AU2014303002A1 - Reducing sugar-based sulfide scavengers and methods of use in subterranean operations - Google Patents
Reducing sugar-based sulfide scavengers and methods of use in subterranean operations Download PDFInfo
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- AU2014303002A1 AU2014303002A1 AU2014303002A AU2014303002A AU2014303002A1 AU 2014303002 A1 AU2014303002 A1 AU 2014303002A1 AU 2014303002 A AU2014303002 A AU 2014303002A AU 2014303002 A AU2014303002 A AU 2014303002A AU 2014303002 A1 AU2014303002 A1 AU 2014303002A1
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- Prior art keywords
- sulfide
- fluid
- treatment fluid
- ions
- fluids
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Links
- 238000000034 method Methods 0.000 title claims abstract description 50
- 235000000346 sugar Nutrition 0.000 title claims abstract description 40
- UCKMPCXJQFINFW-UHFFFAOYSA-N Sulphide Chemical compound [S-2] UCKMPCXJQFINFW-UHFFFAOYSA-N 0.000 title claims abstract description 37
- 239000012530 fluid Substances 0.000 claims abstract description 149
- 239000000654 additive Substances 0.000 claims abstract description 73
- 238000011282 treatment Methods 0.000 claims abstract description 40
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 claims abstract description 33
- 230000002000 scavenging effect Effects 0.000 claims abstract description 33
- -1 sulfide ions Chemical class 0.000 claims abstract description 33
- 229910000037 hydrogen sulfide Inorganic materials 0.000 claims abstract description 31
- 239000007788 liquid Substances 0.000 claims abstract description 25
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 24
- 230000000996 additive effect Effects 0.000 claims abstract description 22
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 claims abstract description 21
- 150000008163 sugars Chemical class 0.000 claims abstract description 20
- 229910052717 sulfur Inorganic materials 0.000 claims abstract description 16
- 239000011593 sulfur Substances 0.000 claims abstract description 15
- 239000002244 precipitate Substances 0.000 claims abstract description 8
- 238000005553 drilling Methods 0.000 claims description 24
- 229910021645 metal ion Inorganic materials 0.000 claims description 15
- 239000002585 base Substances 0.000 claims description 9
- 239000000047 product Substances 0.000 claims description 8
- 150000001299 aldehydes Chemical class 0.000 claims description 6
- 239000003637 basic solution Substances 0.000 claims description 4
- 229910052976 metal sulfide Inorganic materials 0.000 claims description 4
- 229930091371 Fructose Natural products 0.000 claims description 3
- 239000005715 Fructose Substances 0.000 claims description 3
- RFSUNEUAIZKAJO-ARQDHWQXSA-N Fructose Chemical compound OC[C@H]1O[C@](O)(CO)[C@@H](O)[C@@H]1O RFSUNEUAIZKAJO-ARQDHWQXSA-N 0.000 claims description 3
- 230000000149 penetrating effect Effects 0.000 claims 1
- 238000005755 formation reaction Methods 0.000 abstract description 18
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 10
- 239000000203 mixture Substances 0.000 description 8
- 239000003795 chemical substances by application Substances 0.000 description 7
- 239000007789 gas Substances 0.000 description 7
- 238000006243 chemical reaction Methods 0.000 description 6
- 229930195733 hydrocarbon Natural products 0.000 description 6
- 150000002430 hydrocarbons Chemical class 0.000 description 6
- 230000014759 maintenance of location Effects 0.000 description 6
- 238000012545 processing Methods 0.000 description 6
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 6
- 230000008901 benefit Effects 0.000 description 5
- 150000001875 compounds Chemical class 0.000 description 5
- 239000004215 Carbon black (E152) Substances 0.000 description 4
- CWYNVVGOOAEACU-UHFFFAOYSA-N Fe2+ Chemical compound [Fe+2] CWYNVVGOOAEACU-UHFFFAOYSA-N 0.000 description 4
- 238000002156 mixing Methods 0.000 description 4
- 150000003839 salts Chemical class 0.000 description 4
- MBMLMWLHJBBADN-UHFFFAOYSA-N Ferrous sulfide Chemical compound [Fe]=S MBMLMWLHJBBADN-UHFFFAOYSA-N 0.000 description 3
- 229950003768 ferric fructose Drugs 0.000 description 3
- 229910052742 iron Inorganic materials 0.000 description 3
- 238000004519 manufacturing process Methods 0.000 description 3
- SPNHUEKXVKBAQQ-WMUOJARJSA-N potassium;(2s,3s,4r,5r)-2-(hydroxymethyl)oxane-2,3,4,5-tetrol;iron(3+) Chemical compound [K+].[Fe+3].OC[C@]1(O)OC[C@@H](O)[C@@H](O)[C@@H]1O SPNHUEKXVKBAQQ-WMUOJARJSA-N 0.000 description 3
- 150000004763 sulfides Chemical class 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 2
- SRBFZHDQGSBBOR-IOVATXLUSA-N D-xylopyranose Chemical compound O[C@@H]1COC(O)[C@H](O)[C@H]1O SRBFZHDQGSBBOR-IOVATXLUSA-N 0.000 description 2
- MHAJPDPJQMAIIY-UHFFFAOYSA-N Hydrogen peroxide Chemical compound OO MHAJPDPJQMAIIY-UHFFFAOYSA-N 0.000 description 2
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 2
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 2
- CZMRCDWAGMRECN-UGDNZRGBSA-N Sucrose Chemical compound O[C@H]1[C@H](O)[C@@H](CO)O[C@@]1(CO)O[C@@H]1[C@H](O)[C@@H](O)[C@H](O)[C@@H](CO)O1 CZMRCDWAGMRECN-UGDNZRGBSA-N 0.000 description 2
- 229930006000 Sucrose Natural products 0.000 description 2
- 239000005864 Sulphur Substances 0.000 description 2
- PYMYPHUHKUWMLA-UHFFFAOYSA-N arabinose Natural products OCC(O)C(O)C(O)C=O PYMYPHUHKUWMLA-UHFFFAOYSA-N 0.000 description 2
- SRBFZHDQGSBBOR-UHFFFAOYSA-N beta-D-Pyranose-Lyxose Natural products OC1COC(O)C(O)C1O SRBFZHDQGSBBOR-UHFFFAOYSA-N 0.000 description 2
- 230000007797 corrosion Effects 0.000 description 2
- 238000005260 corrosion Methods 0.000 description 2
- 239000000839 emulsion Substances 0.000 description 2
- 230000007613 environmental effect Effects 0.000 description 2
- 230000036541 health Effects 0.000 description 2
- 230000003993 interaction Effects 0.000 description 2
