CA2432160C - Well treatment fluid compositions and methods for their use - Google Patents
Well treatment fluid compositions and methods for their use Download PDFInfo
- Publication number
- CA2432160C CA2432160C CA2432160A CA2432160A CA2432160C CA 2432160 C CA2432160 C CA 2432160C CA 2432160 A CA2432160 A CA 2432160A CA 2432160 A CA2432160 A CA 2432160A CA 2432160 C CA2432160 C CA 2432160C
- Authority
- CA
- Canada
- Prior art keywords
- ester
- composition
- alcohol
- citrate
- peroxide
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
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- 239000000203 mixture Substances 0.000 title claims abstract description 88
- 239000003180 well treatment fluid Substances 0.000 title claims abstract description 39
- 238000000034 method Methods 0.000 title claims description 48
- 150000002148 esters Chemical class 0.000 claims abstract description 90
- -1 ester compound Chemical class 0.000 claims abstract description 69
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 53
- 229920000642 polymer Polymers 0.000 claims abstract description 51
- 239000003431 cross linking reagent Substances 0.000 claims abstract description 38
- 239000002904 solvent Substances 0.000 claims abstract description 33
- WEAPVABOECTMGR-UHFFFAOYSA-N triethyl 2-acetyloxypropane-1,2,3-tricarboxylate Chemical compound CCOC(=O)CC(C(=O)OCC)(OC(C)=O)CC(=O)OCC WEAPVABOECTMGR-UHFFFAOYSA-N 0.000 claims abstract description 31
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 31
- 239000002253 acid Substances 0.000 claims abstract description 28
- 150000004676 glycans Chemical class 0.000 claims abstract description 15
- 229910052751 metal Inorganic materials 0.000 claims abstract description 15
- 239000002184 metal Substances 0.000 claims abstract description 15
- 229920001282 polysaccharide Polymers 0.000 claims abstract description 15
- 239000005017 polysaccharide Substances 0.000 claims abstract description 15
- 229920002678 cellulose Polymers 0.000 claims abstract description 13
- 239000001913 cellulose Substances 0.000 claims abstract description 13
- 229940071106 ethylenediaminetetraacetate Drugs 0.000 claims abstract description 11
- 229910052726 zirconium Inorganic materials 0.000 claims abstract description 11
- QCWXUUIWCKQGHC-UHFFFAOYSA-N Zirconium Chemical compound [Zr] QCWXUUIWCKQGHC-UHFFFAOYSA-N 0.000 claims abstract description 10
- 229920000926 Galactomannan Polymers 0.000 claims abstract description 9
- OMDQUFIYNPYJFM-XKDAHURESA-N (2r,3r,4s,5r,6s)-2-(hydroxymethyl)-6-[[(2r,3s,4r,5s,6r)-4,5,6-trihydroxy-3-[(2s,3s,4s,5s,6r)-3,4,5-trihydroxy-6-(hydroxymethyl)oxan-2-yl]oxyoxan-2-yl]methoxy]oxane-3,4,5-triol Chemical compound O[C@@H]1[C@@H](O)[C@@H](O)[C@@H](CO)O[C@@H]1OC[C@@H]1[C@@H](O[C@H]2[C@H]([C@@H](O)[C@H](O)[C@@H](CO)O2)O)[C@H](O)[C@H](O)[C@H](O)O1 OMDQUFIYNPYJFM-XKDAHURESA-N 0.000 claims abstract description 8
- BTBUEUYNUDRHOZ-UHFFFAOYSA-N Borate Chemical group [O-]B([O-])[O-] BTBUEUYNUDRHOZ-UHFFFAOYSA-N 0.000 claims abstract description 8
- RTAQQCXQSZGOHL-UHFFFAOYSA-N Titanium Chemical compound [Ti] RTAQQCXQSZGOHL-UHFFFAOYSA-N 0.000 claims abstract description 8
- 239000012530 fluid Substances 0.000 claims description 179
- 230000015572 biosynthetic process Effects 0.000 claims description 50
- 229910052784 alkaline earth metal Inorganic materials 0.000 claims description 26
- 244000303965 Cyamopsis psoralioides Species 0.000 claims description 24
- KRKNYBCHXYNGOX-UHFFFAOYSA-N citric acid Natural products OC(=O)CC(O)(C(O)=O)CC(O)=O KRKNYBCHXYNGOX-UHFFFAOYSA-N 0.000 claims description 24
- SPAGIJMPHSUYSE-UHFFFAOYSA-N Magnesium peroxide Chemical compound [Mg+2].[O-][O-] SPAGIJMPHSUYSE-UHFFFAOYSA-N 0.000 claims description 21
- 229960004995 magnesium peroxide Drugs 0.000 claims description 21
- 150000001342 alkaline earth metals Chemical class 0.000 claims description 18
- 150000002978 peroxides Chemical class 0.000 claims description 16
- DLINORNFHVEIFE-UHFFFAOYSA-N hydrogen peroxide;zinc Chemical compound [Zn].OO DLINORNFHVEIFE-UHFFFAOYSA-N 0.000 claims description 14
- 229940105296 zinc peroxide Drugs 0.000 claims description 13
- 229920002907 Guar gum Polymers 0.000 claims description 12
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 claims description 12
- 239000000665 guar gum Substances 0.000 claims description 12
- 235000010417 guar gum Nutrition 0.000 claims description 12
- 229960002154 guar gum Drugs 0.000 claims description 12
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 claims description 10
- 235000019402 calcium peroxide Nutrition 0.000 claims description 10
- 229910052725 zinc Inorganic materials 0.000 claims description 10
- 239000011701 zinc Substances 0.000 claims description 10
- QZCLKYGREBVARF-UHFFFAOYSA-N Acetyl tributyl citrate Chemical compound CCCCOC(=O)CC(C(=O)OCCCC)(OC(C)=O)CC(=O)OCCCC QZCLKYGREBVARF-UHFFFAOYSA-N 0.000 claims description 9
- 239000004343 Calcium peroxide Substances 0.000 claims description 9
- ZFOZVQLOBQUTQQ-UHFFFAOYSA-N Tributyl citrate Chemical compound CCCCOC(=O)CC(O)(C(=O)OCCCC)CC(=O)OCCCC ZFOZVQLOBQUTQQ-UHFFFAOYSA-N 0.000 claims description 9
- LHJQIRIGXXHNLA-UHFFFAOYSA-N calcium peroxide Chemical compound [Ca+2].[O-][O-] LHJQIRIGXXHNLA-UHFFFAOYSA-N 0.000 claims description 9
- MWNQXXOSWHCCOZ-UHFFFAOYSA-L sodium;oxido carbonate Chemical compound [Na+].[O-]OC([O-])=O MWNQXXOSWHCCOZ-UHFFFAOYSA-L 0.000 claims description 9
- 150000003755 zirconium compounds Chemical class 0.000 claims description 9
- 229920003090 carboxymethyl hydroxyethyl cellulose Polymers 0.000 claims description 8
- 125000005342 perphosphate group Chemical group 0.000 claims description 8
- 108090000790 Enzymes Proteins 0.000 claims description 7
- 102000004190 Enzymes Human genes 0.000 claims description 7
- HCHKCACWOHOZIP-UHFFFAOYSA-N Zinc Chemical compound [Zn] HCHKCACWOHOZIP-UHFFFAOYSA-N 0.000 claims description 7
- 239000000463 material Substances 0.000 claims description 7
- AKHNMLFCWUSKQB-UHFFFAOYSA-L sodium thiosulfate Chemical compound [Na+].[Na+].[O-]S([O-])(=O)=S AKHNMLFCWUSKQB-UHFFFAOYSA-L 0.000 claims description 7
- 235000019345 sodium thiosulphate Nutrition 0.000 claims description 7
- NIQCNGHVCWTJSM-UHFFFAOYSA-N Dimethyl phthalate Chemical compound COC(=O)C1=CC=CC=C1C(=O)OC NIQCNGHVCWTJSM-UHFFFAOYSA-N 0.000 claims description 6
- 229910019142 PO4 Inorganic materials 0.000 claims description 6
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims description 6
- 230000003111 delayed effect Effects 0.000 claims description 6
- DOIRQSBPFJWKBE-UHFFFAOYSA-N dibutyl phthalate Chemical compound CCCCOC(=O)C1=CC=CC=C1C(=O)OCCCC DOIRQSBPFJWKBE-UHFFFAOYSA-N 0.000 claims description 6
- 239000010452 phosphate Substances 0.000 claims description 6
- 229920002134 Carboxymethyl cellulose Polymers 0.000 claims description 5
- 229920002581 Glucomannan Polymers 0.000 claims description 5
- 229920000569 Gum karaya Polymers 0.000 claims description 5
- 239000004354 Hydroxyethyl cellulose Substances 0.000 claims description 5
- 229920000663 Hydroxyethyl cellulose Polymers 0.000 claims description 5
- 229920000161 Locust bean gum Polymers 0.000 claims description 5
- OKIZCWYLBDKLSU-UHFFFAOYSA-M N,N,N-Trimethylmethanaminium chloride Chemical compound [Cl-].C[N+](C)(C)C OKIZCWYLBDKLSU-UHFFFAOYSA-M 0.000 claims description 5
- 241000934878 Sterculia Species 0.000 claims description 5
- GSEJCLTVZPLZKY-UHFFFAOYSA-N Triethanolamine Chemical compound OCCN(CCO)CCO GSEJCLTVZPLZKY-UHFFFAOYSA-N 0.000 claims description 5
