WO2017055087A1 - Absorptionsmittel und verfahren zur selektiven entfernung von schwefelwasserstoff - Google Patents
Absorptionsmittel und verfahren zur selektiven entfernung von schwefelwasserstoff Download PDFInfo
- Publication number
- WO2017055087A1 WO2017055087A1 PCT/EP2016/071700 EP2016071700W WO2017055087A1 WO 2017055087 A1 WO2017055087 A1 WO 2017055087A1 EP 2016071700 W EP2016071700 W EP 2016071700W WO 2017055087 A1 WO2017055087 A1 WO 2017055087A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- absorbent
- tert
- ethoxy
- ether
- ethyl
- Prior art date
Links
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 title claims abstract description 40
- 238000000034 method Methods 0.000 title claims abstract description 23
- 238000010521 absorption reaction Methods 0.000 title abstract description 39
- 239000003795 chemical substances by application Substances 0.000 title abstract description 6
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 claims abstract description 122
- 229910002092 carbon dioxide Inorganic materials 0.000 claims abstract description 71
- 239000012530 fluid Substances 0.000 claims abstract description 46
- 125000002887 hydroxy group Chemical group [H]O* 0.000 claims abstract description 34
- 239000006184 cosolvent Substances 0.000 claims abstract description 26
- 239000001569 carbon dioxide Substances 0.000 claims abstract description 21
- 239000003125 aqueous solvent Substances 0.000 claims abstract description 11
- 125000001033 ether group Chemical group 0.000 claims abstract description 8
- 125000000524 functional group Chemical group 0.000 claims abstract description 4
- 239000002250 absorbent Substances 0.000 claims description 111
- 230000002745 absorbent Effects 0.000 claims description 111
- 150000003335 secondary amines Chemical class 0.000 claims description 26
- 229910000037 hydrogen sulfide Inorganic materials 0.000 claims description 22
- 239000002904 solvent Substances 0.000 claims description 22
- MTHSVFCYNBDYFN-UHFFFAOYSA-N diethylene glycol Chemical compound OCCOCCO MTHSVFCYNBDYFN-UHFFFAOYSA-N 0.000 claims description 16
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 15
- -1 isopropylamino group Chemical group 0.000 claims description 13
- LYCAIKOWRPUZTN-UHFFFAOYSA-N ethylene glycol Natural products OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 claims description 11
- WERYXYBDKMZEQL-UHFFFAOYSA-N butane-1,4-diol Chemical compound OCCCCO WERYXYBDKMZEQL-UHFFFAOYSA-N 0.000 claims description 10
- ZIBGPFATKBEMQZ-UHFFFAOYSA-N triethylene glycol Chemical compound OCCOCCOCCO ZIBGPFATKBEMQZ-UHFFFAOYSA-N 0.000 claims description 9
- 239000000203 mixture Substances 0.000 claims description 8
- YPFDHNVEDLHUCE-UHFFFAOYSA-N 1,3-propanediol Substances OCCCO YPFDHNVEDLHUCE-UHFFFAOYSA-N 0.000 claims description 6
- YDEDDFNFQOPRQJ-UHFFFAOYSA-N 2-[2-(tert-butylamino)ethoxy]ethanol Chemical compound CC(C)(C)NCCOCCO YDEDDFNFQOPRQJ-UHFFFAOYSA-N 0.000 claims description 6
- LRHPLDYGYMQRHN-UHFFFAOYSA-N N-Butanol Chemical compound CCCCO LRHPLDYGYMQRHN-UHFFFAOYSA-N 0.000 claims description 6
- SECXISVLQFMRJM-UHFFFAOYSA-N N-Methylpyrrolidone Chemical compound CN1CCCC1=O SECXISVLQFMRJM-UHFFFAOYSA-N 0.000 claims description 6
- AMQJEAYHLZJPGS-UHFFFAOYSA-N N-Pentanol Chemical compound CCCCCO AMQJEAYHLZJPGS-UHFFFAOYSA-N 0.000 claims description 6
- ZSIAUFGUXNUGDI-UHFFFAOYSA-N hexan-1-ol Chemical compound CCCCCCO ZSIAUFGUXNUGDI-UHFFFAOYSA-N 0.000 claims description 6
- DNIAPMSPPWPWGF-VKHMYHEASA-N (+)-propylene glycol Chemical compound C[C@H](O)CO DNIAPMSPPWPWGF-VKHMYHEASA-N 0.000 claims description 5
- RBZQLPFPTPQBEI-UHFFFAOYSA-N 2-[2-(propan-2-ylamino)ethoxy]ethanol Chemical compound CC(C)NCCOCCO RBZQLPFPTPQBEI-UHFFFAOYSA-N 0.000 claims description 5
- 238000010438 heat treatment Methods 0.000 claims description 5
- 229920000166 polytrimethylene carbonate Polymers 0.000 claims description 5
- RILLZYSZSDGYGV-UHFFFAOYSA-N 2-(propan-2-ylamino)ethanol Chemical compound CC(C)NCCO RILLZYSZSDGYGV-UHFFFAOYSA-N 0.000 claims description 4
- VGZJOXPMODLELN-UHFFFAOYSA-N 2-(propan-2-ylamino)propan-1-ol Chemical compound CC(C)NC(C)CO VGZJOXPMODLELN-UHFFFAOYSA-N 0.000 claims description 4
- IUXYVKZUDNLISR-UHFFFAOYSA-N 2-(tert-butylamino)ethanol Chemical compound CC(C)(C)NCCO IUXYVKZUDNLISR-UHFFFAOYSA-N 0.000 claims description 4
- YEJRWHAVMIAJKC-UHFFFAOYSA-N 4-Butyrolactone Chemical compound O=C1CCCO1 YEJRWHAVMIAJKC-UHFFFAOYSA-N 0.000 claims description 4
- UWHCKJMYHZGTIT-UHFFFAOYSA-N Tetraethylene glycol, Natural products OCCOCCOCCOCCO UWHCKJMYHZGTIT-UHFFFAOYSA-N 0.000 claims description 4
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 claims description 4
- UGGUOQMUQUMCJX-UHFFFAOYSA-N n-[2-[2-[2-(tert-butylamino)ethoxy]ethoxy]ethyl]-2-methylpropan-2-amine Chemical compound CC(C)(C)NCCOCCOCCNC(C)(C)C UGGUOQMUQUMCJX-UHFFFAOYSA-N 0.000 claims description 4
- XSOAXXACLJTBDN-UHFFFAOYSA-N n-[2-[2-[2-[2-(propan-2-ylamino)ethoxy]ethoxy]ethoxy]ethyl]propan-2-amine Chemical compound CC(C)NCCOCCOCCOCCNC(C)C XSOAXXACLJTBDN-UHFFFAOYSA-N 0.000 claims description 4
- FTIKLPXVOPLKJI-UHFFFAOYSA-N n-[2-[2-[2-[2-(tert-butylamino)ethoxy]ethoxy]ethoxy]ethyl]-2-methylpropan-2-amine Chemical compound CC(C)(C)NCCOCCOCCOCCNC(C)(C)C FTIKLPXVOPLKJI-UHFFFAOYSA-N 0.000 claims description 4
- HXJUTPCZVOIRIF-UHFFFAOYSA-N sulfolane Chemical compound O=S1(=O)CCCC1 HXJUTPCZVOIRIF-UHFFFAOYSA-N 0.000 claims description 4
- DNIAPMSPPWPWGF-GSVOUGTGSA-N (R)-(-)-Propylene glycol Chemical compound C[C@@H](O)CO DNIAPMSPPWPWGF-GSVOUGTGSA-N 0.000 claims description 3
- SBASXUCJHJRPEV-UHFFFAOYSA-N 2-(2-methoxyethoxy)ethanol Chemical compound COCCOCCO SBASXUCJHJRPEV-UHFFFAOYSA-N 0.000 claims description 3
- DJCYDDALXPHSHR-UHFFFAOYSA-N 2-(2-propoxyethoxy)ethanol Chemical compound CCCOCCOCCO DJCYDDALXPHSHR-UHFFFAOYSA-N 0.000 claims description 3
- WFSMVVDJSNMRAR-UHFFFAOYSA-N 2-[2-(2-ethoxyethoxy)ethoxy]ethanol Chemical compound CCOCCOCCOCCO WFSMVVDJSNMRAR-UHFFFAOYSA-N 0.000 claims description 3
- KCBPVRDDYVJQHA-UHFFFAOYSA-N 2-[2-(2-propoxyethoxy)ethoxy]ethanol Chemical compound CCCOCCOCCOCCO KCBPVRDDYVJQHA-UHFFFAOYSA-N 0.000 claims description 3
- XXJWXESWEXIICW-UHFFFAOYSA-N diethylene glycol monoethyl ether Chemical compound CCOCCOCCO XXJWXESWEXIICW-UHFFFAOYSA-N 0.000 claims description 3
- 229940075557 diethylene glycol monoethyl ether Drugs 0.000 claims description 3
- GUVUOGQBMYCBQP-UHFFFAOYSA-N dmpu Chemical compound CN1CCCN(C)C1=O GUVUOGQBMYCBQP-UHFFFAOYSA-N 0.000 claims description 3
- DNIAPMSPPWPWGF-UHFFFAOYSA-N monopropylene glycol Natural products CC(O)CO DNIAPMSPPWPWGF-UHFFFAOYSA-N 0.000 claims description 3