- 230000007246 mechanism Effects 0.000 description 2
- 150000001455 metallic ions Chemical class 0.000 description 2
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 239000003921 oil Substances 0.000 description 2
- 238000007254 oxidation reaction Methods 0.000 description 2
- 238000012856 packing Methods 0.000 description 2
- 230000001105 regulatory effect Effects 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 239000005720 sucrose Substances 0.000 description 2
- OWEGMIWEEQEYGQ-UHFFFAOYSA-N 100676-05-9 Natural products OC1C(O)C(O)C(CO)OC1OCC1C(O)C(O)C(O)C(OC2C(OC(O)C(O)C2O)CO)O1 OWEGMIWEEQEYGQ-UHFFFAOYSA-N 0.000 description 1
- MSWZFWKMSRAUBD-IVMDWMLBSA-N 2-amino-2-deoxy-D-glucopyranose Chemical compound N[C@H]1C(O)O[C@H](CO)[C@@H](O)[C@@H]1O MSWZFWKMSRAUBD-IVMDWMLBSA-N 0.000 description 1
- GUBGYTABKSRVRQ-XLOQQCSPSA-N Alpha-Lactose Chemical compound O[C@@H]1[C@@H](O)[C@@H](O)[C@@H](CO)O[C@H]1O[C@@H]1[C@@H](CO)O[C@H](O)[C@H](O)[C@H]1O GUBGYTABKSRVRQ-XLOQQCSPSA-N 0.000 description 1
- RYGMFSIKBFXOCR-UHFFFAOYSA-N Copper Chemical compound [Cu] RYGMFSIKBFXOCR-UHFFFAOYSA-N 0.000 description 1
- 239000005749 Copper compound Substances 0.000 description 1
- GUBGYTABKSRVRQ-CUHNMECISA-N D-Cellobiose Chemical compound O[C@@H]1[C@@H](O)[C@H](O)[C@@H](CO)O[C@H]1O[C@@H]1[C@@H](CO)OC(O)[C@H](O)[C@H]1O GUBGYTABKSRVRQ-CUHNMECISA-N 0.000 description 1
- YTBSYETUWUMLBZ-UHFFFAOYSA-N D-Erythrose Natural products OCC(O)C(O)C=O YTBSYETUWUMLBZ-UHFFFAOYSA-N 0.000 description 1
- YTBSYETUWUMLBZ-IUYQGCFVSA-N D-erythrose Chemical compound OC[C@@H](O)[C@@H](O)C=O YTBSYETUWUMLBZ-IUYQGCFVSA-N 0.000 description 1
- SHZGCJCMOBCMKK-UHFFFAOYSA-N D-mannomethylose Natural products CC1OC(O)C(O)C(O)C1O SHZGCJCMOBCMKK-UHFFFAOYSA-N 0.000 description 1
- WQZGKKKJIJFFOK-QTVWNMPRSA-N D-mannopyranose Chemical compound OC[C@H]1OC(O)[C@@H](O)[C@@H](O)[C@@H]1O WQZGKKKJIJFFOK-QTVWNMPRSA-N 0.000 description 1
- HMFHBZSHGGEWLO-SOOFDHNKSA-N D-ribofuranose Chemical compound OC[C@H]1OC(O)[C@H](O)[C@@H]1O HMFHBZSHGGEWLO-SOOFDHNKSA-N 0.000 description 1
- ZAQJHHRNXZUBTE-NQXXGFSBSA-N D-ribulose Chemical compound OC[C@@H](O)[C@@H](O)C(=O)CO ZAQJHHRNXZUBTE-NQXXGFSBSA-N 0.000 description 1
- ZAQJHHRNXZUBTE-UHFFFAOYSA-N D-threo-2-Pentulose Natural products OCC(O)C(O)C(=O)CO ZAQJHHRNXZUBTE-UHFFFAOYSA-N 0.000 description 1
- 206010056474 Erythrosis Diseases 0.000 description 1
- OTMSDBZUPAUEDD-UHFFFAOYSA-N Ethane Chemical compound CC OTMSDBZUPAUEDD-UHFFFAOYSA-N 0.000 description 1
- VTLYFUHAOXGGBS-UHFFFAOYSA-N Fe3+ Chemical compound [Fe+3] VTLYFUHAOXGGBS-UHFFFAOYSA-N 0.000 description 1
- WQZGKKKJIJFFOK-GASJEMHNSA-N Glucose Natural products OC[C@H]1OC(O)[C@H](O)[C@@H](O)[C@@H]1O WQZGKKKJIJFFOK-GASJEMHNSA-N 0.000 description 1
- 239000005909 Kieselgur Substances 0.000 description 1
- SHZGCJCMOBCMKK-JFNONXLTSA-N L-rhamnopyranose Chemical compound C[C@@H]1OC(O)[C@H](O)[C@H](O)[C@H]1O SHZGCJCMOBCMKK-JFNONXLTSA-N 0.000 description 1
- PNNNRSAQSRJVSB-UHFFFAOYSA-N L-rhamnose Natural products CC(O)C(O)C(O)C(O)C=O PNNNRSAQSRJVSB-UHFFFAOYSA-N 0.000 description 1
- GUBGYTABKSRVRQ-QKKXKWKRSA-N Lactose Natural products OC[C@H]1O[C@@H](O[C@H]2[C@H](O)[C@@H](O)C(O)O[C@@H]2CO)[C@H](O)[C@@H](O)[C@H]1O GUBGYTABKSRVRQ-QKKXKWKRSA-N 0.000 description 1
- DUKURNFHYQXCJG-UHFFFAOYSA-N Lewis A pentasaccharide Natural products OC1C(O)C(O)C(C)OC1OC1C(OC2C(C(O)C(O)C(CO)O2)O)C(NC(C)=O)C(OC2C(C(OC3C(OC(O)C(O)C3O)CO)OC(CO)C2O)O)OC1CO DUKURNFHYQXCJG-UHFFFAOYSA-N 0.000 description 1
- GUBGYTABKSRVRQ-PICCSMPSSA-N Maltose Natural products O[C@@H]1[C@@H](O)[C@H](O)[C@@H](CO)O[C@@H]1O[C@@H]1[C@@H](CO)OC(O)[C@H](O)[C@H]1O GUBGYTABKSRVRQ-PICCSMPSSA-N 0.000 description 1
- OVRNDRQMDRJTHS-FMDGEEDCSA-N N-acetyl-beta-D-glucosamine Chemical compound CC(=O)N[C@H]1[C@H](O)O[C@H](CO)[C@@H](O)[C@@H]1O OVRNDRQMDRJTHS-FMDGEEDCSA-N 0.000 description 1
- 229940123973 Oxygen scavenger Drugs 0.000 description 1
- PYMYPHUHKUWMLA-LMVFSUKVSA-N Ribose Natural products OC[C@@H](O)[C@@H](O)[C@@H](O)C=O PYMYPHUHKUWMLA-LMVFSUKVSA-N 0.000 description 1
- HCHKCACWOHOZIP-UHFFFAOYSA-N Zinc Chemical compound [Zn] HCHKCACWOHOZIP-UHFFFAOYSA-N 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 150000007513 acids Chemical class 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- HMFHBZSHGGEWLO-UHFFFAOYSA-N alpha-D-Furanose-Ribose Natural products OCC1OC(O)C(O)C1O HMFHBZSHGGEWLO-UHFFFAOYSA-N 0.000 description 1
- WQZGKKKJIJFFOK-PHYPRBDBSA-N alpha-D-galactose Chemical compound OC[C@H]1O[C@H](O)[C@H](O)[C@@H](O)[C@H]1O WQZGKKKJIJFFOK-PHYPRBDBSA-N 0.000 description 1
- SRBFZHDQGSBBOR-STGXQOJASA-N alpha-D-lyxopyranose Chemical compound O[C@@H]1CO[C@H](O)[C@@H](O)[C@H]1O SRBFZHDQGSBBOR-STGXQOJASA-N 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 239000002518 antifoaming agent Substances 0.000 description 1
- PYMYPHUHKUWMLA-WDCZJNDASA-N arabinose Chemical compound OC[C@@H](O)[C@@H](O)[C@H](O)C=O PYMYPHUHKUWMLA-WDCZJNDASA-N 0.000 description 1
- MSWZFWKMSRAUBD-UHFFFAOYSA-N beta-D-galactosamine Natural products NC1C(O)OC(CO)C(O)C1O MSWZFWKMSRAUBD-UHFFFAOYSA-N 0.000 description 1
- WQZGKKKJIJFFOK-VFUOTHLCSA-N beta-D-glucose Chemical compound OC[C@H]1O[C@@H](O)[C@H](O)[C@@H](O)[C@@H]1O WQZGKKKJIJFFOK-VFUOTHLCSA-N 0.000 description 1
- GUBGYTABKSRVRQ-QUYVBRFLSA-N beta-maltose Chemical compound OC[C@H]1O[C@H](O[C@H]2[C@H](O)[C@@H](O)[C@H](O)O[C@@H]2CO)[C@H](O)[C@@H](O)[C@@H]1O GUBGYTABKSRVRQ-QUYVBRFLSA-N 0.000 description 1
- 239000003139 biocide Substances 0.000 description 1
- 239000012267 brine Substances 0.000 description 1
- 150000001720 carbohydrates Chemical class 0.000 description 1
- 239000001569 carbon dioxide Substances 0.000 description 1
- 229910002092 carbon dioxide Inorganic materials 0.000 description 1
- 230000015556 catabolic process Effects 0.000 description 1
- 239000003054 catalyst Substances 0.000 description 1
- 230000009920 chelation Effects 0.000 description 1
