high-pressure CO2 injection, which helps to repressurize the oil reservoir. The high-pressure CO2 also acts as a solvent, dissolving the residual oil, thereby reducing its viscosity and improving its flow characteristics, allowing it to be pumped out of an aging reservoir.
[0005] One difficulty with the use of CO2 to increase oil production is that it requires large quantities of CO2, and the availability of such large quantities of CO2 is limited.
[0006] CO2 from natural sources can be utilized, but generally requires the natural source to be in the proximity of the oil reservoir to avoid the construction and use of pipelines, which could make such use uneconomical.
[0007] Use of CO,, from combustion sources (such as power plants) has also been considered (see, for example, US7299868 and publications cited therein), but the separation of CO2 from the combustion gases is difficult and generally not considered economical.
[0008] More recently, CO2 from synthesis gas production operations has been considered for use in EOR. See, for example, US7481275. Synthesis gas production operations include, for example, catalytic gasification and hydromethanation processes, non-catalytic gasification processes and methane reforming processes. These processes typically produce one or more of methane, hydrogen and/or syngas (a mixture of hydrogen and carbon monoxide) as a raw gas product, which can be processed and ultimately used for power generation and/or other industrial applications. These processes also produce CO2, which is removed via acid gas removal processes, as is generally known to those of ordinary skill in the relevant art. Historically, this CO2 has simply been vented to the atmosphere but, in view of environmental concerns, capture and sequestration/use of this CO2 is becoming a necessity. EOR is thus a logical outlet for CO2 streams from synthesis gas production operations.
[0009] At least one such synthesis gas production operation which utilizes a CO2 by-product stream for EOR currently exists at the Great Plains Synfuels Plant (near Beulah, North Dakota USA). At this facility, coal/lignite is gasified to a synthesis gas stream containing carbon dioxide, which is separated via a solvent-based acid gas removal technique.
The resulting CO2 stream (which is greater than 95% pure) is compressed and transported via a 205-mile supercritical CO2 pipeline to oil fields in Canada for use in EOR operations.
This operation is described in more detail in Perry and Eliason, "CO2 Recovery and Sequestration at Dakota Gasification Company" (October 2004) (available from www.gasification.org), and on the Dakota Gasification Company website (www.dakotagas.com).
The resulting CO2 stream (which is greater than 95% pure) is compressed and transported via a 205-mile supercritical CO2 pipeline to oil fields in Canada for use in EOR operations.
This operation is described in more detail in Perry and Eliason, "CO2 Recovery and Sequestration at Dakota Gasification Company" (October 2004) (available from www.gasification.org), and on the Dakota Gasification Company website (www.dakotagas.com).
[0010] A disadvantage in this operation is the pipeline, as supercritical CO2 is considered a hazardous material. The construction, permitting, operation and maintenance of a supercritical CO2 pipeline, particularly one as long as 205 miles, is expensive. A more advantageous way to get the CO2 from the synthesis gas operation to the EOR site would, therefore, be highly desirable.
[0011] Another disadvantage to the use of CO2 for EOR is that, as more CO2 is pumped into an oil reservoir, more CO2 is also produced along with the other liquids and gases that come out of the well. Traditionally, CO2 that is co-produced with oil is separated and vented to the atmosphere; however, as with synthesis gas production operations, environmental concerns make this CO2 venting undesirable.
[00121 It would, therefore, be highly desirable to integrate synthesis gas production processes with EOR processes in a way that minimizes the release of CO2 into the atmosphere (maximizes capture and sequestration of CO2), reduces the need for long CO2 transport pipelines, and improves the overall integration, efficiency and economics of the two processes. Some embodiments of the present invention provide such an integration.
Summary of the Invention [0013] In a first aspect, the present invention provides an integrated process to (i) produce an acid gas-depleted gaseous hydrocarbon product steam, (ii) produce an acid gas-depleted synthesis gas stream, (iii) produce a liquid hydrocarbon product stream and (iv) enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir, the process comprising the steps of:
[0014] (1) injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir to enhance production of the hydrocarbon-containing fluid from the underground hydrocarbon reservoir via a hydrocarbon production well, the hydrocarbon-containing fluid comprising carbon dioxide;
[0015] (2) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well;
[0016] (3) separating the hydrocarbon-containing fluid into (a) the liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide;
[0017] (4) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
[0018] (5) producing a synthesis gas stream from a carbonaceous feedstock, the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane;
[0019] (6) treating the synthesis gas stream in a second acid gas absorber unit to produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
[0020] (7) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and [0021] (8) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
[0022] In a second aspect, the present invention provides a process to enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir via a hydrocarbon production well, by injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir, wherein the hydrocarbon-containing fluid comprises CA 02773718.2012-03-08 carbon dioxide, and wherein the pressurized carbon dioxide stream is generated by a process comprising the steps of:
[0023] (I) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well;
[0024] (II) splitting the hydrocarbon-containing fluid into (a) a liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide;
[0025] (III) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce an acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
[0026] (IV) producing a synthesis gas stream from a carbonaceous feedstock,.
the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane;
[0027] (V) treating the synthesis gas stream in a second acid gas absorber unit to produce an acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
[0028] (VI) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and [0029] (VII) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
[0030] In a third aspect, the invention provides an apparatus for generating a liquid hydrocarbon product stream, an acid gas-depleted gaseous hydrocarbon product stream and an acid gas-depleted synthesis gas stream, the apparatus comprising:
[0031] (A) a synthesis gas production system adapted to produce a synthesis gas from a carbonaceous feedstock, the synthesis gas comprising (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane;
[0032] (B) a carbon dioxide injection well in fluid communication with an underground hydrocarbon reservoir, the carbon dioxide injection well adapted to inject a pressurized carbon dioxide stream into the underground hydrocarbon reservoir for enhanced oil recovery;
[0033] (C) a hydrocarbon production well in fluid communication with the underground hydrocarbon reservoir, the hydrocarbon production well adapted to remove a hydrocarbon fluid from the underground hydrocarbon reservoir, the hydrocarbon fluid comprising carbon dioxide;
[0034] (D) a separation device in fluid communication with the hydrocarbon production well, the separation device adapted (i) to receive the hydrocarbon fluid from the hydrocarbon production well, and (ii) to separate the hydrocarbon fluid into the liquid hydrocarbon product stream and a gaseous hydrocarbon stream comprising carbon dioxide;
[0035] (E) a first acid gas absorber unit in fluid communication with the separation device, the first acid gas absorber unit adapted to (i) receive the gaseous hydrocarbon stream from the separation device, and (ii) treat the gaseous hydrocarbon stream to remove acid gases and produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
[0036] (F) a second acid gas absorber unit in fluid communication with the synthesis gas generation system, the second acid gas absorber unit adapted to (i) receive the synthesis gas from the synthesis gas generation system, and (ii) treat the synthesis gas to remove acid gases and produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
[0037] (G) an absorber regeneration unit in fluid communication with the first acid gas absorber unit and the second acid gas absorber unit, the absorber regeneration unit adapted to (i) receive the first acid gas-rich absorber stream from the first acid gas absorber unit and the second acid gas-rich absorber stream from the second acid gas absorber unit, (ii) remove acid gases from the first acid gas-rich absorber stream and the second acid gas-rich absorber stream, and (iii) generate an acid gas-lean absorber stream and a carbon dioxide-rich recycle stream; and [0038] (H) a compressor unit in fluid communication with the absorber regeneration unit and the carbon dioxide injection well, the compressor unit adapted to (i) receive the carbon dioxide-rich recycle stream, and (ii) compress the carbon dioxide recycle stream to generate the pressurized carbon dioxide stream, and (iii) provide the pressurized carbon dioxide stream to the carbon dioxide injection well.
[0038a] According to one aspect of the present invention, there is provided an integrated process to (i) produce an acid gas-depleted gaseous hydrocarbon product stream, (ii) produce an acid gas-depleted synthesis gas stream, (iii) produce a liquid hydrocarbon product stream and (iv) enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir, the process comprising the steps of: (1) injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir to enhance production of the hydrocarbon-containing fluid from the underground hydrocarbon reservoir via a hydrocarbon production well, the hydrocarbon-containing fluid comprising carbon dioxide;
(2) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well; (3) separating the hydrocarbon-containing fluid into (a) the liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide; (4) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream; (5) producing a synthesis gas stream from a carbonaceous feedstock, the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane; (6) treating the synthesis gas stream in a second acid gas absorber unit to produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream; (7) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and (8) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
[003813] According to another aspect of the present invention, there is provided an apparatus for generating a liquid hydrocarbon product stream, an acid gas-depleted gaseous hydrocarbon product stream and an acid gas-depleted synthesis gas stream, the apparatus comprising: (A) a synthesis gas generation system adapted to produce a synthesis gas from a carbonaceous feedstock, the synthesis gas comprising (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane; (B) a carbon dioxide injection well in fluid communication with an underground hydrocarbon reservoir, the carbon dioxide injection well adapted to inject a pressurized carbon dioxide stream into the underground hydrocarbon reservoir for enhanced oil recovery; (C) a hydrocarbon production well in fluid 5a communication with the underground hydrocarbon reservoir, the hydrocarbon production well adapted to remove a hydrocarbon fluid from the underground hydrocarbon reservoir, the hydrocarbon fluid comprising carbon dioxide; (D) a separation device in fluid communication with the hydrocarbon production well, the separation device adapted (i) to receive the hydrocarbon fluid from the hydrocarbon production well, and (ii) to separate the hydrocarbon fluid into the liquid hydrocarbon product stream and a gaseous hydrocarbon stream comprising carbon dioxide; (E) a first acid gas absorber unit in fluid communication with the separation device, the first acid gas absorber unit adapted to (i) receive the gaseous hydrocarbon stream from the separation device, and (ii) treat the gaseous hydrocarbon stream to remove acid gases and produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream; (F) a second acid gas absorber unit in fluid communication with the synthesis gas generation system, the second acid gas absorber unit adapted to (i) receive the synthesis gas from the synthesis gas generation system, and (ii) treat the synthesis gas to remove acid gases and produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream; (G) an absorber regeneration unit in fluid communication with the first acid gas absorber unit and the second acid gas absorber unit, the absorber regeneration unit adapted to (i) receive the first acid gas-rich absorber stream from the first acid gas absorber unit and the second acid gas-rich absorber stream from the second acid gas absorber unit, (ii) remove acid gases from the first acid gas-rich absorber stream and the second acid gas-rich absorber stream, and (iii) generate an acid gas-lean absorber stream and a carbon dioxide-rich recycle stream; and (II) a compressor unit in fluid communication with the absorber regeneration unit and the carbon dioxide injection well, the compressor unit adapted to (i) receive the carbon dioxide-rich recycle stream, and (ii) compress the carbon dioxide recycle stream to generate the pressurized carbon dioxide stream, and (iii) provide the pressurized carbon dioxide stream to the carbon dioxide injection well.
[0039] These and other embodiments, features and advantages of the present invention will be more readily understood by those of ordinary skill in the art from a reading of the following detailed description.
5b Brief Description of the Drawings [0040] Figure 1 is a diagram of an embodiment of an integrated process in accordance with the present invention.
[0041] Figure 2 is a diagram of an embodiment of the gas processing portion of the overall integrated process.
Detailed Description [0042] The present disclosure relates to integrating synthesis gas production processes with enhanced oil recovery processes. Further details are provided below.
[0043] In the context of the present description, all publications, patent applications, patents and other references mentioned herein, if not otherwise indicated, are explicitly incorporated by reference herein in their entirety for all purposes as if fully set forth.
[0044] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs. In case of conflict, the present specification, including definitions, will control.
[0045] Except where expressly noted, trademarks are shown in upper case.
[0046] Although methods and materials similar or equivalent to those described herein can be used in the practice or testing of the present disclosure, suitable methods and materials are described herein.
[0047] Unless stated otherwise, all percentages, parts, ratios, etc., are by weight.
[0048] Unless stated otherwise, pressures expressed in psi units are gauge, and pressures expressed in kPa units are absolute.
[0049] When an amount, concentration, or other value or parameter is given as a range, or a list of upper and lower values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper and lower range limits, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. It is not intended that the scope of the present disclosure be limited to the specific values recited when defining a range.
[0050] When the term "about" is used in describing a value or an end-point of a range, the disclosure should be understood to include the specific value or end-point referred to.
[0051] As used herein, the terms "comprises," "comprising," "includes,"
"including," "has,"
"having" or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, method, article, or apparatus that comprises a list of elements is not necessarily limited to only those elements but can include other elements not expressly listed or inherent to such process, method, article, or apparatus. Further, unless expressly stated to the contrary, "or" refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).
[0052] The use of "a" or "an" to describe the various elements and components herein is merely for convenience and to give a general sense of the disclosure. This description should be read to include one or at least one and the singular also includes the plural unless it is obvious that it is meant otherwise.
[0053] The term "substantial portion", as used herein, unless otherwise defined herein, means that greater than about 90% of the referenced material, preferably greater than about 95% of the referenced material, and more preferably greater than about 97% of the referenced material. The percent is on a molar basis when reference is made to a molecule (such as methane, carbon dioxide, carbon monoxide and hydrogen sulfide), and otherwise is on a weight basis (such as the liquid component of the hydrocarbon-containing fluid).
[0054] The term "predominant portion", as used herein, unless otherwise defined herein, means that greater than about 50% of the referenced material. The percent is on a molar basis when reference is made to a molecule (such as hydrogen, methane, carbon dioxide, carbon monoxide and hydrogen sulfide), and otherwise is on a weight basis (such as the liquid component of the hydrocarbon-containing fluid).
[0055] The term "hydrocarbon-containing fluid", as used herein, means a fluid comprising any hydrocarbon liquid and/or gas. A hydrocarbon-containing fluid may also comprise solid . particles. Oil, gas-condensate and the like, and also their mixtures with other liquids such as water, may be examples of a liquid contained in a hydrocarbon-containing fluid. Any gaseous hydrocarbon (for example, methane, ethane, propane, propylene, butane or the like), and mixtures of gaseous hydrocarbons, may be contained in a hydrocarbon-containing fluid. In the context of the present invention, the hydrocarbon-containing fluid is recovered from an underground hydrocarbon reservoir, such as an oil-bearing formation, a gas-condensate reservoir, a natural gas reservoir and the like.
[0056] The term "carbonaceous" as used herein is synonymous with hydrocarbon.
[0057] The term "carbonaceous material" as used herein is a material containing organic hydrocarbon content. Carbonaceous materials can be classified as biomass or non-biomass materials as defined herein.
[0058] The term "biomass" as used herein refers to carbonaceous materials derived from recently (for example, within the past 100 years) living organisms, including plant-based biomass and animal-based biomass. For clarification, biomass does not include fossil-based carbonaceous materials, such as coal. For example, see US2009/0217575A1 and US2009/0217587A1.
[0059] The term "plant-based biomass" as used herein means materials derived from green plants, crops, algae, and trees, such as, but not limited to, sweet sorghum, bagasse, sugarcane, bamboo, hybrid poplar, hybrid willow, albizia trees, eucalyptus, alfalfa, clover, oil palm, switchgrass, sudangrass, millet, jatropha, and miscanthus (e.g., Miseanthus x giganteus).
Biomass further include wastes from agricultural cultivation, processing, and/or degradation such as corn cobs and husks, corn stover, straw, nut shells, vegetable oils, canola oil, rapeseed oil, biodiesels, tree bark, wood chips, sawdust, and yard wastes.
[0060] The term "animal-based biomass" as used herein means wastes generated from animal cultivation and/or utilization. For example, biomass includes, but is not limited to, wastes from livestock cultivation and processing such as animal manure, guano, poultry litter, animal fats, and municipal solid wastes (e.g., sewage).
[0061] The term "non-biomass", as used herein, means those carbonaceous materials which are not encompassed by the term "biomass" as defined herein. For example, non-biomass include, but is not limited to, anthracite, bituminous coal, sub-bituminous coal, lignite, petroleum coke, asphaltenes, liquid petroleum residues or mixtures thereof.
For example, see US2009/0166588A1, US2009/0165379A1, US2009/0165380A1, US2009/0165361A1, US2009/0217590A1 and US2009/0217586A1.
[0062] The terms "petroleum coke" and "petcoke" as used here include both (i) the solid thermal decomposition product of high-boiling hydrocarbon fractions obtained in petroleum processing (heavy residues ¨ "resid petcoke"); and (ii) the solid thermal decomposition product of processing tar sands (bituminous sands or oil sands ¨ "tar sands petcoke"). Such carbonization products include, for example, green, calcined, needle and fluidized bed petcoke.
[0063] Resid petcoke can also be derived from a crude oil, for example, by coking processes used for upgrading heavy-gravity residual crude oil, which petcoke contains ash as a minor component, typically about 1.0 wt% or less, and more typically about 0.5 wt%
of less, based on the weight of the coke. Typically, the ash in such lower-ash cokes comprises metals such as nickel and vanadium.
[0064] Tar sands petcoke can be derived from an oil sand, for example, by coking processes used for upgrading oil sand. Tar sands petcoke contains ash as a minor component, typically in the range of about 2 wt% to about 12 wt%, and more typically in the range of about 4 wt%
to about 12 wt%, based on the overall weight of the tar sands petcoke.
Typically, the ash in such higher-ash cokes comprises materials such as silica and/or alumina.
[0065] Petroleum coke has an inherently low moisture content, typically, in the range of from about 0.2 to about 2 wt% (based on total petroleum coke weight); it also typically has a very low water soaking capacity to allow for conventional catalyst impregnation methods.
The resulting particulate compositions contain, for example, a lower average moisture content which increases the efficiency of downstream drying operation versus conventional drying operations.
[0066] The petroleum coke can comprise at least about 70 wt% carbon, at least about 80 wt% carbon, or at least about 90 wt% carbon, based on the total weight of the petroleum coke. Typically, the petroleum coke comprises less than about 20 wt% inorganic compounds, based on the weight of the petroleum coke.
[0067] The term "asphaltene" as used herein is an aromatic carbonaceous solid at room temperature, and can be derived, for example, from the processing of crude oil and crude oil tar sands.
[0068] The term "coal" as used herein means peat, lignite, sub-bituminous coal, bituminous coal, anthracite, or mixtures thereof. In certain embodiments, the coal has a carbon content of less than about 85%, or less than about 80%, or less than about 75%, or less than about 70%, or less than about 65%, or less than about 60%, or less than about 55%, or less than about 50% by weight, based on the total coal weight. In other embodiments, the coal has a carbon content ranging up to about 85%, or up to about 80%, or up to about 75%
by weight, based on the total coal weight. Examples of useful coal include, but are not limited to, Illinois #6, Pittsburgh #8, Beulah (ND), Utah Blind Canyon, and Powder River Basin (PRB) coals.
Anthracite, bituminous coal, sub-bituminous coal, and lignite coal may contain about 10 wt%, from about 5 to about 7 wt%, from about 4 to about 8 wt%, and from about 9 to about 11 wt%, ash by total weight of the coal on a dry basis, respectively. However, the ash content of any particular coal source will depend on the rank and source of the coal, as is familiar to those skilled in the art. See, for example, "Coal Data: A
Reference", Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels, U.S.
Department of Energy, DOE/EIA-0064(93), February 1995.
[0069] The ash produced from combustion of a coal typically comprises both a fly ash and a bottom ash, as are familiar to those skilled in the art. The fly ash from a bituminous coal can comprise from about 20 to about 60 wt% silica and from about 5 to about 35 wt%
alumina, based on the total weight of the fly ash. The fly ash from a sub-bituminous coal can comprise from about 40 to about 60 wt% silica and from about 20 to about 30 wt%
alumina, based on the total weight of the fly ash. The fly ash from a lignite coal can comprise from about 15 to about 45 wt% silica and from about 20 to about 25 wt% alumina, based on the total weight of the fly ash. See, for example, Meyers, et al. "Fly Ash. A Highway Construction Material,"
Federal Highway Administration, Report No. FHWA-IP-76-16, Washington, DC, 1976.
[0070] The bottom ash from a bituminous coal can comprise from about 40 to about 60 wt%
silica and from about 20 to about 30 wt% alumina, based on the total weight of the bottom ash. The bottom ash from a sub-bituminous coal can comprise from about 40 to about 50 wt% silica and from about 15 to about 25 wt% alumina, based on the total weight of the bottom ash. The bottom ash from a lignite coal can comprise from about 30 to about 80 wt%
silica and from about 10 to about 20 wt% alumina, based on the total weight of the bottom ash. See, for example, Moulton, Lyle K. "Bottom Ash and Boiler Slag,"
Proceedings of the Third International Ash Utilization Symposium, U.S. Bureau of Mines, Information Circular No. 8640, Washington, DC, 1973.
[0071] A carbonaceous material such as methane can be biomass or non-biomass under the above definitions depending on its source of origin.
[0072] The term "unit" refers to a unit operation. When more than one "unit"
is described as being present, those units are operated in a parallel fashion. A single "unit", however, may comprise more than one of the units in series, or in parallel, depending on the context. For example, an acid gas removal unit may comprise a hydrogen sulfide removal unit followed in series by a carbon dioxide removal unit. As another example, a contaminant removal unit may comprise a first removal unit for a first contaminant followed in series by a second removal unit for a second contaminant. As yet another example, a compressor may comprise a first compressor to compress a stream to a first pressure, followed in series by a second compressor to further compress the stream to a second (higher) pressure.
[0073] The materials, methods, and examples herein are illustrative only and, except as specifically stated, are not intended to be limiting.
General Process Information [0074] In one embodiment of the invention, an acid gas-depleted gaseous hydrocarbon product steam (31), an acid gas-depleted synthesis gas stream (30) and a liquid hydrocarbon product stream (85) are produced in an integrated EOR and synthesis gas production process as illustrated in Figures 1 and 2.
Enhanced Oil Recovery [0075] Referring to Figure 1, the EOR portion of the process involves injecting a pressurized carbon dioxide stream (89) via an injection well (500) (one or more) into an underground hydrocarbon reservoir (20) utilizing techniques well known to those of ordinary skill in the relevant art. As indicated above, the pressurized carbon dioxide stream (89), which will typically be in a supercritical fluid state, serves to enhance production of a hydrocarbon fluid (82) from a production well (600) through a combination of mechanisms typically involving a repressurization of the underground reservoir and a viscosity reduction of the trapped hydrocarbon (improving flow properties). Typically, the pressurized carbon dioxide stream (89) will be injected into the underground reservoir at a pressure of at least about 1200 psig (about 8375 kPa), or at least about 1500 psig (about 10444 kPa), or at least about 2000 psig (about 13891 kPa).
[0076] As is well-known to those of ordinary skill in the art, carbon dioxide-based EOR can also involve co-injection of pressurized water, steam, nitrogen and other fluids, or alternating injections of a pressurized carbon dioxide-rich stream, a water/steam stream and/or a nitrogen stream. The actual carbon dioxide-based EOR process utilized is not critical to the present invention in its broadest sense.
[0077] The resulting hydrocarbon-containing fluid (82) is produced and recovered through a hydrocarbon production well (600) (one or more). The produced hydrocarbon-containing fluid (82) will typically contain liquid and gas hydrocarbon components, as well as other liquid and gaseous components depending on the hydrocarbon reservoir and EOR
conditions.
The liquid hydrocarbon component can generally be considered as a crude oil, while the gaseous hydrocarbon component will typically comprise hydrocarbons that are gases at ambient conditions, such as methane, ethane, propane, propylene and butane (typical components of natural gas). Other typical liquid components include water or brine. The hydrocarbon-containing fluid (82) will also comprise carbon dioxide, and may comprise other gaseous components such as hydrogen sulfide (from a sour well) and nitrogen.
The hydrocarbon-containing fluid (82) may also include solid carbon and mineral matter.