- 239000001768 carboxy methyl cellulose Substances 0.000 claims description 5
- 235000010948 carboxy methyl cellulose Nutrition 0.000 claims description 5
- 125000002057 carboxymethyl group Chemical group [H]OC(=O)C([H])([H])[*] 0.000 claims description 5
- 239000008112 carboxymethyl-cellulose Substances 0.000 claims description 5
- 235000019447 hydroxyethyl cellulose Nutrition 0.000 claims description 5
- 239000000231 karaya gum Substances 0.000 claims description 5
- 235000010494 karaya gum Nutrition 0.000 claims description 5
- 229940039371 karaya gum Drugs 0.000 claims description 5
- 239000000711 locust bean gum Substances 0.000 claims description 5
- 235000010420 locust bean gum Nutrition 0.000 claims description 5
- 239000001103 potassium chloride Substances 0.000 claims description 5
- 235000011164 potassium chloride Nutrition 0.000 claims description 5
- 150000003839 salts Chemical class 0.000 claims description 5
- 239000004094 surface-active agent Substances 0.000 claims description 5
- 239000010936 titanium Substances 0.000 claims description 5
- 150000003609 titanium compounds Chemical class 0.000 claims description 5
- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 claims description 4
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 claims description 4
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims description 4
- DOOTYTYQINUNNV-UHFFFAOYSA-N Triethyl citrate Chemical compound CCOC(=O)CC(O)(C(=O)OCC)CC(=O)OCC DOOTYTYQINUNNV-UHFFFAOYSA-N 0.000 claims description 4
- 150000001639 boron compounds Chemical group 0.000 claims description 4
- 239000008188 pellet Substances 0.000 claims description 4
- BWHMMNNQKKPAPP-UHFFFAOYSA-L potassium carbonate Chemical compound [K+].[K+].[O-]C([O-])=O BWHMMNNQKKPAPP-UHFFFAOYSA-L 0.000 claims description 4
- 229940095064 tartrate Drugs 0.000 claims description 4
- VZCYOOQTPOCHFL-UHFFFAOYSA-N trans-butenedioic acid Natural products OC(=O)C=CC(O)=O VZCYOOQTPOCHFL-UHFFFAOYSA-N 0.000 claims description 4
- 239000001069 triethyl citrate Substances 0.000 claims description 4
- VMYFZRTXGLUXMZ-UHFFFAOYSA-N triethyl citrate Natural products CCOC(=O)C(O)(C(=O)OCC)C(=O)OCC VMYFZRTXGLUXMZ-UHFFFAOYSA-N 0.000 claims description 4
- 235000013769 triethyl citrate Nutrition 0.000 claims description 4
- IEPRKVQEAMIZSS-UHFFFAOYSA-N Di-Et ester-Fumaric acid Natural products CCOC(=O)C=CC(=O)OCC IEPRKVQEAMIZSS-UHFFFAOYSA-N 0.000 claims description 3
- IEPRKVQEAMIZSS-WAYWQWQTSA-N Diethyl maleate Chemical compound CCOC(=O)\C=C/C(=O)OCC IEPRKVQEAMIZSS-WAYWQWQTSA-N 0.000 claims description 3
- JVTAAEKCZFNVCJ-UHFFFAOYSA-M Lactate Chemical compound CC(O)C([O-])=O JVTAAEKCZFNVCJ-UHFFFAOYSA-M 0.000 claims description 3
- 239000004372 Polyvinyl alcohol Substances 0.000 claims description 3
- 239000011324 bead Substances 0.000 claims description 3
- 229910021538 borax Inorganic materials 0.000 claims description 3
- KGBXLFKZBHKPEV-UHFFFAOYSA-N boric acid Chemical compound OB(O)O KGBXLFKZBHKPEV-UHFFFAOYSA-N 0.000 claims description 3
- 239000004327 boric acid Substances 0.000 claims description 3
- 239000012267 brine Substances 0.000 claims description 3
- WYACBZDAHNBPPB-UHFFFAOYSA-N diethyl oxalate Chemical compound CCOC(=O)C(=O)OCC WYACBZDAHNBPPB-UHFFFAOYSA-N 0.000 claims description 3
- YSAVZVORKRDODB-WDSKDSINSA-N diethyl tartrate Chemical compound CCOC(=O)[C@@H](O)[C@H](O)C(=O)OCC YSAVZVORKRDODB-WDSKDSINSA-N 0.000 claims description 3
- FBSAITBEAPNWJG-UHFFFAOYSA-N dimethyl phthalate Natural products CC(=O)OC1=CC=CC=C1OC(C)=O FBSAITBEAPNWJG-UHFFFAOYSA-N 0.000 claims description 3
- 229960001826 dimethylphthalate Drugs 0.000 claims description 3
- 229920002401 polyacrylamide Polymers 0.000 claims description 3
- 229920002451 polyvinyl alcohol Polymers 0.000 claims description 3
- 235000010339 sodium tetraborate Nutrition 0.000 claims description 3
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 claims description 3
- YBRBMKDOPFTVDT-UHFFFAOYSA-N tert-butylamine Chemical compound CC(C)(C)N YBRBMKDOPFTVDT-UHFFFAOYSA-N 0.000 claims description 3
- POILWHVDKZOXJZ-ARJAWSKDSA-M (z)-4-oxopent-2-en-2-olate Chemical compound C\C([O-])=C\C(C)=O POILWHVDKZOXJZ-ARJAWSKDSA-M 0.000 claims description 2
- RJQQOKKINHMXIM-UHFFFAOYSA-N 2-hydroxypropanoate;tris(2-hydroxyethyl)azanium Chemical compound CC(O)C(O)=O.OCCN(CCO)CCO RJQQOKKINHMXIM-UHFFFAOYSA-N 0.000 claims description 2
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 claims description 2
- 240000007049 Juglans regia Species 0.000 claims description 2
- 235000009496 Juglans regia Nutrition 0.000 claims description 2
- 239000004677 Nylon Substances 0.000 claims description 2
- 239000006004 Quartz sand Substances 0.000 claims description 2
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 2
- UIIMBOGNXHQVGW-DEQYMQKBSA-M Sodium bicarbonate-14C Chemical compound [Na+].O[14C]([O-])=O UIIMBOGNXHQVGW-DEQYMQKBSA-M 0.000 claims description 2
- 229910052782 aluminium Inorganic materials 0.000 claims description 2
- XAGFODPZIPBFFR-UHFFFAOYSA-N aluminium Chemical compound [Al] XAGFODPZIPBFFR-UHFFFAOYSA-N 0.000 claims description 2
- 239000001110 calcium chloride Substances 0.000 claims description 2
- 229910001628 calcium chloride Inorganic materials 0.000 claims description 2
- 239000000919 ceramic Substances 0.000 claims description 2
- 229910021540 colemanite Inorganic materials 0.000 claims description 2
- 239000012634 fragment Substances 0.000 claims description 2
- 239000011521 glass Substances 0.000 claims description 2
- 229910001629 magnesium chloride Inorganic materials 0.000 claims description 2
- 229920001778 nylon Polymers 0.000 claims description 2
- 229910000027 potassium carbonate Inorganic materials 0.000 claims description 2
- 229910000029 sodium carbonate Inorganic materials 0.000 claims description 2
- 239000011780 sodium chloride Substances 0.000 claims description 2
- BSVBQGMMJUBVOD-UHFFFAOYSA-N trisodium borate Chemical group [Na+].[Na+].[Na+].[O-]B([O-])[O-] BSVBQGMMJUBVOD-UHFFFAOYSA-N 0.000 claims description 2
- 229910021539 ulexite Inorganic materials 0.000 claims description 2
- 235000020234 walnut Nutrition 0.000 claims description 2
- PLVWNARVBMHCST-UHFFFAOYSA-L zinc;oxidooxy(oxo)borane Chemical compound [Zn+2].[O-]OB=O.[O-]OB=O PLVWNARVBMHCST-UHFFFAOYSA-L 0.000 claims description 2
- HDDLVZWGOPWKFW-UHFFFAOYSA-N trimethyl 2-hydroxypropane-1,2,3-tricarboxylate Chemical compound COC(=O)CC(O)(C(=O)OC)CC(=O)OC HDDLVZWGOPWKFW-UHFFFAOYSA-N 0.000 claims 9
- MGFYIUFZLHCRTH-UHFFFAOYSA-N nitrilotriacetic acid Chemical compound OC(=O)CN(CC(O)=O)CC(O)=O MGFYIUFZLHCRTH-UHFFFAOYSA-N 0.000 claims 8
- JKRZOJADNVOXPM-UHFFFAOYSA-N Oxalic acid dibutyl ester Chemical compound CCCCOC(=O)C(=O)OCCCC JKRZOJADNVOXPM-UHFFFAOYSA-N 0.000 claims 4
- FLKPEMZONWLCSK-UHFFFAOYSA-N diethyl phthalate Chemical compound CCOC(=O)C1=CC=CC=C1C(=O)OCC FLKPEMZONWLCSK-UHFFFAOYSA-N 0.000 claims 4
- MQHNKCZKNAJROC-UHFFFAOYSA-N dipropyl phthalate Chemical compound CCCOC(=O)C1=CC=CC=C1C(=O)OCCC MQHNKCZKNAJROC-UHFFFAOYSA-N 0.000 claims 4
- ODHUFJLMXDXVRC-UHFFFAOYSA-N tripropyl 2-hydroxypropane-1,2,3-tricarboxylate Chemical compound CCCOC(=O)CC(O)(C(=O)OCCC)CC(=O)OCCC ODHUFJLMXDXVRC-UHFFFAOYSA-N 0.000 claims 3
- LTMRRSWNXVJMBA-UHFFFAOYSA-L 2,2-diethylpropanedioate Chemical compound CCC(CC)(C([O-])=O)C([O-])=O LTMRRSWNXVJMBA-UHFFFAOYSA-L 0.000 claims 2
- FUZLRTGGPPIBJQ-UHFFFAOYSA-N 2-n,2-n,4-n,4-n-tetramethylpyrimidine-2,4-diamine Chemical compound CN(C)C1=CC=NC(N(C)C)=N1 FUZLRTGGPPIBJQ-UHFFFAOYSA-N 0.000 claims 2