- 239000007795 chemical reaction product Substances 0.000 description 1
- 239000003638 chemical reducing agent Substances 0.000 description 1
- 239000004927 clay Substances 0.000 description 1
- 239000011248 coating agent Substances 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000004891 communication Methods 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 229910052802 copper Inorganic materials 0.000 description 1
- 239000010949 copper Substances 0.000 description 1
- 150000001880 copper compounds Chemical class 0.000 description 1
- 239000007857 degradation product Substances 0.000 description 1
- 238000006731 degradation reaction Methods 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 229910003460 diamond Inorganic materials 0.000 description 1
- 239000010432 diamond Substances 0.000 description 1
- 150000002016 disaccharides Chemical class 0.000 description 1
- 239000002270 dispersing agent Substances 0.000 description 1
- 230000009977 dual effect Effects 0.000 description 1
- 150000002148 esters Chemical class 0.000 description 1
- 229910001447 ferric ion Inorganic materials 0.000 description 1
- 239000008394 flocculating agent Substances 0.000 description 1
- 239000006260 foam Substances 0.000 description 1
- 239000008398 formation water Substances 0.000 description 1
- 239000012634 fragment Substances 0.000 description 1
- 239000013505 freshwater Substances 0.000 description 1
- 229930182830 galactose Natural products 0.000 description 1
- 239000000499 gel Substances 0.000 description 1
- 229960002442 glucosamine Drugs 0.000 description 1
- 239000008103 glucose Substances 0.000 description 1
- 150000004676 glycans Chemical class 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 125000004435 hydrogen atom Chemical class [H]* 0.000 description 1
- 239000003112 inhibitor Substances 0.000 description 1
- 150000002506 iron compounds Chemical class 0.000 description 1
- KAEAMHPPLLJBKF-UHFFFAOYSA-N iron(3+) sulfide Chemical compound [S-2].[S-2].[S-2].[Fe+3].[Fe+3] KAEAMHPPLLJBKF-UHFFFAOYSA-N 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 239000008101 lactose Substances 0.000 description 1
- 239000000314 lubricant Substances 0.000 description 1
- WPBNNNQJVZRUHP-UHFFFAOYSA-L manganese(2+);methyl n-[[2-(methoxycarbonylcarbamothioylamino)phenyl]carbamothioyl]carbamate;n-[2-(sulfidocarbothioylamino)ethyl]carbamodithioate Chemical compound [Mn+2].[S-]C(=S)NCCNC([S-])=S.COC(=O)NC(=S)NC1=CC=CC=C1NC(=S)NC(=O)OC WPBNNNQJVZRUHP-UHFFFAOYSA-L 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 229910000000 metal hydroxide Inorganic materials 0.000 description 1
- 150000004692 metal hydroxides Chemical class 0.000 description 1
- 239000002480 mineral oil Substances 0.000 description 1
- 239000003607 modifier Substances 0.000 description 1
- 238000012544 monitoring process Methods 0.000 description 1
- 150000002772 monosaccharides Chemical class 0.000 description 1
- 229950006780 n-acetylglucosamine Drugs 0.000 description 1
- 229910052759 nickel Inorganic materials 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 230000003647 oxidation Effects 0.000 description 1
- 239000011236 particulate material Substances 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 229920001282 polysaccharide Polymers 0.000 description 1
- 239000005017 polysaccharide Substances 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 230000000069 prophylactic effect Effects 0.000 description 1
- 238000004064 recycling Methods 0.000 description 1
- 239000011347 resin Substances 0.000 description 1
- 229920005989 resin Polymers 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 239000002455 scale inhibitor Substances 0.000 description 1
- 239000013535 sea water Substances 0.000 description 1
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 125000006850 spacer group Chemical group 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 239000000725 suspension Substances 0.000 description 1
- 231100000419 toxicity Toxicity 0.000 description 1
- 230000001988 toxicity Effects 0.000 description 1
- 150000003918 triazines Chemical class 0.000 description 1
- 231100000925 very toxic Toxicity 0.000 description 1
- 239000000080 wetting agent Substances 0.000 description 1
- 239000011701 zinc Substances 0.000 description 1
- 229910052725 zinc Inorganic materials 0.000 description 1
- 150000003752 zinc compounds Chemical class 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/06—Arrangements for treating drilling fluids outside the borehole
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
- C09K8/532—Sulfur
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/20—Hydrogen sulfide elimination
Landscapes
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Chemical & Material Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Mechanical Engineering (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Inorganic Chemistry (AREA)
- Solid-Sorbent Or Filter-Aiding Compositions (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Treating Waste Gases (AREA)
- Treatment Of Water By Oxidation Or Reduction (AREA)
- Gas Separation By Absorption (AREA)
- Processing Of Solid Wastes (AREA)
Abstract
Improved methods and additives for eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids are provided. In one embodiment, the methods comprise: providing a treatment fluid comprising a base liquid and a sulfide scavenging additive comprising one or more reducing sugars; introducing the treatment fluid into at least a portion of a subterranean formation; and allowing at least a portion of the sulfide scavenging additive to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a precipitate comprising one or more sulfur species.
Description