[0078] The produced hydrocarbon-containing fluid (82) is passed to a separation device (300) to separate the gaseous components from the liquid/solid components to generate a gaseous hydrocarbon stream (84), a liquid hydrocarbon product stream (85) and, optionally, a stream (86) containing solids components from the hydrocarbon-containing fluid (82). The solids may also optionally be carried with the liquid hydrocarbon product stream (85) for later separation, or separated out prior to separation device (300), by well-known techniques such as settling, centrifugation and/or filtration. In one embodiment, larger/denser solids are separated in conjunction with separation device (300), and finer solids that may become entrained in liquid hydrocarbon product stream (85) are separated subsequently through well-known techniques such as filtration.
[0079] Suitable separation devices for use as separation device (300) are well known to those of ordinary skill in the art and include, for example, single and multistage horizontal separators and cyclones. The actual separation device utilized is not critical to the present invention in its broadest sense.
[0080] The liquid hydrocarbon product stream (85), consequently, will typically comprise at least a predominant portion (or a substantial portion, or substantially all) of the liquid components from the hydrocarbon-containing fluid (82) including, for example, crude oil and water/brine. The liquid hydrocarbon product stream (85) can subsequently be processed to separate out the water and other contaminants, then further processed (e.g., refined) to a variety of end products or for a variety of end uses, as is well-known to those or ordinary skill in the relevant art.
[0081] If a stream (86) containing solids components is present, that will typically be removed from separation device (300) as a concentrated slurry or with some portion of the liquid content of the hydrocarbon-containing fluid (82). Oil that may be withdrawn with the solids in stream (86) can be recovered from the solids via washing or other techniques well-known to those of ordinary skill in the relevant art.
[00121 It would, therefore, be highly desirable to integrate synthesis gas production processes with EOR processes in a way that minimizes the release of CO2 into the atmosphere (maximizes capture and sequestration of CO2), reduces the need for long CO2 transport pipelines, and improves the overall integration, efficiency and economics of the two processes. Some embodiments of the present invention provide such an integration.
Summary of the Invention [0013] In a first aspect, the present invention provides an integrated process to (i) produce an acid gas-depleted gaseous hydrocarbon product steam, (ii) produce an acid gas-depleted synthesis gas stream, (iii) produce a liquid hydrocarbon product stream and (iv) enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir, the process comprising the steps of:
[0014] (1) injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir to enhance production of the hydrocarbon-containing fluid from the underground hydrocarbon reservoir via a hydrocarbon production well, the hydrocarbon-containing fluid comprising carbon dioxide;
[0015] (2) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well;
[0016] (3) separating the hydrocarbon-containing fluid into (a) the liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide;
[0017] (4) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
[0018] (5) producing a synthesis gas stream from a carbonaceous feedstock, the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane;
[0019] (6) treating the synthesis gas stream in a second acid gas absorber unit to produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
[0020] (7) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and [0021] (8) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
[0022] In a second aspect, the present invention provides a process to enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir via a hydrocarbon production well, by injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir, wherein the hydrocarbon-containing fluid comprises CA 02773718.2012-03-08 carbon dioxide, and wherein the pressurized carbon dioxide stream is generated by a process comprising the steps of:
[0023] (I) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well;
[0024] (II) splitting the hydrocarbon-containing fluid into (a) a liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide;
[0025] (III) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce an acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
[0026] (IV) producing a synthesis gas stream from a carbonaceous feedstock,.
the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane;
[0027] (V) treating the synthesis gas stream in a second acid gas absorber unit to produce an acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
[0028] (VI) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and [0029] (VII) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
[0030] In a third aspect, the invention provides an apparatus for generating a liquid hydrocarbon product stream, an acid gas-depleted gaseous hydrocarbon product stream and an acid gas-depleted synthesis gas stream, the apparatus comprising:
[0031] (A) a synthesis gas production system adapted to produce a synthesis gas from a carbonaceous feedstock, the synthesis gas comprising (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane;
[0032] (B) a carbon dioxide injection well in fluid communication with an underground hydrocarbon reservoir, the carbon dioxide injection well adapted to inject a pressurized carbon dioxide stream into the underground hydrocarbon reservoir for enhanced oil recovery;
[0033] (C) a hydrocarbon production well in fluid communication with the underground hydrocarbon reservoir, the hydrocarbon production well adapted to remove a hydrocarbon fluid from the underground hydrocarbon reservoir, the hydrocarbon fluid comprising carbon dioxide;
[0034] (D) a separation device in fluid communication with the hydrocarbon production well, the separation device adapted (i) to receive the hydrocarbon fluid from the hydrocarbon production well, and (ii) to separate the hydrocarbon fluid into the liquid hydrocarbon product stream and a gaseous hydrocarbon stream comprising carbon dioxide;
[0035] (E) a first acid gas absorber unit in fluid communication with the separation device, the first acid gas absorber unit adapted to (i) receive the gaseous hydrocarbon stream from the separation device, and (ii) treat the gaseous hydrocarbon stream to remove acid gases and produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
[0036] (F) a second acid gas absorber unit in fluid communication with the synthesis gas generation system, the second acid gas absorber unit adapted to (i) receive the synthesis gas from the synthesis gas generation system, and (ii) treat the synthesis gas to remove acid gases and produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
[0037] (G) an absorber regeneration unit in fluid communication with the first acid gas absorber unit and the second acid gas absorber unit, the absorber regeneration unit adapted to (i) receive the first acid gas-rich absorber stream from the first acid gas absorber unit and the second acid gas-rich absorber stream from the second acid gas absorber unit, (ii) remove acid gases from the first acid gas-rich absorber stream and the second acid gas-rich absorber stream, and (iii) generate an acid gas-lean absorber stream and a carbon dioxide-rich recycle stream; and [0038] (H) a compressor unit in fluid communication with the absorber regeneration unit and the carbon dioxide injection well, the compressor unit adapted to (i) receive the carbon dioxide-rich recycle stream, and (ii) compress the carbon dioxide recycle stream to generate the pressurized carbon dioxide stream, and (iii) provide the pressurized carbon dioxide stream to the carbon dioxide injection well.
[0038a] According to one aspect of the present invention, there is provided an integrated process to (i) produce an acid gas-depleted gaseous hydrocarbon product stream, (ii) produce an acid gas-depleted synthesis gas stream, (iii) produce a liquid hydrocarbon product stream and (iv) enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir, the process comprising the steps of: (1) injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir to enhance production of the hydrocarbon-containing fluid from the underground hydrocarbon reservoir via a hydrocarbon production well, the hydrocarbon-containing fluid comprising carbon dioxide;
(2) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well; (3) separating the hydrocarbon-containing fluid into (a) the liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide; (4) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream; (5) producing a synthesis gas stream from a carbonaceous feedstock, the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane; (6) treating the synthesis gas stream in a second acid gas absorber unit to produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream; (7) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and (8) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
[003813] According to another aspect of the present invention, there is provided an apparatus for generating a liquid hydrocarbon product stream, an acid gas-depleted gaseous hydrocarbon product stream and an acid gas-depleted synthesis gas stream, the apparatus comprising: (A) a synthesis gas generation system adapted to produce a synthesis gas from a carbonaceous feedstock, the synthesis gas comprising (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane; (B) a carbon dioxide injection well in fluid communication with an underground hydrocarbon reservoir, the carbon dioxide injection well adapted to inject a pressurized carbon dioxide stream into the underground hydrocarbon reservoir for enhanced oil recovery; (C) a hydrocarbon production well in fluid 5a communication with the underground hydrocarbon reservoir, the hydrocarbon production well adapted to remove a hydrocarbon fluid from the underground hydrocarbon reservoir, the hydrocarbon fluid comprising carbon dioxide; (D) a separation device in fluid communication with the hydrocarbon production well, the separation device adapted (i) to receive the hydrocarbon fluid from the hydrocarbon production well, and (ii) to separate the hydrocarbon fluid into the liquid hydrocarbon product stream and a gaseous hydrocarbon stream comprising carbon dioxide; (E) a first acid gas absorber unit in fluid communication with the separation device, the first acid gas absorber unit adapted to (i) receive the gaseous hydrocarbon stream from the separation device, and (ii) treat the gaseous hydrocarbon stream to remove acid gases and produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream; (F) a second acid gas absorber unit in fluid communication with the synthesis gas generation system, the second acid gas absorber unit adapted to (i) receive the synthesis gas from the synthesis gas generation system, and (ii) treat the synthesis gas to remove acid gases and produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream; (G) an absorber regeneration unit in fluid communication with the first acid gas absorber unit and the second acid gas absorber unit, the absorber regeneration unit adapted to (i) receive the first acid gas-rich absorber stream from the first acid gas absorber unit and the second acid gas-rich absorber stream from the second acid gas absorber unit, (ii) remove acid gases from the first acid gas-rich absorber stream and the second acid gas-rich absorber stream, and (iii) generate an acid gas-lean absorber stream and a carbon dioxide-rich recycle stream; and (II) a compressor unit in fluid communication with the absorber regeneration unit and the carbon dioxide injection well, the compressor unit adapted to (i) receive the carbon dioxide-rich recycle stream, and (ii) compress the carbon dioxide recycle stream to generate the pressurized carbon dioxide stream, and (iii) provide the pressurized carbon dioxide stream to the carbon dioxide injection well.
[0039] These and other embodiments, features and advantages of the present invention will be more readily understood by those of ordinary skill in the art from a reading of the following detailed description.
5b Brief Description of the Drawings [0040] Figure 1 is a diagram of an embodiment of an integrated process in accordance with the present invention.
[0041] Figure 2 is a diagram of an embodiment of the gas processing portion of the overall integrated process.
Detailed Description [0042] The present disclosure relates to integrating synthesis gas production processes with enhanced oil recovery processes. Further details are provided below.
[0043] In the context of the present description, all publications, patent applications, patents and other references mentioned herein, if not otherwise indicated, are explicitly incorporated by reference herein in their entirety for all purposes as if fully set forth.
[0044] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure belongs. In case of conflict, the present specification, including definitions, will control.
[0045] Except where expressly noted, trademarks are shown in upper case.
[0046] Although methods and materials similar or equivalent to those described herein can be used in the practice or testing of the present disclosure, suitable methods and materials are described herein.
[0047] Unless stated otherwise, all percentages, parts, ratios, etc., are by weight.
[0048] Unless stated otherwise, pressures expressed in psi units are gauge, and pressures expressed in kPa units are absolute.
[0049] When an amount, concentration, or other value or parameter is given as a range, or a list of upper and lower values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper and lower range limits, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. It is not intended that the scope of the present disclosure be limited to the specific values recited when defining a range.
[0050] When the term "about" is used in describing a value or an end-point of a range, the disclosure should be understood to include the specific value or end-point referred to.
[0051] As used herein, the terms "comprises," "comprising," "includes,"
"including," "has,"
"having" or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, method, article, or apparatus that comprises a list of elements is not necessarily limited to only those elements but can include other elements not expressly listed or inherent to such process, method, article, or apparatus. Further, unless expressly stated to the contrary, "or" refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).
[0052] The use of "a" or "an" to describe the various elements and components herein is merely for convenience and to give a general sense of the disclosure. This description should be read to include one or at least one and the singular also includes the plural unless it is obvious that it is meant otherwise.
[0053] The term "substantial portion", as used herein, unless otherwise defined herein, means that greater than about 90% of the referenced material, preferably greater than about 95% of the referenced material, and more preferably greater than about 97% of the referenced material. The percent is on a molar basis when reference is made to a molecule (such as methane, carbon dioxide, carbon monoxide and hydrogen sulfide), and otherwise is on a weight basis (such as the liquid component of the hydrocarbon-containing fluid).
[0054] The term "predominant portion", as used herein, unless otherwise defined herein, means that greater than about 50% of the referenced material. The percent is on a molar basis when reference is made to a molecule (such as hydrogen, methane, carbon dioxide, carbon monoxide and hydrogen sulfide), and otherwise is on a weight basis (such as the liquid component of the hydrocarbon-containing fluid).
[0055] The term "hydrocarbon-containing fluid", as used herein, means a fluid comprising any hydrocarbon liquid and/or gas. A hydrocarbon-containing fluid may also comprise solid . particles. Oil, gas-condensate and the like, and also their mixtures with other liquids such as water, may be examples of a liquid contained in a hydrocarbon-containing fluid. Any gaseous hydrocarbon (for example, methane, ethane, propane, propylene, butane or the like), and mixtures of gaseous hydrocarbons, may be contained in a hydrocarbon-containing fluid. In the context of the present invention, the hydrocarbon-containing fluid is recovered from an underground hydrocarbon reservoir, such as an oil-bearing formation, a gas-condensate reservoir, a natural gas reservoir and the like.
[0056] The term "carbonaceous" as used herein is synonymous with hydrocarbon.
[0057] The term "carbonaceous material" as used herein is a material containing organic hydrocarbon content. Carbonaceous materials can be classified as biomass or non-biomass materials as defined herein.
[0058] The term "biomass" as used herein refers to carbonaceous materials derived from recently (for example, within the past 100 years) living organisms, including plant-based biomass and animal-based biomass. For clarification, biomass does not include fossil-based carbonaceous materials, such as coal. For example, see US2009/0217575A1 and US2009/0217587A1.
[0059] The term "plant-based biomass" as used herein means materials derived from green plants, crops, algae, and trees, such as, but not limited to, sweet sorghum, bagasse, sugarcane, bamboo, hybrid poplar, hybrid willow, albizia trees, eucalyptus, alfalfa, clover, oil palm, switchgrass, sudangrass, millet, jatropha, and miscanthus (e.g., Miseanthus x giganteus).
Biomass further include wastes from agricultural cultivation, processing, and/or degradation such as corn cobs and husks, corn stover, straw, nut shells, vegetable oils, canola oil, rapeseed oil, biodiesels, tree bark, wood chips, sawdust, and yard wastes.
[0060] The term "animal-based biomass" as used herein means wastes generated from animal cultivation and/or utilization. For example, biomass includes, but is not limited to, wastes from livestock cultivation and processing such as animal manure, guano, poultry litter, animal fats, and municipal solid wastes (e.g., sewage).
[0061] The term "non-biomass", as used herein, means those carbonaceous materials which are not encompassed by the term "biomass" as defined herein. For example, non-biomass include, but is not limited to, anthracite, bituminous coal, sub-bituminous coal, lignite, petroleum coke, asphaltenes, liquid petroleum residues or mixtures thereof.
For example, see US2009/0166588A1, US2009/0165379A1, US2009/0165380A1, US2009/0165361A1, US2009/0217590A1 and US2009/0217586A1.
[0062] The terms "petroleum coke" and "petcoke" as used here include both (i) the solid thermal decomposition product of high-boiling hydrocarbon fractions obtained in petroleum processing (heavy residues ¨ "resid petcoke"); and (ii) the solid thermal decomposition product of processing tar sands (bituminous sands or oil sands ¨ "tar sands petcoke"). Such carbonization products include, for example, green, calcined, needle and fluidized bed petcoke.
[0063] Resid petcoke can also be derived from a crude oil, for example, by coking processes used for upgrading heavy-gravity residual crude oil, which petcoke contains ash as a minor component, typically about 1.0 wt% or less, and more typically about 0.5 wt%
of less, based on the weight of the coke. Typically, the ash in such lower-ash cokes comprises metals such as nickel and vanadium.
[0064] Tar sands petcoke can be derived from an oil sand, for example, by coking processes used for upgrading oil sand. Tar sands petcoke contains ash as a minor component, typically in the range of about 2 wt% to about 12 wt%, and more typically in the range of about 4 wt%
to about 12 wt%, based on the overall weight of the tar sands petcoke.
Typically, the ash in such higher-ash cokes comprises materials such as silica and/or alumina.
[0065] Petroleum coke has an inherently low moisture content, typically, in the range of from about 0.2 to about 2 wt% (based on total petroleum coke weight); it also typically has a very low water soaking capacity to allow for conventional catalyst impregnation methods.
The resulting particulate compositions contain, for example, a lower average moisture content which increases the efficiency of downstream drying operation versus conventional drying operations.
[0066] The petroleum coke can comprise at least about 70 wt% carbon, at least about 80 wt% carbon, or at least about 90 wt% carbon, based on the total weight of the petroleum coke. Typically, the petroleum coke comprises less than about 20 wt% inorganic compounds, based on the weight of the petroleum coke.
[0067] The term "asphaltene" as used herein is an aromatic carbonaceous solid at room temperature, and can be derived, for example, from the processing of crude oil and crude oil tar sands.
[0068] The term "coal" as used herein means peat, lignite, sub-bituminous coal, bituminous coal, anthracite, or mixtures thereof. In certain embodiments, the coal has a carbon content of less than about 85%, or less than about 80%, or less than about 75%, or less than about 70%, or less than about 65%, or less than about 60%, or less than about 55%, or less than about 50% by weight, based on the total coal weight. In other embodiments, the coal has a carbon content ranging up to about 85%, or up to about 80%, or up to about 75%
by weight, based on the total coal weight. Examples of useful coal include, but are not limited to, Illinois #6, Pittsburgh #8, Beulah (ND), Utah Blind Canyon, and Powder River Basin (PRB) coals.
Anthracite, bituminous coal, sub-bituminous coal, and lignite coal may contain about 10 wt%, from about 5 to about 7 wt%, from about 4 to about 8 wt%, and from about 9 to about 11 wt%, ash by total weight of the coal on a dry basis, respectively. However, the ash content of any particular coal source will depend on the rank and source of the coal, as is familiar to those skilled in the art. See, for example, "Coal Data: A
Reference", Energy Information Administration, Office of Coal, Nuclear, Electric and Alternate Fuels, U.S.
Department of Energy, DOE/EIA-0064(93), February 1995.
[0069] The ash produced from combustion of a coal typically comprises both a fly ash and a bottom ash, as are familiar to those skilled in the art. The fly ash from a bituminous coal can comprise from about 20 to about 60 wt% silica and from about 5 to about 35 wt%
alumina, based on the total weight of the fly ash. The fly ash from a sub-bituminous coal can comprise from about 40 to about 60 wt% silica and from about 20 to about 30 wt%
alumina, based on the total weight of the fly ash. The fly ash from a lignite coal can comprise from about 15 to about 45 wt% silica and from about 20 to about 25 wt% alumina, based on the total weight of the fly ash. See, for example, Meyers, et al. "Fly Ash. A Highway Construction Material,"
Federal Highway Administration, Report No. FHWA-IP-76-16, Washington, DC, 1976.
[0070] The bottom ash from a bituminous coal can comprise from about 40 to about 60 wt%
silica and from about 20 to about 30 wt% alumina, based on the total weight of the bottom ash. The bottom ash from a sub-bituminous coal can comprise from about 40 to about 50 wt% silica and from about 15 to about 25 wt% alumina, based on the total weight of the bottom ash. The bottom ash from a lignite coal can comprise from about 30 to about 80 wt%
silica and from about 10 to about 20 wt% alumina, based on the total weight of the bottom ash. See, for example, Moulton, Lyle K. "Bottom Ash and Boiler Slag,"
Proceedings of the Third International Ash Utilization Symposium, U.S. Bureau of Mines, Information Circular No. 8640, Washington, DC, 1973.
[0071] A carbonaceous material such as methane can be biomass or non-biomass under the above definitions depending on its source of origin.
[0072] The term "unit" refers to a unit operation. When more than one "unit"
is described as being present, those units are operated in a parallel fashion. A single "unit", however, may comprise more than one of the units in series, or in parallel, depending on the context. For example, an acid gas removal unit may comprise a hydrogen sulfide removal unit followed in series by a carbon dioxide removal unit. As another example, a contaminant removal unit may comprise a first removal unit for a first contaminant followed in series by a second removal unit for a second contaminant. As yet another example, a compressor may comprise a first compressor to compress a stream to a first pressure, followed in series by a second compressor to further compress the stream to a second (higher) pressure.
[0073] The materials, methods, and examples herein are illustrative only and, except as specifically stated, are not intended to be limiting.
General Process Information [0074] In one embodiment of the invention, an acid gas-depleted gaseous hydrocarbon product steam (31), an acid gas-depleted synthesis gas stream (30) and a liquid hydrocarbon product stream (85) are produced in an integrated EOR and synthesis gas production process as illustrated in Figures 1 and 2.
Enhanced Oil Recovery [0075] Referring to Figure 1, the EOR portion of the process involves injecting a pressurized carbon dioxide stream (89) via an injection well (500) (one or more) into an underground hydrocarbon reservoir (20) utilizing techniques well known to those of ordinary skill in the relevant art. As indicated above, the pressurized carbon dioxide stream (89), which will typically be in a supercritical fluid state, serves to enhance production of a hydrocarbon fluid (82) from a production well (600) through a combination of mechanisms typically involving a repressurization of the underground reservoir and a viscosity reduction of the trapped hydrocarbon (improving flow properties). Typically, the pressurized carbon dioxide stream (89) will be injected into the underground reservoir at a pressure of at least about 1200 psig (about 8375 kPa), or at least about 1500 psig (about 10444 kPa), or at least about 2000 psig (about 13891 kPa).
[0076] As is well-known to those of ordinary skill in the art, carbon dioxide-based EOR can also involve co-injection of pressurized water, steam, nitrogen and other fluids, or alternating injections of a pressurized carbon dioxide-rich stream, a water/steam stream and/or a nitrogen stream. The actual carbon dioxide-based EOR process utilized is not critical to the present invention in its broadest sense.
[0077] The resulting hydrocarbon-containing fluid (82) is produced and recovered through a hydrocarbon production well (600) (one or more). The produced hydrocarbon-containing fluid (82) will typically contain liquid and gas hydrocarbon components, as well as other liquid and gaseous components depending on the hydrocarbon reservoir and EOR
conditions.
The liquid hydrocarbon component can generally be considered as a crude oil, while the gaseous hydrocarbon component will typically comprise hydrocarbons that are gases at ambient conditions, such as methane, ethane, propane, propylene and butane (typical components of natural gas). Other typical liquid components include water or brine. The hydrocarbon-containing fluid (82) will also comprise carbon dioxide, and may comprise other gaseous components such as hydrogen sulfide (from a sour well) and nitrogen.
The hydrocarbon-containing fluid (82) may also include solid carbon and mineral matter.
[0078] The produced hydrocarbon-containing fluid (82) is passed to a separation device (300) to separate the gaseous components from the liquid/solid components to generate a gaseous hydrocarbon stream (84), a liquid hydrocarbon product stream (85) and, optionally, a stream (86) containing solids components from the hydrocarbon-containing fluid (82). The solids may also optionally be carried with the liquid hydrocarbon product stream (85) for later separation, or separated out prior to separation device (300), by well-known techniques such as settling, centrifugation and/or filtration. In one embodiment, larger/denser solids are separated in conjunction with separation device (300), and finer solids that may become entrained in liquid hydrocarbon product stream (85) are separated subsequently through well-known techniques such as filtration.
[0079] Suitable separation devices for use as separation device (300) are well known to those of ordinary skill in the art and include, for example, single and multistage horizontal separators and cyclones. The actual separation device utilized is not critical to the present invention in its broadest sense.
[0080] The liquid hydrocarbon product stream (85), consequently, will typically comprise at least a predominant portion (or a substantial portion, or substantially all) of the liquid components from the hydrocarbon-containing fluid (82) including, for example, crude oil and water/brine. The liquid hydrocarbon product stream (85) can subsequently be processed to separate out the water and other contaminants, then further processed (e.g., refined) to a variety of end products or for a variety of end uses, as is well-known to those or ordinary skill in the relevant art.
[0081] If a stream (86) containing solids components is present, that will typically be removed from separation device (300) as a concentrated slurry or with some portion of the liquid content of the hydrocarbon-containing fluid (82). Oil that may be withdrawn with the solids in stream (86) can be recovered from the solids via washing or other techniques well-known to those of ordinary skill in the relevant art.
[0082] The resulting gaseous hydrocarbon stream (84) exiting separation device (300) typically comprises at least a substantial portion (or substantially all) of the gaseous components from the hydrocarbon-containing fluid (82), including at least a substantial portion (or substantially all) of the gaseous hydrocarbons and carbon dioxide from the hydrocarbon-containing fluid (82). The gaseous hydrocarbon stream (84) may also comprise minor amounts of water vapor, which should be substantially removed prior to treatment in the first acid gas absorber unit (230) as discussed below, as well as minor amount of other contaminants such as hydrogen sulfide.