- GQZXRLWUYONVCP-UHFFFAOYSA-N 3-[1-(dimethylamino)ethyl]phenol Chemical compound CN(C)C(C)C1=CC=CC(O)=C1 GQZXRLWUYONVCP-UHFFFAOYSA-N 0.000 claims 2
- YUXIBTJKHLUKBD-UHFFFAOYSA-N Dibutyl succinate Chemical compound CCCCOC(=O)CCC(=O)OCCCC YUXIBTJKHLUKBD-UHFFFAOYSA-N 0.000 claims 2
- DKMROQRQHGEIOW-UHFFFAOYSA-N Diethyl succinate Chemical compound CCOC(=O)CCC(=O)OCC DKMROQRQHGEIOW-UHFFFAOYSA-N 0.000 claims 2
- MUXOBHXGJLMRAB-UHFFFAOYSA-N Dimethyl succinate Chemical compound COC(=O)CCC(=O)OC MUXOBHXGJLMRAB-UHFFFAOYSA-N 0.000 claims 2
- PCYQQSKDZQTOQG-NXEZZACHSA-N dibutyl (2r,3r)-2,3-dihydroxybutanedioate Chemical compound CCCCOC(=O)[C@H](O)[C@@H](O)C(=O)OCCCC PCYQQSKDZQTOQG-NXEZZACHSA-N 0.000 claims 2
- JBSLOWBPDRZSMB-FPLPWBNLSA-N dibutyl (z)-but-2-enedioate Chemical compound CCCCOC(=O)\C=C/C(=O)OCCCC JBSLOWBPDRZSMB-FPLPWBNLSA-N 0.000 claims 2
- NFKGQHYUYGYHIS-UHFFFAOYSA-N dibutyl propanedioate Chemical compound CCCCOC(=O)CC(=O)OCCCC NFKGQHYUYGYHIS-UHFFFAOYSA-N 0.000 claims 2
- 229960002097 dibutylsuccinate Drugs 0.000 claims 2
- PVRATXCXJDHJJN-UHFFFAOYSA-N dimethyl 2,3-dihydroxybutanedioate Chemical compound COC(=O)C(O)C(O)C(=O)OC PVRATXCXJDHJJN-UHFFFAOYSA-N 0.000 claims 2
- LDCRTTXIJACKKU-ARJAWSKDSA-N dimethyl maleate Chemical compound COC(=O)\C=C/C(=O)OC LDCRTTXIJACKKU-ARJAWSKDSA-N 0.000 claims 2
- BEPAFCGSDWSTEL-UHFFFAOYSA-N dimethyl malonate Chemical compound COC(=O)CC(=O)OC BEPAFCGSDWSTEL-UHFFFAOYSA-N 0.000 claims 2
- LOMVENUNSWAXEN-NUQCWPJISA-N dimethyl oxalate Chemical group CO[14C](=O)[14C](=O)OC LOMVENUNSWAXEN-NUQCWPJISA-N 0.000 claims 2
- WCHBXSPACACNBJ-UHFFFAOYSA-N dipropyl 2,3-dihydroxybutanedioate Chemical compound CCCOC(=O)C(O)C(O)C(=O)OCCC WCHBXSPACACNBJ-UHFFFAOYSA-N 0.000 claims 2
- HZHMMLIMOUNKCK-UHFFFAOYSA-N dipropyl oxalate Chemical compound CCCOC(=O)C(=O)OCCC HZHMMLIMOUNKCK-UHFFFAOYSA-N 0.000 claims 2
- LWIWFCDNJNZEKB-UHFFFAOYSA-N dipropyl propanedioate Chemical compound CCCOC(=O)CC(=O)OCCC LWIWFCDNJNZEKB-UHFFFAOYSA-N 0.000 claims 2
- LZNZCMHEVACKGP-UHFFFAOYSA-N methyl 2-[2-[bis(2-methoxy-2-oxoethyl)amino]ethyl-(2-methoxy-2-oxoethyl)amino]acetate Chemical compound COC(=O)CN(CC(=O)OC)CCN(CC(=O)OC)CC(=O)OC LZNZCMHEVACKGP-UHFFFAOYSA-N 0.000 claims 2
- DNJDQMRARVPSHZ-UHFFFAOYSA-N n,n,n',n'-tetrabutylethane-1,2-diamine Chemical compound CCCCN(CCCC)CCN(CCCC)CCCC DNJDQMRARVPSHZ-UHFFFAOYSA-N 0.000 claims 2
- DIHKMUNUGQVFES-UHFFFAOYSA-N n,n,n',n'-tetraethylethane-1,2-diamine Chemical compound CCN(CC)CCN(CC)CC DIHKMUNUGQVFES-UHFFFAOYSA-N 0.000 claims 2
- LAHAQBFRDZWRQZ-UHFFFAOYSA-N propyl 2-[2-[bis(2-oxo-2-propoxyethyl)amino]ethyl-(2-oxo-2-propoxyethyl)amino]acetate Chemical compound CCCOC(=O)CN(CC(=O)OCCC)CCN(CC(=O)OCCC)CC(=O)OCCC LAHAQBFRDZWRQZ-UHFFFAOYSA-N 0.000 claims 2
- 239000007800 oxidant agent Substances 0.000 abstract description 14
- 150000001875 compounds Chemical class 0.000 abstract description 10
- 229910052723 transition metal Inorganic materials 0.000 abstract description 6
- KRKNYBCHXYNGOX-UHFFFAOYSA-K Citrate Chemical compound [O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O KRKNYBCHXYNGOX-UHFFFAOYSA-K 0.000 abstract description 5
- 150000003624 transition metals Chemical class 0.000 abstract description 5
- KCXVZYZYPLLWCC-UHFFFAOYSA-N EDTA Chemical compound OC(=O)CN(CC(O)=O)CCN(CC(O)=O)CC(O)=O KCXVZYZYPLLWCC-UHFFFAOYSA-N 0.000 abstract description 3
- MUBZPKHOEPUJKR-UHFFFAOYSA-N Oxalic acid Chemical compound OC(=O)C(O)=O MUBZPKHOEPUJKR-UHFFFAOYSA-N 0.000 abstract description 3
- 238000005755 formation reaction Methods 0.000 description 43
- 239000000499 gel Substances 0.000 description 33
- 238000011282 treatment Methods 0.000 description 19
- 230000015556 catabolic process Effects 0.000 description 13
- 238000006731 degradation reaction Methods 0.000 description 12
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 description 10
- 230000007062 hydrolysis Effects 0.000 description 10
- 238000006460 hydrolysis reaction Methods 0.000 description 10
- 239000000243 solution Substances 0.000 description 10
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 9
- 150000001298 alcohols Chemical class 0.000 description 9
- 238000004519 manufacturing process Methods 0.000 description 9
- 238000013400 design of experiment Methods 0.000 description 7
- 230000000694 effects Effects 0.000 description 7
- 239000004971 Cross linker Substances 0.000 description 6
- 150000007513 acids Chemical class 0.000 description 6
- 125000000217 alkyl group Chemical group 0.000 description 6
- 239000000470 constituent Substances 0.000 description 6
- 230000002028 premature Effects 0.000 description 6
- 230000002255 enzymatic effect Effects 0.000 description 5
- 229940088598 enzyme Drugs 0.000 description 5
- 238000002474 experimental method Methods 0.000 description 5
- 230000009467 reduction Effects 0.000 description 5
- 230000002829 reductive effect Effects 0.000 description 5
- 230000000717 retained effect Effects 0.000 description 5
- LRHPLDYGYMQRHN-UHFFFAOYSA-N N-Butanol Chemical compound CCCCO LRHPLDYGYMQRHN-UHFFFAOYSA-N 0.000 description 4
- 229910052796 boron Inorganic materials 0.000 description 4
- 150000001732 carboxylic acid derivatives Chemical class 0.000 description 4
- 239000002738 chelating agent Substances 0.000 description 4
- 238000004132 cross linking Methods 0.000 description 4
- 239000007789 gas Substances 0.000 description 4
- ZSIAUFGUXNUGDI-UHFFFAOYSA-N hexan-1-ol Chemical compound CCCCCCO ZSIAUFGUXNUGDI-UHFFFAOYSA-N 0.000 description 4
- 238000002347 injection Methods 0.000 description 4
- 239000007924 injection Substances 0.000 description 4
- 229910021645 metal ion Inorganic materials 0.000 description 4
- 230000004048 modification Effects 0.000 description 4
- 238000012986 modification Methods 0.000 description 4
- 230000008569 process Effects 0.000 description 4
- BDERNNFJNOPAEC-UHFFFAOYSA-N propan-1-ol Chemical compound CCCO BDERNNFJNOPAEC-UHFFFAOYSA-N 0.000 description 4
- 238000011084 recovery Methods 0.000 description 4
- ZOXJGFHDIHLPTG-UHFFFAOYSA-N Boron Chemical compound [B] ZOXJGFHDIHLPTG-UHFFFAOYSA-N 0.000 description 3
- 230000000903 blocking effect Effects 0.000 description 3
- 229920006037 cross link polymer Polymers 0.000 description 3
- 230000007423 decrease Effects 0.000 description 3
- 238000013461 design Methods 0.000 description 3
- 230000007246 mechanism Effects 0.000 description 3
- 238000002156 mixing Methods 0.000 description 3
- 238000012856 packing Methods 0.000 description 3
- 125000001997 phenyl group Chemical group [H]C1=C([H])C([H])=C(*)C([H])=C1[H] 0.000 description 3
- 239000000047 product Substances 0.000 description 3
- 239000003381 stabilizer Substances 0.000 description 3
- 239000000126 substance Substances 0.000 description 3
- 229920001059 synthetic polymer Polymers 0.000 description 3
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- AEMRFAOFKBGASW-UHFFFAOYSA-N Glycolic acid Chemical compound OCC(O)=O AEMRFAOFKBGASW-UHFFFAOYSA-N 0.000 description 2
- NBIIXXVUZAFLBC-UHFFFAOYSA-N Phosphoric acid Chemical compound OP(O)(O)=O NBIIXXVUZAFLBC-UHFFFAOYSA-N 0.000 description 2
- DHKHKXVYLBGOIT-UHFFFAOYSA-N acetaldehyde Diethyl Acetal Natural products CCOC(C)OCC DHKHKXVYLBGOIT-UHFFFAOYSA-N 0.000 description 2
- 239000000654 additive Substances 0.000 description 2
- 150000001450 anions Chemical class 0.000 description 2
- 125000004432 carbon atom Chemical group C* 0.000 description 2
- 239000013043 chemical agent Substances 0.000 description 2
- 238000006243 chemical reaction Methods 0.000 description 2