WO 2014/209639 PCT/US2014/042361 REDUCING SUGAR-BASED SULFIDE SCAVENGERS AND METHODS OF USE IN SUBTERRANEAN OPERATIONS BACKGROUND 5 [0001] This application claims priority to U.S. Patent Application Serial No. 13/927,714, filed June 26, 2013, the entire contents of which are incorporated by reference herein. [0002] The present disclosure relates to fluids, additives, and methods for use in subterranean operations, and more specifically, to improved methods and additives for 0 eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids. [0003] Hydrocarbon producing wells may contain many different formation liquids and gases such as methane, ethane, and other higher hydrocarbons, as well as hydrogen sulfide, water, and other compounds. In order to evaluate the commercial value of a hydrocarbon 5 producing well, or as an aid in operations and well planning, it is often useful to obtain information by analyzing the component concentrations of the produced fluid from a formation or an individual well. Numerous systems have been developed to evaluate a downhole fluid composition and the relative component concentrations in the downhole fluid. [0004] Hydrogen sulfide (H 2 S) is a very toxic, flammable, and pungent gas that 0 causes numerous problems in various aspects of the oil and gas industry. H2S is extremely corrosive to metal, which may damage or destroy tubing, casings, or other types of well bore equipment. H 2 S also presents health risks to operations personnel that may be exposed to H 2 S gas at a well site or in processing of well bore fluids. Severe iron sulfide scaling may also choke production, either in the production piping, perforations or within the producing formation itself. 5 Thus, it is typically desirable to reduce or eliminate sulfides from subterranean formations and well bores, among other reasons, to control corrosion rates and to plan for safe development and production of the hydrocarbons. [0005] The release of H 2 S gas can sometimes be controlled by maintaining the pH of the fluid containing H 2 S above 10. However, in many cases, it is not practical or possible 0 to maintain this level pH in a fluid for extended periods of time. Sulfide scavengers are often used to react with H 2 S and convert it to a more inert form. Conventional H 2 S scavengers include certain aldehydes, certain amine-based chemicals, triazines, copper compounds, hydrogen peroxide, zinc compounds, and iron compounds. However, the reaction products of many of these compounds with H 2 S are poorly soluble in treatment fluids and/or fluids in the well bore, 1 WO 2014/209639 PCT/US2014/042361 or may decompose, thereby releasing H 2 S. Moreover, many conventional sulfide scavengers themselves may have undesirable environmental and/or toxicity problems, and as such may be impractical to use or prohibited altogether in certain circumstances and/or jurisdictions. 5 2 WO 2014/209639 PCT/US2014/042361 SUMMARY [0006] The present disclosure relates to fluids, additives, and methods for use in subterranean operations, and more specifically, to improved methods and additives for 5 eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids. [0007] In one embodiment, the present disclosure provides a method comprising: providing a treatment fluid comprising a base liquid and a sulfide scavenging additive comprising one or more reducing sugars; introducing the treatment fluid into at least a portion of 0 a subterranean formation; and allowing at least a portion of the sulfide scavenging additive to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a precipitate comprising one or more sulfur species. [0008] In another embodiment, the present disclosure provides a method comprising: providing a treatment fluid comprising a base liquid and a sulfide scavenging 5 additive comprising one or more reducing sugars chelated with one or more metal ions; introducing the treatment fluid into at least a portion of a subterranean formation; allowing at least one of the metal ions to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a first product comprising one or more sulfur species; and allowing the reducing sugar to interact with hydrogen sulfide or sulfide ions present in the treatment fluid 0 to produce a second product comprising one or more sulfur species. [0009] In another embodiment, the present disclosure provides a method of treating a fluid comprising a first concentration of hydrogen sulfide or sulfide ions, the method comprising: adding a sulfide scavenging additive comprising one or more reducing sugars to the fluid; and allowing at least a portion of the sulfide scavenging additive to interact with at least a 5 portion of the hydrogen sulfide or sulfide ions in the fluid to reduce the concentration of hydrogen sulfide or sulfide ions to a second concentration that is lower than the first concentration. [0010] The features and advantages of the present disclosure will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in 0 the art, such changes are within the spirit of the disclosure. 3 WO 2014/209639 PCT/US2014/042361 BRIEF DESCRIPTION OF THE FIGURES [0011] Some specific example embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings. 5 [0012] Figure 1 illustrates an example of a well bore drilling assembly that may be used in accordance with certain embodiments of the present disclosure. [0013] While the present disclosure is susceptible to various modifications and alternative forms, specific example embodiments have been shown in the figures and are herein described in more detail. It should be understood, however, that the description of specific 0 example embodiments is not intended to limit the invention to the particular forms disclosed. On the contrary, this disclosure is to cover all modifications and equivalents as illustrated, in part, by the appended claims. 