[0083] The gaseous hydrocarbon stream (84) exiting separation device (300) is ultimately processed with synthesis gas stream (50) in an acid gas removal unit as discussed below.
Prior to processing in the acid gas removal unit, gaseous hydrocarbon stream (84) may optionally be compressed or heated (not depicted) to temperature and pressure conditions suitable for optional downstream processing as further described below.
Synthesis Gas Generation (100) [0084] Synthesis gas stream (50) contains (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane. The actual composition of synthesis gas stream (50) will depend on the synthesis gas process and carbonaceous feedstock utilized to generate the stream, including any gas processing that may occur before acid gas removal.
[0085] In one embodiment, synthesis gas stream (50) comprises carbon dioxide and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon dioxide and methane. In another embodiment, synthesis gas stream (50) comprises carbon dioxide, methane and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon monoxide and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon monoxide, methane and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon dioxide, carbon monoxide, methane and hydrogen. The synthesis gas stream (50) may also contain other gaseous components such as, for example, hydrogen sulfide, steam and other gaseous hydrocarbons again depending on the synthesis gas production process and carbonaceous feedstock.
[0086] Any synthesis gas generating process can be utilized in the context of the present invention, so long as the synthesis gas generating process (including gas processing prior to acid gas removal) results in a synthesis gas stream as required in the context of the present invention. Suitable synthesis gas processes are generally known to those of ordinary skill in the relevant art, and many applicable technologies are commercially available.
[0087] Non-limiting examples of different types of suitable synthesis gas generation processes are discussed below. These may be used individually or in combination. All synthesis gas generation process will involve a reactor, which is generically depicted as (110) in Figure 2, where a carbonaceous feedstock (10) will be processed to produce synthesis gases, which may be further treated prior to acid gas removal. General reference can be made to Figure 2 in the context of the various synthesis gas generating processes described below.
Gas-Based Methane Reforming/Partial Oxidation [0088] In one embodiment, the synthesis gas generating process is based on a gas-fed methane partial oxidation/reforming process, such as non-catalytic gaseous partial oxidation, catalytic autothermal reforming or catalytic stream-methane reforming process.
These processes are generally well-known in the relevant art. See, for example, Rice and Mann, "Autothermal Reforming of Natural Gas to Synthesis Gas, Reference: KBR Paper #2031,"
Sandia National Laboratory Publication No. SAND2007-2331 (2007); and Bogdan, "Reactor Modeling and Process Analysis for Partial Oxidation of Natural Gas", printed by Febodruk, WV., ISBN: 90-365-2100-9 (2004).
[0089] Technologies and reactors potentially suitable for use in conjunction with the present invention are commercially available from Royal Dutch Shell plc, Siemens AG, General Electric Company, Lurgi AG, Haldor Topsoe A/S, Uhde AG, KBR Inc. and others.
[0090] These gas-based processes convert a gaseous methane-containing stream as a carbonaceous feedstock (10, Figure 2), in a reactor (110) into a syngas (hydrogen plus carbon monoxide) as synthesis gas stream (50) which, depending on the specific process, will have differing ratios of hydrogen:carbon monoxide, will generally contain minor amounts of carbon dioxide, and may contain minor amounts of other gaseous components such as steam.
[0091] The methane-containing stream useful in these processes comprises methane in a predominant amount, and may comprise other gaseous hydrocarbon and components.
Examples of commonly used methane-containing streams include natural gas and synthetic natural gas.
[0092] In non-catalytic gaseous partial oxidation and autothermal reforming, an oxygen-rich gas stream (12) is fed into the reactor (110) along with carbonaceous feedstock (10).
Optionally, steam (14) may also be fed into the reactor (110). In steam-methane reforming, steam (14) is fed into the reactor along with the carbonaceous feedstock (10).
In some cases, minor amounts of other gases such as carbon dioxide, hydrogen and/or nitrogen may also be fed in the reactor (110).
[0093] Reaction and other operating conditions, and equipment and configurations, of the various reactors and technologies are in a general sense known to those of ordinary skill in the relevant art, and are not critical to the present invention in its broadest sense.
Solids/Liquids-Based Gasification to Syngas [0094] In another embodiment, the synthesis gas generating process is based on a non-catalytic thermal gasification process, such as a partial oxidation gasification process (like an oxygen-blown gasifier), where a non-gaseous (liquid, semi-solid and/or solid) hydrocarbon is utilized as the carbonaceous feedstock (10). A wide variety of biomass and non-biomass materials (as described above) can be utilized as the carbonaceous feedstock (10) in these processes.
[0095] Oxygen-blown solids/liquids gasifiers potentially suitable for use in conjunction with the present invention are, in a general sense, known to those of ordinary skill in the relevant art and include, for example, those based on technologies available from Royal Dutch Shell plc, ConocoPhillips Company, Siemens AG, Lurgi AG (Sasol), General Electric Company and others. Other potentially suitable syngas generators are disclosed, for example, in US2009/0018222A1, US2007/0205092A1 and US6863878.
[0096] These processes convert a solid, semi-solid and/or liquid carbonaceous feedstock (10, Figure 2), in a reactor (110) such as an oxygen-blown gasifier, into a syngas (hydrogen plus carbon monoxide) as synthesis gas stream (50) which, depending on the specific process and carbonaceous feedstock, will have differing ratios of hydrogen:carbon monoxide, will generally contain minor amounts of carbon dioxide, and may contain minor amounts of other gaseous components such as methane, steam, sulfur oxides and nitrogen oxides.
[0097] In certain of these processes, an oxygen-rich gas stream (12) is fed into the reactor (110) along with the carbonaceous feedstock (10). Optionally, steam (14) may also be fed into the reactor (110), as well as other gases such as carbon dioxide, hydrogen, methane and/or nitrogen.
[0098] In certain of these processes, steam (14) may be utilized as an oxidant at elevated temperatures in place of all or a part of the oxygen-rich gas stream (12).
[0099] The gasification in the reactor (110) will typically occur in a fluidized bed of the carbonaceous feedstock (10) that is fluidized by the flow of the oxygen-rich gas stream (12), steam (14) and/or other fluidizing gases (like carbon dioxide and/or nitrogen) that may be fed to reactor (110).
[00100] Typically, thermal gasification is a non-catalytic process, so no gasification catalyst needs to be added to the carbonaceous feedstock (10) or into the reactor (110); however, a catalyst that promotes syngas formation may be utilized.
[00101] These thermal gasification processes are typically operated under high temperature and pressure conditions, and may run under slagging or non-slagging operating conditions depending on the process and carbonaceous feedstock.
[00102] Reaction and other operating conditions, and equipment and configurations, of the various reactors and technologies are in a general sense known to those of ordinary skill in the relevant art, and are not critical to the present invention in its broadest sense.
Catalytic Gasification/Hydromethanation to a Methane-Enriched Gas [00103] In another alternative embodiment, the synthesis gas generating process is a catalytic gasification/hydromethanation process, in which gasification of a non-gaseous carbonaceous feedstock (10) takes place in a reactor (110) in the presence of steam and a catalyst to result in a methane-enriched gas stream as the synthesis gas stream (50), which typically comprises methane, hydrogen, carbon monoxide, carbon dioxide and steam.
[00104] The hydromethanation of a carbon source to methane typically involves four concurrent reactions:
[00105] Steam carbon: C + H2O ---> CO + H2 (I) [00106] Water-gas shift: CO + H20 ---> H2 + CO2 (II) [00107] CO Methanation: C0+3H2 --> CH4 + H20 (III) [00108] Hydro-gasification: 2H2 + C --> CH4 (IV) [00109] In the hydromethanation reaction, the first three reactions (I-III) predominate to result in the following overall reaction:
[00110] 2C + 2H20 ---> CH4 + CO2 (V).
[00111] The overall reaction is essentially thermally balanced; however, due to process heat losses and other energy requirements (such as required for evaporation of moisture entering the reactor with the feedstock), some heat must be added to maintain the thermal balance.
[00112] The reactions are also essentially syngas (hydrogen and carbon monoxide) balanced (syngas is produced and consumed); therefore, as carbon monoxide and hydrogen are withdrawn with the product gases, carbon monoxide and hydrogen need to be added to the reaction as required to avoid a deficiency.
[00113] In order to maintain the net heat of reaction as close to neutral as possible (only slightly exothermic or endothermic), and maintain the syngas balance, a superheated gas stream of steam (14) and syngas (16) (carbon monoxide and hydrogen) is often fed to the reactor (110). Frequently, the carbon monoxide and hydrogen streams are recycle streams separated from the product gas, and/or are provided by reforming a portion of the product methane.
[00114] The carbonaceous feedstocks useful in these processes include, for example, a wide variety of biomass and non-biomass materials.
[00115] Catalysts utilized in these processes include, for example, alkali metals, alkaline earth metals and transition metals, and compounds, mixtures and complexes thereof.
[00116] The temperature and pressure operating conditions in a catalytic gasification/hydromethanation process are typically milder (lower temperature and pressure) than a non-catalytic gasification process, which can sometimes have advantages in terms of cost and efficiency.
[00117] Catalytic gasification/hydromethanation processes and conditions are disclosed, for example, in US3998607, US4057512, US4094650, US4204843, US4558027, US4604105, US6955695, and US2003/0167691 Al, as well as in commonly owned US2007/0000177A1 , US2007/0083072A1, US2007/0277437A1, US2009/0048476A1, US2009/0090056A1, US2009/0090055A1, US2009/0165383A1, US2009/0166588A1, US2009/0165379A1, US2009/0170968A1, US2009/0165380A1, US2009/0165381A1, US2009/0165361A1, US2009/0165382A1, US2009/0169449A1, US2009/0169448A1, US2009/0165376A1, US2009/0165384A1, US2009/0217582A1, US2009/0220406A1, US2009/0217590A1, US2009/0217586A1, US2009/0217588A1, US2009/0218424A1, US2009/0217589A1, US2009/0217575A1, US2009/0229182A1, US2009/0217587A1, US2009/0246120A1, US2009/0260287A1, US2009/0259080A1, US2009/0324458A1, US2009/0324459A1, US2009/0324460A1, US2009/0324461A1, US2009/0324462A1, US2010/0121125A1, US2010/0120926A1, US2010/0071262A1, US2010/0076235A1, US2010/0179232A1, US2010/0168495A1, US2010/0168494A1, US2010/0292350A1, US2010/0287836A1, US2010/0287835A1, US2011/0031439A1, US2011/0062012A1, US2011/0062722A1, US2011/0062721A1 and US2011/0064648A1.
[00118] General reaction and other operating conditions of the various catalytic gasification/hydromethanation reactors and technologies can be found from the above references, and are not critical to the present invention in its broadest sense.
Heat Exchange (140) [00119] All of the above described synthesis gas generation processes typically will generate a synthesis gas stream (50) of a temperature higher than suitable for feeding downstream gas processes (including second acid gas absorber unit (210)), so upon exit from reactor (110) the synthesis gas stream (50) is typically passed through a heat exchanger unit (140) to remove heat energy and generate a cooled synthesis gas stream (52).
[00120] The heat energy recovered in heat exchanger unit (140) can be used, for example, to generate steam and/or superheat various process streams, as will be recognized by a person of ordinary skill in the art. Any steam generated can be used for internal process requirements and/or used to generate electrical power.
[00121] In one embodiment, the resulting cooled synthesis gas stream (52) will typically exit heat exchanger unit (140) at a temperature ranging from about 450 F (about 232 C) to about 1100 F (about 593 C), more typically from about 550 F (about 288 C) to about 950 F (about 510 C), and at a pressure suitable for subsequent acid gas removal processing (taking into account any intermediate processing). Typically, this pressure will be from about 50 psig (about 446 kPa) to about 800 psig (about 5617 kPa), more typically from about 400 psig (about 2860 kPa) to about 600 psig (about 4238 kPa).
Gas Treatment Prior to Acid Gas Removal [00122] Synthesis gas stream (50) and gaseous hydrocarbon stream (84) may be processed in various treatment processes, which will be primarily dependent on the composition, temperature and pressure of the two streams, and any desired end products.
[00123] Processing options prior to acid gas removal typically include, for example, one or more of sour shift (700) (water gas shift), contaminant removal (710) and dehydration (720 and 720a). While these intermediate processing steps can occur in any order, dehydration (720 and 720a) will usually occur just prior to acid gas removal (last in the series), as a substantial portion of any water in synthesis gas stream (50) and gaseous hydrocarbon stream (84) desirably should be removed prior to treatment in acid gas absorber units (210 and 230).
[00124] Typically, the gaseous hydrocarbon stream (84) will require at least some compression prior to treatment in first acid gas absorber unit (230).
Sour Shift (700) [00125] In certain embodiments, particularly where a stream contains appreciable amounts of carbon monoxide, and it is desired to maximize hydrogen and/or carbon dioxide production, all or a part of such stream (such as synthesis gas stream (50)) can be supplied to a sour shift reactor (700).
[00126] In sour shift reactor (700), the gases undergo a sour shift reaction (also known as a water-gas shift reaction) in the presence of an aqueous medium (such as steam) to convert at least a predominant portion (or a substantial portion, or substantially all) of the CO to CO2, which also increases the fraction of H2 in order to produce a hydrogen-enriched stream (54).
[00127] A sour shift process is described in detail, for example, in U57074373. The process involves adding water, or using water contained in the gas, and reacting the resulting water-gas mixture adiabatically over a steam reforming catalyst. Typical steam reforming catalysts include one or more Group VIII metals on a heat-resistant support.
[00128] Methods and reactors for performing the sour gas shift reaction on a CO-containing gas stream are well known to those of skill in the art. Suitable reaction conditions and suitable reactors can vary depending on the amount of CO that must be depleted from the gas stream. In some embodiments, the sour gas shift can be performed in a single stage within a temperature range from about 100 C, or from about 150 C, or from about 200 C, to about 250 C, or to about 300 C, or to about 350 C. In these embodiments, the shift reaction can be catalyzed by any suitable catalyst known to those of skill in the art. Such catalysts include, but are not limited to, Fe203-based catalysts, such as Fe203-Cr203 catalysts, and other transition metal-based and transition metal oxide-based catalysts. In other embodiments, the sour gas shift can be performed in multiple stages. In one particular embodiment, the sour gas shift is performed in two stages. This two-stage process uses a high-temperature sequence followed by a low-temperature sequence. The gas temperature for the high-temperature shift reaction ranges from about 350 C to about 1050 C. Typical high-temperature catalysts include, but are not limited to, iron oxide optionally combined with lesser amounts of chromium oxide. The gas temperature for the low-temperature shift ranges from about 150 C to about 300 C, or from about 200 C to about 250 C. Low-temperature shift catalysts include, but are not limited to, copper oxides that may be supported on zinc oxide or alumina. Suitable methods for the sour shift process are described in US2009/0246120A1.
[00129] The sour shift reaction is exothermic, so it is often carried out with a heat exchanger (not depicted) to permit the efficient use of heat energy. Shift reactors employing these features are well known to those of skill in the art. Recovered heat energy can be used, for example, to generate steam, superheat various process streams and/or preheat boiler feed water for use in other steam generating operations. An example of a suitable shift reactor is illustrated in US7074373, although other designs known to those of skill in the art are also effective.
[00130] If sour shift is present and it is desired to retain some carbon monoxide content, a portion of the stream can be split off to bypass sour shift reactor (700) and be combined with hydrogen-enriched stream (54) at some point prior to second acid gas absorber unit (210).
This is particularly useful when it is desired to recover a separate methane by-product, as the retained carbon monoxide can be subsequently methanated as discussed below.
Contaminant Removal (710) [00131] As is familiar to those skilled in the art, the contamination levels of synthesis gas stream (50) will depend on the nature of the carbonaceous feedstock and the synthesis gas generation conditions. For example, petcoke and certain coals can have high sulfur contents, leading to higher sulfur oxide (S0x), H2S and/or COS contamination. Certain coals can contain significant levels of mercury which can be volatilized during the synthesis gas generation. Other feedstocks can be high in nitrogen content, leading to ammonia, nitrogen oxides (N0x) and/or cyanides.
[00132] Some of these contaminants are typically removed in second acid gas absorber unit (210), such as H2S and COS. Others such as ammonia and mercury, require removal prior to second acid gas absorber unit (210).
[00133] When present, contaminant removal of a particular contaminant should remove at least a substantial portion (or substantially all) of that contaminant from the so-treated cleaned gas stream (56), typically to levels at or lower than the specification limits for the desired second acid gas absorber unit (210), or the desired end product.
[00134] While not shown in Figure 2, gaseous hydrocarbon stream (84) may be treated separately for contaminant removal as needed.
[00135] Contaminant removal process are in a general sense well know to those of ordinary skill in the relevant art, as exemplified in many of the previously-incorporated references.
Dehydration (720 and 720a) [00136] In addition, prior to acid gas removal, the synthesis gas stream (50) and gaseous hydrocarbon stream (84) should be treated to reduced residual water content via a dehydration unit (720) and (720a) to produce a dehydrated stream (58) and (58a) for feeding to second acid gas absorber unit (210) and first acid gas absorber unit (230), respectively.
[00137] Examples of suitable dehydration units include a knock-out drum or similar water separation device, and/or water absorption processes such as glycol treatment.
[00138] Such dehydration units and processes again are in a general sense well known to those of ordinary skill in the relevant art.
Acid Gas Removal [00139] In accordance with the present invention, the synthesis gas stream (50) and the gaseous hydrocarbon stream (84) (or derivative streams resulting from intermediate treatment) are processed in an acid gas removal unit to remove carbon dioxide and other acid gases (such as hydrogen sulfide if present), and generate a carbon dioxide-rich recycle stream (87), an acid gas-depleted gaseous hydrocarbon product stream (31) and an acid gas-depleted synthesis gas stream (30).
[00140] As indicated previously, the synthesis gas stream (50) and the gaseous hydrocarbon stream (84) are first individually treated in a second acid gas absorber unit (210) and a first acid gas absorber unit (230), respectively, to generate a separate acid gas-depleted synthesis gas stream (30) and second acid gas-rich absorber stream (35), and a separate acid gas-depleted gaseous hydrocarbon product stream (31) and first acid gas-rich absorber stream (36).
[00141] The resulting acid gas-depleted gaseous hydrocarbon product stream (31) and an acid gas-depleted synthesis gas stream (30) may be co-processed or separately processed as described further below.
[00142] The resulting first acid gas-rich absorber stream (36) and second acid gas-rich absorber stream (35) are co-processed in an absorber regeneration unit (250) to ultimately result in an acid gas stream containing the combined acid gases (and other contaminants) removed from both synthesis gas stream (50) and gaseous hydrocarbon stream (84). First acid gas-rich absorber stream (36) and second acid gas-rich absorber stream (35) may be combined prior to or within absorber regeneration unit (250) for co-processing.
[00143] Ultimately, a carbon dioxide-rich recycle stream (87) is generated containing a substantial portion of carbon dioxide from both synthesis gas stream (50) and gaseous hydrocarbon stream (84). An acid gas-lean absorber stream (70) is also generated, which can be recycled back to one or both of first acid gas absorber unit (230) and second acid gas absorber unit (210) along with make-up absorber as required. If one or both of synthesis gas stream (50) and gaseous hydrocarbon stream (84) contain other acid gas contaminants, such as hydrogen sulfide, then an additional stream may be generated, such as hydrogen sulfide stream (88).
[00144] Acid gas removal processes typically involve contacting a gas stream with a solvent such as monoethanolamine, diethanolamine, methyldiethanolamine, diisopropylamine, diglycolamine, a solution of sodium salts of amino acids, methanol, hot potassium carbonate or the like to generate CO2 and/or H2S laden absorbers. One method can involve the use of Selexol (UOP LLC, Des Plaines, IL USA). or Rectisol (Lurgi AG, Frankfurt am Main, Germany) solvent having two trains; each train containing an H2S absorber and a CO2 absorber.
[00145] One method for removing acid gases is described in US2009/0220406A1.
[00146] At least a substantial portion (e.g., substantially all) of the CO2 and/or H2S (and other remaining trace contaminants) should be removed via the acid gas removal processes.
"Substantial" removal in the context of acid gas removal means removal of a high enough percentage of the component such that a desired end product can be generated.
The actual amounts of removal may thus vary from component to component. Desirably, only trace amounts (at most) of H2S should be present in the acid gas-depleted gaseous hydrocarbon product stream, although higher amounts of CO2 may be tolerable depending on the desired end product.
[001471 Typically, at least about 85%, or at least about 90%, or at least about 92%, of the CO2, and at least about 95%, or at least about 98%, or at least about 99.5%, of the H2S, should be removed, based on the amount of those components contained in the streams fed to =
the acid gas removal.
[00148] Any recovered H2S (88) from the acid gas removal can be converted to elemental sulfur by any method known to those skilled in the art, including the Claus process. Sulfur can be recovered as a molten liquid.
Compression (400) [00149] As discussed above, the recovered carbon dioxide-rich recycle stream (87) is in whole or in part compressed via compressor (400) to generate pressurized carbon dioxide stream (89) for the EOR portion of the process. A CO2 product stream (90) can also optionally be split off of carbon dioxide-rich recycle stream (87) and/or pressurized carbon dioxide stream (89).
[00150] Suitable compressors for compressing carbon dioxide-rich recycle stream (87) to appropriate pressures and conditions for EOR are in a general sense well-known to those of ordinary skill in the relevant art.
Acid Gas-Depleted Synthesis Gas Stream (30) and Acid Gas-Depleted Gaseous Hydrocarbon Product Stream (31) [00151] The resulting acid gas-depleted gaseous hydrocarbon product stream (31) will generally comprise CH4 and other gaseous hydrocarbons from the gaseous hydrocarbon stream (84), and typically no more than contaminant amounts of CO2, H20, H2S
and other contaminants. The resulting acid gas-depleted synthesis gas stream (30) will generally comprise one or both of CH4 and H2, and optionally CO (for the downstream methanation), and typically no more than contaminant amounts of CO2, H20, H2S and other contaminants.
[00152] All or a portion of these two streams individually, or combined in whole or in part, may be processed to end products or for end uses as are well known to those of ordinary skill in the relevant art. The two streams may be combined at various points subsequent to acid gas removal.
[00153] Non-limiting options are discussed below in reference to Figure 2.
Although Figure 2 only depicts some of the options as applied to acid gas-depleted synthesis gas stream (30), these options (and others) may be applied to gas-depleted gaseous hydrocarbon product stream (31) (or a combined stream) where appropriate.
Optional Further Processing Hydrogen Separation (730) [00154] If present, hydrogen may be separated from all or a portion of acid gas-depleted synthesis gas stream (30) (and/or the acid gas-depleted gaseous hydrocarbon product stream (31)) according to methods known to those skilled in the art, such as cryogenic distillation, the use of molecular sieves, gas separation (e.g., ceramic or polymeric) membranes, and/or pressure swing adsorption (PSA) techniques.
[00155] In one embodiment, a PSA device is utilized for hydrogen separation.
PSA
technology for separation of hydrogen from gas mixtures containing methane (and optionally carbon monoxide) is in general well-known to those of ordinary skill in the relevant art as disclosed, for example, in US6379645 (and other citations referenced therein).
PSA devices are generally commercially available, for example, based on technologies available from Air Products and Chemicals Inc. (Allentown, PA), UOP LLC (Des Plaines, IL) and others.
[00156] In another embodiment, a hydrogen membrane separator can be used followed by a PSA device.
[00157] Such separation provides a high-purity hydrogen product stream (72) and a hydrogen-depleted gas stream (74).
[00158] The recovered hydrogen product stream (72) preferably has a purity of at least about 99 mole%, or at least 99.5 mole%, or at least about 99.9 mole%.