- OXLRHYVCQQKZRQ-UHFFFAOYSA-N n-[2-[2-[2-(propan-2-ylamino)ethoxy]ethoxy]ethyl]propan-2-amine Chemical compound CC(C)NCCOCCOCCNC(C)C OXLRHYVCQQKZRQ-UHFFFAOYSA-N 0.000 claims description 3
- JLFNLZLINWHATN-UHFFFAOYSA-N pentaethylene glycol Chemical compound OCCOCCOCCOCCOCCO JLFNLZLINWHATN-UHFFFAOYSA-N 0.000 claims description 3
- 235000013772 propylene glycol Nutrition 0.000 claims description 3
- JLGLQAWTXXGVEM-UHFFFAOYSA-N triethylene glycol monomethyl ether Chemical compound COCCOCCOCCO JLGLQAWTXXGVEM-UHFFFAOYSA-N 0.000 claims description 3
- SAAJBXYUPFMGBK-UHFFFAOYSA-N 2-[2-[2-(propan-2-ylamino)ethoxy]ethoxy]ethanol Chemical compound CC(C)NCCOCCOCCO SAAJBXYUPFMGBK-UHFFFAOYSA-N 0.000 claims description 2
- LLIRWOACVGPCOK-UHFFFAOYSA-N 2-[2-[2-(tert-butylamino)ethoxy]ethoxy]ethanol Chemical compound CC(C)(C)NCCOCCOCCO LLIRWOACVGPCOK-UHFFFAOYSA-N 0.000 claims description 2
- UUFAIPPYEQNTLS-UHFFFAOYSA-N 2-[2-hydroxyethyl-(2,2,6,6-tetramethylpiperidin-4-yl)amino]ethanol Chemical compound CC1(C)CC(N(CCO)CCO)CC(C)(C)N1 UUFAIPPYEQNTLS-UHFFFAOYSA-N 0.000 claims description 2
- RPVALYOISHUWPI-UHFFFAOYSA-N 3-(2,2,6,6-tetramethylpiperidin-4-yl)oxypropan-1-ol Chemical compound OCCCOC1CC(NC(C1)(C)C)(C)C RPVALYOISHUWPI-UHFFFAOYSA-N 0.000 claims description 2
- FKIGQUQTZVAPJC-UHFFFAOYSA-N 4-(2,2,6,6-tetramethylpiperidin-4-yl)oxybutan-1-ol Chemical compound OCCCCOC1CC(NC(C1)(C)C)(C)C FKIGQUQTZVAPJC-UHFFFAOYSA-N 0.000 claims description 2
- 150000001298 alcohols Chemical class 0.000 claims description 2
- 150000001346 alkyl aryl ethers Chemical class 0.000 claims description 2
- 150000001408 amides Chemical class 0.000 claims description 2
- 235000013877 carbamide Nutrition 0.000 claims description 2
- 150000001983 dialkylethers Chemical class 0.000 claims description 2
- 150000002009 diols Chemical class 0.000 claims description 2
- 150000002148 esters Chemical class 0.000 claims description 2
- 150000003951 lactams Chemical class 0.000 claims description 2
- 150000002596 lactones Chemical class 0.000 claims description 2
- OKNVUKWJUTVFNV-UHFFFAOYSA-N n-[2-[2-(propan-2-ylamino)ethoxy]ethyl]propan-2-amine Chemical compound CC(C)NCCOCCNC(C)C OKNVUKWJUTVFNV-UHFFFAOYSA-N 0.000 claims description 2
- ZAWCVKBSJMRLLG-UHFFFAOYSA-N n-[2-[2-(tert-butylamino)ethoxy]ethyl]-2-methylpropan-2-amine Chemical compound CC(C)(C)NCCOCCNC(C)(C)C ZAWCVKBSJMRLLG-UHFFFAOYSA-N 0.000 claims description 2
- 150000003457 sulfones Chemical class 0.000 claims description 2
- 125000006318 tert-butyl amino group Chemical group [H]N(*)C(C([H])([H])[H])(C([H])([H])[H])C([H])([H])[H] 0.000 claims description 2
- RKMGAJGJIURJSJ-UHFFFAOYSA-N 2,2,6,6-tetramethylpiperidine Chemical compound CC1(C)CCCC(C)(C)N1 RKMGAJGJIURJSJ-UHFFFAOYSA-N 0.000 claims 2
- 125000000217 alkyl group Chemical group 0.000 claims 1
- 229920001577 copolymer Polymers 0.000 claims 1
- 239000007789 gas Substances 0.000 abstract description 49
- 230000008929 regeneration Effects 0.000 abstract description 16
- 238000011069 regeneration method Methods 0.000 abstract description 16
- 239000002253 acid Substances 0.000 abstract description 9
- 125000004122 cyclic group Chemical group 0.000 abstract description 3
- 125000000467 secondary amino group Chemical class [H]N([*:1])[*:2] 0.000 abstract description 3
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 28
- 238000011068 loading method Methods 0.000 description 21
- 150000001875 compounds Chemical class 0.000 description 20
- 150000001412 amines Chemical class 0.000 description 18
- 239000003345 natural gas Substances 0.000 description 13
- 239000006096 absorbing agent Substances 0.000 description 10
- 238000003795 desorption Methods 0.000 description 9
- 230000002378 acidificating effect Effects 0.000 description 8
- 229930195733 hydrocarbon Natural products 0.000 description 7
- 150000002430 hydrocarbons Chemical class 0.000 description 7
- 229910052799 carbon Inorganic materials 0.000 description 6
- 239000000243 solution Substances 0.000 description 6
- 150000001721 carbon Chemical group 0.000 description 5
- 239000000470 constituent Substances 0.000 description 5
- 239000011521 glass Substances 0.000 description 5
- 239000007788 liquid Substances 0.000 description 5
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical compound OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 description 5
- 238000012856 packing Methods 0.000 description 5
- 229940035437 1,3-propanediol Drugs 0.000 description 4
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 230000015572 biosynthetic process Effects 0.000 description 4
- 229910052757 nitrogen Inorganic materials 0.000 description 4
- 229920001223 polyethylene glycol Polymers 0.000 description 4
- 150000003141 primary amines Chemical class 0.000 description 4
- SQGYOTSLMSWVJD-UHFFFAOYSA-N silver(1+) nitrate Chemical compound [Ag+].[O-]N(=O)=O SQGYOTSLMSWVJD-UHFFFAOYSA-N 0.000 description 4
- UHOVQNZJYSORNB-UHFFFAOYSA-N Benzene Chemical compound C1=CC=CC=C1 UHOVQNZJYSORNB-UHFFFAOYSA-N 0.000 description 3
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 3
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 description 3
- 239000002184 metal Substances 0.000 description 3
- 229910052751 metal Inorganic materials 0.000 description 3
- 238000005191 phase separation Methods 0.000 description 3
- 238000000926 separation method Methods 0.000 description 3
- 150000003464 sulfur compounds Chemical class 0.000 description 3
- 150000003512 tertiary amines Chemical class 0.000 description 3
- 238000005406 washing Methods 0.000 description 3
- IWSZDQRGNFLMJS-UHFFFAOYSA-N 2-(dibutylamino)ethanol Chemical compound CCCCN(CCO)CCCC IWSZDQRGNFLMJS-UHFFFAOYSA-N 0.000 description 2
- QGZKDVFQNNGYKY-UHFFFAOYSA-N Ammonia Chemical compound N QGZKDVFQNNGYKY-UHFFFAOYSA-N 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 description 2
- UEEJHVSXFDXPFK-UHFFFAOYSA-N N-dimethylaminoethanol Chemical compound CN(C)CCO UEEJHVSXFDXPFK-UHFFFAOYSA-N 0.000 description 2
- 239000002202 Polyethylene glycol Substances 0.000 description 2
- GSEJCLTVZPLZKY-UHFFFAOYSA-N Triethanolamine Chemical compound OCCN(CCO)CCO GSEJCLTVZPLZKY-UHFFFAOYSA-N 0.000 description 2
- 239000000654 additive Substances 0.000 description 2
- 239000007864 aqueous solution Substances 0.000 description 2
- 125000004432 carbon atom Chemical group C* 0.000 description 2
- 239000011203 carbon fibre reinforced carbon Substances 0.000 description 2
- 239000000919 ceramic Substances 0.000 description 2
- 230000000052 comparative effect Effects 0.000 description 2
- 238000005260 corrosion Methods 0.000 description 2