4 WO 2014/209639 PCT/US2014/042361 DESCRIPTION OF PREFERRED EMBODIMENTS [0014] The present disclosure relates to fluids, additives, and methods for use in subterranean operations, and more specifically, to improved methods and additives for 5 eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids. [0015] The fluids and sulfide scavenging additives of the present disclosure generally comprise one or more reducing sugars. The term "reducing sugar" is defined herein to include any saccharide that includes an aldehyde functional group or can isomerize to form an 0 aldehyde functional group in basic solution. In certain embodiments, the fluids and sulfide scavenging additives of the present disclosure may be substantially free of compounds having aldehyde functional group prior to placement in basic solution. In certain embodiments, the reducing sugar may be chelated with a metal ion, such as iron. When added to a fluid comprising a liquid, a chelated reducing sugar may interact with H 2 S and/or sulfide ions present 5 in the fluid to produce one or more sulfur species (e.g., metal sulfides (such as Fe 2
S
3 and FeS) and elemental sulfur), inter alia, in the form of a precipitate that can be removed from the liquid. In certain embodiments, this may be accomplished without further oxidization of the metal ions. [0016] Among the many potential advantages of the present disclosure, the methods and compositions of the present disclosure may, among other things, provide a means 0 of reducing or eliminating concentrations of hydrogen sulfide or soluble sulfide ions in fluids found and/or used in subterranean formations with significantly less risk of environmental damage and/or health and safety hazards. Such methods and compositions may be more compatible with regulatory requirements in various jurisdictions. The sulfide scavenging additives of the present disclosure comprising one or more reducing sugars may be effective at a 5 wider range of pH levels (e.g., pH ranges above about 8) than other sulfide scavenging additives known in the art, and may reduce or eliminate concentrations of hydrogen sulfide or soluble sulfide ions in fluids more effectively. The methods and compositions of the present disclosure also may be more cost effective than other sulfide scavenging methods and additives known in the art. 0 [0017] The reducing sugars used in the methods, fluids, and sulfide scavenging additives of the present disclosure may comprise any reducing sugar (or combination thereof) known in the art. Such reducing sugars may comprise monosaccharides, disaccharides, polysaccharides, and/or combinations thereof. Examples of reducing sugars that may be suitable 5 WO 2014/209639 PCT/US2014/042361 for use in certain embodiments of the present disclosure include, but are not limited to, glucose, glucosamine, acetyl glucosamine, fructose, sucrose, lactose, maltose, cellobiose, galactose, mannose, ribose, ribulose, xylose, lyxose, rhamnose, arabinose, erythrose, and/or combinations thereof. In certain embodiments, the reducing sugars used in the methods, fluids, and sulfide 5 scavenging additives of the present disclosure may have a molecular weight of from about 180 daltons to about 360 daltons. The reducing sugar optionally may be chelated with any metal ion known in the art, including but not limited to iron, zinc, copper, nickel, manganese, and the like. Chelated reducing sugars that may be suitable for use in certain embodiments of the present disclosure include, but are not limited to, ferric fructose, ferrous sucrose, and the like. 0 [0018] The sulfide scavenging additives used in the present disclosure may exhibit, among other features, an enhanced ability to scavenge sulfides as compared to conventional sulfide scavengers due, at least in part, to the manner in which they react with sulfides and other components of the fluid. In particular, sulfide scavenging additives of the present disclosure that comprise one or more metal ions chelated with reducing sugars may 5 exhibit a dual sulfide scavenging mechanism wherein the metal ion and the reducing sugar each interact with hydrogen sulfide or sulfide ions to produce different products that may be precipitated or otherwise removed from of the fluid. The interaction of the metal ions with hydrogen sulfide or sulfide ions may proceed according to one or more reactions similar those discussed in paragraph [0015] below. The interaction of the reducing sugar with hydrogen 0 sulfide or sulfide ions may involve the degradation of the reducing sugar and the reaction of those degradation products with hydrogen sulfide or sulfide ions. Alternatively, the reducing sugar may interact with hydrogen sulfide or sulfide ions to form an intermediate sulfur containing compound, the sugar moiety in which may fragment to form other sulfur containing species. The chelation of the reducing sugar with the metal ion also may inhibit the conversion 5 of the metal ion to a metal hydroxide, leaving the metal ion free to interact with and/or scavenge hydrogen sulfide or sulfide ions present in the fluid. However, the reaction mechanisms disclosed herein are provided only as non-limiting illustrations of how the sulfide scavenging additives of the present disclosure may react in certain embodiments, and are not intended to limit the scope of the claims. 0 [0019] One example of a sulfide scavenging additive that may be suitable for use in the present disclosure comprises ferric fructose. In those embodiments, the iron (III) ions in the ferric fructose may react with hydrogen sulfide to produce iron (III) sulfide (Fe 2
S
3 ). Additionally, the iron (III) ions may be reduced by hydrogen sulfide to their iron (II) oxidation state, producing elemental sulfur (SO) (see Equation (1) below). The reduced iron (II) ion may 6 WO 2014/209639 PCT/US2014/042361 react with additional hydrogen sulfides to produce iron (II) sulfide (FeS) (see Equation (2) below).