- 238000006482 condensation reaction Methods 0.000 description 2
- HPXRVTGHNJAIIH-UHFFFAOYSA-N cyclohexanol Chemical compound OC1CCCCC1 HPXRVTGHNJAIIH-UHFFFAOYSA-N 0.000 description 2
- 230000000593 degrading effect Effects 0.000 description 2
- 239000000839 emulsion Substances 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 239000003112 inhibitor Substances 0.000 description 2
- 238000002955 isolation Methods 0.000 description 2
- 239000003446 ligand Substances 0.000 description 2
- 230000007935 neutral effect Effects 0.000 description 2
- 150000007524 organic acids Chemical class 0.000 description 2
- 239000006174 pH buffer Substances 0.000 description 2
- JRKICGRDRMAZLK-UHFFFAOYSA-L peroxydisulfate Chemical class [O-]S(=O)(=O)OOS([O-])(=O)=O JRKICGRDRMAZLK-UHFFFAOYSA-L 0.000 description 2
- 150000003014 phosphoric acid esters Chemical class 0.000 description 2
- 229910052698 phosphorus Inorganic materials 0.000 description 2
- 229920005646 polycarboxylate Polymers 0.000 description 2
- TYJJADVDDVDEDZ-UHFFFAOYSA-M potassium hydrogencarbonate Chemical compound [K+].OC([O-])=O TYJJADVDDVDEDZ-UHFFFAOYSA-M 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- 230000004044 response Effects 0.000 description 2
- 239000011734 sodium Substances 0.000 description 2
- XRCRWCVBMHENNE-UHFFFAOYSA-N sym-di-n-butyl citrate Natural products CCCCOC(=O)CC(O)(C(O)=O)CC(=O)OCCCC XRCRWCVBMHENNE-UHFFFAOYSA-N 0.000 description 2
- LUEWUZLMQUOBSB-FSKGGBMCSA-N (2s,3s,4s,5s,6r)-2-[(2r,3s,4r,5r,6s)-6-[(2r,3s,4r,5s,6s)-4,5-dihydroxy-2-(hydroxymethyl)-6-[(2r,4r,5s,6r)-4,5,6-trihydroxy-2-(hydroxymethyl)oxan-3-yl]oxyoxan-3-yl]oxy-4,5-dihydroxy-2-(hydroxymethyl)oxan-3-yl]oxy-6-(hydroxymethyl)oxane-3,4,5-triol 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]2[C@H](O[C@@H](OC3[C@H](O[C@@H](O)[C@@H](O)[C@H]3O)CO)[C@@H](O)[C@H]2O)CO)[C@H](O)[C@H]1O LUEWUZLMQUOBSB-FSKGGBMCSA-N 0.000 description 1
- SVONRAPFKPVNKG-UHFFFAOYSA-N 2-ethoxyethyl acetate Chemical compound CCOCCOC(C)=O SVONRAPFKPVNKG-UHFFFAOYSA-N 0.000 description 1
- 125000006283 4-chlorobenzyl group Chemical group [H]C1=C([H])C(=C([H])C([H])=C1Cl)C([H])([H])* 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 108010059892 Cellulase Proteins 0.000 description 1
- 108010073178 Glucan 1,4-alpha-Glucosidase Proteins 0.000 description 1
- 244000241838 Lycium barbarum Species 0.000 description 1
- 206010027336 Menstruation delayed Diseases 0.000 description 1
- 229910017950 MgOz Inorganic materials 0.000 description 1
- OAICVXFJPJFONN-UHFFFAOYSA-N Phosphorus Chemical compound [P] OAICVXFJPJFONN-UHFFFAOYSA-N 0.000 description 1
- 239000008186 active pharmaceutical agent Substances 0.000 description 1
- 230000010933 acylation Effects 0.000 description 1
- 238000005917 acylation reaction Methods 0.000 description 1
- 150000004974 alkaline earth metal peroxides Chemical class 0.000 description 1
- 125000005037 alkyl phenyl group Chemical group 0.000 description 1
- 108090000637 alpha-Amylases Proteins 0.000 description 1
- 108010028144 alpha-Glucosidases Proteins 0.000 description 1
- 102000016679 alpha-Glucosidases Human genes 0.000 description 1
- 229910000147 aluminium phosphate Inorganic materials 0.000 description 1
- 230000003466 anti-cipated effect Effects 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 125000001797 benzyl group Chemical group [H]C1=C([H])C([H])=C(C([H])=C1[H])C([H])([H])* 0.000 description 1
- 108010019077 beta-Amylase Proteins 0.000 description 1
- 108010051210 beta-Fructofuranosidase Proteins 0.000 description 1
- 239000003139 biocide Substances 0.000 description 1
- 150000001642 boronic acid derivatives Chemical class 0.000 description 1
- 229910052794 bromium Inorganic materials 0.000 description 1
- 239000000872 buffer Substances 0.000 description 1
- 125000000484 butyl group Chemical group [H]C([*])([H])C([H])([H])C([H])([H])C([H])([H])[H] 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 125000003178 carboxy group Chemical group [H]OC(*)=O 0.000 description 1
- 150000007942 carboxylates Chemical group 0.000 description 1
- 150000001735 carboxylic acids Chemical class 0.000 description 1
- 229940106157 cellulase Drugs 0.000 description 1
- 239000013522 chelant Substances 0.000 description 1
- 238000010382 chemical cross-linking Methods 0.000 description 1
- 229910052801 chlorine Inorganic materials 0.000 description 1
- 125000004803 chlorobenzyl group Chemical group 0.000 description 1
- 239000007859 condensation product Substances 0.000 description 1
- 229920001577 copolymer Polymers 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000000354 decomposition reaction Methods 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 150000005690 diesters Chemical class 0.000 description 1
- 230000003292 diminished effect Effects 0.000 description 1
- UQGFMSUEHSUPRD-UHFFFAOYSA-N disodium;3,7-dioxido-2,4,6,8,9-pentaoxa-1,3,5,7-tetraborabicyclo[3.3.1]nonane Chemical compound [Na+].[Na+].O1B([O-])OB2OB([O-])OB1O2 UQGFMSUEHSUPRD-UHFFFAOYSA-N 0.000 description 1
- 238000004090 dissolution Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 230000002708 enhancing effect Effects 0.000 description 1
- 230000032050 esterification Effects 0.000 description 1
- 238000005886 esterification reaction Methods 0.000 description 1
- XYIBRDXRRQCHLP-UHFFFAOYSA-N ethyl acetoacetate Chemical compound CCOC(=O)CC(C)=O XYIBRDXRRQCHLP-UHFFFAOYSA-N 0.000 description 1
- 125000001495 ethyl group Chemical group [H]C([H])([H])C([H])([H])* 0.000 description 1
- 229910052731 fluorine Inorganic materials 0.000 description 1
- 239000006260 foam Substances 0.000 description 1
- 239000003349 gelling agent Substances 0.000 description 1
- 229940046240 glucomannan Drugs 0.000 description 1
- 229940059442 hemicellulase Drugs 0.000 description 1
- 108010002430 hemicellulase Proteins 0.000 description 1
- 125000005842 heteroatom Chemical group 0.000 description 1
- 125000004051 hexyl group Chemical group [H]C([H])([H])C([H])([H])C([H])([H])C([H])([H])C([H])([H])C([H])([H])* 0.000 description 1
- 230000000887 hydrating effect Effects 0.000 description 1
- 230000036571 hydration Effects 0.000 description 1
- 238000006703 hydration reaction Methods 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- 239000001257 hydrogen Substances 0.000 description 1
- 125000004435 hydrogen atom Chemical class [H]* 0.000 description 1
- 125000002887 hydroxy group Chemical group [H]O* 0.000 description 1
- 230000003993 interaction Effects 0.000 description 1
- 239000001573 invertase Substances 0.000 description 1
- 235000011073 invertase Nutrition 0.000 description 1
- 229910052740 iodine Inorganic materials 0.000 description 1
- 125000000959 isobutyl group Chemical group [H]C([H])([H])C([H])(C([H])([H])[H])C([H])([H])* 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 229910052749 magnesium Inorganic materials 0.000 description 1
- 239000011777 magnesium Substances 0.000 description 1
- 230000014759 maintenance of location Effects 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 125000002496 methyl group Chemical group [H]C([H])([H])* 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 235000005985 organic acids Nutrition 0.000 description 1
- 150000002895 organic esters Chemical class 0.000 description 1
- 150000001451 organic peroxides Chemical class 0.000 description 1
- 150000002902 organometallic compounds Chemical class 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- 229910052760 oxygen Inorganic materials 0.000 description 1