- 230000007797 corrosion Effects 0.000 description 2
- 229960002887 deanol Drugs 0.000 description 2
- 230000003247 decreasing effect Effects 0.000 description 2
- 239000012972 dimethylethanolamine Substances 0.000 description 2
- TUEYHEWXYWCDHA-UHFFFAOYSA-N ethyl 5-methylthiadiazole-4-carboxylate Chemical compound CCOC(=O)C=1N=NSC=1C TUEYHEWXYWCDHA-UHFFFAOYSA-N 0.000 description 2
- 239000001257 hydrogen Substances 0.000 description 2
- 229910052739 hydrogen Inorganic materials 0.000 description 2
- 125000004435 hydrogen atom Chemical group [H]* 0.000 description 2
- 150000002500 ions Chemical group 0.000 description 2
- 239000003949 liquefied natural gas Substances 0.000 description 2
- 239000003915 liquefied petroleum gas Substances 0.000 description 2
- 239000000463 material Substances 0.000 description 2
- 238000000465 moulding Methods 0.000 description 2
- 125000004433 nitrogen atom Chemical group N* 0.000 description 2
- 239000004033 plastic Substances 0.000 description 2
- 229920003023 plastic Polymers 0.000 description 2
- 239000000047 product Substances 0.000 description 2
- BDERNNFJNOPAEC-UHFFFAOYSA-N propan-1-ol Chemical compound CCCO BDERNNFJNOPAEC-UHFFFAOYSA-N 0.000 description 2
- 229960004063 propylene glycol Drugs 0.000 description 2
- 229910001961 silver nitrate Inorganic materials 0.000 description 2
- 238000003786 synthesis reaction Methods 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- 238000004448 titration Methods 0.000 description 2
- VDVUCLWJZJHFAV-UHFFFAOYSA-N 2,2,6,6-tetramethylpiperidin-4-ol Chemical compound CC1(C)CC(O)CC(C)(C)N1 VDVUCLWJZJHFAV-UHFFFAOYSA-N 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 101710178035 Chorismate synthase 2 Proteins 0.000 description 1
- 101710152694 Cysteine synthase 2 Proteins 0.000 description 1
- XTHFKEDIFFGKHM-UHFFFAOYSA-N Dimethoxyethane Chemical compound COCCOC XTHFKEDIFFGKHM-UHFFFAOYSA-N 0.000 description 1
- 108090000790 Enzymes Proteins 0.000 description 1
- 102000004190 Enzymes Human genes 0.000 description 1
- VGGSQFUCUMXWEO-UHFFFAOYSA-N Ethene Chemical compound C=C VGGSQFUCUMXWEO-UHFFFAOYSA-N 0.000 description 1
- 239000005977 Ethylene Substances 0.000 description 1
- CTQNGGLPUBDAKN-UHFFFAOYSA-N O-Xylene Chemical compound CC1=CC=CC=C1C CTQNGGLPUBDAKN-UHFFFAOYSA-N 0.000 description 1
- VMHLLURERBWHNL-UHFFFAOYSA-M Sodium acetate Chemical compound [Na+].CC([O-])=O VMHLLURERBWHNL-UHFFFAOYSA-M 0.000 description 1
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 1
- 229910052946 acanthite Inorganic materials 0.000 description 1
- 239000012190 activator Substances 0.000 description 1
- 239000003463 adsorbent Substances 0.000 description 1
- 150000001338 aliphatic hydrocarbons Chemical class 0.000 description 1
- 150000001414 amino alcohols Chemical class 0.000 description 1
- 125000003277 amino group Chemical group 0.000 description 1
- 229910021529 ammonia Inorganic materials 0.000 description 1
- 150000004945 aromatic hydrocarbons Chemical class 0.000 description 1
- 239000003990 capacitor Substances 0.000 description 1
- 239000003054 catalyst Substances 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 239000007795 chemical reaction product Substances 0.000 description 1
- 239000003245 coal Substances 0.000 description 1
- 239000000571 coke Substances 0.000 description 1
- 238000004939 coking Methods 0.000 description 1
- 239000000567 combustion gas Substances 0.000 description 1
- 238000009833 condensation Methods 0.000 description 1
- 230000005494 condensation Effects 0.000 description 1
- 230000007423 decrease Effects 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 230000018109 developmental process Effects 0.000 description 1
- SBZXBUIDTXKZTM-UHFFFAOYSA-N diglyme Chemical compound COCCOCCOC SBZXBUIDTXKZTM-UHFFFAOYSA-N 0.000 description 1
- 239000003085 diluting agent Substances 0.000 description 1
- 230000003292 diminished effect Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000005265 energy consumption Methods 0.000 description 1
- 239000003623 enhancer Substances 0.000 description 1
- 238000006266 etherification reaction Methods 0.000 description 1
- 125000001301 ethoxy group Chemical group [H]C([H])([H])C([H])([H])O* 0.000 description 1
- 230000007717 exclusion Effects 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 239000000945 filler Substances 0.000 description 1
- 238000002309 gasification Methods 0.000 description 1
- 239000012535 impurity Substances 0.000 description 1
- 239000003112 inhibitor Substances 0.000 description 1
- 150000007529 inorganic bases Chemical class 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 239000012528 membrane Substances 0.000 description 1
- RIVIDPPYRINTTH-UHFFFAOYSA-N n-ethylpropan-2-amine Chemical compound CCNC(C)C RIVIDPPYRINTTH-UHFFFAOYSA-N 0.000 description 1
- SBOJXQVPLKSXOG-UHFFFAOYSA-N o-amino-hydroxylamine Chemical class NON SBOJXQVPLKSXOG-UHFFFAOYSA-N 0.000 description 1
- 150000007530 organic bases Chemical class 0.000 description 1
- 239000003960 organic solvent Substances 0.000 description 1
- 125000004430 oxygen atom Chemical group O* 0.000 description 1
- 125000002924 primary amino group Chemical group [H]N([H])* 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
- QQONPFPTGQHPMA-UHFFFAOYSA-N propylene Natural products CC=C QQONPFPTGQHPMA-UHFFFAOYSA-N 0.000 description 1
- 125000004805 propylene group Chemical group [H]C([H])([H])C([H])([*:1])C([H])([H])[*:2] 0.000 description 1
- 230000002040 relaxant effect Effects 0.000 description 1
- 238000005070 sampling Methods 0.000 description 1
- 238000005201 scrubbing Methods 0.000 description 1
- FSJWWSXPIWGYKC-UHFFFAOYSA-M silver;silver;sulfanide Chemical compound [SH-].[Ag].[Ag+] FSJWWSXPIWGYKC-UHFFFAOYSA-M 0.000 description 1
- 239000001632 sodium acetate Substances 0.000 description 1
- 235000017281 sodium acetate Nutrition 0.000 description 1
- 230000003068 static effect Effects 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 239000011593 sulfur Substances 0.000 description 1
- YBRBMKDOPFTVDT-UHFFFAOYSA-N tert-butylamine Chemical compound CC(C)(C)N YBRBMKDOPFTVDT-UHFFFAOYSA-N 0.000 description 1
- 238000010998 test method Methods 0.000 description 1
- 125000000101 thioether group Chemical group 0.000 description 1
- 125000003396 thiol group Chemical group [H]S* 0.000 description 1
- 231100000331 toxic Toxicity 0.000 description 1
- 230000002588 toxic effect Effects 0.000 description 1
- 238000012546 transfer Methods 0.000 description 1
- 229930195735 unsaturated hydrocarbon Natural products 0.000 description 1
- 239000008096 xylene Substances 0.000 description 1