[00159] The recovered hydrogen can be used, for example, as an energy source and/or as a reactant. For example, the hydrogen can be used as an energy source for hydrogen-based fuel cells, or for power and/or steam generation (760). The hydrogen can also be used as a - reactant in various hydrogenation processes, such as found in the chemical and petroleum refining industries.
[00160] The hydrogen-depleted gas stream (74) will substantially comprise light hydrocarbons, such as methane (and generally predominantly methane, or substantially methane), with optional minor amounts of carbon monoxide (depending primarily on the extent of the sour shift reaction and bypass), carbon dioxide (depending primarily on the effectiveness of the acid gas removal process) and hydrogen (depending primarily on the extent and effectiveness of the hydrogen separation technology), and can be further processed/utilized as described below.
Methanation (740) [00161] If the acid gas-depleted synthesis gas stream (30) (and/or the acid gas-depleted gaseous hydrocarbon product stream (31), and/or the hydrogen-depleted sweetened gas stream (74)) contains carbon monoxide and hydrogen, all or part of the stream may be fed to a (trim) methanation unit (740) to generate additional methane from the carbon monoxide and hydrogen, resulting in a methane-enriched gas stream (75).
[00162] The methanation reaction can be carried out in any suitable reactor, e.g., a single-stage methanation reactor, a series of single-stage methanation reactors or a multistage reactor. Methanation reactors include, without limitation, fixed bed, moving bed or fluidized bed reactors. See, for instance, US3958957, US4252771, U53996014 and US4235044.
Methanation reactors and catalysts are generally commercially available. The catalyst used in the methanation, and methanation conditions, are generally known to those of ordinary skill in the relevant art, and will depend, for example, on the temperature, pressure, flow rate and composition of the incoming gas stream.
[00163] As the methanation reaction is exothermic, the methane-enriched gas stream (75) may be, for example, further provided to a heat exchanger unit (750). While the heat exchanger unit (750) is depicted as a separate unit, it can exist as such and/or be integrated into methanation unit (740), thus being capable of cooling the methanation unit (740) and removing at least a portion of the heat energy from the methane-enriched stream (75) to reduce the temperature and generate a cooled methane-enriched stream (76). The recovered heat energy can be utilized, for example, to generate a process steam stream from a water and/or steam source.
[00164] All or part of the methane-enriched stream (75) can be recovered as a methane product stream (77) or, it can be further processed, when necessary, to separate and recover CH4 by any suitable gas separation method known to those skilled in the art including, but not limited to, cryogenic distillation and the use of molecular sieves or gas separation (e.g., ceramic) membranes.
Pipeline-Quality Natural Gas [00165] In certain embodiments, the acid gas-depleted synthesis gas stream (30), the acid gas-depleted hydrocarbon stream (31), the hydrogen-depleted gas stream (74), the methane-enriched gas stream (75), and/or a combination of the above, is a "pipeline-quality natural gas". A "pipeline-quality natural gas" typically refers to a methane-containing gas that is (1) within 5 % of the heating value of pure methane (whose heating value is 1010 btu/ft3 under standard atmospheric conditions), (2) substantially free of water (typically a dew point of about -40 C or less), and (3) substantially free of toxic or corrosive contaminants.
Uses of Gaseous Hydrocarbon Product Streams [00166] All or a portion of the acid gas-depleted synthesis gas stream (30) and/or acid gas-depleted gaseous hydrocarbon product stream (31) (or derivative product stream as discussed above) can, for example, be utilized for combustion and/or steam generation in a power generation block (760), for example, to produce electrical power (79) which may be either utilized within the plant or can be sold onto the power grid.
[00167] All or a portion of these streams can also be used as a recycle hydrocarbon stream (78), for example, for use as carbonaceous feedstock (10) in a gaseous partial oxidation/methane reforming process, or for the generation of syngas feed stream (16) for use in a hydromethanation process (in, for example, a gaseous partial oxidation/methane reforming process). Both of these uses can, for example, ultimately result in an optimized production of hydrogen product stream (72), and carbon dioxide-rich recycle stream (87).
Examples of Specific Embodiments [00168] In one embodiment, the synthesis gas stream is produced by a catalytic steam methane reforming process utilizing a methane-containing stream as the carbonaceous feedstock.
[00169] In another embodiment, the synthesis gas stream is produced by a non-catalytic (thermal) gaseous partial oxidation process utilizing a methane-containing stream as the carbonaceous feedstock.
[00170] In another embodiment, the synthesis gas stream is produced by a catalytic autothermal reforming process utilizing a methane-containing stream as the carbonaceous feedstock.
[00171] The methane-containing stream for use in these processes may be a natural gas stream, a synthetic natural gas stream or a combination thereof. In one embodiment, the methane-containing stream comprises all or a portion of the acid gas-depleted gaseous hydrocarbon product stream, the acid gas-depleted synthesis gas stream, a combination of these streams, and/or a derivative of one or both of these streams after downstream processing.
[00172] The resulting synthesis gas stream from these processes will typically comprise at least hydrogen and one or both of carbon monoxide and carbon dioxide, depending on gas processing prior to acid gas removal.
[00173] In another embodiment, the synthesis gas stream is produced by a non-catalytic thermal gasification process utilizing a non-gaseous carbonaceous material as the carbonaceous feedstock, such as coal, petcoke, biomass and mixtures thereof.
[00174] The resulting synthesis gas stream from this process will typically comprise at least hydrogen and one or both of carbon monoxide and carbon dioxide, depending on gas processing prior to acid gas removal.
[00175] In another embodiment, the synthesis gas stream is produced by a catalytic hydromethanation process utilizing a non-gaseous carbonaceous material as the carbonaceous feedstock, such as coal, petcoke, biomass and mixtures thereof.
[00176] The resulting synthesis gas stream from this process will typically comprise at least methane, hydrogen and carbon dioxide, and optionally carbon monoxide, depending on gas processing prior to acid gas removal.
[00177] In another embodiment, at least a portion of the synthesis gas stream is subject to a sour shift to generate a hydrogen-enriched stream. The hydrogen-enriched stream is subsequently treated in the acid gas removal step.
[00178] In another embodiment, the acid-gas depleted synthesis gas stream comprises hydrogen, and at least a portion of the hydrogen is separated to generate a hydrogen product stream and a hydrogen-depleted gas stream.
[00179] In another embodiment, this hydrogen-depleted gas stream is a pipeline-quality natural gas.
[00180] In another embodiment, the acid gas-depleted gaseous hydrocarbon product stream is a pipeline-quality natural gas.
[00181] In another embodiment, the acid-gas depleted synthesis gas stream comprises hydrogen and carbon monoxide, and is subject to a methanation to produce a methane-enriched gas stream, which can be a pipeline-quality natural gas.
[00182] In another embodiment, this hydrogen-depleted gas stream comprises hydrogen and carbon monoxide, and is subject to a methanation to produce a methane-enriched gas stream, which can be a pipeline-quality natural gas.
[00183] In another embodiment, at least a portion of the acid-gas depleted gaseous hydrocarbon product stream and/or the acid gas-depleted synthesis gas stream (or the hydrogen-depleted stream if present, or the methane-enriched stream if present), is the carbonaceous feedstock.
[00184] In another embodiment, at least a portion of the acid-gas depleted gaseous hydrocarbon product stream and/or acid gas-depleted synthesis gas stream (or the hydrogen-depleted stream if present, or the methane-enriched stream if present), is used to generate electrical power.
[00185] In another embodiment, at least a portion of the acid-gas depleted gaseous hydrocarbon product stream and/or acid gas-depleted synthesis gas stream (or the hydrogen-depleted stream if present, or the methane-enriched stream if present), is used to generate a syngas feed stream for use in a hydromethanation process.
[00186] In one embodiment, the synthesis gas stream and the gaseous hydrocarbon stream are subject to a dehydration prior to acid gas removal.
[00187] In one embodiment, the acid-gas lean absorber stream is recycled back to one or both of the first and second acid gas absorber units.
[00188] In an embodiment of the apparatus, the absorber regeneration unit is further adapted to (iv) provide the acid gas-lean absorber stream to one or both the first and second acid gas absorber units.
[0083] The gaseous hydrocarbon stream (84) exiting separation device (300) is ultimately processed with synthesis gas stream (50) in an acid gas removal unit as discussed below.
Prior to processing in the acid gas removal unit, gaseous hydrocarbon stream (84) may optionally be compressed or heated (not depicted) to temperature and pressure conditions suitable for optional downstream processing as further described below.
Synthesis Gas Generation (100) [0084] Synthesis gas stream (50) contains (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane. The actual composition of synthesis gas stream (50) will depend on the synthesis gas process and carbonaceous feedstock utilized to generate the stream, including any gas processing that may occur before acid gas removal.
[0085] In one embodiment, synthesis gas stream (50) comprises carbon dioxide and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon dioxide and methane. In another embodiment, synthesis gas stream (50) comprises carbon dioxide, methane and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon monoxide and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon monoxide, methane and hydrogen. In another embodiment, synthesis gas stream (50) comprises carbon dioxide, carbon monoxide, methane and hydrogen. The synthesis gas stream (50) may also contain other gaseous components such as, for example, hydrogen sulfide, steam and other gaseous hydrocarbons again depending on the synthesis gas production process and carbonaceous feedstock.
[0086] Any synthesis gas generating process can be utilized in the context of the present invention, so long as the synthesis gas generating process (including gas processing prior to acid gas removal) results in a synthesis gas stream as required in the context of the present invention. Suitable synthesis gas processes are generally known to those of ordinary skill in the relevant art, and many applicable technologies are commercially available.
[0087] Non-limiting examples of different types of suitable synthesis gas generation processes are discussed below. These may be used individually or in combination. All synthesis gas generation process will involve a reactor, which is generically depicted as (110) in Figure 2, where a carbonaceous feedstock (10) will be processed to produce synthesis gases, which may be further treated prior to acid gas removal. General reference can be made to Figure 2 in the context of the various synthesis gas generating processes described below.
Gas-Based Methane Reforming/Partial Oxidation [0088] In one embodiment, the synthesis gas generating process is based on a gas-fed methane partial oxidation/reforming process, such as non-catalytic gaseous partial oxidation, catalytic autothermal reforming or catalytic stream-methane reforming process.
These processes are generally well-known in the relevant art. See, for example, Rice and Mann, "Autothermal Reforming of Natural Gas to Synthesis Gas, Reference: KBR Paper #2031,"
Sandia National Laboratory Publication No. SAND2007-2331 (2007); and Bogdan, "Reactor Modeling and Process Analysis for Partial Oxidation of Natural Gas", printed by Febodruk, WV., ISBN: 90-365-2100-9 (2004).
[0089] Technologies and reactors potentially suitable for use in conjunction with the present invention are commercially available from Royal Dutch Shell plc, Siemens AG, General Electric Company, Lurgi AG, Haldor Topsoe A/S, Uhde AG, KBR Inc. and others.
[0090] These gas-based processes convert a gaseous methane-containing stream as a carbonaceous feedstock (10, Figure 2), in a reactor (110) into a syngas (hydrogen plus carbon monoxide) as synthesis gas stream (50) which, depending on the specific process, will have differing ratios of hydrogen:carbon monoxide, will generally contain minor amounts of carbon dioxide, and may contain minor amounts of other gaseous components such as steam.
[0091] The methane-containing stream useful in these processes comprises methane in a predominant amount, and may comprise other gaseous hydrocarbon and components.
Examples of commonly used methane-containing streams include natural gas and synthetic natural gas.
[0092] In non-catalytic gaseous partial oxidation and autothermal reforming, an oxygen-rich gas stream (12) is fed into the reactor (110) along with carbonaceous feedstock (10).
Optionally, steam (14) may also be fed into the reactor (110). In steam-methane reforming, steam (14) is fed into the reactor along with the carbonaceous feedstock (10).
In some cases, minor amounts of other gases such as carbon dioxide, hydrogen and/or nitrogen may also be fed in the reactor (110).
[0093] Reaction and other operating conditions, and equipment and configurations, of the various reactors and technologies are in a general sense known to those of ordinary skill in the relevant art, and are not critical to the present invention in its broadest sense.
Solids/Liquids-Based Gasification to Syngas [0094] In another embodiment, the synthesis gas generating process is based on a non-catalytic thermal gasification process, such as a partial oxidation gasification process (like an oxygen-blown gasifier), where a non-gaseous (liquid, semi-solid and/or solid) hydrocarbon is utilized as the carbonaceous feedstock (10). A wide variety of biomass and non-biomass materials (as described above) can be utilized as the carbonaceous feedstock (10) in these processes.
[0095] Oxygen-blown solids/liquids gasifiers potentially suitable for use in conjunction with the present invention are, in a general sense, known to those of ordinary skill in the relevant art and include, for example, those based on technologies available from Royal Dutch Shell plc, ConocoPhillips Company, Siemens AG, Lurgi AG (Sasol), General Electric Company and others. Other potentially suitable syngas generators are disclosed, for example, in US2009/0018222A1, US2007/0205092A1 and US6863878.
[0096] These processes convert a solid, semi-solid and/or liquid carbonaceous feedstock (10, Figure 2), in a reactor (110) such as an oxygen-blown gasifier, into a syngas (hydrogen plus carbon monoxide) as synthesis gas stream (50) which, depending on the specific process and carbonaceous feedstock, will have differing ratios of hydrogen:carbon monoxide, will generally contain minor amounts of carbon dioxide, and may contain minor amounts of other gaseous components such as methane, steam, sulfur oxides and nitrogen oxides.
[0097] In certain of these processes, an oxygen-rich gas stream (12) is fed into the reactor (110) along with the carbonaceous feedstock (10). Optionally, steam (14) may also be fed into the reactor (110), as well as other gases such as carbon dioxide, hydrogen, methane and/or nitrogen.
[0098] In certain of these processes, steam (14) may be utilized as an oxidant at elevated temperatures in place of all or a part of the oxygen-rich gas stream (12).
[0099] The gasification in the reactor (110) will typically occur in a fluidized bed of the carbonaceous feedstock (10) that is fluidized by the flow of the oxygen-rich gas stream (12), steam (14) and/or other fluidizing gases (like carbon dioxide and/or nitrogen) that may be fed to reactor (110).
[00100] Typically, thermal gasification is a non-catalytic process, so no gasification catalyst needs to be added to the carbonaceous feedstock (10) or into the reactor (110); however, a catalyst that promotes syngas formation may be utilized.
[00101] These thermal gasification processes are typically operated under high temperature and pressure conditions, and may run under slagging or non-slagging operating conditions depending on the process and carbonaceous feedstock.
[00102] Reaction and other operating conditions, and equipment and configurations, of the various reactors and technologies are in a general sense known to those of ordinary skill in the relevant art, and are not critical to the present invention in its broadest sense.
Catalytic Gasification/Hydromethanation to a Methane-Enriched Gas [00103] In another alternative embodiment, the synthesis gas generating process is a catalytic gasification/hydromethanation process, in which gasification of a non-gaseous carbonaceous feedstock (10) takes place in a reactor (110) in the presence of steam and a catalyst to result in a methane-enriched gas stream as the synthesis gas stream (50), which typically comprises methane, hydrogen, carbon monoxide, carbon dioxide and steam.
[00104] The hydromethanation of a carbon source to methane typically involves four concurrent reactions:
[00105] Steam carbon: C + H2O ---> CO + H2 (I) [00106] Water-gas shift: CO + H20 ---> H2 + CO2 (II) [00107] CO Methanation: C0+3H2 --> CH4 + H20 (III) [00108] Hydro-gasification: 2H2 + C --> CH4 (IV) [00109] In the hydromethanation reaction, the first three reactions (I-III) predominate to result in the following overall reaction:
[00110] 2C + 2H20 ---> CH4 + CO2 (V).
[00111] The overall reaction is essentially thermally balanced; however, due to process heat losses and other energy requirements (such as required for evaporation of moisture entering the reactor with the feedstock), some heat must be added to maintain the thermal balance.
[00112] The reactions are also essentially syngas (hydrogen and carbon monoxide) balanced (syngas is produced and consumed); therefore, as carbon monoxide and hydrogen are withdrawn with the product gases, carbon monoxide and hydrogen need to be added to the reaction as required to avoid a deficiency.
[00113] In order to maintain the net heat of reaction as close to neutral as possible (only slightly exothermic or endothermic), and maintain the syngas balance, a superheated gas stream of steam (14) and syngas (16) (carbon monoxide and hydrogen) is often fed to the reactor (110). Frequently, the carbon monoxide and hydrogen streams are recycle streams separated from the product gas, and/or are provided by reforming a portion of the product methane.
[00114] The carbonaceous feedstocks useful in these processes include, for example, a wide variety of biomass and non-biomass materials.
[00115] Catalysts utilized in these processes include, for example, alkali metals, alkaline earth metals and transition metals, and compounds, mixtures and complexes thereof.
[00116] The temperature and pressure operating conditions in a catalytic gasification/hydromethanation process are typically milder (lower temperature and pressure) than a non-catalytic gasification process, which can sometimes have advantages in terms of cost and efficiency.
[00117] Catalytic gasification/hydromethanation processes and conditions are disclosed, for example, in US3998607, US4057512, US4094650, US4204843, US4558027, US4604105, US6955695, and US2003/0167691 Al, as well as in commonly owned US2007/0000177A1 , US2007/0083072A1, US2007/0277437A1, US2009/0048476A1, US2009/0090056A1, US2009/0090055A1, US2009/0165383A1, US2009/0166588A1, US2009/0165379A1, US2009/0170968A1, US2009/0165380A1, US2009/0165381A1, US2009/0165361A1, US2009/0165382A1, US2009/0169449A1, US2009/0169448A1, US2009/0165376A1, US2009/0165384A1, US2009/0217582A1, US2009/0220406A1, US2009/0217590A1, US2009/0217586A1, US2009/0217588A1, US2009/0218424A1, US2009/0217589A1, US2009/0217575A1, US2009/0229182A1, US2009/0217587A1, US2009/0246120A1, US2009/0260287A1, US2009/0259080A1, US2009/0324458A1, US2009/0324459A1, US2009/0324460A1, US2009/0324461A1, US2009/0324462A1, US2010/0121125A1, US2010/0120926A1, US2010/0071262A1, US2010/0076235A1, US2010/0179232A1, US2010/0168495A1, US2010/0168494A1, US2010/0292350A1, US2010/0287836A1, US2010/0287835A1, US2011/0031439A1, US2011/0062012A1, US2011/0062722A1, US2011/0062721A1 and US2011/0064648A1.
[00118] General reaction and other operating conditions of the various catalytic gasification/hydromethanation reactors and technologies can be found from the above references, and are not critical to the present invention in its broadest sense.
Heat Exchange (140) [00119] All of the above described synthesis gas generation processes typically will generate a synthesis gas stream (50) of a temperature higher than suitable for feeding downstream gas processes (including second acid gas absorber unit (210)), so upon exit from reactor (110) the synthesis gas stream (50) is typically passed through a heat exchanger unit (140) to remove heat energy and generate a cooled synthesis gas stream (52).
[00120] The heat energy recovered in heat exchanger unit (140) can be used, for example, to generate steam and/or superheat various process streams, as will be recognized by a person of ordinary skill in the art. Any steam generated can be used for internal process requirements and/or used to generate electrical power.
[00121] In one embodiment, the resulting cooled synthesis gas stream (52) will typically exit heat exchanger unit (140) at a temperature ranging from about 450 F (about 232 C) to about 1100 F (about 593 C), more typically from about 550 F (about 288 C) to about 950 F (about 510 C), and at a pressure suitable for subsequent acid gas removal processing (taking into account any intermediate processing). Typically, this pressure will be from about 50 psig (about 446 kPa) to about 800 psig (about 5617 kPa), more typically from about 400 psig (about 2860 kPa) to about 600 psig (about 4238 kPa).
Gas Treatment Prior to Acid Gas Removal [00122] Synthesis gas stream (50) and gaseous hydrocarbon stream (84) may be processed in various treatment processes, which will be primarily dependent on the composition, temperature and pressure of the two streams, and any desired end products.
[00123] Processing options prior to acid gas removal typically include, for example, one or more of sour shift (700) (water gas shift), contaminant removal (710) and dehydration (720 and 720a). While these intermediate processing steps can occur in any order, dehydration (720 and 720a) will usually occur just prior to acid gas removal (last in the series), as a substantial portion of any water in synthesis gas stream (50) and gaseous hydrocarbon stream (84) desirably should be removed prior to treatment in acid gas absorber units (210 and 230).
[00124] Typically, the gaseous hydrocarbon stream (84) will require at least some compression prior to treatment in first acid gas absorber unit (230).
Sour Shift (700) [00125] In certain embodiments, particularly where a stream contains appreciable amounts of carbon monoxide, and it is desired to maximize hydrogen and/or carbon dioxide production, all or a part of such stream (such as synthesis gas stream (50)) can be supplied to a sour shift reactor (700).
[00126] In sour shift reactor (700), the gases undergo a sour shift reaction (also known as a water-gas shift reaction) in the presence of an aqueous medium (such as steam) to convert at least a predominant portion (or a substantial portion, or substantially all) of the CO to CO2, which also increases the fraction of H2 in order to produce a hydrogen-enriched stream (54).
[00127] A sour shift process is described in detail, for example, in U57074373. The process involves adding water, or using water contained in the gas, and reacting the resulting water-gas mixture adiabatically over a steam reforming catalyst. Typical steam reforming catalysts include one or more Group VIII metals on a heat-resistant support.
[00128] Methods and reactors for performing the sour gas shift reaction on a CO-containing gas stream are well known to those of skill in the art. Suitable reaction conditions and suitable reactors can vary depending on the amount of CO that must be depleted from the gas stream. In some embodiments, the sour gas shift can be performed in a single stage within a temperature range from about 100 C, or from about 150 C, or from about 200 C, to about 250 C, or to about 300 C, or to about 350 C. In these embodiments, the shift reaction can be catalyzed by any suitable catalyst known to those of skill in the art. Such catalysts include, but are not limited to, Fe203-based catalysts, such as Fe203-Cr203 catalysts, and other transition metal-based and transition metal oxide-based catalysts. In other embodiments, the sour gas shift can be performed in multiple stages. In one particular embodiment, the sour gas shift is performed in two stages. This two-stage process uses a high-temperature sequence followed by a low-temperature sequence. The gas temperature for the high-temperature shift reaction ranges from about 350 C to about 1050 C. Typical high-temperature catalysts include, but are not limited to, iron oxide optionally combined with lesser amounts of chromium oxide. The gas temperature for the low-temperature shift ranges from about 150 C to about 300 C, or from about 200 C to about 250 C. Low-temperature shift catalysts include, but are not limited to, copper oxides that may be supported on zinc oxide or alumina. Suitable methods for the sour shift process are described in US2009/0246120A1.
[00129] The sour shift reaction is exothermic, so it is often carried out with a heat exchanger (not depicted) to permit the efficient use of heat energy. Shift reactors employing these features are well known to those of skill in the art. Recovered heat energy can be used, for example, to generate steam, superheat various process streams and/or preheat boiler feed water for use in other steam generating operations. An example of a suitable shift reactor is illustrated in US7074373, although other designs known to those of skill in the art are also effective.
[00130] If sour shift is present and it is desired to retain some carbon monoxide content, a portion of the stream can be split off to bypass sour shift reactor (700) and be combined with hydrogen-enriched stream (54) at some point prior to second acid gas absorber unit (210).
This is particularly useful when it is desired to recover a separate methane by-product, as the retained carbon monoxide can be subsequently methanated as discussed below.
Contaminant Removal (710) [00131] As is familiar to those skilled in the art, the contamination levels of synthesis gas stream (50) will depend on the nature of the carbonaceous feedstock and the synthesis gas generation conditions. For example, petcoke and certain coals can have high sulfur contents, leading to higher sulfur oxide (S0x), H2S and/or COS contamination. Certain coals can contain significant levels of mercury which can be volatilized during the synthesis gas generation. Other feedstocks can be high in nitrogen content, leading to ammonia, nitrogen oxides (N0x) and/or cyanides.
[00132] Some of these contaminants are typically removed in second acid gas absorber unit (210), such as H2S and COS. Others such as ammonia and mercury, require removal prior to second acid gas absorber unit (210).