- 239000001301 oxygen Substances 0.000 description 1
- 239000003002 pH adjusting agent Substances 0.000 description 1
- 239000012188 paraffin wax Substances 0.000 description 1
- 230000036961 partial effect Effects 0.000 description 1
- 125000001147 pentyl group Chemical group C(CCCC)* 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 239000011574 phosphorus Substances 0.000 description 1
- 230000002035 prolonged effect Effects 0.000 description 1
- 125000001436 propyl group Chemical group [H]C([*])([H])C([H])([H])C([H])([H])[H] 0.000 description 1
- 150000003254 radicals Chemical class 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 125000002914 sec-butyl group Chemical group [H]C([H])([H])C([H])([H])C([H])(*)C([H])([H])[H] 0.000 description 1
- 229910052710 silicon Inorganic materials 0.000 description 1
- 239000004328 sodium tetraborate Substances 0.000 description 1
- 230000003068 static effect Effects 0.000 description 1
- 125000000547 substituted alkyl group Chemical group 0.000 description 1
- 229910052717 sulfur Inorganic materials 0.000 description 1
- 230000002195 synergetic effect Effects 0.000 description 1
- 125000000999 tert-butyl group Chemical group [H]C([H])([H])C(*)(C([H])([H])[H])C([H])([H])[H] 0.000 description 1
- 238000012360 testing method Methods 0.000 description 1
- 125000003698 tetramethyl group Chemical group [H]C([H])([H])* 0.000 description 1
- DHCDFWKWKRSZHF-UHFFFAOYSA-L thiosulfate(2-) Chemical compound [O-]S([S-])(=O)=O DHCDFWKWKRSZHF-UHFFFAOYSA-L 0.000 description 1
- 229910052719 titanium Inorganic materials 0.000 description 1
- 150000005691 triesters Chemical class 0.000 description 1
- DQWPFSLDHJDLRL-UHFFFAOYSA-N triethyl phosphate Chemical compound CCOP(=O)(OCC)OCC DQWPFSLDHJDLRL-UHFFFAOYSA-N 0.000 description 1
- 239000003643 water by type Substances 0.000 description 1
- 150000003751 zinc Chemical class 0.000 description 1
Classifications
-
- 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
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
- C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/887—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
-
- 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
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/66—Compositions based on water or polar solvents
- C09K8/68—Compositions based on water or polar solvents containing organic compounds
- C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
Abstract
A well treatment fluid composition comprises a solvent (such as water), a polymer soluble or hydratable in the solvent, a crosslinking agent, an inorgnaic breaking agent, and an ester compound,. Preferably, the hydratable polymer is a polysaccharide, such as galactomannan, cellulose, or derivatives thereof. The crosslinking agent is preferably a borate, titanate, or zirconium-containing compound. The inorganic breaking agent is preferably a metal-based oxidizing agent, such as an alkaline ear metal or transition metal-based oxidizing agent. The ester compound is preferably an ester of polycarboxylic acid, such as an ester of oxalate, citrate, or ethylenediamine tetraacetate. One example of a suitable ester compound is acetyl triethyl citrate.
Description
WELL TREATMENT FLUID COMPOSITIONS
AND METHODS FOR THEIR USE
FIELD OF THE INVENTION
AND METHODS FOR THEIR USE
FIELD OF THE INVENTION
[0002] The invention relates to methods and compositions for treating subterranean formations.
More particularly, it relates to methods and compositions for treating a subterranean formation io penetrated by a wellbore into which a gel with a high viscosity is injected. This invention specifically relates to a method and composition for reducing the viscosity of the gel upon completion of the well treatment.
BACKGROUND OF THE INVENTION
More particularly, it relates to methods and compositions for treating a subterranean formation io penetrated by a wellbore into which a gel with a high viscosity is injected. This invention specifically relates to a method and composition for reducing the viscosity of the gel upon completion of the well treatment.
BACKGROUND OF THE INVENTION
[0003] Viscous well treatment fluids are commonly used in the drilling, completion, and treatment of subterranean formations penetrated by wellbores. A viscous well treatment fluid is generally composed of a polysaccharide or synthetic polymer in an aqueous solution which is crosslinked by an organometallic compound. Examples of well treatments in which metal-crosslinked polymers are used are hydraulic fracturing, gravel packing operations, water blocking, and other well completion operations.
[0004] Hydraulic fracturing techniques are widely employed to enhance oil and gas production from subterranean formations. During hydraulic fracturing, fluid is injected into a well bore under high pressure. Once the natural reservoir pressures are exceeded, the fracturing fluid initiates a fracture in the formation which generally continues to grow during pumping. As the fracture widens to a suitable width during the course of the treatment, a propping agent is then also added to the fluid. The treatment design generally requires the fluid to reach a maximum viscosity as it enters the fracture which affects the fracture length and width. The viscosity of most fracturing fluids is generated from water-soluble polysaccharides, such as galactomannans or cellulose derivatives. Employing crosslinking agents, such as borate, titanate, or zirconium ions, can further increase the viscosity. The gelled fluid may be accompanied by a propping agent (i.e., proppant) which results in placement of the proppant within the fracture thus produced. The proppant remains in the produced fracture to prevent the complete closure of the fracture and to form a conductive channel extending from the well bore into the formation being treated once the fracturing fluid is recovered.
[0005] In order for the treatment to be successful, it is preferred that the fluid viscosity eventually diminish to levels approaching that of water after the proppant is placed. This allows a portion of the treating fluid to be recovered without producing excessive amounts of proppant after the well is opened and returned to production. The recovery of the fracturing fluid is accomplished by reducing the viscosity of the fluid to a lower value such that it flows naturally io from the formation under the influence of formation fluids. This viscosity reduction or conversion is referred to as "breaking" and can be accomplished by incorporating chemical agents, referred to as "breakers," into the initial gel.
[0006] Certain gels of fracturing fluids, such as those based upon guar polymers, undergo a natural break without the intervention of a breaking agent. However, the breaking time for such is gelled fluids generally is excessive and impractical, being somewhere in the range from greater than 24 hours to in excess of weeks, months, or years depending on reservoir conditions.
Accordingly, to decrease the break time of gels used in fracturing, chemical agents are usually incorporated into the gel and become a part of the gel itself. Typically, these agents are either oxidants or enzymes which operate to degrade the polymeric gel structure. Most degradation or 20 "breaking" is caused by oxidizing agents, such as persulfate salts (used either as is or encapsulated), chromous salts, organic peroxides or alkaline earth or zinc peroxide salts, or by enzymes.