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1493—Selection of liquid materials for use as absorbents
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1468—Removing hydrogen sulfide
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
- C10L3/103—Sulfur containing contaminants
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
- C10L3/104—Carbon dioxide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/202—Alcohols or their derivatives
- B01D2252/2023—Glycols, diols or their derivatives
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/202—Alcohols or their derivatives
- B01D2252/2023—Glycols, diols or their derivatives
- B01D2252/2026—Polyethylene glycol, ethers or esters thereof, e.g. Selexol
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
- B01D2252/20405—Monoamines
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
- B01D2252/20426—Secondary amines
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
- B01D2252/20478—Alkanolamines
- B01D2252/20484—Alkanolamines with one hydroxyl group
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/205—Other organic compounds not covered by B01D2252/00 - B01D2252/20494
- B01D2252/2056—Sulfur compounds, e.g. Sulfolane, thiols
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/40—Absorbents explicitly excluding the presence of water
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/50—Combinations of absorbents
- B01D2252/502—Combinations of absorbents having two or more functionalities in the same molecule other than alkanolamine
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/50—Combinations of absorbents
- B01D2252/504—Mixtures of two or more absorbents
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
- C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
- C10L2290/542—Adsorption of impurities during preparation or upgrading of a fuel
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- 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
Definitions
- the present invention relates to an absorbent and a method for the selective removal of hydrogen sulphide from a fluid stream, in particular for the selective removal of hydrogen sulphide from carbon dioxide.
- CO2 has to be removed from natural gas, because a high concentration of CO2 when used as a pipeline or sales gas reduces the calorific value of the gas.
- CO2 can lead to corrosion of pipes and fittings.
- too low a concentration of CO2 is also undesirable because it may cause the calorific value of the gas to be too high.
- the CO 2 concentrations for pipeline or sales gas are between 1, 5 and 3.5 vol .-%.
- washes are used with aqueous solutions of inorganic or organic bases. When acid gases are dissolved in the absorbent, ions form with the bases.
- the absorbent may be regenerated by depressurization to a lower pressure and / or stripping whereby the ionic species react back to sour gases and / or are stripped out by steam. After the regeneration process, the absorbent can be reused.
- total absorption A process in which all acid gases, especially CO2 and H2S, are removed as far as possible is called "total absorption".
- H2S before CO2
- z. B. to obtain a calorific value-optimized CC ⁇ / L-S ratio for a downstream Claus plant.
- An unfavorable CO I-S ratio can affect the performance and efficiency of the Claus plant by formation of COS / CS 2 and coking of the Claus catalyst or by a too low calorific value.
- Highly hindered secondary amines such as 2- (2-tert-butylaminoethoxy) ethanol, and tertiary amines, such as methyldiethanolamine (MDEA), show kinetic selectivity for H2S over CO2.
- MDEA methyldiethanolamine
- These amines do not react directly with CO2; instead, CO2 reacts slowly with the amine and with water to form bicarbonate - in contrast, H2S reacts instantly in aqueous amine solutions.
- Such amines are therefore particularly suitable for the selective removal of H 2 S from gas mixtures containing CU 2 and H 2 S.
- the selective removal of hydrogen sulfide is widely used in fluid streams with low sour gas partial pressures such.
- AGE Acid Gas Enrichment
- Natural gas treatment for pipeline gas may also require selective removal of H2S from CO2.
- natural gas treatment seeks to simultaneously remove H2S and CO2 while meeting F S limits and eliminating the need for complete removal of CO2.
- the piping gas specification requires sour gas removal to about 1.5 to 3.5 vol.% CO2 and less than 4 vppm H2S. In these cases maximum F S selectivity is not desired.
- DE 31 17 556 A1 describes a process for the selective removal of sulfur compounds from C02-containing gases by means of an aqueous washing solution containing tertiary amines and / or sterically hindered primary or secondary amines in the form of diamino ethers or amino alcohols.
- US 2015/0027055 A1 describes a process for the selective removal of H 2 S from a CO 2 -containing gas mixture by means of an absorption medium which comprises sterically hindered, terminally etherified alkanolamines. It was found that the terminal etherification of the alkanolamines or the exclusion of water allows a higher F S selectivity.
- US 2015/0147254 A1 describes a process for the selective removal of hydrogen sulphide from carbon dioxide from a gas mixture by means of an absorbent which contains an amine, water and at least one C 2 -C 4 -thioalkanol compound. It has been found that the use of the thioalkanol compounds allows increased h S selectivity.
- WO 2013/181242 A1 describes an absorbent for the selective removal of h S from carbon dioxide from a gas mixture by means of an absorbent which contains water, an organic solvent and the reaction product of tert-butylamine and polyethylene glycol in a certain molar mass range.
- the invention has for its object to provide an absorbent and method for the selective separation of hydrogen sulfide from a carbon dioxide and hydrogen sulfide-containing fluid stream, wherein the absorbent has the good regenerability and high cyclic sour gas capacity.
- an absorbent for selectively removing hydrogen sulfide from a fluid stream containing carbon dioxide and hydrogen sulfide which contains a) from 10 to 70% by weight of at least one sterically hindered secondary amine which contains at least one ether group and / or at least one hydroxyl group in the Molecule has; b) at least one non-aqueous solvent having at least two functional groups selected from ether groups and hydroxyl groups in the molecule; and c) optionally a co-solvent; wherein the hydroxyl group density of the absorbent pAbs is in the range of 8.5 to 35 mol (OH) / kg.