[00133] When present, contaminant removal of a particular contaminant should remove at least a substantial portion (or substantially all) of that contaminant from the so-treated cleaned gas stream (56), typically to levels at or lower than the specification limits for the desired second acid gas absorber unit (210), or the desired end product.
[00134] While not shown in Figure 2, gaseous hydrocarbon stream (84) may be treated separately for contaminant removal as needed.
[00135] Contaminant removal process are in a general sense well know to those of ordinary skill in the relevant art, as exemplified in many of the previously-incorporated references.
Dehydration (720 and 720a) [00136] In addition, prior to acid gas removal, the synthesis gas stream (50) and gaseous hydrocarbon stream (84) should be treated to reduced residual water content via a dehydration unit (720) and (720a) to produce a dehydrated stream (58) and (58a) for feeding to second acid gas absorber unit (210) and first acid gas absorber unit (230), respectively.
[00137] Examples of suitable dehydration units include a knock-out drum or similar water separation device, and/or water absorption processes such as glycol treatment.
[00138] Such dehydration units and processes again are in a general sense well known to those of ordinary skill in the relevant art.
Acid Gas Removal [00139] In accordance with the present invention, the synthesis gas stream (50) and the gaseous hydrocarbon stream (84) (or derivative streams resulting from intermediate treatment) are processed in an acid gas removal unit to remove carbon dioxide and other acid gases (such as hydrogen sulfide if present), and generate a carbon dioxide-rich recycle stream (87), an acid gas-depleted gaseous hydrocarbon product stream (31) and an acid gas-depleted synthesis gas stream (30).
[00140] As indicated previously, the synthesis gas stream (50) and the gaseous hydrocarbon stream (84) are first individually treated in a second acid gas absorber unit (210) and a first acid gas absorber unit (230), respectively, to generate a separate acid gas-depleted synthesis gas stream (30) and second acid gas-rich absorber stream (35), and a separate acid gas-depleted gaseous hydrocarbon product stream (31) and first acid gas-rich absorber stream (36).
[00141] The resulting acid gas-depleted gaseous hydrocarbon product stream (31) and an acid gas-depleted synthesis gas stream (30) may be co-processed or separately processed as described further below.
[00142] The resulting first acid gas-rich absorber stream (36) and second acid gas-rich absorber stream (35) are co-processed in an absorber regeneration unit (250) to ultimately result in an acid gas stream containing the combined acid gases (and other contaminants) removed from both synthesis gas stream (50) and gaseous hydrocarbon stream (84). First acid gas-rich absorber stream (36) and second acid gas-rich absorber stream (35) may be combined prior to or within absorber regeneration unit (250) for co-processing.
[00143] Ultimately, a carbon dioxide-rich recycle stream (87) is generated containing a substantial portion of carbon dioxide from both synthesis gas stream (50) and gaseous hydrocarbon stream (84). An acid gas-lean absorber stream (70) is also generated, which can be recycled back to one or both of first acid gas absorber unit (230) and second acid gas absorber unit (210) along with make-up absorber as required. If one or both of synthesis gas stream (50) and gaseous hydrocarbon stream (84) contain other acid gas contaminants, such as hydrogen sulfide, then an additional stream may be generated, such as hydrogen sulfide stream (88).
[00144] Acid gas removal processes typically involve contacting a gas stream with a solvent such as monoethanolamine, diethanolamine, methyldiethanolamine, diisopropylamine, diglycolamine, a solution of sodium salts of amino acids, methanol, hot potassium carbonate or the like to generate CO2 and/or H2S laden absorbers. One method can involve the use of Selexol (UOP LLC, Des Plaines, IL USA). or Rectisol (Lurgi AG, Frankfurt am Main, Germany) solvent having two trains; each train containing an H2S absorber and a CO2 absorber.
[00145] One method for removing acid gases is described in US2009/0220406A1.
[00146] At least a substantial portion (e.g., substantially all) of the CO2 and/or H2S (and other remaining trace contaminants) should be removed via the acid gas removal processes.
"Substantial" removal in the context of acid gas removal means removal of a high enough percentage of the component such that a desired end product can be generated.
The actual amounts of removal may thus vary from component to component. Desirably, only trace amounts (at most) of H2S should be present in the acid gas-depleted gaseous hydrocarbon product stream, although higher amounts of CO2 may be tolerable depending on the desired end product.
[001471 Typically, at least about 85%, or at least about 90%, or at least about 92%, of the CO2, and at least about 95%, or at least about 98%, or at least about 99.5%, of the H2S, should be removed, based on the amount of those components contained in the streams fed to =
the acid gas removal.
[00148] Any recovered H2S (88) from the acid gas removal can be converted to elemental sulfur by any method known to those skilled in the art, including the Claus process. Sulfur can be recovered as a molten liquid.
Compression (400) [00149] As discussed above, the recovered carbon dioxide-rich recycle stream (87) is in whole or in part compressed via compressor (400) to generate pressurized carbon dioxide stream (89) for the EOR portion of the process. A CO2 product stream (90) can also optionally be split off of carbon dioxide-rich recycle stream (87) and/or pressurized carbon dioxide stream (89).
[00150] Suitable compressors for compressing carbon dioxide-rich recycle stream (87) to appropriate pressures and conditions for EOR are in a general sense well-known to those of ordinary skill in the relevant art.
Acid Gas-Depleted Synthesis Gas Stream (30) and Acid Gas-Depleted Gaseous Hydrocarbon Product Stream (31) [00151] The resulting acid gas-depleted gaseous hydrocarbon product stream (31) will generally comprise CH4 and other gaseous hydrocarbons from the gaseous hydrocarbon stream (84), and typically no more than contaminant amounts of CO2, H20, H2S
and other contaminants. The resulting acid gas-depleted synthesis gas stream (30) will generally comprise one or both of CH4 and H2, and optionally CO (for the downstream methanation), and typically no more than contaminant amounts of CO2, H20, H2S and other contaminants.
[00152] All or a portion of these two streams individually, or combined in whole or in part, may be processed to end products or for end uses as are well known to those of ordinary skill in the relevant art. The two streams may be combined at various points subsequent to acid gas removal.
[00153] Non-limiting options are discussed below in reference to Figure 2.
Although Figure 2 only depicts some of the options as applied to acid gas-depleted synthesis gas stream (30), these options (and others) may be applied to gas-depleted gaseous hydrocarbon product stream (31) (or a combined stream) where appropriate.
Optional Further Processing Hydrogen Separation (730) [00154] If present, hydrogen may be separated from all or a portion of acid gas-depleted synthesis gas stream (30) (and/or the acid gas-depleted gaseous hydrocarbon product stream (31)) according to methods known to those skilled in the art, such as cryogenic distillation, the use of molecular sieves, gas separation (e.g., ceramic or polymeric) membranes, and/or pressure swing adsorption (PSA) techniques.
[00155] In one embodiment, a PSA device is utilized for hydrogen separation.
PSA
technology for separation of hydrogen from gas mixtures containing methane (and optionally carbon monoxide) is in general well-known to those of ordinary skill in the relevant art as disclosed, for example, in US6379645 (and other citations referenced therein).
PSA devices are generally commercially available, for example, based on technologies available from Air Products and Chemicals Inc. (Allentown, PA), UOP LLC (Des Plaines, IL) and others.
[00156] In another embodiment, a hydrogen membrane separator can be used followed by a PSA device.
[00157] Such separation provides a high-purity hydrogen product stream (72) and a hydrogen-depleted gas stream (74).
[00158] The recovered hydrogen product stream (72) preferably has a purity of at least about 99 mole%, or at least 99.5 mole%, or at least about 99.9 mole%.
[00159] The recovered hydrogen can be used, for example, as an energy source and/or as a reactant. For example, the hydrogen can be used as an energy source for hydrogen-based fuel cells, or for power and/or steam generation (760). The hydrogen can also be used as a - reactant in various hydrogenation processes, such as found in the chemical and petroleum refining industries.
[00160] The hydrogen-depleted gas stream (74) will substantially comprise light hydrocarbons, such as methane (and generally predominantly methane, or substantially methane), with optional minor amounts of carbon monoxide (depending primarily on the extent of the sour shift reaction and bypass), carbon dioxide (depending primarily on the effectiveness of the acid gas removal process) and hydrogen (depending primarily on the extent and effectiveness of the hydrogen separation technology), and can be further processed/utilized as described below.
Methanation (740) [00161] If the acid gas-depleted synthesis gas stream (30) (and/or the acid gas-depleted gaseous hydrocarbon product stream (31), and/or the hydrogen-depleted sweetened gas stream (74)) contains carbon monoxide and hydrogen, all or part of the stream may be fed to a (trim) methanation unit (740) to generate additional methane from the carbon monoxide and hydrogen, resulting in a methane-enriched gas stream (75).
[00162] The methanation reaction can be carried out in any suitable reactor, e.g., a single-stage methanation reactor, a series of single-stage methanation reactors or a multistage reactor. Methanation reactors include, without limitation, fixed bed, moving bed or fluidized bed reactors. See, for instance, US3958957, US4252771, U53996014 and US4235044.
Methanation reactors and catalysts are generally commercially available. The catalyst used in the methanation, and methanation conditions, are generally known to those of ordinary skill in the relevant art, and will depend, for example, on the temperature, pressure, flow rate and composition of the incoming gas stream.
[00163] As the methanation reaction is exothermic, the methane-enriched gas stream (75) may be, for example, further provided to a heat exchanger unit (750). While the heat exchanger unit (750) is depicted as a separate unit, it can exist as such and/or be integrated into methanation unit (740), thus being capable of cooling the methanation unit (740) and removing at least a portion of the heat energy from the methane-enriched stream (75) to reduce the temperature and generate a cooled methane-enriched stream (76). The recovered heat energy can be utilized, for example, to generate a process steam stream from a water and/or steam source.
[00164] All or part of the methane-enriched stream (75) can be recovered as a methane product stream (77) or, it can be further processed, when necessary, to separate and recover CH4 by any suitable gas separation method known to those skilled in the art including, but not limited to, cryogenic distillation and the use of molecular sieves or gas separation (e.g., ceramic) membranes.
Pipeline-Quality Natural Gas [00165] In certain embodiments, the acid gas-depleted synthesis gas stream (30), the acid gas-depleted hydrocarbon stream (31), the hydrogen-depleted gas stream (74), the methane-enriched gas stream (75), and/or a combination of the above, is a "pipeline-quality natural gas". A "pipeline-quality natural gas" typically refers to a methane-containing gas that is (1) within 5 % of the heating value of pure methane (whose heating value is 1010 btu/ft3 under standard atmospheric conditions), (2) substantially free of water (typically a dew point of about -40 C or less), and (3) substantially free of toxic or corrosive contaminants.
Uses of Gaseous Hydrocarbon Product Streams [00166] All or a portion of the acid gas-depleted synthesis gas stream (30) and/or acid gas-depleted gaseous hydrocarbon product stream (31) (or derivative product stream as discussed above) can, for example, be utilized for combustion and/or steam generation in a power generation block (760), for example, to produce electrical power (79) which may be either utilized within the plant or can be sold onto the power grid.
[00167] All or a portion of these streams can also be used as a recycle hydrocarbon stream (78), for example, for use as carbonaceous feedstock (10) in a gaseous partial oxidation/methane reforming process, or for the generation of syngas feed stream (16) for use in a hydromethanation process (in, for example, a gaseous partial oxidation/methane reforming process). Both of these uses can, for example, ultimately result in an optimized production of hydrogen product stream (72), and carbon dioxide-rich recycle stream (87).
Examples of Specific Embodiments [00168] In one embodiment, the synthesis gas stream is produced by a catalytic steam methane reforming process utilizing a methane-containing stream as the carbonaceous feedstock.
[00169] In another embodiment, the synthesis gas stream is produced by a non-catalytic (thermal) gaseous partial oxidation process utilizing a methane-containing stream as the carbonaceous feedstock.
[00170] In another embodiment, the synthesis gas stream is produced by a catalytic autothermal reforming process utilizing a methane-containing stream as the carbonaceous feedstock.
[00171] The methane-containing stream for use in these processes may be a natural gas stream, a synthetic natural gas stream or a combination thereof. In one embodiment, the methane-containing stream comprises all or a portion of the acid gas-depleted gaseous hydrocarbon product stream, the acid gas-depleted synthesis gas stream, a combination of these streams, and/or a derivative of one or both of these streams after downstream processing.
[00172] The resulting synthesis gas stream from these processes will typically comprise at least hydrogen and one or both of carbon monoxide and carbon dioxide, depending on gas processing prior to acid gas removal.
[00173] In another embodiment, the synthesis gas stream is produced by a non-catalytic thermal gasification process utilizing a non-gaseous carbonaceous material as the carbonaceous feedstock, such as coal, petcoke, biomass and mixtures thereof.
[00174] The resulting synthesis gas stream from this process will typically comprise at least hydrogen and one or both of carbon monoxide and carbon dioxide, depending on gas processing prior to acid gas removal.
[00175] In another embodiment, the synthesis gas stream is produced by a catalytic hydromethanation process utilizing a non-gaseous carbonaceous material as the carbonaceous feedstock, such as coal, petcoke, biomass and mixtures thereof.
[00176] The resulting synthesis gas stream from this process will typically comprise at least methane, hydrogen and carbon dioxide, and optionally carbon monoxide, depending on gas processing prior to acid gas removal.
[00177] In another embodiment, at least a portion of the synthesis gas stream is subject to a sour shift to generate a hydrogen-enriched stream. The hydrogen-enriched stream is subsequently treated in the acid gas removal step.
[00178] In another embodiment, the acid-gas depleted synthesis gas stream comprises hydrogen, and at least a portion of the hydrogen is separated to generate a hydrogen product stream and a hydrogen-depleted gas stream.
[00179] In another embodiment, this hydrogen-depleted gas stream is a pipeline-quality natural gas.
[00180] In another embodiment, the acid gas-depleted gaseous hydrocarbon product stream is a pipeline-quality natural gas.
[00181] In another embodiment, the acid-gas depleted synthesis gas stream comprises hydrogen and carbon monoxide, and is subject to a methanation to produce a methane-enriched gas stream, which can be a pipeline-quality natural gas.
[00182] In another embodiment, this hydrogen-depleted gas stream comprises hydrogen and carbon monoxide, and is subject to a methanation to produce a methane-enriched gas stream, which can be a pipeline-quality natural gas.
[00183] In another embodiment, at least a portion of the acid-gas depleted gaseous hydrocarbon product stream and/or the acid gas-depleted synthesis gas stream (or the hydrogen-depleted stream if present, or the methane-enriched stream if present), is the carbonaceous feedstock.
[00184] In another embodiment, at least a portion of the acid-gas depleted gaseous hydrocarbon product stream and/or acid gas-depleted synthesis gas stream (or the hydrogen-depleted stream if present, or the methane-enriched stream if present), is used to generate electrical power.
[00185] In another embodiment, at least a portion of the acid-gas depleted gaseous hydrocarbon product stream and/or acid gas-depleted synthesis gas stream (or the hydrogen-depleted stream if present, or the methane-enriched stream if present), is used to generate a syngas feed stream for use in a hydromethanation process.
[00186] In one embodiment, the synthesis gas stream and the gaseous hydrocarbon stream are subject to a dehydration prior to acid gas removal.
[00187] In one embodiment, the acid-gas lean absorber stream is recycled back to one or both of the first and second acid gas absorber units.
[00188] In an embodiment of the apparatus, the absorber regeneration unit is further adapted to (iv) provide the acid gas-lean absorber stream to one or both the first and second acid gas absorber units.
Claims (10)
1. An integrated process to (i) produce an acid gas-depleted gaseous hydrocarbon product stream, (ii) produce an acid gas-depleted synthesis gas stream, (iii) produce a liquid hydrocarbon product stream and (iv) enhance production of a hydrocarbon-containing fluid from an underground hydrocarbon reservoir, the process comprising the steps of:
(1) injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir to enhance production of the hydrocarbon-containing fluid from the underground hydrocarbon reservoir via a hydrocarbon production well, the hydrocarbon-containing fluid comprising carbon dioxide;
(2) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well;
(3) separating the hydrocarbon-containing fluid into (a) the liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide;
(4) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
(5) producing a synthesis gas stream from a carbonaceous feedstock, the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane;
(6) treating the synthesis gas stream in a second acid gas absorber unit to produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
(7) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and (8) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
(1) injecting a pressurized carbon dioxide stream into an underground hydrocarbon reservoir to enhance production of the hydrocarbon-containing fluid from the underground hydrocarbon reservoir via a hydrocarbon production well, the hydrocarbon-containing fluid comprising carbon dioxide;
(2) recovering the hydrocarbon-containing fluid produced from the hydrocarbon production well;
(3) separating the hydrocarbon-containing fluid into (a) the liquid hydrocarbon product stream and (b) a gaseous hydrocarbon stream comprising carbon dioxide;
(4) treating the gaseous hydrocarbon stream in a first acid gas absorber unit to produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
(5) producing a synthesis gas stream from a carbonaceous feedstock, the synthesis gas stream comprising (a) at least one of carbon monoxide and carbon dioxide, and (b) at least one of hydrogen and methane;
(6) treating the synthesis gas stream in a second acid gas absorber unit to produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
(7) feeding the first acid gas-rich absorber stream and the second acid gas-rich absorber stream into an absorber regeneration unit to produce a carbon dioxide-rich recycle stream and an acid gas-lean absorber stream; and (8) pressurizing the carbon dioxide-rich recycle stream to generate the pressurized carbon dioxide stream.
2. The process of claim 1, wherein the synthesis gas stream is produced by a catalytic steam methane reforming process utilizing a methane-containing stream as the carbonaceous feedstock, or the synthesis gas stream is produced by a non-catalytic gaseous partial oxidation process utilizing a methane-containing stream as the carbonaceous feedstock, or the synthesis gas stream is produced by a catalytic autothermal reforming process utilizing a methane-containing stream as the carbonaceous feedstock.
3. The process of claim 2, wherein the methane-containing stream comprises at least one of: all or a portion of the acid gas-depleted gaseous hydrocarbon product stream, the acid gas-depleted synthesis gas stream, a combination of these streams, and a derivative of one or both of these streams after downstream processing.
4. The process of claim 1, wherein the synthesis gas stream is produced by a non-catalytic thermal gasification process utilizing a non-gaseous carbonaceous material as the carbonaceous feedstock.
5. The process of any one of claims 1-4, wherein the synthesis gas stream comprises hydrogen and one or both of carbon monoxide and carbon dioxide.
6. The process of claim 1, wherein the synthesis gas stream is produced by a catalytic hydromethanation process utilizing a non-gaseous carbonaceous material as the carbonaceous feedstock.
7. The process of claim 1 or claim 6, wherein the synthesis gas stream comprises methane, hydrogen and carbon dioxide.
8. The process of any one of claims 1-7, wherein at least a portion of the synthesis gas stream is subject to a sour shift to generate a hydrogen-enriched stream.
9. The process of any one of claims 1-8, wherein (i) the acid-gas depleted synthesis gas stream comprises hydrogen, and at least a portion of the hydrogen is separated to generate a hydrogen product stream and a hydrogen-depleted gas stream; or (ii) the acid-gas depleted synthesis gas stream comprises hydrogen and carbon monoxide, and is subject to a methanation to produce a methane-enriched gas stream; or (iii) both (i) and (ii).
10. An apparatus for generating a liquid hydrocarbon product stream, an acid gas-depleted gaseous hydrocarbon product stream and an acid gas-depleted synthesis gas stream, the apparatus comprising:
(A) a synthesis gas generation system adapted to produce a synthesis gas from a carbonaceous feedstock, the synthesis gas comprising (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane;
(B) a carbon dioxide injection well in fluid communication with an underground hydrocarbon reservoir, the carbon dioxide injection well adapted to inject a pressurized carbon dioxide stream into the underground hydrocarbon reservoir for enhanced oil recovery;
(C) a hydrocarbon production well in fluid communication with the underground hydrocarbon reservoir, the hydrocarbon production well adapted to remove a hydrocarbon fluid from the underground hydrocarbon reservoir, the hydrocarbon fluid comprising carbon dioxide;
(D) a separation device in fluid communication with the hydrocarbon production well, the separation device adapted (i) to receive the hydrocarbon fluid from the hydrocarbon production well, and (ii) to separate the hydrocarbon fluid into the liquid hydrocarbon product stream and a gaseous hydrocarbon stream comprising carbon dioxide;
(E) a first acid gas absorber unit in fluid communication with the separation device, the first acid gas absorber unit adapted to (i) receive the gaseous hydrocarbon stream from the separation device, and (ii) treat the gaseous hydrocarbon stream to remove acid gases and produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
(F) a second acid gas absorber unit in fluid communication with the synthesis gas generation system, the second acid gas absorber unit adapted to (i) receive the synthesis gas from the synthesis gas generation system, and (ii) treat the synthesis gas to remove acid gases and produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
(G) an absorber regeneration unit in fluid communication with the first acid gas absorber unit and the second acid gas absorber unit, the absorber regeneration unit adapted to (i) receive the first acid gas-rich absorber stream from the first acid gas absorber unit and the second acid gas-rich absorber stream from the second acid gas absorber unit, (ii) remove acid gases from the first acid gas-rich absorber stream and the second acid gas-rich absorber stream, and (iii) generate an acid gas-lean absorber stream and a carbon dioxide-rich recycle stream; and (H) a compressor unit in fluid communication with the absorber regeneration unit and the carbon dioxide injection well, the compressor unit adapted to (i) receive the carbon dioxide-rich recycle stream, and (ii) compress the carbon dioxide recycle stream to generate the pressurized carbon dioxide stream, and (iii) provide the pressurized carbon dioxide stream to the carbon dioxide injection well.
(A) a synthesis gas generation system adapted to produce a synthesis gas from a carbonaceous feedstock, the synthesis gas comprising (i) at least one of carbon monoxide and carbon dioxide, and (ii) at least one of hydrogen and methane;
(B) a carbon dioxide injection well in fluid communication with an underground hydrocarbon reservoir, the carbon dioxide injection well adapted to inject a pressurized carbon dioxide stream into the underground hydrocarbon reservoir for enhanced oil recovery;
(C) a hydrocarbon production well in fluid communication with the underground hydrocarbon reservoir, the hydrocarbon production well adapted to remove a hydrocarbon fluid from the underground hydrocarbon reservoir, the hydrocarbon fluid comprising carbon dioxide;
(D) a separation device in fluid communication with the hydrocarbon production well, the separation device adapted (i) to receive the hydrocarbon fluid from the hydrocarbon production well, and (ii) to separate the hydrocarbon fluid into the liquid hydrocarbon product stream and a gaseous hydrocarbon stream comprising carbon dioxide;
(E) a first acid gas absorber unit in fluid communication with the separation device, the first acid gas absorber unit adapted to (i) receive the gaseous hydrocarbon stream from the separation device, and (ii) treat the gaseous hydrocarbon stream to remove acid gases and produce the acid gas-depleted gaseous hydrocarbon product stream and a first acid gas-rich absorber stream;
(F) a second acid gas absorber unit in fluid communication with the synthesis gas generation system, the second acid gas absorber unit adapted to (i) receive the synthesis gas from the synthesis gas generation system, and (ii) treat the synthesis gas to remove acid gases and produce the acid gas-depleted synthesis gas stream and a second acid gas-rich absorber stream;
(G) an absorber regeneration unit in fluid communication with the first acid gas absorber unit and the second acid gas absorber unit, the absorber regeneration unit adapted to (i) receive the first acid gas-rich absorber stream from the first acid gas absorber unit and the second acid gas-rich absorber stream from the second acid gas absorber unit, (ii) remove acid gases from the first acid gas-rich absorber stream and the second acid gas-rich absorber stream, and (iii) generate an acid gas-lean absorber stream and a carbon dioxide-rich recycle stream; and (H) a compressor unit in fluid communication with the absorber regeneration unit and the carbon dioxide injection well, the compressor unit adapted to (i) receive the carbon dioxide-rich recycle stream, and (ii) compress the carbon dioxide recycle stream to generate the pressurized carbon dioxide stream, and (iii) provide the pressurized carbon dioxide stream to the carbon dioxide injection well.