Accordingly, to decrease the break time of gels used in fracturing, chemical agents are usually incorporated into the gel and become a part of the gel itself. Typically, these agents are either oxidants or enzymes which operate to degrade the polymeric gel structure. Most degradation or 20 "breaking" is caused by oxidizing agents, such as persulfate salts (used either as is or encapsulated), chromous salts, organic peroxides or alkaline earth or zinc peroxide salts, or by enzymes.
[0007] In addition to the importance of providing a breaking mechanism for the gelled fluid to facilitate recovery of the fluid and to resume production, the timing of the break is also of great 25 importance. Gels which break prematurely can cause suspended proppant material to settle out of the gel before being introduced a sufficient distance into the produced fracture. Premature breaking can also lead to a premature reduction in the fluid viscosity, resulting in a less than desirable fracture width in the formation causing excessive injection pressures and premature termination of the treatment.
30 [0008] On the other hand, gelled fluids which break too slowly can cause slow recovery of the fracturing fluid from the produced fracture with attendant delay in resuming the production of formation fluids and severely impair anticipated hydrocarbon production.
Additional problems may occur, such as the tendency of proppant to become dislodged from the fracture, resulting in at least partial closing and decreased efficiency of the fracturing operation.
Preferably, the fracturing gel should begin to break when the pumping operations are concluded. For practical purposes, the gel preferably should be completely broken within about 24 hours after completion of the fracturing treatment.
[0009] U.S. Patent No. 3,960,736 (issued June 1, 1976) suggests the use of acetal esters and polysaccharides in well treatment compositions. The acetal esters hydrolyze to release the component alcohols and acids, which subsequently catalyze breakdown of the polysaccharides.
io This breakdown reduces the viscosity of the composition.
[0010] U.S. Patent No. 5,224,546 (issued June 6, 1993) offers the use of an esterified carboxylated chelator for the hydrolysis of metal crosslinked polymer gels used in oil and gas well applications. At elevated temperatures, the esterified chelator undergoes hydrolysis to form an acid and an active ligand which subsequently removes the crosslinking metal ion from the gel and hydrolyses the polymer. This reduces the viscosity of the gel and allows removal of the material after treatment of the well.
[0011 ] For the foregoing reasons, there is a continuing need for a well treatment fluid which could maintain a relatively high viscosity while it is injected into a wellbore. After a sufficient period of time to allow complete well treatment, the viscosity of the fluid should decrease to a level such that the fluid could be removed relatively easily.
SUMMARY OF THE INVENTION
[0012] Most fluid breakers either reduce the fluid viscosity too soon or, on the other extreme, provide incomplete viscosity reduction. It has been discovered that a synergistic effect occurs between certain inorganic oxidizing agents and certain organic esters.
Particularly, oxidizing salts having alkaline earth or transition metal cations and polycarboxylic esters are the most suitable mixtures. This combination of chemicals has been found to provide initial high viscosity fluids while also providing complete fluid degradation at later times. This combination allows for optimum fracture growth and proppant placement while enhancing the amount of treating fluid recovered after the well is placed back on production.
Ultimately, this effect significantly improves well productivity. U.S. Patent No. 5,224,546 (issued June 6, 1993) offers the use of an esterified carboxylated chelator for the hydrolysis of metal crosslinked polymer gels used in oil and gas well applications. At elevated temperatures, the esterified chelator undergoes hydrolysis to form an acid and an active ligand which subsequently removes the crosslinking metal ion from the gel and hydrolyses the polymer. This reduces the viscosity of the gel and allows removal of the material after treatment of the well.
[0012a] In accordance with an embodiment of the present invention there is provided a well treatment fluid composition comprising: a solvent; a polymer which is either soluble or hydratable in the solvent; a crosslinking agent; a breaking agent;
and an ester, wherein: the breaking agent is selected from the group consisting of an alkaline earth metal or zinc, percarbonate, perborate, peroxide and perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
[0012b] In accordance with another embodiment of the present invention there is provided a well treatment fluid composition comprising: water; a polymer selected from the group consisting of a galactomannan gum, a glucomannan gum, a guar, a derived guar, cellulose, a cellulose derivative, guar gum, a guar gum derivative, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose; a crosslinking agent selected from the group consisting of a boron compound, a titanium compound, and a zirconium compound;
a breaking agent selected from the group consisting of an alkaline earth metal persulfate, an alkaline earth metal percarbonate, an alkaline earth metal perborate, an alkaline earth metal peroxide, an alkaline earth metal perphosphate, a zinc peroxide, a zinc perphosphate, a zinc perborate, and a zinc percarbonate; and an ester selected from the group consisting of a C1-C11 alcohol oxalate ester, a C, -C>> alcohol citrate ester, a Ci-C>> alcohol ethylene diamine tetraacetate ester, a Cl-C11 alcohol nitrilotriacetate ester, a C1-C>> alcohol phosphate ester, a Cl-C11 alcohol phthalate ester, a CI-C1I
alcohol maleate ester, and a CI -CI1 alcohol tartrate ester.
[0012c] A further embodiment of the present invention provides a well treatment fluid composition comprising: water; a polysaccharide; a zirconium compound;
magnesium peroxide, calcium peroxide, or zinc peroxide; and acetyl triethyl citrate.
[0012d] A still further embodiment provides a well treatment fluid composition comprising; water; a polysaccharide at a concentration of about 0.2 wt% to about 0.8 wt% based on the weight of the composition; a zirconium compound at a concentration - 4a -of about 10 ppm metal to about 100 ppm metal; a breaking agent selected from the group consisting of magnesium peroxide, calcium peroxide, and zinc peroxide, wherein the breaking agent is at a concentration of about 0.25 lb/thousand gallons (PPTG) (0.146 kg/m3) to about 5 PPTG (2.91 kg/m3); and acetyl triethyl citrate at a concentration of about 0.25 gallons/thousand gallons (0.25 1/m) to about 3 gallons/thousand gallons (3 1/m).
[0012e] Another embodiment of the present invention provides a method of fracturing a subterranean formation, the method comprising: obtaining a well treatment fluid comprising a solvent, a polymer which is either soluble or hydratable in the solvent, a crosslinking agent, a breaking agent, and an ester; and contacting the well treatment fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation; wherein: the breaking agent is selected from the group consisting of an alkaline earth metal or zinc percarbonate, perborate, peroxide, and perphosphate; and the ester is an ester of a polycarboxylic acid and a CI -C>>
alcohol.
[0012f] Yet another embodiment provides a method of fracturing a subterranean formation, the method comprising: contacting water or brine with guar gum, hydroxypropyl guar, carboxymethyl guar, carboxymethyl hydroxypropyl guar, or carboxymethyl hydroxyethyl cellulose to form a base gel, contacting the base gel with:
a borate, titanate or zirconium crosslinking agent; an alkaline earth metal peroxide or zinc peroxide; and a citric acid ester to form a gelling fluid; and contacting the gelling fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation, wherein: the citric acid ester provides delayed breaking initially and substantially complete breaking after fracture formation is completed.
[0012g] A further embodiment of the present invention provides a well treatment fluid composition comprising: a solvent; a polymer which is either soluble or hydratable in the solvent; a crosslinking agent; a breaking agent; an enzyme; and an ester, wherein:
the breaking agent is an inorganic percarbonate, perborate, peroxide, or perphosphate;
and the ester is an ester of a polycarboxylic acid and a CI-C1 i alcohol.
DESCRIPTION OF THE FIGURES
[0013] The following figure forms part of the present specification and is included to further demonstrate certain aspects of the present invention. The invention may be - 4b -better understood by reference to the figure in combination with the detailed description of specific embodiments presented herein.
[0014] Figure 1 is a plot of viscosity curves as a function of time for various well treatment fluids.
DETAILED DESCRIPTION OF THE INVENTION
[0015] The aforementioned need is met by embodiments of the invention in one or more of the following aspects. In one aspect, the invention relates to a well treatment fluid composition. The composition comprises a solvent, a polymer soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, and an ester compound. Preferably, the solvent includes water, and the polymer is hydratable in water. The solvent may be an aqueous potassium chloride solution. The inorganic breaking agent may be a metal-based oxidizing agent, such as an alkaline earth metal or a transition metal. The inorganic breaking agent may be magnesium peroxide, calcium peroxide, or zinc peroxide. The ester compound may be an ester of a polycarboxylic acid. For example, the ester compound may be an ester of oxalate, citrate, or ethylene diamine tetraacetate. The ester compound having hydroxyl groups can also be acetylated. An example of this is that citric acid can be acetylated to form acetyl triethyl citrate. A presently preferred ester is acetyl triethyl citrate. The hydratable polymer may be a water soluble polysaccharide, such as galactomannan, cellulose, or derivatives thereof. The crosslinking agent may be a borate, titanate, or zirconium-containing compound. For example, the crosslinking agent can be sodium borate x H20 (varying waters of hydration), boric acid, borate crosslinkers (a mixture of a titanate constituent, preferably an organotitanate constituent, with a boron constituent. The organotitanate constituent can be TYZOR chelate esters from E.I. du Pont de Nemours & Company. The organotitanate constituent can be a mixture of a first organotitanate compound having a lactate base and a second organotitanate compound having s triethanolamine base. The boron constituent can be selected from the group consisting of boric acid, sodium tetraborate, and mixtures thereof. These are described in U.S.