- the invention also relates to a process for the selective removal of hydrogen sulfide from a fluid stream containing carbon dioxide and hydrogen sulfide, in which the fluid stream is contacted with the absorbent and receives a loaded absorbent and a treated fluid stream.
- Sterically hindered amines show kinetic selectivity for H2S over CO2. These amines do not react directly with CO2; rather, CO2 is converted into ionic products in a slow reaction with the amine and with a proton donor, such as water.
- Hydroxyl groups introduced via the sterically hindered amine and / or the solvent into the absorbent represent proton donors. It has now been found that by controlling the hydroxyl group density of the absorbent, the H2S selectivity of the absorbent and the regenerability and cyclic sour gas capacity can be controlled , It is believed that a low supply of hydroxyl groups in the absorbent impedes CO 2 absorption. A low hydroxyl group density therefore leads to an increase in H2S selectivity.
- the hydroxyl group density can be used to set the desired selectivity of the adsorbent for H2S over CO2.
- the hydroxyl group density of a compound p compound is the number of moles of hydroxyl groups per kg of compound and is calculated as
- Pharm Mo l weight x 1000 ⁇ wherein the molecular weight is received in g / mol, and "Number OH groups” means the number of the OH groups in one molecule of the compound.
- the number of hydroxyl groups in the molecule enem water as a 2 is set as a water molecule has two hydrogen atoms bonded to an oxygen atom.
- the contributions of the compounds contained in the absorbent ie the amines and solvents contained, are added together.
- the contribution of a compound to the hydroxyl group density of the absorbent pAbs is the product of the hydroxyl group density of the compound p-compound and its percentage by weight based on the total weight of the absorbent.
- the hydroxyl group density of the absorbent pAbs is in the range from 8.5 to 35 mol (OH) / kg, preferably in the range from 9.0 to 32 mol (OH) / kg, particularly preferably in the range from 9.5 to 30 mol (OH) / kg.
- the contribution of the sterically hindered secondary amine a) to pAbs is in the range of 0 to 6 mol (OH) / kg, more preferably in the range 1 to 5 mol (OH) / kg, and most preferably in the range of 2 to 4 mol (OH) / kg.
- the contribution of the nonaqueous solvent b) to pAbs is in the range from 2.5 to 35 mol (OH) / kg, particularly preferably in the range from 3.5 to 30 mol (OH) / kg, and very particularly preferably in the range from 4.5 to 25 moles (OH) / kg.
- the contribution of sterically hindered secondary amine a) to pAbs ranges from 0 to 6 moles (OH) / kg and the contribution of nonaqueous solvent b) to pAbs ranges from 2.5 to 35 moles (OH) / kg.
- the contribution of the hindered secondary amine a) to pAbs is in the range of 1 to 5 mol (OH) / kg and the contribution of the nonaqueous solvent b) to pAbs in the range of 3.5 to 30 mol (OH) / kg.
- the contribution of sterically hindered secondary amine a) to pAbs is in the range of 2 to 4 moles (OH) / kg and the contribution of nonaqueous solvent b) to pAbs is in the range of 4.5 to 25 moles (OH ) / kg.
- the absorbent contains 10 to 70 wt .-%, preferably 15 to 65 wt .-%, particularly preferably 20 to 60 wt .-% of a sterically hindered secondary amine a), which via at least one ether group and / or at least one hydroxyl group in the molecule features.
- secondary amino groups are understood as meaning the presence of at least one secondary or tertiary carbon atom in the immediate vicinity of the nitrogen atom of the amino group.
- Amines a) in addition to sterically hindered secondary amines also include compounds which are referred to in the art as hindered secondary amines and have a steric parameter (Taft constant) of more than 1.75.
- a secondary carbon atom is understood to mean a carbon atom which has two carbon-carbon bonds in addition to the bond to the sterically hindered position.
- a tertiary carbon atom is understood to mean a carbon atom which has three carbon-carbon bonds in addition to the bond to the sterically hindered position.
- a secondary amine is meant a compound having a nitrogen atom substituted by two organic radicals other than hydrogen.
- the sterically hindered secondary amine a) preferably comprises an isopropylamino group, a tert-butylamino group or a 2,2,6,6-tetramethylpiperidinyl group.
- the sterically hindered secondary amine a) is particularly preferably selected from 2- (tert-butylamino) ethanol, 2- (isopropylamino) -1-ethanol, 2- (isopropylamino) -1-propanol, 2- (2-tert-butylaminoethoxy) ethanol, 2- (2-isopropylaminoethoxy) ethanol, 2- (2- (2-tert-butylaminoethoxy) ethoxy) ethanol, 2- (2- (2-isopropylaminoethoxy) ethoxy) ethanol, 4-hydroxy-2,2,6 , 6-tetramethylpiperidine, 4- (3'-hydroxypropoxy) -2,2,6,6-tetramethylpiperidine, 4- (4'-hydroxybutoxy) -2,2,6,6-tetramethylpiperidine, bis- (2- (tert-butylamino) ethyl) ether, bis (2- (isopropylamino) ethyl)
- the sterically hindered secondary amine a) selected from 2- (2-isopropylaminoethoxy) ethanol (IPAEE), 2- (2-tert-butylaminoethoxy) ethanol (TBAEE), 2- (2- (2-tert-butylaminoethoxy ) ethoxy) ethyl tert -butylamine, 2- (2- (2-isopropylaminoethoxy) ethoxy) ethyl-isopropylamine, 2- (2- (2- (2-tert-butylaminoethoxy) ethoxy) ethoxy) ethoxy) ethyl tert -butylamine, and 2- (2- (2- (2-isopropylaminoethoxy) ethoxy) ethyl-isopropylamine.
- IPAEE 2- (2-isopropylaminoethoxy) ethanol
- TSAEE 2- (2-tert-butylaminoeth
- the absorbent does not contain a sterically unhindered primary amine or sterically unhindered secondary amine.
- a sterically unhindered primary amine is understood to mean compounds which have primary amino groups to which only hydrogen atoms or primary or secondary carbon atoms are bonded.
- a sterically unhindered secondary amine is meant compounds having secondary amino groups to which only hydrogen or primary carbon atoms are attached. Sterically unhindered primary amines or sterically unhindered secondary amines act as strong activators of CO 2 absorption. By their presence in the absorbent, the h S selectivity of the absorbent can be lost.
- the absorbent also contains a nonaqueous solvent b) which has at least two functional groups selected from ether groups and hydroxyl groups in the molecule.
- the nonaqueous solvent b) preferably has no thioether group and no thiol group.
- the nonaqueous solvent b) is preferably selected from C 2 -C 8 diols, poly (C 2 -C 4 alkylene glycols), poly (C 2 -C 4 alkylene glycol) monoalkyl ethers and poly (C 2 -C 4 alkylene glycol) dialkyl ethers ,
- the nonaqueous solvent b) is selected under
- non-aqueous solvent b) is selected from
- the absorbent comprises a sterically hindered secondary amine a) selected from 2- (2-isopropylaminoethoxy) ethanol (IPAEE), 2- (2-tert-butylaminoethoxy) ethanol (TBAEE), 2- (2- (2 tert-butylaminoethoxy) ethoxy) ethyl-tert-butylamine, 2- (2- (2-isopropylaminoethoxy) ethoxy) ethyl-isopropylamine, 2- (2- (2- (2-tert-butylaminoethoxy) ethoxy) ethoxy) ethoxy) ethyl tert-butylamine, and 2- (2- (2- (isopropylaminoethoxy) ethoxy) ethoxy) ethyl-isopropylamine, and a nonaqueous solvent b) selected from 1,2-propanediol, 1,3-propanediol
- the molar ratio of amine a) to nonaqueous solvent b) is generally in the range from 0.1 to 1.3, preferably in the range from 0.15 to 1.2, more preferably in the range from 0.2 to 1 , 1 and most preferably in the range of 0.3 to 1, 0.