Applications Claiming Priority (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US25293609P | 2009-10-19 | 2009-10-19 | |
US61/252,936 | 2009-10-19 | ||
PCT/US2010/053027 WO2011049858A2 (en) | 2009-10-19 | 2010-10-18 | Integrated enhanced oil recovery process |
Publications (2)
Publication Number | Publication Date |
---|---|
CA2773718A1 CA2773718A1 (en) | 2011-04-28 |
CA2773718C true CA2773718C (en) | 2014-05-13 |
Family
ID=43759953
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
CA2773718A Expired - Fee Related CA2773718C (en) | 2009-10-19 | 2010-10-18 | Integrated enhanced oil recovery process |
Country Status (5)
Country | Link |
---|---|
US (1) | US8479833B2 (en) |
CN (1) | CN102667057B (en) |
AU (1) | AU2010310846B2 (en) |
CA (1) | CA2773718C (en) |
WO (1) | WO2011049858A2 (en) |
Families Citing this family (73)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US7506685B2 (en) * | 2006-03-29 | 2009-03-24 | Pioneer Energy, Inc. | Apparatus and method for extracting petroleum from underground sites using reformed gases |
US9605522B2 (en) * | 2006-03-29 | 2017-03-28 | Pioneer Energy, Inc. | Apparatus and method for extracting petroleum from underground sites using reformed gases |
US8616294B2 (en) | 2007-05-20 | 2013-12-31 | Pioneer Energy, Inc. | Systems and methods for generating in-situ carbon dioxide driver gas for use in enhanced oil recovery |
US20090090056A1 (en) * | 2007-10-09 | 2009-04-09 | Greatpoint Energy, Inc. | Compositions for Catalytic Gasification of a Petroleum Coke |
CN101910375B (en) | 2007-12-28 | 2014-11-05 | 格雷特波因特能源公司 | Steam generating slurry gasifier for the catalytic gasification of a carbonaceous feedstock |
US20090165380A1 (en) * | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Petroleum Coke Compositions for Catalytic Gasification |
US8123827B2 (en) | 2007-12-28 | 2012-02-28 | Greatpoint Energy, Inc. | Processes for making syngas-derived products |
WO2009086372A1 (en) * | 2007-12-28 | 2009-07-09 | Greatpoint Energy, Inc. | Carbonaceous fuels and processes for making and using them |
US20090166588A1 (en) * | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Petroleum Coke Compositions for Catalytic Gasification |
US8361428B2 (en) | 2008-02-29 | 2013-01-29 | Greatpoint Energy, Inc. | Reduced carbon footprint steam generation processes |
WO2009111331A2 (en) * | 2008-02-29 | 2009-09-11 | Greatpoint Energy, Inc. | Steam generation processes utilizing biomass feedstocks |
US8297542B2 (en) * | 2008-02-29 | 2012-10-30 | Greatpoint Energy, Inc. | Coal compositions for catalytic gasification |
US20090217575A1 (en) | 2008-02-29 | 2009-09-03 | Greatpoint Energy, Inc. | Biomass Char Compositions for Catalytic Gasification |
WO2009111345A2 (en) | 2008-02-29 | 2009-09-11 | Greatpoint Energy, Inc. | Catalytic gasification particulate compositions |
US8286901B2 (en) | 2008-02-29 | 2012-10-16 | Greatpoint Energy, Inc. | Coal compositions for catalytic gasification |
CA2716135C (en) * | 2008-02-29 | 2013-05-28 | Greatpoint Energy, Inc. | Particulate composition for gasification, preparation and continuous conversion thereof |
US20090260287A1 (en) * | 2008-02-29 | 2009-10-22 | Greatpoint Energy, Inc. | Process and Apparatus for the Separation of Methane from a Gas Stream |
WO2009124017A2 (en) * | 2008-04-01 | 2009-10-08 | Greatpoint Energy, Inc. | Processes for the separation of methane from a gas stream |
WO2009124019A2 (en) | 2008-04-01 | 2009-10-08 | Greatpoint Energy, Inc. | Sour shift process for the removal of carbon monoxide from a gas stream |
US20090324459A1 (en) * | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Three-Train Catalytic Gasification Systems |
US20090324458A1 (en) * | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Two-Train Catalytic Gasification Systems |
US20090324462A1 (en) * | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Four-Train Catalytic Gasification Systems |
US8450536B2 (en) | 2008-07-17 | 2013-05-28 | Pioneer Energy, Inc. | Methods of higher alcohol synthesis |
US20100120926A1 (en) * | 2008-09-19 | 2010-05-13 | Greatpoint Energy, Inc. | Processes for Gasification of a Carbonaceous Feedstock |
CN103865585A (en) * | 2008-09-19 | 2014-06-18 | 格雷特波因特能源公司 | Gasification device of a Carbonaceous Feedstock |
CN102159687B (en) * | 2008-09-19 | 2016-06-08 | 格雷特波因特能源公司 | Use the gasification process of charcoal methanation catalyst |
US8647402B2 (en) | 2008-09-19 | 2014-02-11 | Greatpoint Energy, Inc. | Processes for gasification of a carbonaceous feedstock |
CN102197117B (en) * | 2008-10-23 | 2014-12-24 | 格雷特波因特能源公司 | Processes for gasification of a carbonaceous feedstock |
CN102272268B (en) | 2008-12-30 | 2014-07-23 | 格雷特波因特能源公司 | Processes for preparing a catalyzed coal particulate |
CN102272267A (en) | 2008-12-30 | 2011-12-07 | 格雷特波因特能源公司 | Processes for preparing a catalyzed carbonaceous particulate |
US8728182B2 (en) * | 2009-05-13 | 2014-05-20 | Greatpoint Energy, Inc. | Processes for hydromethanation of a carbonaceous feedstock |
US8268899B2 (en) | 2009-05-13 | 2012-09-18 | Greatpoint Energy, Inc. | Processes for hydromethanation of a carbonaceous feedstock |
KR101468768B1 (en) * | 2009-05-13 | 2014-12-04 | 그레이트포인트 에너지, 인크. | Processes for hydromethanation of a carbonaceous feedstock |
CN102549121B (en) * | 2009-09-16 | 2015-03-25 | 格雷特波因特能源公司 | Integrated hydromethanation combined cycle process |
CN102575181B (en) * | 2009-09-16 | 2016-02-10 | 格雷特波因特能源公司 | Integrated hydromethanation combined cycle process |
WO2011034888A1 (en) * | 2009-09-16 | 2011-03-24 | Greatpoint Energy, Inc. | Processes for hydromethanation of a carbonaceous feedstock |
US7937948B2 (en) * | 2009-09-23 | 2011-05-10 | Pioneer Energy, Inc. | Systems and methods for generating electricity from carbonaceous material with substantially no carbon dioxide emissions |
US8479833B2 (en) | 2009-10-19 | 2013-07-09 | Greatpoint Energy, Inc. | Integrated enhanced oil recovery process |
US8479834B2 (en) * | 2009-10-19 | 2013-07-09 | Greatpoint Energy, Inc. | Integrated enhanced oil recovery process |
US8733459B2 (en) | 2009-12-17 | 2014-05-27 | Greatpoint Energy, Inc. | Integrated enhanced oil recovery process |
CN102754266B (en) | 2010-02-23 | 2015-09-02 | 格雷特波因特能源公司 | integrated hydrogenation methanation fuel cell power generation |
US8652696B2 (en) | 2010-03-08 | 2014-02-18 | Greatpoint Energy, Inc. | Integrated hydromethanation fuel cell power generation |
WO2011139694A1 (en) | 2010-04-26 | 2011-11-10 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock with vanadium recovery |
KR101506381B1 (en) | 2010-05-28 | 2015-03-26 | 그레이트포인트 에너지, 인크. | Conversion of liquid heavy hydrocarbon feedstocks to gaseous products |
KR101424941B1 (en) | 2010-08-18 | 2014-08-01 | 그레이트포인트 에너지, 인크. | Hydromethanation of carbonaceous feedstock |
KR20130080471A (en) | 2010-09-10 | 2013-07-12 | 그레이트포인트 에너지, 인크. | Hydromethanation of a carbonaceous feedstock |
CN103249815B (en) | 2010-11-01 | 2016-08-24 | 格雷特波因特能源公司 | The hydrogenation methanation of carbon containing feed |
JP6124795B2 (en) | 2010-11-01 | 2017-05-10 | グレイトポイント・エナジー・インコーポレイテッド | Hydrogenation methanation of carbonaceous feedstock. |
WO2012116003A1 (en) | 2011-02-23 | 2012-08-30 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock with nickel recovery |
CN103717289A (en) | 2011-04-11 | 2014-04-09 | Ada-Es股份有限公司 | Fluidized bed method and system for gas component capture |
WO2012145497A1 (en) | 2011-04-22 | 2012-10-26 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock with char beneficiation |
WO2012166879A1 (en) | 2011-06-03 | 2012-12-06 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock |
US9404345B2 (en) * | 2011-07-01 | 2016-08-02 | Exxonmobil Upstream Research Company | Subsea sour gas and/or acid gas injection systems and methods |
WO2013025808A1 (en) | 2011-08-17 | 2013-02-21 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock |
WO2013025812A1 (en) | 2011-08-17 | 2013-02-21 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock |
US9012524B2 (en) | 2011-10-06 | 2015-04-21 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock |
WO2013053017A1 (en) * | 2011-10-13 | 2013-04-18 | Linc Energy Ltd | System and method for integrated enhanced oil recovery |
CN104812467B (en) | 2012-09-20 | 2017-05-17 | Ada-Es股份有限公司 | Method and system to reclaim functional sites on sorbent contaminated by heat stable salts |
WO2014055365A1 (en) | 2012-10-01 | 2014-04-10 | Greatpoint Energy, Inc. | Use of contaminated low-rank coal for combustion |
KR101646890B1 (en) | 2012-10-01 | 2016-08-12 | 그레이트포인트 에너지, 인크. | Agglomerated particulate low-rank coal feedstock and uses thereof |
US9034058B2 (en) | 2012-10-01 | 2015-05-19 | Greatpoint Energy, Inc. | Agglomerated particulate low-rank coal feedstock and uses thereof |
KR101576781B1 (en) | 2012-10-01 | 2015-12-10 | 그레이트포인트 에너지, 인크. | Agglomerated particulate low-rank coal feedstock and uses thereof |
US11268038B2 (en) | 2014-09-05 | 2022-03-08 | Raven Sr, Inc. | Process for duplex rotary reformer |
US10131551B2 (en) | 2015-06-23 | 2018-11-20 | Conocophillips Company | Separation of kinetic hydrate inhibitors from an aqueous solution |
US10323495B2 (en) * | 2016-03-30 | 2019-06-18 | Exxonmobil Upstream Research Company | Self-sourced reservoir fluid for enhanced oil recovery |
WO2019013855A1 (en) | 2017-07-10 | 2019-01-17 | Exxonmobil Upstream Research Company | Methods for deep reservoir stimulation using acid-forming fluids |
MX2020003635A (en) * | 2017-10-06 | 2020-09-17 | Oxy Usa Inc | System and method for oil production separation. |
US10464872B1 (en) | 2018-07-31 | 2019-11-05 | Greatpoint Energy, Inc. | Catalytic gasification to produce methanol |
US10344231B1 (en) | 2018-10-26 | 2019-07-09 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock with improved carbon utilization |
US10435637B1 (en) | 2018-12-18 | 2019-10-08 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock with improved carbon utilization and power generation |
CN109538178A (en) * | 2019-01-15 | 2019-03-29 | 西南石油大学 | Spontaneous CO in a kind of layer2Inflating medium system preferred embodiment |
US10618818B1 (en) | 2019-03-22 | 2020-04-14 | Sure Champion Investment Limited | Catalytic gasification to produce ammonia and urea |
US11300284B2 (en) | 2019-05-07 | 2022-04-12 | Kore Infrastructure | Production of renewable fuel for steam generation for heavy oil extraction |
Family Cites Families (372)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
GB593910A (en) | 1945-01-15 | 1947-10-29 | Standard Oil Dev Co | Improved process for the catalytic synthesis of hydrocarbons from carbon monoxide and hydrogen |
FR797089A (en) | 1935-10-30 | 1936-04-20 | Manufacturing process of special solid fuels for gasifiers producing gases for vehicle engines | |
GB676615A (en) | 1946-08-10 | 1952-07-30 | Standard Oil Dev Co | Improvements in or relating to processes involving the contacting of finely divided solids and gases |
GB640907A (en) | 1946-09-10 | 1950-08-02 | Standard Oil Dev Co | An improved method of producing normally gaseous fuels from carbon-containing materials |
US2694623A (en) | 1949-05-14 | 1954-11-16 | Standard Oil Dev Co | Process for enrichment of water gas |
GB701131A (en) | 1951-03-22 | 1953-12-16 | Standard Oil Dev Co | Improvements in or relating to gas adsorbent by activation of acid sludge coke |
GB798741A (en) | 1953-03-09 | 1958-07-23 | Gas Council | Process for the production of combustible gas enriched with methane |
BE529007A (en) | 1953-05-21 | |||
US2813126A (en) | 1953-12-21 | 1957-11-12 | Pure Oil Co | Process for selective removal of h2s by absorption in methanol |
US2791549A (en) | 1953-12-30 | 1957-05-07 | Exxon Research Engineering Co | Fluid coking process with quenching of hydrocarbon vapors |
US2860959A (en) | 1954-06-14 | 1958-11-18 | Inst Gas Technology | Pressure hydrogasification of natural gas liquids and petroleum distillates |
US2886405A (en) | 1956-02-24 | 1959-05-12 | Benson Homer Edwin | Method for separating co2 and h2s from gas mixtures |
GB820257A (en) | 1958-03-06 | 1959-09-16 | Gas Council | Process for the production of gases containing methane from hydrocarbons |
US3034848A (en) | 1959-04-14 | 1962-05-15 | Du Pont | Compaction of dyes |
DE1403859A1 (en) | 1960-09-06 | 1968-10-31 | Neidl Dipl Ing Georg | Circulation pump |
US3114930A (en) | 1961-03-17 | 1963-12-24 | American Cyanamid Co | Apparatus for densifying and granulating powdered materials |
GB996327A (en) | 1962-04-18 | 1965-06-23 | Metallgesellschaft Ag | A method of raising the calorific value of gasification gases |
US3351563A (en) | 1963-06-05 | 1967-11-07 | Chemical Construction Corp | Production of hydrogen-rich synthesis gas |
GB1033764A (en) | 1963-09-23 | 1966-06-22 | Gas Council | Improvements in or relating to the production of methane gases |
DE1494806C3 (en) | 1966-10-14 | 1975-07-10 | Metallgesellschaft Ag, 6000 Frankfurt | Process for hydrogen sulfide and carbon dioxide scrubbing of fuel and synthesis gases and regeneration of the loaded detergent |
US3435590A (en) | 1967-09-01 | 1969-04-01 | Chevron Res | Co2 and h2s removal |
US3544291A (en) | 1968-04-22 | 1970-12-01 | Texaco Inc | Coal gasification process |
US3615300A (en) | 1969-06-04 | 1971-10-26 | Chevron Res | Hydrogen production by reaction of carbon with steam and oxygen |
US3594985A (en) | 1969-06-11 | 1971-07-27 | Allied Chem | Acid gas removal from gas mixtures |
US3814725A (en) | 1969-08-29 | 1974-06-04 | Celanese Corp | Polyalkylene terephthalate molding resin |
US3759036A (en) | 1970-03-01 | 1973-09-18 | Chevron Res | Power generation |
CH530262A (en) | 1971-10-22 | 1972-11-15 | Hutt Gmbh | Process and device for the utilization of sawdust and grinding dust particles produced in the manufacture of chipboard |
US3689240A (en) | 1971-03-18 | 1972-09-05 | Exxon Research Engineering Co | Production of methane rich gases |
US3740193A (en) | 1971-03-18 | 1973-06-19 | Exxon Research Engineering Co | Hydrogen production by catalytic steam gasification of carbonaceous materials |
US3915670A (en) | 1971-09-09 | 1975-10-28 | British Gas Corp | Production of gases |
US3746522A (en) | 1971-09-22 | 1973-07-17 | Interior | Gasification of carbonaceous solids |
US3969089A (en) | 1971-11-12 | 1976-07-13 | Exxon Research And Engineering Company | Manufacture of combustible gases |
US3779725A (en) | 1971-12-06 | 1973-12-18 | Air Prod & Chem | Coal gassification |
US3985519A (en) | 1972-03-28 | 1976-10-12 | Exxon Research And Engineering Company | Hydrogasification process |
US3817725A (en) | 1972-05-11 | 1974-06-18 | Chevron Res | Gasification of solid waste material to obtain high btu product gas |
DE2229213C2 (en) | 1972-06-15 | 1982-12-02 | Metallgesellschaft Ag, 6000 Frankfurt | Process for the processing of waste water resulting from the degassing or gasification of coal |
CA1003217A (en) | 1972-09-08 | 1977-01-11 | Robert E. Pennington | Catalytic gasification process |
US4094650A (en) | 1972-09-08 | 1978-06-13 | Exxon Research & Engineering Co. | Integrated catalytic gasification process |
US3929431A (en) | 1972-09-08 | 1975-12-30 | Exxon Research Engineering Co | Catalytic reforming process |
US3920229A (en) | 1972-10-10 | 1975-11-18 | Pcl Ind Limited | Apparatus for feeding polymeric material in flake form to an extruder |
US3870481A (en) | 1972-10-12 | 1975-03-11 | William P Hegarty | Method for production of synthetic natural gas from crude oil |
DE2250169A1 (en) | 1972-10-13 | 1974-04-25 | Metallgesellschaft Ag | PROCESS FOR DESULFURIZATION OF TECHNICAL FUEL GASES AND SYNTHESIS GASES |
JPS5323777B2 (en) | 1972-12-04 | 1978-07-17 | ||
GB1448562A (en) | 1972-12-18 | 1976-09-08 | British Gas Corp | Process for the production of methane containing gases |
US3828474A (en) | 1973-02-01 | 1974-08-13 | Pullman Inc | Process for producing high strength reducing gas |
US4021370A (en) | 1973-07-24 | 1977-05-03 | Davy Powergas Limited | Fuel gas production |
CA1041553A (en) | 1973-07-30 | 1978-10-31 | John P. Longwell | Methanol and synthetic natural gas concurrent production |
US3847567A (en) | 1973-08-27 | 1974-11-12 | Exxon Research Engineering Co | Catalytic coal hydrogasification process |
US3904386A (en) | 1973-10-26 | 1975-09-09 | Us Interior | Combined shift and methanation reaction process for the gasification of carbonaceous materials |
US4053554A (en) | 1974-05-08 | 1977-10-11 | Catalox Corporation | Removal of contaminants from gaseous streams |
DE2427530C2 (en) | 1974-06-07 | 1984-04-05 | Metallgesellschaft Ag, 6000 Frankfurt | Methanation reactor |
US3958957A (en) | 1974-07-01 | 1976-05-25 | Exxon Research And Engineering Company | Methane production |
US3904389A (en) | 1974-08-13 | 1975-09-09 | David L Banquy | Process for the production of high BTU methane-containing gas |
US4104201A (en) | 1974-09-06 | 1978-08-01 | British Gas Corporation | Catalytic steam reforming and catalysts therefor |
US4046523A (en) | 1974-10-07 | 1977-09-06 | Exxon Research And Engineering Company | Synthesis gas production |
US3971639A (en) | 1974-12-23 | 1976-07-27 | Gulf Oil Corporation | Fluid bed coal gasification |
DE2501376A1 (en) | 1975-01-15 | 1976-07-22 | Metallgesellschaft Ag | METHOD FOR REMOVING MONOPHENOLS, DIPHENOLS AND THE LIKE FROM WASTEWATERS |
DE2503507C2 (en) | 1975-01-29 | 1981-11-19 | Metallgesellschaft Ag, 6000 Frankfurt | Process for the purification of gases produced by gasifying solid fossil fuels using water vapor and oxygen under pressure |
US3989811A (en) | 1975-01-30 | 1976-11-02 | Shell Oil Company | Process for recovering sulfur from fuel gases containing hydrogen sulfide, carbon dioxide, and carbonyl sulfide |
GB1508712A (en) | 1975-03-31 | 1978-04-26 | Battelle Memorial Institute | Treating solid fuel |
US3975168A (en) | 1975-04-02 | 1976-08-17 | Exxon Research And Engineering Company | Process for gasifying carbonaceous solids and removing toxic constituents from aqueous effluents |
US3998607A (en) | 1975-05-12 | 1976-12-21 | Exxon Research And Engineering Company | Alkali metal catalyst recovery process |
US4017272A (en) | 1975-06-05 | 1977-04-12 | Bamag Verfahrenstechnik Gmbh | Process for gasifying solid carbonaceous fuel |
US4162902A (en) | 1975-06-24 | 1979-07-31 | Metallgesellschaft Aktiengesellschaft | Removing phenols from waste water |
US4091073A (en) | 1975-08-29 | 1978-05-23 | Shell Oil Company | Process for the removal of H2 S and CO2 from gaseous streams |
US4005996A (en) | 1975-09-04 | 1977-02-01 | El Paso Natural Gas Company | Methanation process for the production of an alternate fuel for natural gas |
US4077778A (en) | 1975-09-29 | 1978-03-07 | Exxon Research & Engineering Co. | Process for the catalytic gasification of coal |
US4052176A (en) * | 1975-09-29 | 1977-10-04 | Texaco Inc. | Production of purified synthesis gas H2 -rich gas, and by-product CO2 -rich gas |
US4057512A (en) | 1975-09-29 | 1977-11-08 | Exxon Research & Engineering Co. | Alkali metal catalyst recovery system |
US4322222A (en) | 1975-11-10 | 1982-03-30 | Occidental Petroleum Corporation | Process for the gasification of carbonaceous materials |
DE2551717C3 (en) | 1975-11-18 | 1980-11-13 | Basf Ag, 6700 Ludwigshafen | and possibly COS from gases |
US4113615A (en) | 1975-12-03 | 1978-09-12 | Exxon Research & Engineering Co. | Method for obtaining substantially complete removal of phenols from waste water |
US4069304A (en) | 1975-12-31 | 1978-01-17 | Trw | Hydrogen production by catalytic coal gasification |
US3999607A (en) | 1976-01-22 | 1976-12-28 | Exxon Research And Engineering Company | Recovery of hydrocarbons from coal |
US4330305A (en) | 1976-03-19 | 1982-05-18 | Basf Aktiengesellschaft | Removal of CO2 and/or H2 S from gases |
US4044098A (en) | 1976-05-18 | 1977-08-23 | Phillips Petroleum Company | Removal of mercury from gas streams using hydrogen sulfide and amines |
JPS5311893A (en) | 1976-07-20 | 1978-02-02 | Fujimi Kenmazai Kougiyou Kk | Catalysts |
US4270937A (en) | 1976-12-01 | 1981-06-02 | Cng Research Company | Gas separation process |
US4159195A (en) | 1977-01-24 | 1979-06-26 | Exxon Research & Engineering Co. | Hydrothermal alkali metal recovery process |
US4211538A (en) | 1977-02-25 | 1980-07-08 | Exxon Research & Engineering Co. | Process for the production of an intermediate Btu gas |
US4118204A (en) | 1977-02-25 | 1978-10-03 | Exxon Research & Engineering Co. | Process for the production of an intermediate Btu gas |
JPS53106623A (en) | 1977-03-01 | 1978-09-16 | Univ Tohoku | Method of recovering nickel from coal ash residue containing nickel |