Patent No.
4,514,309.), borate based ores such as ulexite and colemanite, Ti(IV) acetylacetonate, Ti(IV) triethanolamine, Zr lactate, Zr triethanolamine, Zr lactate-triethanolamine, or Zr lactate-triethanolamine-triisopropanolamine. In some embodiments, the well treatment fluid io composition may further comprise a proppant.
[0016] In another aspect, the invention relates to a well treatment fluid composition. The composition includes a solvent, a polymer soluble or hydratable in the solvent, a crosslinking agent, an alkaline earth metal or a transition metal-based breaking agent, and an ester of a carboxylic acid. The breaking agent may be magnesium peroxide, calcium peroxide, or zinc 15 peroxide. A presently preferred ester is acetyl triethyl citrate. The solvent may include water, and the polymer is hydratable in water. The solvent may be an aqueous potassium chloride solution. The hydratable polymer may be a polysaccharide.
[0017] In still another aspect, the invention relates to a method of treating a subterranean formation. The method comprises: formulating a fracturing fluid comprising a solvent, a 20 polymer soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, and an ester compound; and injecting the fracturing fluid into a bore hole to contact at least a part of the formation by the fracturing fluid under a sufficient pressure to fracture the formation. The fracturing fluid has a viscosity that changes in response to a condition. The method may further comprise removing the fracturing fluid after the viscosity of the fracturing fluid is reduced. In 25 some embodiments, the method may further comprise injecting a proppant into the formation.
The proppant may be injected into the formation with the fracturing fluid. The fracturing fluid may have a pH at or above about 7. Preferably, the fracturing fluid should have a pH in the range of about 8 to about 12. The inorganic breaking agent may be a metal-based oxidizing agent. The metal may be an alkaline earth metal or a transition metal. The inorganic breaking 3o agent may be magnesium peroxide, calcium peroxide, or zinc peroxide. The ester compound may be an ester of an polycarboxylic acid, such as an ester of oxalate, citrate, or ethylene diamine tetraacetate. A presently preferred ester compound is acetyl triethyl citrate. Preferably, the solvent includes water, and the polymer is a water soluble polysaccharide, such as galactomannan, cellulose, or derivatives thereof. The solvent may be an aqueous potassium chloride solution. The crosslinking agent may be a borate, titanate, or zirconium-containing compound. The fracturing fluid can further comprise sodium thiosulfate.
[0018] Embodiments of the invention provide a well treatment fluid composition and a method of using the fluid composition to treat subterranean formations. The well treatment fluid composition can be used in hydraulic fracturing as a fracturing fluid, gravel packing operations, water blocking, temporary plugs for purposes of wellbore isolation and/or fluid loss control and other well completion operations. Most well treatment fluids are aqueous, although non-aqueous io fluids may be formulated and used as well.
[0019] The well treatment fluid composition comprises a solvent (such as water), a polymer soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, and an ester compound. Optionally, the well treatment fluid composition may further include various other fluid additives, such as pH buffers, biocides, stabilizers, propping agents (i.e., proppants), mutual solvents, and surfactants designed to prevent emulsion with formation fluids, to reduce surface tension, to enhance load recovery, and/or to foam the fracturing fluid. The well treatment fluid composition may also contain one or more salts, such as potassium chloride, magnesium chloride, sodium chloride, calcium chloride, tetramethyl ammonium chloride, and mixtures thereof. It is found that a fracturing fluid made in accordance with embodiments of the invention exhibits reduced or minimal premature breaking and breaks completely or substantially completely after a well treatment is finished.
[0020] "Premature breaking" as used herein refers to a phenomenon in which a gel viscosity becomes diminished to an undesirable extent before all of the fluid is introduced into the formation to be fractured. Thus, to be satisfactory, the gel viscosity should preferably remain in the range from about 50% to about 75% of the initial viscosity of the gel for at least two hours of exposure to the expected operating temperature. Preferably the fluid should have a viscosity in excess of 100 centipoise (eP) at 100 sec 1 while injection into the reservoir as measured on a Fann 50 C viscometer in the laboratory.
[0021 ] "Complete breaking" as used herein refers to a phenomenon in which the viscosity of a gel is reduced to such a level that the gel can be flushed from the formation by the flowing formation fluids or that it can be recovered by a swabbing operation. In laboratory settings, a completely broken, non-crosslinked gel is one whose viscosity is about 10 cP
or less as measured on a Mode135 Fann viscometer having a R1B1 rotor and bob assembly rotating at 300 rpm.
[0022] An aqueous fracturing fluid may be prepared by blending a hydratable polymer with an aqueous base fluid. The base aqueous fluid can be, -for example, water or brine. Any suitable mixing apparatus may be used for this procedure. In the case of batch mixing, the hydratable polymer and aqueous fluid are blended for a period of time which is sufficient to form a hydrated sol.
[0023] Suitable hydratable polymers that may be used in embodiments of the invention include any of the hydratable polysaccharides which are capable of forming a gel in the presence of a io crosslinking agent. For instance, suitable hydratable polysaccharides include, but are not limited to, galactomannan gums, glucomannan gums, guars, derived guars, and cellulose derivatives.
Specific examples are guar gum, guar gum derivatives, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose.
Presently preferred gelling agents include, but are not limited to, guar gums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar, carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitable hydratable polymers may also include synthetic polymers, such as polyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propane sulfonic acid, and various other synthetic polymers and copolymers. Other suitable polymers are known to those skilled in the art.
[0024] The hydratable polymer may be present in the fluid in concentrations ranging from about 0.10% to about 5.0% by weight of the aqueous fluid. A preferred range for the hydratable polymer is about 0.20% to about 0.80% by weight.
[0025] A suitable crosslinking agent can be any compound that increases the viscosity of the fluid by chemical crosslinking, physical crosslinking, or any other mechanisms. For example, the gellation of a hydratable polymer can be achieved by crosslinking the polymer with metal ions including boron, zirconium, and titanium containing compounds, or mixtures thereof. One class of suitable crosslinking agents is organotitanates. Another class of suitable crosslinking agents is borates as described, for example, in U.S. Patent No. 4,514,309. The selection of an appropriate crosslinking agent depends upon the type of treatment to be performed and the 3o hydratable polymer to be used. The amount of the crosslinking agent used also depends upon the well conditions and the type of treatment to be effected, but is generally in the range of from about 10 ppm to about 1000 ppm of metal ion of the crosslinking agent in the hydratable polymer fluid. In some applications, the aqueous polymer solution is crosslinked immediately upon addition of the crosslinking agent to form a highly viscous gel. In other applications, the reaction of the crosslinking agent can be retarded so that viscous gel formation does not occur until the desired time.
[0026] The pH of an aqueous fluid which contains a hydratable polymer can be adjusted if necessary to render the fluid compatible with a crosslinking agent.
Preferably, a pH adjusting material is added to the aqueous fluid after the addition of the polymer to the aqueous fluid.
Typical materials for adjusting the pH are commonly used acids, acid buffers, and mixtures of io acids and bases. For example, sodium bicarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, and sodium carbonate are typical pH adjusting agents.
Acceptable pH
values for the fluid may range from neutral to basic, i.e., from about 5 to about 14. Preferably, the pH is kept neutral or basic, i.e., from about 7 to about 14, more preferably between about 8 to about 12.
[0027] The term "breaking agent" or "breaker" refers to any chemical that is capable of reducing the viscosity of a gelled fluid. As described above, after a fracturing fluid is formed and pumped into a subterranean formation, it is generally desirable to convert the highly viscous gel to a lower viscosity fluid. This allows the fluid to be easily and effectively removed from the formation and to allow desired material, such as oil or gas, to flow into the well bore. This 2o reduction in viscosity of the treating fluid is commonly referred to as "breaking". Consequently, the chemicals used to break the viscosity of the fluid is referred to as a breaking agent or a breaker.
[0028] There are various methods available for breaking a fracturing fluid or a treating fluid.
Typically, fluids break after the passage of time and/or prolonged exposure to high temperatures.
However, it is desirable to be able to predict and control the breaking within relatively narrow limits. Mild oxidizing agents are useful as breakers when a fluid is used in a relatively high temperature formation, although formation temperatures of 300 F (149 C). or higher will generally break the fluid relatively quickly without the aid of an oxidizing agent.
[0029] Examples of inorganic breaking agents for use in this invention include, but are not limited to, persulfates, percarbonates, perborates, peroxides, perphosphates, permanganates, etc.
Specific examples of inorganic breaking agents include, but are not limited to, alkaline earth metal persulfates, alkaline earth metal percarbonates, alkaline earth metal perborates, alkaline earth metal peroxides, alkaline earth metal perphosphates, zinc salts of peroxide, perphosphate, perborate, and percarbonate, and so on. Additional suitable breaking agents are disclosed in U.S.