- the absorbent also optionally contains a cosolvent c).
- the cosolvent c) can be used to achieve a desired pAbs.
- pAbs can be obtained by adding a co-solvent c) are lowered with low p c (the co-solvent acts as a pAbs diluent).
- the contribution of the cosolvent c) to pAbs is then preferably in the range from 0 to 4 mol (OH) / kg, particularly preferably in the range from 0 to 2 mol (OH) / kg, and very particularly preferably in the range from 0 to 1 mol (OH) / kg.
- pAbs can be increased by adding a co-solvent c) with high p c (the co-solvent acts as a pAbs enhancer).
- the contribution of the cosolvent c) to pAbs is then preferably in the range of 10 to 32.5 mol (OH) / kg, more preferably in the range of 10 to 30 mol (OH) / kg, and most preferably in the range of 10 to 25 mol (OH) / kg.
- the cosolvent c) is selected from water, C 4 -C 10 alcohols, esters, lactones, amides, lactams, sulfones and cyclic ureas. Particularly preferred is the cosolvent c) selected from n-butanol, n-pentanol, n-hexanol, sulfolane, N-methyl-2-pyrrolidone (NMP), dimethylpropyleneurea (DMPU) and ⁇ -butyrolactone. Most preferably, the cosolvent c) sulfolane. Water provides a high contribution to the hydroxyl group density of the absorbent.
- the proportion of water is therefore preferably at most 30 wt .-%, more preferably at most 20 wt .-%, most preferably at most 15 wt .-% and most preferably at most 10 wt .-%.
- the absorbent comprises from 20 to 60% by weight of the hindered secondary amine a), from 20 to 80% by weight of the nonaqueous solvent b) and from 10 to 60% by weight of the cosolvent c) wherein the cosolvent c) comprises at most 20% by weight of water, based on the weight of the absorbent.
- the non-aqueous solvent b) at a temperature of 293.15 K and a pressure of 1, 0133-10 5 Pa, a relative dielectric constant ⁇ (also referred to as relative static permittivity) of at least 7, more preferably at least 8.5 and most preferably at least 10 on.
- a relative dielectric constant ⁇ also referred to as relative static permittivity
- the absorbent contains the nonaqueous solvent b) and a cosolvent c) in such proportions that a mixture of the nonaqueous solvent b) and a cosolvent c) in the ratio of these mass fractions at a temperature of 293.15 K and a pressure of 1, 0133-10 5 Pa has a relative dielectric constant ⁇ of at least 7, more preferably at least 8.5, and most preferably at least at least 10.
- a mixture of the non-aqueous solvent b) and a cosolvent c) which remains when the amine a) is thought of from an absorbent according to the invention, the specified dielectric constant ⁇ on.
- the absorbent contains the nonaqueous solvent b) and a cosolvent c) in such proportions that a mixture of the nonaqueous solvent b) and a cosolvent c) in the ratio of these mass fractions at a temperature of 293.15 K and a pressure of 1, 0133 0 5 Pa has a relative dielectric constant ⁇ in the range of 7 to 70.
- the relative dielectric constant ⁇ of the compounds contained in the absorbent influences the polarity of the absorbent.
- the absorption of H2S in the present case is based on ion pair formation between the sterically hindered secondary amine a) and h S, where the amine a) is protonated and h S is deprotonated. A high polarity of the absorbent is therefore advantageous for the absorption of H2S.
- the absorbent may also contain additives such as corrosion inhibitors, enzymes, antifoams, etc. In general, the amount of such additives ranges from about 0.005 to 3% by weight of the absorbent.
- the absorbent preferably has an H2S: CO 2 loading ratio of at least 1.1, and more preferably at least 1.3.
- the H2S: CO 2 loading ratio is preferably at most 5.0, and more preferably at most 4.5.
- the absorbent preferably has an H2S: CO 2 Loading ratio in the range of 1, 1 to 5.0, more preferably in the range of 1, 3 to 4.5.
- C02 loadability ratio is the quotient of the maximum H2S loading by the maximum C02 loading under equilibrium conditions when loading the absorbent with CO2 or H2S at 40 ° C and ambient pressure (about 1 bar) understood. Suitable test methods are mentioned in Example 1.
- the H2S: C02 loading ratio serves as an indication of the expected H S selectivity; the higher the H2S: C02 loading ratio, the higher the expected h S selectivity.
- the maximum h S loading capacity of the absorbent is at least 0.6 mol (H 2 S) / mol (amine), more preferably at least 0.7 mol (H 2 S) / mol (amine), most preferably at least 0.75 mol (H 2 S) / mol (amine), and most preferably at least 0.8 mol (H 2 S) / mol (amine).
- the process according to the invention is suitable for the treatment of fluids of all kinds.
- Fluids are on the one hand gases such as natural gas, synthesis gas, coke oven gas, cracked gas, coal gasification gas, cycle gas, landfill gas and combustion gases, and on the other hand with the absorbent substantially immiscible liquids such as LPG (Liquefied Petroleum Gas) or NGL (Natural Gas Liquids).
- LPG Liquefied Petroleum Gas
- NGL Natural Gas Liquids
- the process according to the invention is particularly suitable for the treatment of hydrocarbon-containing fluid streams.
- the hydrocarbons contained are z.
- aliphatic hydrocarbons such as Ci-C4 hydrocarbons such as methane, unsaturated hydrocarbons such as ethylene or propylene, or aromatic hydrocarbons such as benzene, toluene or xylene.
- the inventive method or absorbent is suitable for the removal of CO2 and H2S.
- CO2 and H2S include carbon dioxide and hydrogen sulfide, other acidic gases may be present in the fluid stream, such as COS and mercaptans.
- SO3, SO2, CS2 and HCN can also be removed.
- the inventive method is suitable for the selective removal of hydrogen sulfide to CO2.
- selectivity for hydrogen sulfide herein is meant the value of the following quotient: y (H2S) feed -y (H2S) treat
- y (H2S) f ee d for the molar fraction (mol / mol) of H2S in the starting fluid
- y (C02) treat for the mole fraction of CO2 in the treated fluid preferably at least 4.
- the removal of sour gas from natural gas for use as a pipeline or sales gas total absorption of carbon dioxide is undesirable.
- the residual content of carbon dioxide in the treated fluid stream is at least 0.5% by volume, preferably at least 1.0% by volume and more preferably at least 1.5% by volume.
- the fluid stream is a hydrocarbon-containing fluid stream; in particular a natural gas stream. More preferably, the fluid stream contains more than 1.0% by volume of hydrocarbons, more preferably more than 5.0% by volume of hydrocarbons, most preferably more than 15% by volume of hydrocarbons.
- the hydrogen sulfide partial pressure in the fluid stream is usually at least 2.5 mbar.
- a hydrogen sulfide partial pressure of at least 0.1 bar, in particular at least 1 bar, and a carbon dioxide partial pressure of at least 0.2 bar, in particular at least 1 bar are present in the fluid stream.
- Particularly preferred in the fluid stream is a hydrogen sulfide partial pressure of at least 0.1 bar and a carbon dioxide partial pressure of at least 1 bar.
- Very particular preference is given to a hydrogen sulfide partial pressure of at least 0.5 bar and a carbon dioxide partial pressure of at least 1 bar in the fluid stream.
- the stated partial pressures refer to the fluid flow upon first contact with the absorbent in the absorption step.
- the fluid stream has a total pressure of at least 3.0 bar, more preferably at least 5.0 bar, most preferably at least 20 bar. In preferred embodiments, the fluid flow has a total pressure of at most 180 bar. The total pressure refers to the fluid flow upon initial contact with the absorbent in the absorption step.