US4100256A (en) | 1977-03-18 | 1978-07-11 | The Dow Chemical Company | Hydrolysis of carbon oxysulfide |
IT1075397B (en) | 1977-04-15 | 1985-04-22 | Snam Progetti | METHANATION REACTOR |
US4116996A (en) | 1977-06-06 | 1978-09-26 | Ethyl Corporation | Catalyst for methane production |
GB1599932A (en) | 1977-07-01 | 1981-10-07 | Exxon Research Engineering Co | Distributing coal-liquefaction or-gasifaction catalysts in coal |
US4152119A (en) | 1977-08-01 | 1979-05-01 | Dynecology Incorporated | Briquette comprising caking coal and municipal solid waste |
US4617027A (en) | 1977-12-19 | 1986-10-14 | Exxon Research And Engineering Co. | Gasification process |
US4200439A (en) | 1977-12-19 | 1980-04-29 | Exxon Research & Engineering Co. | Gasification process using ion-exchanged coal |
US4204843A (en) | 1977-12-19 | 1980-05-27 | Exxon Research & Engineering Co. | Gasification process |
US4157246A (en) | 1978-01-27 | 1979-06-05 | Exxon Research & Engineering Co. | Hydrothermal alkali metal catalyst recovery process |
US4265868A (en) | 1978-02-08 | 1981-05-05 | Koppers Company, Inc. | Production of carbon monoxide by the gasification of carbonaceous materials |
US4193771A (en) | 1978-05-08 | 1980-03-18 | Exxon Research & Engineering Co. | Alkali metal recovery from carbonaceous material conversion process |
US4219338A (en) | 1978-05-17 | 1980-08-26 | Exxon Research & Engineering Co. | Hydrothermal alkali metal recovery process |
US4193772A (en) | 1978-06-05 | 1980-03-18 | Exxon Research & Engineering Co. | Process for carbonaceous material conversion and recovery of alkali metal catalyst constituents held by ion exchange sites in conversion residue |
US4189307A (en) | 1978-06-26 | 1980-02-19 | Texaco Development Corporation | Production of clean HCN-free synthesis gas |
US4318712A (en) | 1978-07-17 | 1982-03-09 | Exxon Research & Engineering Co. | Catalytic coal gasification process |
US4372755A (en) | 1978-07-27 | 1983-02-08 | Enrecon, Inc. | Production of a fuel gas with a stabilized metal carbide catalyst |
GB2027444B (en) | 1978-07-28 | 1983-03-02 | Exxon Research Engineering Co | Gasification of ash-containing solid fuels |
US4173465A (en) | 1978-08-15 | 1979-11-06 | Midrex Corporation | Method for the direct reduction of iron using gas from coal |
US4211669A (en) | 1978-11-09 | 1980-07-08 | Exxon Research & Engineering Co. | Process for the production of a chemical synthesis gas from coal |
DE2852710A1 (en) | 1978-12-06 | 1980-06-12 | Didier Eng | Steam gasification of coal or coke - with injection of gaseous ammonia or aq. metal oxide as catalyst |
US4235044A (en) | 1978-12-21 | 1980-11-25 | Union Carbide Corporation | Split stream methanation process |
US4249471A (en) | 1979-01-29 | 1981-02-10 | Gunnerman Rudolf W | Method and apparatus for burning pelletized organic fibrous fuel |
US4225457A (en) | 1979-02-26 | 1980-09-30 | Dynecology Incorporated | Briquette comprising caking coal and municipal solid waste |
US4609388A (en) | 1979-04-18 | 1986-09-02 | Cng Research Company | Gas separation process |
US4243639A (en) | 1979-05-10 | 1981-01-06 | Tosco Corporation | Method for recovering vanadium from petroleum coke |
US4260421A (en) | 1979-05-18 | 1981-04-07 | Exxon Research & Engineering Co. | Cement production from coal conversion residues |
US4334893A (en) | 1979-06-25 | 1982-06-15 | Exxon Research & Engineering Co. | Recovery of alkali metal catalyst constituents with sulfurous acid |
AR228573A1 (en) | 1979-09-04 | 1983-03-30 | Tosco Corp | METHOD TO PRODUCE A SYNTHESIS GAS FROM VAPOR GASIFICATION OF OIL COKE |
US4315758A (en) | 1979-10-15 | 1982-02-16 | Institute Of Gas Technology | Process for the production of fuel gas from coal |
US4462814A (en) | 1979-11-14 | 1984-07-31 | Koch Process Systems, Inc. | Distillative separations of gas mixtures containing methane, carbon dioxide and other components |
US4284416A (en) | 1979-12-14 | 1981-08-18 | Exxon Research & Engineering Co. | Integrated coal drying and steam gasification process |
US4292048A (en) | 1979-12-21 | 1981-09-29 | Exxon Research & Engineering Co. | Integrated catalytic coal devolatilization and steam gasification process |
US4331451A (en) | 1980-02-04 | 1982-05-25 | Mitsui Toatsu Chemicals, Inc. | Catalytic gasification |
US4336034A (en) | 1980-03-10 | 1982-06-22 | Exxon Research & Engineering Co. | Process for the catalytic gasification of coal |
GB2072216A (en) | 1980-03-18 | 1981-09-30 | British Gas Corp | Treatment of hydrocarbon feedstocks |
DK148915C (en) | 1980-03-21 | 1986-06-02 | Haldor Topsoe As | METHOD FOR PREPARING HYDROGEN OR AMMONIA SYNTHESIC GAS |
US4298584A (en) | 1980-06-05 | 1981-11-03 | Eic Corporation | Removing carbon oxysulfide from gas streams |
GB2078251B (en) | 1980-06-19 | 1984-02-15 | Gen Electric | System for gasifying coal and reforming gaseous products thereof |
US4353713A (en) | 1980-07-28 | 1982-10-12 | Cheng Shang I | Integrated gasification process |
US4315753A (en) | 1980-08-14 | 1982-02-16 | The United States Of America As Represented By The Secretary Of The Interior | Electrochemical apparatus for simultaneously monitoring two gases |
US4540681A (en) | 1980-08-18 | 1985-09-10 | United Catalysts, Inc. | Catalyst for the methanation of carbon monoxide in sour gas |
US4347063A (en) | 1981-03-27 | 1982-08-31 | Exxon Research & Engineering Co. | Process for catalytically gasifying carbon |
US4344486A (en) | 1981-02-27 | 1982-08-17 | Standard Oil Company (Indiana) | Method for enhanced oil recovery |
NL8101447A (en) | 1981-03-24 | 1982-10-18 | Shell Int Research | METHOD FOR PREPARING HYDROCARBONS FROM CARBON-CONTAINING MATERIAL |
DE3264214D1 (en) | 1981-03-24 | 1985-07-25 | Exxon Research Engineering Co | Apparatus for converting a fuel into combustible gas |
DE3113993A1 (en) | 1981-04-07 | 1982-11-11 | Metallgesellschaft Ag, 6000 Frankfurt | METHOD FOR THE SIMULTANEOUS PRODUCTION OF COMBUSTION GAS AND PROCESS HEAT FROM CARBON-MATERIAL MATERIALS |
DE3268510D1 (en) | 1981-06-05 | 1986-02-27 | Exxon Research Engineering Co | An integrated catalytic coal devolatilisation and steam gasification process |
JPS6053730B2 (en) | 1981-06-26 | 1985-11-27 | 康勝 玉井 | Nickel refining method |
US4428535A (en) | 1981-07-06 | 1984-01-31 | Liquid Carbonic Corporation | Apparatus to cool particulate matter for grinding |
US4365975A (en) | 1981-07-06 | 1982-12-28 | Exxon Research & Engineering Co. | Use of electromagnetic radiation to recover alkali metal constituents from coal conversion residues |
US4500323A (en) | 1981-08-26 | 1985-02-19 | Kraftwerk Union Aktiengesellschaft | Process for the gasification of raw carboniferous materials |
US4348486A (en) | 1981-08-27 | 1982-09-07 | Exxon Research And Engineering Co. | Production of methanol via catalytic coal gasification |
US4432773A (en) | 1981-09-14 | 1984-02-21 | Euker Jr Charles A | Fluidized bed catalytic coal gasification process |
US4439210A (en) | 1981-09-25 | 1984-03-27 | Conoco Inc. | Method of catalytic gasification with increased ash fusion temperature |
US4348487A (en) | 1981-11-02 | 1982-09-07 | Exxon Research And Engineering Co. | Production of methanol via catalytic coal gasification |
US4397656A (en) | 1982-02-01 | 1983-08-09 | Mobil Oil Corporation | Process for the combined coking and gasification of coal |
DE3209856A1 (en) | 1982-03-18 | 1983-09-29 | Rheinische Braunkohlenwerke AG, 5000 Köln | METHOD FOR THE OXIDATION OF HYDROGEN SULFUR SOLVED IN THE WASTE WATER FROM CARBON GASIFICATION PLANTS |
DE3377360D1 (en) | 1982-03-29 | 1988-08-18 | Asahi Chemical Ind | Process for thermal cracking of carbonaceous substances which increases gasoline fraction and light oil conversions |
US4468231A (en) | 1982-05-03 | 1984-08-28 | Exxon Research And Engineering Co. | Cation ion exchange of coal |
DE3217366A1 (en) | 1982-05-08 | 1983-11-10 | Metallgesellschaft Ag, 6000 Frankfurt | METHOD FOR PRODUCING A MOST INERT-FREE GAS FOR SYNTHESIS |
US4436028A (en) | 1982-05-10 | 1984-03-13 | Wilder David M | Roll mill for reduction of moisture content in waste material |
US4407206A (en) | 1982-05-10 | 1983-10-04 | Exxon Research And Engineering Co. | Partial combustion process for coal |
US5630854A (en) | 1982-05-20 | 1997-05-20 | Battelle Memorial Institute | Method for catalytic destruction of organic materials |
DE3222653C1 (en) | 1982-06-16 | 1983-04-21 | Kraftwerk Union AG, 4330 Mülheim | Process for converting carbonaceous fuel into a combustible product gas |
DE3229396C2 (en) | 1982-08-06 | 1985-10-31 | Bergwerksverband Gmbh, 4300 Essen | Process for the production of carbonaceous adsorbents impregnated with elemental sulfur |
US4436531A (en) | 1982-08-27 | 1984-03-13 | Texaco Development Corporation | Synthesis gas from slurries of solid carbonaceous fuels |
US4597776A (en) | 1982-10-01 | 1986-07-01 | Rockwell International Corporation | Hydropyrolysis process |
US4478425A (en) | 1982-10-21 | 1984-10-23 | Benko John M | Fifth wheel plate |
US4606105A (en) | 1982-11-09 | 1986-08-19 | Snavely Harry C | Method of banjo construction |
US4459138A (en) | 1982-12-06 | 1984-07-10 | The United States Of America As Represented By The United States Department Of Energy | Recovery of alkali metal constituents from catalytic coal conversion residues |
US4524050A (en) | 1983-01-07 | 1985-06-18 | Air Products And Chemicals, Inc. | Catalytic hydrolysis of carbonyl sulfide |
US4482529A (en) | 1983-01-07 | 1984-11-13 | Air Products And Chemicals, Inc. | Catalytic hydrolysis of COS in acid gas removal solvents |
US4620421A (en) | 1983-05-26 | 1986-11-04 | Texaco Inc. | Temperature stabilization system |
US4551155A (en) | 1983-07-07 | 1985-11-05 | Sri International | In situ formation of coal gasification catalysts from low cost alkali metal salts |
US4699632A (en) | 1983-08-02 | 1987-10-13 | Institute Of Gas Technology | Process for gasification of cellulosic materials |
EP0134344A1 (en) | 1983-08-24 | 1985-03-20 | Exxon Research And Engineering Company | The fluidized bed gasification of extracted coal |
GB2147913A (en) | 1983-10-14 | 1985-05-22 | British Gas Corp | Thermal hydrogenation of hydrocarbon liquids |
US4508693A (en) | 1983-11-29 | 1985-04-02 | Shell Oil Co. | Solution removal of HCN from gaseous streams, with pH adjustment of reacted solution and hydrolysis of thiocyanate formed |
US4505881A (en) | 1983-11-29 | 1985-03-19 | Shell Oil Company | Ammonium polysulfide removal of HCN from gaseous streams, with subsequent production of NH3, H2 S, and CO2 |
US4497784A (en) | 1983-11-29 | 1985-02-05 | Shell Oil Company | Solution removal of HCN from gaseous streams, with hydrolysis of thiocyanate formed |
US4515764A (en) | 1983-12-20 | 1985-05-07 | Shell Oil Company | Removal of H2 S from gaseous streams |
FR2559497B1 (en) | 1984-02-10 | 1988-05-20 | Inst Francais Du Petrole | PROCESS FOR CONVERTING HEAVY OIL RESIDUES INTO HYDROGEN AND GASEOUS AND DISTILLABLE HYDROCARBONS |
GB2154600A (en) | 1984-02-23 | 1985-09-11 | British Gas Corp | Producing and purifying methane |
US4619864A (en) | 1984-03-21 | 1986-10-28 | Springs Industries, Inc. | Fabric with reduced permeability to down and fiber fill and method of producing same |
US4594140A (en) | 1984-04-04 | 1986-06-10 | Cheng Shang I | Integrated coal liquefaction, gasification and electricity production process |
US4597775A (en) | 1984-04-20 | 1986-07-01 | Exxon Research And Engineering Co. | Coking and gasification process |
US4558027A (en) | 1984-05-25 | 1985-12-10 | The United States Of America As Represented By The United States Department Of Energy | Catalysts for carbon and coal gasification |
US4704136A (en) | 1984-06-04 | 1987-11-03 | Freeport-Mcmoran Resource Partners, Limited Partnership | Sulfate reduction process useful in coal gasification |
DE3422202A1 (en) | 1984-06-15 | 1985-12-19 | Hüttinger, Klaus J., Prof. Dr.-Ing., 7500 Karlsruhe | Process for catalytic gasification |
DE3439487A1 (en) | 1984-10-27 | 1986-06-26 | M.A.N. Maschinenfabrik Augsburg-Nürnberg AG, 4200 Oberhausen | ENERGY-LOW METHOD FOR THE PRODUCTION OF SYNTHESIS GAS WITH A HIGH METHANE CONTENT |
US4808194A (en) | 1984-11-26 | 1989-02-28 | Texaco Inc. | Stable aqueous suspensions of slag, fly-ash and char |
US4682986A (en) | 1984-11-29 | 1987-07-28 | Exxon Research And Engineering | Process for separating catalytic coal gasification chars |
US4572826A (en) | 1984-12-24 | 1986-02-25 | Shell Oil Company | Two stage process for HCN removal from gaseous streams |
US4854944A (en) | 1985-05-06 | 1989-08-08 | Strong William H | Method for gasifying toxic and hazardous waste oil |
US4690814A (en) | 1985-06-17 | 1987-09-01 | The Standard Oil Company | Process for the production of hydrogen |
US4668428A (en) | 1985-06-27 | 1987-05-26 | Texaco Inc. | Partial oxidation process |
US4668429A (en) | 1985-06-27 | 1987-05-26 | Texaco Inc. | Partial oxidation process |
US4720289A (en) | 1985-07-05 | 1988-01-19 | Exxon Research And Engineering Company | Process for gasifying solid carbonaceous materials |
IN168599B (en) | 1985-11-29 | 1991-05-04 | Dow Chemical Co | |
US4872886A (en) | 1985-11-29 | 1989-10-10 | The Dow Chemical Company | Two-stage coal gasification process |
US4675035A (en) | 1986-02-24 | 1987-06-23 | Apffel Fred P | Carbon dioxide absorption methanol process |
US4747938A (en) | 1986-04-17 | 1988-05-31 | The United States Of America As Represented By The United States Department Of Energy | Low temperature pyrolysis of coal or oil shale in the presence of calcium compounds |
US5223173A (en) | 1986-05-01 | 1993-06-29 | The Dow Chemical Company | Method and composition for the removal of hydrogen sulfide from gaseous streams |
CA1300885C (en) | 1986-08-26 | 1992-05-19 | Donald S. Scott | Hydrogasification of biomass to produce high yields of methane |
IT1197477B (en) | 1986-09-10 | 1988-11-30 | Eniricerche Spa | PROCESS TO OBTAIN A HIGH METHANE CONTENT GASEOUS MIXTURE FROM COAL |
JPS6395292A (en) | 1986-10-09 | 1988-04-26 | Univ Tohoku | Catalytic gasification of coal using chloride |
US4876080A (en) | 1986-12-12 | 1989-10-24 | The United States Of Americal As Represented By The United States Department Of Energy | Hydrogen production with coal using a pulverization device |
US4803061A (en) | 1986-12-29 | 1989-02-07 | Texaco Inc. | Partial oxidation process with magnetic separation of the ground slag |
US5132007A (en) | 1987-06-08 | 1992-07-21 | Carbon Fuels Corporation | Co-generation system for co-producing clean, coal-based fuels and electricity |
US4810475A (en) | 1987-08-18 | 1989-03-07 | Shell Oil Company | Removal of HCN, and HCN and COS, from a substantially chloride-free gaseous stream |
US5055181A (en) | 1987-09-30 | 1991-10-08 | Exxon Research And Engineering Company | Hydropyrolysis-gasification of carbonaceous material |
IT1222811B (en) | 1987-10-02 | 1990-09-12 | Eniricerche Spa | PROCEDURE FOR THE LIQUEFACTION OF THE COAL IN A SINGLE STAGE |
US4781731A (en) | 1987-12-31 | 1988-11-01 | Texaco Inc. | Integrated method of charge fuel pretreatment and tail gas sulfur removal in a partial oxidation process |
US4861346A (en) | 1988-01-07 | 1989-08-29 | Texaco Inc. | Stable aqueous suspension of partial oxidation ash, slag and char containing polyethoxylated quaternary ammonium salt surfactant |
US4892567A (en) | 1988-08-15 | 1990-01-09 | Mobil Oil Corporation | Simultaneous removal of mercury and water from fluids |
US5093094A (en) | 1989-05-05 | 1992-03-03 | Shell Oil Company | Solution removal of H2 S from gas streams |
US4960450A (en) | 1989-09-19 | 1990-10-02 | Syracuse University | Selection and preparation of activated carbon for fuel gas storage |
JPH075895B2 (en) | 1989-09-29 | 1995-01-25 | 宇部興産株式会社 | Method to prevent ash from adhering to gasification furnace wall |
US5057294A (en) | 1989-10-13 | 1991-10-15 | The University Of Tennessee Research Corporation | Recovery and regeneration of spent MHD seed material by the formate process |
US5059406A (en) | 1990-04-17 | 1991-10-22 | University Of Tennessee Research Corporation | Desulfurization process |
US5084362A (en) | 1990-08-29 | 1992-01-28 | Energy Research Corporation | Internal reforming molten carbonate fuel cell system with methane feed |
US5094737A (en) | 1990-10-01 | 1992-03-10 | Exxon Research & Engineering Company | Integrated coking-gasification process with mitigation of bogging and slagging |
DE4041569A1 (en) | 1990-12-22 | 1992-06-25 | Hoechst Ag | METHOD FOR PROCESSING SULFUR HYDROGEN, CYAN HYDROGEN AND AMMONIA CONTAINING AQUEOUS SOLUTIONS |
US5277884A (en) | 1992-03-02 | 1994-01-11 | Reuel Shinnar | Solvents for the selective removal of H2 S from gases containing both H2 S and CO2 |
US5250083A (en) | 1992-04-30 | 1993-10-05 | Texaco Inc. | Process for production desulfurized of synthesis gas |
NZ253874A (en) | 1992-06-05 | 1996-04-26 | Battelle Memorial Institute | Catalytic conversion of liquid organic materials into a product gas of methane, carbon dioxide and hydrogen |
US5865898A (en) | 1992-08-06 | 1999-02-02 | The Texas A&M University System | Methods of biomass pretreatment |
US5733515A (en) | 1993-01-21 | 1998-03-31 | Calgon Carbon Corporation | Purification of air in enclosed spaces |
US5720785A (en) | 1993-04-30 | 1998-02-24 | Shell Oil Company | Method of reducing hydrogen cyanide and ammonia in synthesis gas |
DE4319234A1 (en) | 1993-06-09 | 1994-12-15 | Linde Ag | Process for the removal of HCN from gas mixtures and catalyst for the decomposition of HCN |
US5435940A (en) | 1993-11-12 | 1995-07-25 | Shell Oil Company | Gasification process |
US5536893A (en) | 1994-01-07 | 1996-07-16 | Gudmundsson; Jon S. | Method for production of gas hydrates for transportation and storage |
US5964985A (en) | 1994-02-02 | 1999-10-12 | Wootten; William A. | Method and apparatus for converting coal to liquid hydrocarbons |
US5670122A (en) | 1994-09-23 | 1997-09-23 | Energy And Environmental Research Corporation | Methods for removing air pollutants from combustion flue gas |
US6506349B1 (en) | 1994-11-03 | 2003-01-14 | Tofik K. Khanmamedov | Process for removal of contaminants from a gas stream |
US5641327A (en) | 1994-12-02 | 1997-06-24 | Leas; Arnold M. | Catalytic gasification process and system for producing medium grade BTU gas |
US5855631A (en) | 1994-12-02 | 1999-01-05 | Leas; Arnold M. | Catalytic gasification process and system |
US5496859A (en) | 1995-01-28 | 1996-03-05 | Texaco Inc. | Gasification process combined with steam methane reforming to produce syngas suitable for methanol production |
IT1275410B (en) | 1995-06-01 | 1997-08-05 | Eniricerche Spa | PROCEDURE FOR THE COMPLETE CONVERSION OF HIGH MOLECULAR WEIGHT HYDROCARBON MATERIALS |
US5769165A (en) | 1996-01-31 | 1998-06-23 | Vastar Resources Inc. | Method for increasing methane recovery from a subterranean coal formation by injection of tail gas from a hydrocarbon synthesis process |
EP0958237B1 (en) | 1996-04-23 | 2002-06-26 | ExxonMobil Research and Engineering Company | Process for removal of hydrogen cyanide from synthesis gas |
US6132478A (en) | 1996-10-25 | 2000-10-17 | Jgc Corporation | Coal-water slurry producing process, system therefor, and slurry transfer mechanism |
US6028234A (en) | 1996-12-17 | 2000-02-22 | Mobil Oil Corporation | Process for making gas hydrates |
US6028534A (en) * | 1997-06-02 | 2000-02-22 | Schlumberger Technology Corporation | Formation data sensing with deployed remote sensors during well drilling |
US6090356A (en) | 1997-09-12 | 2000-07-18 | Texaco Inc. | Removal of acidic gases in a gasification power system with production of hydrogen |
US6180843B1 (en) | 1997-10-14 | 2001-01-30 | Mobil Oil Corporation | Method for producing gas hydrates utilizing a fluidized bed |
US6187465B1 (en) | 1997-11-07 | 2001-02-13 | Terry R. Galloway | Process and system for converting carbonaceous feedstocks into energy without greenhouse gas emissions |
US6168768B1 (en) | 1998-01-23 | 2001-01-02 | Exxon Research And Engineering Company | Production of low sulfer syngas from natural gas with C4+/C5+ hydrocarbon recovery |
US6015104A (en) | 1998-03-20 | 2000-01-18 | Rich, Jr.; John W. | Process and apparatus for preparing feedstock for a coal gasification plant |
JP2979149B1 (en) | 1998-11-11 | 1999-11-15 | 財団法人石炭利用総合センター | Method for producing hydrogen by thermochemical decomposition |
US6389820B1 (en) | 1999-02-12 | 2002-05-21 | Mississippi State University | Surfactant process for promoting gas hydrate formation and application of the same |
GB2347938B (en) | 1999-03-15 | 2001-07-11 | Mitsubishi Heavy Ind Ltd | Production method for hydrate and device for producing the same |
JP4054934B2 (en) | 1999-04-09 | 2008-03-05 | 大阪瓦斯株式会社 | Method for producing fuel gas |