H
2 S + 2Fe" -> S' + 2Fe 2 + 2H (1)
H
2 S + Fe2+ -> FeS + 2H+ (2) 5 In this process, the overall result for the ferric ion in this embodiment of the present disclosure may be expressed according to Equation (3) below: 2H 2 S + 2Fe 3 -> S' + 2FeS + 4H (3) The elemental sulfur and iron (II) sulfide may form a precipitate in the fluid being treated, which may be removed from the fluid. Similar reactions may occur using metallic ions other than iron. 0 In embodiments where divalent metallic ions are used, elemental sulfur may not be formed. In addition to the reactions above, the fructose may interact with hydrogen sulfide or sulfide ions to produce various sulfur species that may precipitate or be removed from the fluid being treated. [0020] The reducing sugar (or chelated reducing sugar) may be added to or included in a fluid in any concentration that effectively eliminates or reduces by the desired 5 amount concentrations of H 2 S or sulfide ions that are present or expected to be present in the fluid. For example, the reducing sugar may be added in a stoichiometric amount relative to the estimated amount of H 2 S or sulfide ions in the fluid. In certain embodiments, the reducing sugar may be present a fluid in a concentration of about 0.1 to 5 pounds per barrel. As discussed below, an initial amount of the sulfide scavenging additives of the present disclosure comprising 0 one or more reducing sugars may be added to a fluid, and subsequently, additional amounts of the sulfide scavenging additives of the present disclosure may be added to the same fluid. This technique may be used, among other purposes, to increase and/or maintain a concentration of the reducing sugar that is sufficient to effectively eliminate or reduce by the desired amount concentrations of H 2 S or sulfide ions in the fluid throughout the course of a given operation. 5 [0021] The additives of the present disclosure may be used in conjunction with any fluid, which may include, but are not limited to, treatment fluids introduced into a subterranean formation as well as fluids found in a subterranean formation (e.g., formation water, hydrocarbon fluids, etc.) and/or any combination thereof. The treatment fluids and formation fluids in the present disclosure generally comprise a base liquid, which may comprise 0 any liquid known in the art, such as aqueous liquids, non-aqueous liquids, or any mixture thereof. Where the base liquid comprises an aqueous liquid, it may comprise fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), or seawater. Generally, the water can be from any source, provided that it does not contain compounds that adversely affect other components of the fluid. Where the base liquid 7 WO 2014/209639 PCT/US2014/042361 comprises a non-aqueous liquid, it may comprise any number of organic liquids. Examples of suitable organic liquids include, but are not limited to, mineral oils, synthetic oils, esters, and the like. In certain embodiments, the treatment fluids and/or formation fluids in the present disclosure may comprise emulsions (including invert emulsions), suspensions, gels, foams, or 5 other mixtures of liquids with solids and/or gases. [0022] The fluids used in the present disclosure optionally may comprise any number of additional additives, including, but not limited to, salts, surfactants, acids, fluid loss control additives, gas, nitrogen, carbon dioxide, surface modifying agents, tackifying agents, foamers, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, friction .0 reducers, antifoam agents, bridging agents, dispersants, flocculants, additional H2S scavengers,
CO
2 scavengers, oxygen scavengers, lubricants, viscosifiers, breakers, weighting agents, relative permeability modifiers, resins, particulate materials (e.g., proppant particulates), wetting agents, coating enhancement agents, and the like. A person skilled in the art, with the benefit of this disclosure, will recognize the types of additives that may be included in the fluids of the present 5 disclosure for a particular application. [0023] The methods, fluids, and/or additives of the present disclosure may be used during or in conjunction with any subterranean operation wherein a fluid is used or treated. In certain embodiments, the methods, fluids, and/or additives of the present disclosure may be used in the course of drilling operations. In these embodiments, the methods, fluids, and/or .0 additives of the present disclosure may be used to reduce or eliminate concentrations of H 2 S from a drilling fluid used in drilling a well or borehole, for example, in a hydrocarbon-bearing subterranean formation where H 2 S is often encountered. Other suitable subterranean operations may include, but are not limited to, preflush treatments, afterflush treatments, hydraulic fracturing treatments, sand control treatments (e.g., gravel packing), acidizing treatments (e.g., !5 matrix acidizing or fracture acidizing), "frac-pack" treatments, well bore clean-out treatments, and other operations where a treatment fluid may be useful. Such treatment fluids may include, but are not limited to, drilling fluids, preflush fluids, afterflush fluids, fracturing fluids, acidizing fluids, gravel packing fluids, packer fluids, spacer fluids, and the like. [0024] The reducing sugar may be provided in an additive in a solid form, liquid 0 form (e.g., in solution of water or another solvent), or a combination thereof. The sulfide scavenging additives of the present disclosure may be added to a fluid by any means known in the art. The additive may be added to the fluid, for example, in the mud pit before the fluid has circulated or before the fluid contains any detectable amount of sulphur or H 2 S, as a prophylactic measure against any H 2 S the fluid may encounter downhole. In certain embodiments, the 8 WO 2014/209639 PCT/US2014/042361 additive may be added after the fluid has been circulating downhole and has already encountered sulphur or H 2 S and contains same. In certain embodiments, the amount of the additive added to the fluid may be controlled and/or varied during the course of an operation based on, among other things, the amount of sulfur or H 2 S detected in fluids exiting the well bore. In these 5 embodiments, any system or technique capable of monitoring or detecting sulfur or H 2 S content in fluids exiting the well bore may be used. Moreover, the sulfide scavenging additives of the present disclosure may be added to a fluid in multiple portions that are added to the fluid at separate intervals over a period of time. For example, a first amount of a scavenging additive of the present disclosure may be added to a fluid at one point in time in the course of a particular 0 operation. At a subsequent point during that operation, an elevated amount of sulfur or H 2 S may be detected exiting the well bore, at which point a second amount of a scavenging additive of the present disclosure may be added to the fluid based at least in part on the amount of sulfur or H 2 S detected. [0025] The exemplary fluids and additives disclosed herein may directly or 5 indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, and/or disposal of the disclosed fluids and