- the fluid stream is brought into contact with the absorbent in an absorption step in an absorber, whereby carbon dioxide and hydrogen sulfide are at least partially washed out.
- the absorber is a washing device used in conventional gas scrubbing processes. Suitable washing devices are, for example, packed, packed and tray columns, membrane contactors, radial flow scrubbers, jet scrubbers, venturi scrubbers and rotary scrubbers, preferably packed, packed and tray columns, particularly preferably tray and packed columns.
- the treatment of the fluid stream with the absorbent is preferably carried out in a column in countercurrent.
- the fluid is generally fed into the lower region and the absorbent in the upper region of the column.
- tray columns sieve, bell or valve trays are installed, over which the liquid flows.
- Packed columns can be filled with different moldings. Heat and mass transfer are improved by the enlargement of the surface due to the usually about 25 to 80 mm large moldings.
- Known examples are the Raschig ring (a hollow cylinder), Pall ring, Hiflow ring, Intalox saddle and the like.
- the packing can be ordered, but also random (as a bed) are introduced into the column. Possible materials are glass, ceramics, metal and plastics. Structured packings are a further development of the ordered packing. They have a regularly shaped structure. This makes it possible for packings to reduce pressure losses in the gas flow.
- the temperature of the absorbent in the absorption step is generally about 30 to 100 ° C, using a column, for example 30 to 70 ° C at the top of the column and 50 to 100 ° C at the bottom of the column.
- the process according to the invention may comprise one or more, in particular two, successive absorption steps.
- the absorption can be carried out in several successive sub-steps, wherein the raw gas containing the acidic gas constituents in each of the substeps is brought into contact with a partial stream of the absorbent.
- the absorbent with which the raw gas is brought into contact may already be partially laden with acidic gases, ie it may be, for example, an absorbent which has been recycled from a subsequent absorption step to the first absorption step, or a partially regenerated absorbent.
- the performance of the two-stage absorption reference is made to the publications EP 0 159 495, EP 0 190 434, EP 0 359 991 and WO 00100271.
- the person skilled in the art can achieve a high degree of separation of hydrogen sulfide at a defined selectivity by determining the conditions in the absorption step, in particular the absorber / fluid flow ratio, the column height of the absorber, the type of contact-promoting internals in the absorber, such as fillers, trays or packings, and / or the residual loading of the regenerated absorbent varies.
- a low absorber / fluid flow ratio leads to increased selectivity, a higher absorber / fluid flow ratio leads to a more unselective absorption. Since CO2 is absorbed at a slower rate than H2S, more CO 2 is absorbed with a longer residence time than with a shorter residence time. A higher column therefore causes a more selective absorption. Bottoms or packs with larger liquid holdup also result in less selective absorption.
- the residual load of the regenerated absorbent can be adjusted. A lower residual loading of the regenerated absorbent leads to improved absorption.
- the method preferably comprises a regeneration step in which the CO2 and F S-laden absorbent is regenerated.
- the regeneration step CO2 and H2S and possibly other acidic gas constituents are released from the CO2- and Fs-laden absorption medium, a regenerated absorption medium being obtained.
- the regenerated absorbent is then returned to the absorption step.
- the regeneration step comprises at least one of heating, relaxing and stripping with an inert fluid.
- the regeneration step preferably comprises heating the absorbent laden with the acidic gas constituents, e.g. B. by means of a Aufkochers, natural circulation evaporator, forced circulation evaporator, or
- the absorbed acid gases are stripped off by means of the vapor obtained by heating the solution.
- an inert fluid such as nitrogen may also be used.
- the absolute pressure in the desorber is normally 0.1 to 3.5 bar, preferably 1, 0 to 2.5 bar.
- the temperature is usually from 50 ° C to 170 ° C, preferably from 80 ° C to 130 ° C, the temperature of course being dependent on the pressure.
- the regeneration step may alternatively or additionally include a pressure release. This involves at least a pressure release of the loaded absorbent from a high pressure, as it prevails in the implementation of the absorption step, to a lower pressure.
- the pressure release can be done for example by means of a throttle valve and / or an expansion turbine.
- the regeneration with a relaxation stage is described, for example, in the publications US Pat. Nos. 4,537,753 and 4,553,984.
- the release of the acidic gas constituents in the regeneration step for example, in a flash column, z. B. a vertically or horizontally installed flash tank or a countercurrent column with internals, done.
- the regeneration column may likewise be a packed, packed or tray column.
- the regeneration column has a heater at the bottom, z. B. a forced circulation evaporator with circulation pump. At the top, the regeneration column has an outlet for the liberated acid gases. Entrained absorbent vapors are condensed in a condenser and returned to the column. It can be connected in series, several relaxation columns in which is regenerated at different pressures. For example, in a precompression column at high pressure, which is typically about 1.5 bar above the partial pressure of the acidic gas constituents in the absorption step, and in a main depressurization column at low pressure, for example 1 to 2 bar abs. Regeneration with two or more flash stages is described in US Pat. Nos.
- the absorbent according to the invention has a high loadability with acidic gases, which can also be easily desorbed again. As a result, the energy consumption and the solvent circulation can be significantly reduced in the process according to the invention.
- FIG. 1 is a schematic representation of an apparatus suitable for carrying out the method according to the invention.
- a suitably pretreated gas containing hydrogen sulphide and carbon dioxide is brought into contact, via the supply line Z, in an absorber A1 with regenerated absorption medium, which is supplied via the absorption medium line 1.01, in countercurrent.
- the absorbent removes hydrogen sulfide and carbon dioxide by absorption from the gas; In this case, via the exhaust pipe 1.02 a depleted in hydrogen sulfide and carbon dioxide clean gas.
- the heat exchanger 1.04 in which the CO2 and F S-laden absorbent is heated with the heat of the regenerated absorbent fed via the absorption line 1 .05, and the absorbent line 1.06 is filled with CO2 and F s. loaded absorbent the desorption column D fed and regenerated.
- one or more expansion tank can be provided (not shown in Fig. 1), in which the CO2 and F S-laden absorbent on z. B. 3 to 15 bar is relaxed.
- the absorbent is fed to the reboiler 1 .07, where it is heated.
- the resulting vapor is returned to the desorption column D, while the regenerated absorbent via the absorbent tube 1 .05, the heat exchanger 1 .04 in which the regenerated absorbent heats the CO2 and F S-laden absorbent and thereby cools the absorbent line. 1 .08, the radiator 1 .09 and the absorbent line 1.01 the absorber A1 is supplied again.
- other types of heat exchangers can be used for energy input, such as a natural circulation evaporator, Forced circulation evaporator, or forced circulation evaporator.
- a mixed phase stream of regenerated absorbent and steam is returned to the bottom of the desorption column D, where the phase separation between the vapor and the absorbent takes place.
- the regenerated absorbent to the heat exchanger 1 .04 is withdrawn either from the recycle stream from the bottom of the desorption column D to the evaporator, or passed through a separate line directly from the bottom of the desorption column D to the heat exchanger 1 .04.
- the released in the desorption column D CO2 and h S-containing gas leaves the desorption column D via the exhaust pipe 1 .10. It is fed into a capacitor with integrated phase separation 1 .1 1, where it is separated by entrained absorbent vapor.
- condensation and phase separation may also be present separately from one another.
- the condensate is passed through the absorbent line 1 .12 in the upper region of the desorption column D, and carried out a CO2 and h S-containing gas via the gas line 1 .13. 0
- the following table shows the hydroxyl group density p of selected compounds.
- DEG Diethylene glycol
- PEGDME Polyethylene glycol dimethyl ether
- the sample to be analyzed was weighed into an aqueous solution containing about 2% by weight of sodium acetate and about 3% by weight of ammonia. Subsequently, the H2S content was determined by a potentiometric inflection point titration using silver nitrate solution. At the inflection point, H2S is completely bound as Ag2S.