JP4006560B2 (en) | 1999-04-09 | 2007-11-14 | 大阪瓦斯株式会社 | Method for producing fuel gas |
US6641625B1 (en) | 1999-05-03 | 2003-11-04 | Nuvera Fuel Cells, Inc. | Integrated hydrocarbon reforming system and controls |
AUPQ118899A0 (en) | 1999-06-24 | 1999-07-22 | Woodside Energy Limited | Natural gas hydrate and method for producing same |
EP1207132A4 (en) | 1999-07-09 | 2006-03-29 | Ebara Corp | Process and apparatus for production of hydrogen by gasification of combustible material and method for electric power generation using fuel cell and electric power generation system using fuel cell |
US6379645B1 (en) | 1999-10-14 | 2002-04-30 | Air Products And Chemicals, Inc. | Production of hydrogen using methanation and pressure swing adsorption |
US6790430B1 (en) | 1999-12-09 | 2004-09-14 | The Regents Of The University Of California | Hydrogen production from carbonaceous material |
FR2808223B1 (en) | 2000-04-27 | 2002-11-22 | Inst Francais Du Petrole | PROCESS FOR THE PURIFICATION OF AN EFFLUENT CONTAINING CARBON GAS AND HYDROCARBONS BY COMBUSTION |
US6506361B1 (en) | 2000-05-18 | 2003-01-14 | Air Products And Chemicals, Inc. | Gas-liquid reaction process including ejector and monolith catalyst |
KR100347092B1 (en) | 2000-06-08 | 2002-07-31 | 한국과학기술원 | Method for Separation of Gas Mixtures Using Hydrate Promoter |
JP2002105467A (en) | 2000-09-29 | 2002-04-10 | Osaka Gas Co Ltd | Manufacturing method of hydrogen-methane series fuel gas |
US7074373B1 (en) | 2000-11-13 | 2006-07-11 | Harvest Energy Technology, Inc. | Thermally-integrated low temperature water-gas shift reactor apparatus and process |
EP2302016A3 (en) | 2000-12-21 | 2012-02-29 | Rentech, Inc. | Biomass gasification system and method |
DE60227355D1 (en) | 2001-03-15 | 2008-08-14 | Alexei Leonidovich Zapadinski | METHOD FOR DEVELOPING A CARBON STORAGE STORAGE AND PLANT COMPLEX FOR IMPLEMENTING THE PROCESS |
US6894183B2 (en) | 2001-03-26 | 2005-05-17 | Council Of Scientific And Industrial Research | Method for gas—solid contacting in a bubbling fluidized bed reactor |
US20050107648A1 (en) | 2001-03-29 | 2005-05-19 | Takahiro Kimura | Gas hydrate production device and gas hydrate dehydrating device |
US7118720B1 (en) | 2001-04-27 | 2006-10-10 | The United States Of America As Represented By The United States Department Of Energy | Method for combined removal of mercury and nitrogen oxides from off-gas streams |
US6969494B2 (en) | 2001-05-11 | 2005-11-29 | Continental Research & Engineering, Llc | Plasma based trace metal removal apparatus and method |
US6863878B2 (en) | 2001-07-05 | 2005-03-08 | Robert E. Klepper | Method and apparatus for producing synthesis gas from carbonaceous materials |
JP4259777B2 (en) | 2001-07-31 | 2009-04-30 | 井上 斉 | Biomass gasification method |
JP5019683B2 (en) | 2001-08-31 | 2012-09-05 | 三菱重工業株式会社 | Gas hydrate slurry dewatering apparatus and method |
US20030070808A1 (en) | 2001-10-15 | 2003-04-17 | Conoco Inc. | Use of syngas for the upgrading of heavy crude at the wellhead |
US6797253B2 (en) | 2001-11-26 | 2004-09-28 | General Electric Co. | Conversion of static sour natural gas to fuels and chemicals |
CA2468769A1 (en) | 2001-12-03 | 2003-06-12 | Clean Energy Systems, Inc. | Coal and syngas fueled power generation systems featuring zero atmospheric emissions |
US6955695B2 (en) | 2002-03-05 | 2005-10-18 | Petro 2020, Llc | Conversion of petroleum residua to methane |
US6622361B1 (en) | 2002-03-11 | 2003-09-23 | Timothy R. Wilson | Railroad clip removal system having a pair of arms within a guide slot |
US7132183B2 (en) | 2002-06-27 | 2006-11-07 | Intellergy Corporation | Process and system for converting carbonaceous feedstocks into energy without greenhouse gas emissions |
US7220502B2 (en) | 2002-06-27 | 2007-05-22 | Intellergy Corporation | Process and system for converting carbonaceous feedstocks into energy without greenhouse gas emissions |
US6878358B2 (en) | 2002-07-22 | 2005-04-12 | Bayer Aktiengesellschaft | Process for removing mercury from flue gases |
NO20026021D0 (en) | 2002-12-13 | 2002-12-13 | Statoil Asa I & K Ir Pat | Procedure for increased oil recovery |
JP2004292200A (en) | 2003-03-26 | 2004-10-21 | Ube Ind Ltd | Combustion improving method of inflammable fuel in burning process of cement clinker |
JP2004298818A (en) | 2003-04-01 | 2004-10-28 | Tokyo Gas Co Ltd | Pretreatment method and apparatus therefor in supercritical water treatment of organic material |
CN1477090A (en) | 2003-05-16 | 2004-02-25 | 中国科学院广州能源研究所 | Method for synthesizing dimethyl ether by adopting biomass indirect liquification one-step process |
KR100524875B1 (en) | 2003-06-28 | 2005-10-31 | 엘지.필립스 엘시디 주식회사 | Clean room system |
US7205448B2 (en) | 2003-12-19 | 2007-04-17 | Uop Llc | Process for the removal of nitrogen compounds from a fluid stream |
CA2557159C (en) | 2004-03-22 | 2010-05-25 | The Babcock & Wilcox Company | Dynamic halogenation of sorbents for the removal of mercury from flue gases |
US20050287056A1 (en) | 2004-06-29 | 2005-12-29 | Dakota Gasification Company | Removal of methyl mercaptan from gas streams |
US7309383B2 (en) | 2004-09-23 | 2007-12-18 | Exxonmobil Chemical Patents Inc. | Process for removing solid particles from a gas-solids flow |
JP4556175B2 (en) | 2004-12-20 | 2010-10-06 | 昌弘 小川 | A method for separating and recovering carbon monoxide from the product gas of a refinery hydrogen production system. |
TWI354649B (en) | 2005-04-06 | 2011-12-21 | Cabot Corp | Method to produce hydrogen or synthesis gas and ca |
US7575613B2 (en) | 2005-05-26 | 2009-08-18 | Arizona Public Service Company | Method and apparatus for producing methane from carbonaceous material |
US20070000177A1 (en) | 2005-07-01 | 2007-01-04 | Hippo Edwin J | Mild catalytic steam gasification process |
AT502064A2 (en) | 2005-07-04 | 2007-01-15 | Sf Soepenberg Compag Gmbh | PROCESS FOR OBTAINING CALIUM CARBONATE FROM ASH |
DE102005042640A1 (en) | 2005-09-07 | 2007-03-29 | Future Energy Gmbh | Process and apparatus for producing synthesis gases by partial oxidation of slurries produced from ash-containing fuels with partial quenching and waste heat recovery |
ATE478445T1 (en) | 2005-09-27 | 2010-09-15 | Haldor Topsoe As | METHOD FOR GENERATING ELECTRICITY USING A SOLID ELECTROLYTE STACK AND ETHANOL |
US8114176B2 (en) | 2005-10-12 | 2012-02-14 | Great Point Energy, Inc. | Catalytic steam gasification of petroleum coke to methane |
WO2007068682A1 (en) | 2005-12-12 | 2007-06-21 | Shell Internationale Research Maatschappij B.V. | Enhanced oil recovery process and a process for the sequestration of carbon dioxide |
WO2007077138A1 (en) | 2005-12-30 | 2007-07-12 | Shell Internationale Research Maatschappij B.V. | Enhanced oil recovery process and a process for the sequestration of carbon dioxide |
WO2007077137A1 (en) * | 2005-12-30 | 2007-07-12 | Shell Internationale Research Maatschappij B.V. | A process for enhanced oil recovery and a process for the sequestration of carbon dioxide |
FR2896508B1 (en) | 2006-01-23 | 2008-06-20 | Arkema Sa | ADHESION PROMOTER FOR APPLICATION TO ELASTOMERIC THERMOPLASTIC POLYMER SUBSTRATE AND METHODS OF SURFACE TREATMENT AND BONDING ASSEMBLY THEREOF |
US7758663B2 (en) | 2006-02-14 | 2010-07-20 | Gas Technology Institute | Plasma assisted conversion of carbonaceous materials into synthesis gas |
US7655215B2 (en) | 2006-03-06 | 2010-02-02 | Bioconversion Technology Llc | Method and apparatus for producing synthesis gas from waste materials |
US20070220810A1 (en) | 2006-03-24 | 2007-09-27 | Leveson Philip D | Method for improving gasification efficiency through the use of waste heat |
US9605522B2 (en) | 2006-03-29 | 2017-03-28 | Pioneer Energy, Inc. | Apparatus and method for extracting petroleum from underground sites using reformed gases |
US7506685B2 (en) | 2006-03-29 | 2009-03-24 | Pioneer Energy, Inc. | Apparatus and method for extracting petroleum from underground sites using reformed gases |
US7871457B2 (en) * | 2006-04-03 | 2011-01-18 | Praxair Technology, Inc. | Carbon dioxide production method |
US7550030B2 (en) * | 2006-04-03 | 2009-06-23 | Praxair Technology, Inc. | Process and apparatus to recover high purity carbon dioxide |
US7654320B2 (en) | 2006-04-07 | 2010-02-02 | Occidental Energy Ventures Corp. | System and method for processing a mixture of hydrocarbon and CO2 gas produced from a hydrocarbon reservoir |
US7772292B2 (en) | 2006-05-31 | 2010-08-10 | Exxonmobil Chemical Patents Inc. | Synthesis gas production and use |
US7922782B2 (en) | 2006-06-01 | 2011-04-12 | Greatpoint Energy, Inc. | Catalytic steam gasification process with recovery and recycle of alkali metal compounds |
DE102006054472B4 (en) | 2006-11-18 | 2010-11-04 | Lurgi Gmbh | Process for the recovery of carbon dioxide |
FR2911629A1 (en) | 2007-01-19 | 2008-07-25 | Air Liquide | PROCESS FOR EXTRACTING PETROLEUM PRODUCTS USING EXTRACTION AID FLUIDS |
FR2906879A1 (en) | 2007-02-06 | 2008-04-11 | Air Liquide | Installation for producing a mixture of nitrogen and carbon dioxide for injection into a subterranean hydrocarbon reservoir comprises an air separator, an oxygen consumption unit, a carbon dioxide separator and a mixer |
CN101063406A (en) * | 2007-03-30 | 2007-10-31 | 辽河石油勘探局 | Boiler flue reclaiming CO2 liquify pouring well oil production arrangement |
US7976593B2 (en) | 2007-06-27 | 2011-07-12 | Heat Transfer International, Llc | Gasifier and gasifier system for pyrolizing organic materials |
US8153027B2 (en) | 2007-07-09 | 2012-04-10 | Range Fuels, Inc. | Methods for producing syngas |
US8163048B2 (en) | 2007-08-02 | 2012-04-24 | Greatpoint Energy, Inc. | Catalyst-loaded coal compositions, methods of making and use |
WO2009048723A2 (en) | 2007-10-09 | 2009-04-16 | Greatpoint Energy, Inc. | Compositions for catalytic gasification of a petroleum coke and process for conversion thereof to methane |
US20090090056A1 (en) | 2007-10-09 | 2009-04-09 | Greatpoint Energy, Inc. | Compositions for Catalytic Gasification of a Petroleum Coke |
EP2058471A1 (en) | 2007-11-06 | 2009-05-13 | Bp Exploration Operating Company Limited | Method of injecting carbon dioxide |
WO2009079064A1 (en) * | 2007-12-18 | 2009-06-25 | Chevron U.S.A. Inc. | Process for the capture of co2 from ch4 feedstock and gtl process streams |
US20090165380A1 (en) | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Petroleum Coke Compositions for Catalytic Gasification |
US20090165382A1 (en) | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Catalytic Gasification Process with Recovery of Alkali Metal from Char |
US20090165379A1 (en) | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Coal Compositions for Catalytic Gasification |
CN101910373B (en) | 2007-12-28 | 2013-07-24 | 格雷特波因特能源公司 | Catalytic gasification process with recovery of alkali metal from char |
US20090170968A1 (en) | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Processes for Making Synthesis Gas and Syngas-Derived Products |
KR101140542B1 (en) | 2007-12-28 | 2012-05-22 | 그레이트포인트 에너지, 인크. | Catalytic gasification process with recovery of alkali metal from char |
WO2009086372A1 (en) | 2007-12-28 | 2009-07-09 | Greatpoint Energy, Inc. | Carbonaceous fuels and processes for making and using them |
WO2009086408A1 (en) | 2007-12-28 | 2009-07-09 | Greatpoint Energy, Inc. | Continuous process for converting carbonaceous feedstock into gaseous products |
US8123827B2 (en) | 2007-12-28 | 2012-02-28 | Greatpoint Energy, Inc. | Processes for making syngas-derived products |
US20090166588A1 (en) | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Petroleum Coke Compositions for Catalytic Gasification |
US20090165383A1 (en) | 2007-12-28 | 2009-07-02 | Greatpoint Energy, Inc. | Catalytic Gasification Process with Recovery of Alkali Metal from Char |
CN101910375B (en) | 2007-12-28 | 2014-11-05 | 格雷特波因特能源公司 | Steam generating slurry gasifier for the catalytic gasification of a carbonaceous feedstock |
US8528343B2 (en) | 2008-01-07 | 2013-09-10 | General Electric Company | Method and apparatus to facilitate substitute natural gas production |
US7926750B2 (en) | 2008-02-29 | 2011-04-19 | Greatpoint Energy, Inc. | Compactor feeder |
CA2716135C (en) | 2008-02-29 | 2013-05-28 | Greatpoint Energy, Inc. | Particulate composition for gasification, preparation and continuous conversion thereof |
WO2009111345A2 (en) | 2008-02-29 | 2009-09-11 | Greatpoint Energy, Inc. | Catalytic gasification particulate compositions |
US8286901B2 (en) | 2008-02-29 | 2012-10-16 | Greatpoint Energy, Inc. | Coal compositions for catalytic gasification |
US8297542B2 (en) | 2008-02-29 | 2012-10-30 | Greatpoint Energy, Inc. | Coal compositions for catalytic gasification |
US20090220406A1 (en) | 2008-02-29 | 2009-09-03 | Greatpoint Energy, Inc. | Selective Removal and Recovery of Acid Gases from Gasification Products |
US20090217575A1 (en) | 2008-02-29 | 2009-09-03 | Greatpoint Energy, Inc. | Biomass Char Compositions for Catalytic Gasification |
WO2009111331A2 (en) | 2008-02-29 | 2009-09-11 | Greatpoint Energy, Inc. | Steam generation processes utilizing biomass feedstocks |
US8361428B2 (en) | 2008-02-29 | 2013-01-29 | Greatpoint Energy, Inc. | Reduced carbon footprint steam generation processes |
US8114177B2 (en) | 2008-02-29 | 2012-02-14 | Greatpoint Energy, Inc. | Co-feed of biomass as source of makeup catalysts for catalytic coal gasification |
US20090260287A1 (en) | 2008-02-29 | 2009-10-22 | Greatpoint Energy, Inc. | Process and Apparatus for the Separation of Methane from a Gas Stream |
US20090217582A1 (en) | 2008-02-29 | 2009-09-03 | Greatpoint Energy, Inc. | Processes for Making Adsorbents and Processes for Removing Contaminants from Fluids Using Them |
WO2009124017A2 (en) | 2008-04-01 | 2009-10-08 | Greatpoint Energy, Inc. | Processes for the separation of methane from a gas stream |
WO2009124019A2 (en) | 2008-04-01 | 2009-10-08 | Greatpoint Energy, Inc. | Sour shift process for the removal of carbon monoxide from a gas stream |
US20090324459A1 (en) | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Three-Train Catalytic Gasification Systems |
US20090324458A1 (en) | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Two-Train Catalytic Gasification Systems |
US20090324461A1 (en) | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Four-Train Catalytic Gasification Systems |
WO2009158580A2 (en) | 2008-06-27 | 2009-12-30 | Greatpoint Energy, Inc. | Four-train catalytic gasification systems |
US20090324462A1 (en) | 2008-06-27 | 2009-12-31 | Greatpoint Energy, Inc. | Four-Train Catalytic Gasification Systems |
US20100029350A1 (en) * | 2008-08-01 | 2010-02-04 | Qualcomm Incorporated | Full-duplex wireless transceiver design |
CN103865585A (en) | 2008-09-19 | 2014-06-18 | 格雷特波因特能源公司 | Gasification device of a Carbonaceous Feedstock |
US8647402B2 (en) | 2008-09-19 | 2014-02-11 | Greatpoint Energy, Inc. | Processes for gasification of a carbonaceous feedstock |
CN102159687B (en) | 2008-09-19 | 2016-06-08 | 格雷特波因特能源公司 | Use the gasification process of charcoal methanation catalyst |
US20100120926A1 (en) | 2008-09-19 | 2010-05-13 | Greatpoint Energy, Inc. | Processes for Gasification of a Carbonaceous Feedstock |
CN201288266Y (en) | 2008-09-22 | 2009-08-12 | 厦门灿坤实业股份有限公司 | Heat insulation cover of electric iron |
CN102197117B (en) | 2008-10-23 | 2014-12-24 | 格雷特波因特能源公司 | Processes for gasification of a carbonaceous feedstock |
CN101555420B (en) | 2008-12-19 | 2012-10-24 | 新奥科技发展有限公司 | Method, system and equipment for catalytic coal gasification |
CN102272267A (en) | 2008-12-30 | 2011-12-07 | 格雷特波因特能源公司 | Processes for preparing a catalyzed carbonaceous particulate |
CN102272268B (en) | 2008-12-30 | 2014-07-23 | 格雷特波因特能源公司 | Processes for preparing a catalyzed coal particulate |
US8728182B2 (en) | 2009-05-13 | 2014-05-20 | Greatpoint Energy, Inc. | Processes for hydromethanation of a carbonaceous feedstock |
KR101468768B1 (en) | 2009-05-13 | 2014-12-04 | 그레이트포인트 에너지, 인크. | Processes for hydromethanation of a carbonaceous feedstock |
US8268899B2 (en) | 2009-05-13 | 2012-09-18 | Greatpoint Energy, Inc. | Processes for hydromethanation of a carbonaceous feedstock |
CN102597181B (en) | 2009-08-06 | 2014-04-23 | 格雷特波因特能源公司 | Processes for hydromethanation of a carbonaceous feedstock |
CN102021036B (en) | 2009-09-14 | 2013-08-21 | 新奥科技发展有限公司 | Method for circulating catalyst in gasification process of coal |
CN101792680B (en) | 2009-09-14 | 2013-01-02 | 新奥科技发展有限公司 | Comprehensive utilization method and system for coal |
WO2011029285A1 (en) | 2009-09-14 | 2011-03-17 | 新奥科技发展有限公司 | Multi-layer fluidized bed gasifier |
CN102021037B (en) | 2009-09-14 | 2013-06-19 | 新奥科技发展有限公司 | Method and apparatus for preparing methane by catalytic gasification of coal |
CN102021039A (en) | 2009-09-14 | 2011-04-20 | 新奥科技发展有限公司 | Method and device for preparing methane-containing gas by multi-region coal gasification |
CN102575181B (en) | 2009-09-16 | 2016-02-10 | 格雷特波因特能源公司 | Integrated hydromethanation combined cycle process |
WO2011034891A1 (en) | 2009-09-16 | 2011-03-24 | Greatpoint Energy, Inc. | Two-mode process for hydrogen production |
WO2011034888A1 (en) | 2009-09-16 | 2011-03-24 | Greatpoint Energy, Inc. | Processes for hydromethanation of a carbonaceous feedstock |
CN102549121B (en) | 2009-09-16 | 2015-03-25 | 格雷特波因特能源公司 | Integrated hydromethanation combined cycle process |
US8479833B2 (en) | 2009-10-19 | 2013-07-09 | Greatpoint Energy, Inc. | Integrated enhanced oil recovery process |
US8479834B2 (en) | 2009-10-19 | 2013-07-09 | Greatpoint Energy, Inc. | Integrated enhanced oil recovery process |
CN102079685B (en) | 2009-11-26 | 2014-05-07 | 新奥科技发展有限公司 | Coal gasification process for methane preparation by two stage gasification stove |
US8733459B2 (en) | 2009-12-17 | 2014-05-27 | Greatpoint Energy, Inc. | Integrated enhanced oil recovery process |
CN102652205A (en) | 2009-12-17 | 2012-08-29 | 格雷特波因特能源公司 | Integrated enhanced oil recovery process injecting nitrogen |
CN102754266B (en) | 2010-02-23 | 2015-09-02 | 格雷特波因特能源公司 | integrated hydrogenation methanation fuel cell power generation |
US8652696B2 (en) | 2010-03-08 | 2014-02-18 | Greatpoint Energy, Inc. | Integrated hydromethanation fuel cell power generation |
WO2011139694A1 (en) | 2010-04-26 | 2011-11-10 | Greatpoint Energy, Inc. | Hydromethanation of a carbonaceous feedstock with vanadium recovery |
KR101424941B1 (en) | 2010-08-18 | 2014-08-01 | 그레이트포인트 에너지, 인크. | Hydromethanation of carbonaceous feedstock |
KR20130080471A (en) | 2010-09-10 | 2013-07-12 | 그레이트포인트 에너지, 인크. | Hydromethanation of a carbonaceous feedstock |
CN103249815B (en) | 2010-11-01 | 2016-08-24 | 格雷特波因特能源公司 | The hydrogenation methanation of carbon containing feed |
JP6124795B2 (en) | 2010-11-01 | 2017-05-10 | グレイトポイント・エナジー・インコーポレイテッド | Hydrogenation methanation of carbonaceous feedstock. |
-
2010
- 2010-10-18 US US12/906,547 patent/US8479833B2/en active Active
- 2010-10-18 CA CA2773718A patent/CA2773718C/en not_active Expired - Fee Related
- 2010-10-18 CN CN201080047937.4A patent/CN102667057B/en active Active
- 2010-10-18 AU AU2010310846A patent/AU2010310846B2/en not_active Ceased
- 2010-10-18 WO PCT/US2010/053027 patent/WO2011049858A2/en active Application Filing
Also Published As
Publication number | Publication date |
---|---|
CN102667057B (en) | 2014-10-22 |
US20110088897A1 (en) | 2011-04-21 |
WO2011049858A3 (en) | 2011-08-11 |
US8479833B2 (en) | 2013-07-09 |
WO2011049858A2 (en) | 2011-04-28 |
CA2773718A1 (en) | 2011-04-28 |
AU2010310846A1 (en) | 2012-05-10 |
AU2010310846B2 (en) | 2013-05-30 |
CN102667057A (en) | 2012-09-12 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
CA2773718C (en) | Integrated enhanced oil recovery process | |
CA2773845C (en) | Integrated enhanced oil recovery process | |
US8733459B2 (en) | Integrated enhanced oil recovery process | |
US20110146978A1 (en) | Integrated enhanced oil recovery process | |
US8748687B2 (en) | Hydromethanation of a carbonaceous feedstock | |
US9127221B2 (en) | Hydromethanation of a carbonaceous feedstock | |
US20130042824A1 (en) | Hydromethanation of a carbonaceous feedstock | |
US20130046124A1 (en) | Hydromethanation of a carbonaceous feedstock | |
US20120271072A1 (en) | Hydromethanation of a carbonaceous feedstock | |
CA2807072A1 (en) | Hydromethanation of a carbonaceous feedstock | |
CA2815243A1 (en) | Hydromethanation of a carbonaceous feedstock | |
CA2814201A1 (en) | Hydromethanation of a carbonaceous feedstock |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
EEER | Examination request | ||
MKLA | Lapsed |
Effective date: 20151019 |