additives. For example, and with reference to FIG. 1, the disclosed fluids and additives may directly or indirectly affect one or more components or pieces of equipment associated with an exemplary wellbore drilling assembly 100, according to one or more embodiments. It should be noted that 0 while FIG. 1 generally depicts a land-based drilling assembly, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. [0026] As illustrated, the drilling assembly 100 may include a drilling platform 5 102 that supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108. The drill string 108 may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art. A kelly 110 supports the drill string 108 as it is lowered through a rotary table 112. A drill bit 114 is attached to the distal end of the drill string 108 and is driven either by a downhole motor and/or via rotation of the drill string 108 from the 0 well surface. As the bit 114 rotates, it creates a borehole 116 that penetrates various subterranean formations 118. [0027] A pump 120 (e.g., a mud pump) circulates drilling fluid 122 through a feed pipe 124 and to the kelly 110, which conveys the drilling fluid 122 downhole through the interior of the drill string 108 and through one or more orifices in the drill bit 114. The drilling 9 WO 2014/209639 PCT/US2014/042361 fluid 122 is then circulated back to the surface via an annulus 126 defined between the drill string 108 and the walls of the borehole 116. At the surface, the recirculated or spent drilling fluid 122 exits the annulus 126 and may be conveyed to one or more fluid processing unit(s) 128 via an interconnecting flow line 130. After passing through the fluid processing unit(s) 128, a 5 "cleaned" drilling fluid 122 is deposited into a nearby retention pit 132 (i.e., a mud pit). While illustrated as being arranged at the outlet of the wellbore 116 via the annulus 126, those skilled in the art will readily appreciate that the fluid processing unit(s) 128 may be arranged at any other location in the drilling assembly 100 to facilitate its proper function, without departing from the scope of the scope of the disclosure. 0 [0028] One or more of the disclosed additives may be added to the drilling fluid 122 via a mixing hopper 134 communicably coupled to or otherwise in fluid communication with the retention pit 132. The mixing hopper 134 may include, but is not limited to, mixers and related mixing equipment known to those skilled in the art. In other embodiments, however, the disclosed additives may be added to the drilling fluid 122 at any other location in the drilling 5 assembly 100. In at least one embodiment, for example, there could be more than one retention pit 132, such as multiple retention pits 132 in series. Moreover, the retention pit 132 may be representative of one or more fluid storage facilities and/or units where the disclosed additives may be stored, reconditioned, and/or regulated until added to the drilling fluid 122. [0029] As mentioned above, the disclosed fluids and additives may directly or 0 indirectly affect the components and equipment of the drilling assembly 100. For example, the disclosed fluids and additives may directly or indirectly affect the fluid processing unit(s) 128 which may include, but is not limited to, one or more of a shaker (e.g., shale shaker), a centrifuge, a hydrocyclone, a separator (including magnetic and electrical separators), a desilter, a desander, a separator, a filter (e.g., diatomaceous earth filters), a heat exchanger, any fluid 5 reclamation equipment, The fluid processing unit(s) 128 may further include one or more sensors, gauges, pumps, compressors, and the like used store, monitor, regulate, and/or recondition the exemplary fluids and additives. [0030] The disclosed fluids and additives may directly or indirectly affect the pump 120, which representatively includes any conduits, pipelines, trucks, tubulars, and/or pipes 0 used to fluidically convey the fluids and additives downhole, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the fluids and additives into motion, any valves or related joints used to regulate the pressure or flow rate of the fluids and additives, and any sensors (i.e., pressure, temperature, flow rate, etc.), gauges, and/or combinations thereof, and the 10 WO 2014/209639 PCT/US2014/042361 like. The disclosed fluids and additives may also directly or indirectly affect the mixing hopper 134 and the retention pit 132 and their assorted variations. [0031] The disclosed fluids and additives may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the fluids and additives 5 such as, but not limited to, the drill string 108, any floats, drill collars, mud motors, downhole motors and/or pumps associated with the drill string 108, and any MWD/LWD tools and related telemetry equipment, sensors or distributed sensors associated with the drill string 108. The disclosed fluids and additives may also directly or indirectly affect any downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers and other wellbore 0 isolation devices or components, and the like associated with the wellbore 116. The disclosed fluids and additives may also directly or indirectly affect the drill bit 114, which may include, but is not limited to, roller cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, etc. [0032] While not specifically illustrated herein, the disclosed fluids and additives 5 may also directly or indirectly affect any transport or delivery equipment used to convey the fluids and additives to the drilling assembly 100 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fluidically move the fluids and additives from one location to another, any pumps, compressors, or motors used to drive the fluids and additives into motion, any valves or related joints used to regulate the pressure or flow 0 rate of the fluids and additives, and any sensors (i.e., pressure and temperature), gauges, and/or combinations thereof, and the like. [0033] Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in 5 different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure. While 0 compositions and methods are described in terms of "comprising," "containing," or "including" various components or steps, the compositions and methods can also "consist essentially of' or "consist of' the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. 11 WO 2014/209639 PCT/US2014/042361 In particular, every range of values (of the form, "from about a to about b," or, equivalently, "from approximately a to b," or, equivalently, "from approximately a-b") disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise 5 explicitly and clearly defined by the patentee. Moreover, the indefinite articles "a" or "an", as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 12
Claims (20)
1. A method comprising: providing a treatment fluid comprising a base liquid and a sulfide scavenging additive comprising one or more reducing sugars; 5 introducing the treatment fluid into at least a portion of a subterranean formation; and allowing at least a portion of the sulfide scavenging additive to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a precipitate comprising one or more sulfur species. 0