- the CO 2 content was determined to be Total Inorganic Carbon (TOC-V Series Shimadzu).
- the loading of CO2 or H2S was identical after 3h and 4 h of test within the measurement accuracy.
- the H2S: C02 loading ratio was calculated as the quotient of the h S loading by the CO 2 loading.
- the apparatus was heated to 80 ° C, filled the loaded absorbent and stripped by nitrogen flow (8 Nl / h) at ambient pressure. After 30 minutes, a sample was taken and the CO2 or H S loading of the absorbent was determined as described above.
- Examples 1-1 to 1-4 and 1-5 to 1-8 show that the H2S: CO2 loading ratio increases with decreasing hydroxyl group density pAbs. Likewise, a decreasing hydroxyl group density pAbs causes improved regeneration, recognizable by low residual H2S and C02 after stripping. Too low a hydroxyl group density pAbs conditionally diminished CO2 and H2S loadabilities, as seen in Examples 1-8, 1-9, 1-10, 1-17 and 1-18.
Abstract
Description
Claims
Priority Applications (13)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
AU2016333399A AU2016333399A1 (en) | 2015-09-29 | 2016-09-14 | Absorption agent and a method for selectively removing hydrogen sulphide |
EP16775489.4A EP3356014A1 (de) | 2015-09-29 | 2016-09-14 | Absorptionsmittel und verfahren zur selektiven entfernung von schwefelwasserstoff |
KR1020187008432A KR20180059782A (ko) | 2015-09-29 | 2016-09-14 | 황화수소를 선택적으로 제거하기 위한 흡수제 및 방법 |
CN201680056400.1A CN108025248A (zh) | 2015-09-29 | 2016-09-14 | 吸收剂和选择性脱除硫化氢的方法 |
SG11201801195SA SG11201801195SA (en) | 2015-09-29 | 2016-09-14 | Absorption agent and a method for selectively removing hydrogen sulphide |
JP2018516465A JP2018531146A (ja) | 2015-09-29 | 2016-09-14 | 硫化水素の選択的除去のための吸収剤及び方法 |
CA3000030A CA3000030A1 (en) | 2015-09-29 | 2016-09-14 | Absorption agent and a method for selectively removing hydrogen sulphide |
US15/760,257 US20180257022A1 (en) | 2015-09-29 | 2016-09-14 | Absorption agent and a method for selectively removing hydrogen sulphide |
MX2018004013A MX2018004013A (es) | 2015-09-29 | 2016-09-14 | Agente de absorcion y un metodo para remover selectivamente sulfuro de hidrogeno. |
BR112018003735A BR112018003735A2 (pt) | 2015-09-29 | 2016-09-14 | ?absorvente e processo para a remoção seletiva do sulfeto de hidrogênio? |
IL257874A IL257874A (en) | 2015-09-29 | 2018-03-05 | Absorbent material and method for selective removal of hydrogen sulfide |
CONC2018/0003654A CO2018003654A2 (es) | 2015-09-29 | 2018-04-05 | Agente de absorción y un método para remover selectivamente sulfuro de hidrógeno |
ZA2018/02682A ZA201802682B (en) | 2015-09-29 | 2018-04-23 | Absorption agent and a method for selectively removing hydrogen sulphide |
Applications Claiming Priority (2)
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EP15187395 | 2015-09-29 | ||
EP15187395.7 | 2015-09-29 |
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PCT/EP2016/071700 WO2017055087A1 (de) | 2015-09-29 | 2016-09-14 | Absorptionsmittel und verfahren zur selektiven entfernung von schwefelwasserstoff |
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US (1) | US20180257022A1 (de) |
EP (1) | EP3356014A1 (de) |
JP (1) | JP2018531146A (de) |
KR (1) | KR20180059782A (de) |
CN (1) | CN108025248A (de) |
AU (1) | AU2016333399A1 (de) |
BR (1) | BR112018003735A2 (de) |
CA (1) | CA3000030A1 (de) |
CO (1) | CO2018003654A2 (de) |
IL (1) | IL257874A (de) |
MX (1) | MX2018004013A (de) |
SG (1) | SG11201801195SA (de) |
WO (1) | WO2017055087A1 (de) |
ZA (1) | ZA201802682B (de) |
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CN112191076A (zh) * | 2020-09-30 | 2021-01-08 | 内蒙古信度科技发展有限公司 | 一种吸收式除臭剂及其应用 |
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WO2018146233A1 (en) | 2017-02-10 | 2018-08-16 | Basf Se | Process for removal of acid gases from a fluid stream |
CN110650785B (zh) * | 2017-05-15 | 2022-05-24 | 巴斯夫欧洲公司 | 用于选择性脱除硫化氢的吸收剂和方法 |
WO2020053116A1 (en) * | 2018-09-10 | 2020-03-19 | Eni S.P.A: | Removal of sour gases from gas mixtures containing them |
CN113453784A (zh) * | 2019-02-18 | 2021-09-28 | 巴斯夫欧洲公司 | 从流体料流中脱除酸性气体的方法 |
IT202000028301A1 (it) * | 2020-11-25 | 2022-05-25 | Eni Spa | Rimozione di gas acidi da miscele gassose che li contengono. |
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US20150027055A1 (en) * | 2013-07-29 | 2015-01-29 | Exxonmobil Research And Engineering Company | Separation of hydrogen sulfide from natural gas |
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US8221712B2 (en) * | 2009-05-12 | 2012-07-17 | Basf Se | Absorption medium for the selective removal of hydrogen sulfide from fluid streams |
KR20150044856A (ko) * | 2012-05-31 | 2015-04-27 | 쉘 인터내셔날 리써취 마트샤피지 비.브이. | 황화수소의 선택적 흡수를 위한 흡수성 조성물 및 상기 조성물의 사용 프로세스 |
CN105637070A (zh) * | 2013-10-30 | 2016-06-01 | 陶氏环球技术有限责任公司 | 用于选择性h2s去除的混合溶剂调配物 |
WO2016057499A1 (en) * | 2014-10-10 | 2016-04-14 | Dow Global Technologies Llc | Aqueous solution of 2-dimethylamino-2-hydroxymethyl-1, 3-propanediol useful for acid gas removal from gaseous mixtures |
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2016
- 2016-09-14 JP JP2018516465A patent/JP2018531146A/ja active Pending
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- 2016-09-14 CA CA3000030A patent/CA3000030A1/en not_active Abandoned
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- 2016-09-14 BR BR112018003735A patent/BR112018003735A2/pt not_active Application Discontinuation
- 2016-09-14 KR KR1020187008432A patent/KR20180059782A/ko unknown
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- 2016-09-14 WO PCT/EP2016/071700 patent/WO2017055087A1/de active Application Filing
- 2016-09-14 EP EP16775489.4A patent/EP3356014A1/de not_active Withdrawn
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- 2018-04-05 CO CONC2018/0003654A patent/CO2018003654A2/es unknown
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KR20180059782A (ko) | 2018-06-05 |
EP3356014A1 (de) | 2018-08-08 |
MX2018004013A (es) | 2018-05-23 |
BR112018003735A2 (pt) | 2018-09-25 |
ZA201802682B (en) | 2019-07-31 |
JP2018531146A (ja) | 2018-10-25 |
AU2016333399A1 (en) | 2018-03-29 |
CO2018003654A2 (es) | 2018-08-21 |
IL257874A (en) | 2018-05-31 |
CA3000030A1 (en) | 2017-04-06 |
US20180257022A1 (en) | 2018-09-13 |
CN108025248A (zh) | 2018-05-11 |
SG11201801195SA (en) | 2018-04-27 |
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