2. The method of claim 1 wherein the base liquid comprises an aqueous liquid.
3. The method of claim 1 wherein the treatment fluid comprises a basic solution.
4. The method of claim 1 wherein the treatment fluid is substantially free of aldehydes other than aldehydes formed by the reducing sugars dissolved in the basic solution.
5. The method of claim 1 wherein the pH of the treatment fluid is above 8. 5
6. The method of claim 1 wherein one or more metal ions is chelated with the one or more reducing sugars.
7. The method of claim 6 wherein the one or more metal ions interact with the hydrogen sulfide or sulfide ions to produce a precipitate comprising one or more metal sulfides.
8. The method of claim 1 wherein the sulfide scavenging additive comprises ferric 0 fructose.
9. The method of claim 1 further comprising adding an additional amount of a sulfide scavenging additive comprising one or more reducing sugars to the treatment fluid after the treatment fluid has been introduced into at least a portion of a subterranean formation.
10. The method of claim 1 wherein: 5 the treatment fluid comprises a drilling fluid; and the method further comprises using the drilling fluid to drill at least a portion of a well bore penetrating at least a portion of the subterranean formation. 13 WO 2014/209639 PCT/US2014/042361
11. A method comprising: providing a treatment fluid comprising a base liquid and a sulfide scavenging additive comprising one or more reducing sugars chelated with one or more metal ions; introducing the treatment fluid into at least a portion of a subterranean formation; 5 allowing at least one of the metal ions to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a first product comprising one or more metal sulfides; and allowing the reducing sugar to interact with hydrogen sulfide or sulfide ions present in the treatment fluid to produce a second product comprising one or more sulfur species. 0
12. The method of claim 11 wherein the base liquid comprises an aqueous liquid.
13. The method of claim 11 wherein the pH of the treatment fluid is above 8.
14. The method of claim 11 wherein the sulfur species in the second product are different from the metal sulfides in the first product.
15. The method of claim 11 further comprising removing the first or second products 5 from the treatment fluid in the form of a precipitate.
16. The method of claim 11 further comprising adding an additional amount of a sulfide scavenging additive comprising one or more reducing sugars to the treatment fluid after the treatment fluid has been introduced into at least a portion of a subterranean formation.
17. A method of treating a fluid comprising a first concentration of hydrogen sulfide 0 or sulfide ions, the method comprising: adding a sulfide scavenging additive comprising one or more reducing sugars to the fluid; and allowing at least a portion of the sulfide scavenging additive to interact with at least a portion of the hydrogen sulfide or sulfide ions in the fluid to reduce the concentration of 5 hydrogen sulfide or sulfide ions to a second concentration that is lower than the first concentration.
18. The method of claim 17 wherein the fluid comprises an aqueous liquid.
19. The method of claim 17 wherein the pH of the fluid is above 8.
20. The method of claim 17 wherein the fluid is present in at least a portion of a 0 subterranean formation. 14
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US10544344B2 (en) * | 2016-09-09 | 2020-01-28 | Saudi Arabian Oil Company | Methods and systems for neutralizing hydrogen sulfide during drilling |
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CA1047243A (en) * | 1973-06-28 | 1979-01-30 | Irwin Fox | Porous fe304 drilling mud additive |
US4548720A (en) * | 1983-04-21 | 1985-10-22 | Diamond Shamrock Chemicals Company | Removal of hydrogen sulfide from drilling fluids |
CA2379897A1 (en) * | 1999-07-29 | 2001-02-08 | Halliburton Energy Services, Inc. | Method and composition for scavenging sulphide in drilling fluids |
US7748456B2 (en) * | 2006-08-11 | 2010-07-06 | Halliburton Energy Services, Inc. | Dual functional components and associated methods |
US20100108315A1 (en) * | 2008-11-03 | 2010-05-06 | Stevens David K | Method for reducing the H2S content of an H2S-containing subterranean formation |
EP2442891A2 (en) * | 2009-06-19 | 2012-04-25 | Shell Internationale Research Maatschappij B.V. | Process for the removal of carbon dioxide and/or hydrogen sulphide from a gas |
US20120067783A1 (en) * | 2010-09-21 | 2012-03-22 | Gregory Kaplan | Hydrogen sulfide scavenger compositions, methods for making and processes for removing hydrogen sulfide from liquid hydrocarbon media |
US8993488B2 (en) * | 2011-02-24 | 2015-03-31 | United Laboratories International, Llc | Process for removal of hydrogen sulfide in downhole oilfield applications |
US8573300B2 (en) * | 2011-09-07 | 2013-11-05 | E I Du Pont De Nemours And Company | Reducing sulfide in oil reservoir production fluids |
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AU2014303002B2 (en) | 2017-03-30 |
AR096730A1 (en) | 2016-01-27 |
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