Patents No. 5,877,127; No. 5,649,596; No. 5,669,447; No. 5,624,886; No.
5,106,518; No.
6,162,766; and No. 5,807,812. In some embodiments, an inorganic breaking agent is selected from alkaline earth metal or transition metal-based oxidizing agents, such as magnesium peroxides, zinc peroxides, and calcium peroxides.
[0030] In addition, enzymatic breakers may also be used in place of or in addition to a non-enzymatic breaker. Examples of suitable enzymatic breakers such as guar specific enzymes, jo alpha and beta amylases, amyloglucosidase, aligoglucosidase, invertase, maltase, cellulase, and hemi-cellulase are disclosed in U.S. Patents No. 5,806,597 and No. 5,067,566.
[0031] A breaking agent or breaker may be used "as is" or be encapsulated and activated by a variety of mechanisms including crushing by formation closure or dissolution by formation fluids. Such techniques are disclosed, for example, in U.S. Patents Nos.
4,506,734; 4,741,401;
5,110,486; and 3,163,219.
[0032] Suitable ester compounds include any ester which is capable of assisting the breaker in degrading the viscous fluid in a controlled manner, i.e., providing delayed breaking initially and substantially complete breaking after well treatment is completed. An ester compound is defined as a compound that includes one or more carboxylate groups: R-COO-, wherein R
is phenyl, methoxyphenyl, alkylphenyl, C1-C>> alkyl, C1-C>> substituted alkyl, substituted phenyl, or other organic radicals. Suitable esters include, but are not limited to, diesters, triesters, etc.
[0033] An ester is typically formed by a condensation reaction between an alcohol and an acid by eliminating one or more water molecules. Preferably, the acid is an organic acid, such as a carboxylic acid. A carboxylic acid refers to any of a family of organic acids characterized as polycarboxylic acids and by the presence of more than one carboxyl group. In additional to carbon, hydrogen, and oxygen, a carboxylic acid may include heteroatoms, such as S, N, P, B, Si, F, Cl, Br, and I. In some embodiments, a suitable ester compound is an ester of oxalic, malonic, succinic, malic, tartaric, citrate, phthalic, ethylenediaminetetraacetic (EDTA), nitrilotriacetic, phosphoric, etc. Moreover, suitable esters also include the esters of glycolic acid.
3o The alkyl group in an ester that comes from the corresponding alcohol includes any alkyl group, both substituted or unsubstituted. Preferably, the alkyl group has one to about ten carbon atoms per group. It was found that the number of carbon atoms on the alkyl group affects the water solubility of the resulting ester. For example, esters made from CI-C2 alcohols, such as methanol and ethanol, have relatively higher water solubility. Thus, application temperature range for these esters may range from about 120 F to about 250 F (about 49 C to about 121 C). For higher temperature applications, esters formed from C3-Clo alcohols, such as n-propanol, butanol, hexanol, and cyclohexanol, may be used. Of course, esters formed from C>> or higher alcohols may also be used. In some embodiments, mixed esters, such as acetyl methyl dibutyl citrate, may be used for high temperature applications. Mixed esters refer to those esters made from polycarboxylic acid with two or more different alcohols in a single condensation reaction.
io For example, acetyl methyl dibutyl citrate may be prepared by condensing citric acid with both methanol and butanol and then followed by acylation.
[0034] Specific examples of the alkyl groups originating from an alcohol include, but are not limited to, methyl, ethyl, propyl, butyl, iso-butyl, 2-butyl, t-butyl, benzyl, p-methoxybenzyl, m-methoxybenxyl, chlorobenzyl, p-chlorobenzyl, phenyl, hexyl, pentyl, etc.
Specific examples of suitable ester compounds include, but are not limited to, triethyl phosphate, diethyl oxalate, dimethyl phthalate, dibutyl phthalate, diethyl maleate, diethyl tartrate, 2-ethoxyethyl acetate, ethyl acetylacetate, triethyl citrate, acetyl triethyl citrate, tetracyclohexyl EDTA, tetra-l-octyl EDTA, tetra-n-butyl EDTA, tetrabenzyl EDTA, tetramethyl EDTA, etc. Additional suitable ester compounds are described, for example, in the following U.S. Patents:
3,990,978; 3,960,736;
2o 5,067,556; 5,224,546; 4,795,574; 5,693,837; 6,054,417; 6,069,118;
6,060,436; 6,035,936;
6,147,034; and 6,133,205.
[0035] When an ester of a polycarboxylic acid is used, total esterification of the acid functionality is preferred, although a partially esterified compound may also be used in place of or in addition to a totally esterified compound. In these embodiments, phosphate esters are not used alone. A phosphate ester refers to a condensation product between an alcohol and a phosphorus acid or a phosphoric acid and metal salts thereof. However, in these embodiments, combination of a polycarboxylic acid ester with a phosphate ester may be used to assist the degradation of a viscous gel.
[0036] When esters of polycarboxylic acids, such as esters of oxalic, malonic, succinic, malic, tartaric, citrate, phthalic, ethylenediaminetetraacetic (EDTA), nitrilotriacetic, and other carboxylic acids are used, it was observed that these esters assist metal based oxidizing agents (such as alkaline earth metal or zinc peroxide) in the degradation of fracturing fluids. It was found that the addition of 0.1 gal/Mgal (0.1 1/m3) to 5 gal/Mgal (5 1/m3) of these esters significantly improves the degradation of the fracturing fluid. More importantly, the degradation response is delayed, allowing the fracturing fluid ample time to create the fracture and place the proppant prior to the degradation reactions. The delayed reduction in viscosity is likely due to the relatively slow hydrolysis of the ester, which forms polycarboxylate anions as hydrolysis products. These polycarboxylate anions, in turn, improve the solubility of metal based oxidizing agents by sequestering the metal associated with the oxidizing agents. This may have promoted a relatively rapid decomposition of the oxidizing agent and caused the fracturing fluid degradation.
io [0037] Generally, the temperature and the pH of a fracturing fluid affects the rate of hydrolysis of an ester. For downhole operations, the bottom hole static temperature ("BHST") cannot be easily controlled or changed. The pH of a fracturing fluid usually is adjusted to a level to assure proper fluid performance during the fracturing treatment. Therefore, the rate of hydrolysis of an ester could not be easily changed by altering BHST or the pH of a fracturing fluid. However, the is rate of hydrolysis may be controlled by the amount of an ester used in a fracturing fluid. For higher temperature applications, the hydrolysis of an ester may be retarded or delayed by dissolving the ester in a hydrocarbon solvent. Moreover, the delay time may be adjusted by selecting esters that provide more or less water solubility. For example, for low temperature applications, polycarboxylic esters made from low molecular weight alcohols, such as methanol 2o or ethanol, are recommended. The application temperature range for these esters could range from about 120 F to about 250 F (about 49 C to about 121 C). On the other hand, for higher temperature applications or longer injection times, esters made from higher molecular weight alcohols should preferably be used. The higher molecular weight alcohols include, but are not limited to, C3-C6 alcohols, e.g., n-propanol, hexanol, and cyclohexanol.
25 [0038] In some embodiments, esters of citric acid are used in formulating a well treatment fluid.
A preferred ester of citric acid is acetyl triethyl citrate, which is available under the trade name Citroflex A2 from Morflex, Inc., Greensboro, North Carolina.
[0039] As described previously, propping agents or proppants are typically added to the fracturing fluid prior to the addition of a crosslinking agent. However, proppants may be 30 introduced in any manner which achieves the desired result. Any proppant may be used in embodiments of the invention. Examples of suitable proppants include, but are not limited to, quartz sand grains, glass and ceramic beads, walnut shell fragments, aluminum pellets, nylon pellets, and the like. Proppants are typically used in concentrations between about 1 to 8 lbs. per gallon of a fracturing fluid, although higher or lower concentrations may also be used as desired.
The fracturing fluid may also contain other additives, such as surfactants, corrosion inhibitors, mutual solvents, stabilizers, paraffin inhibitors, tracers to monitor fluid flow back, and so on.
[0040] The well treatment fluid composition in accordance with embodiments of the invention has many useful applications. For example, it may be used in hydraulic fracturing, gravel packing operations, water blocking, temporary plugs for purposes of wellbore isolation and/or fluid loss control, and other well completion operations. One application of the fluid composition is to use it as a fracturing fluid. Accordingly, embodiments of the invention also io provide a method of treating a subterranean formation. The method includes formulating a fracturing fluid comprising an aqueous fluid, a hydratable polymer, a crosslinking agent, an inorganic breaking agent, and an ester compound; and injecting the fracturing fluid into a bore hole to contact at least a part of the formation by the fracturing fluid under a sufficient pressure to fracture the formation. Initially, the viscosity of the fracturing fluid should be maintained above at least 200 cP at 40 sec 1 during injection and, afterwards, should be reduced to less than 200 cP at 40 sec"I . After the viscosity of the fracturing fluid is lowered to an acceptable level, at least a portion of the fracturing fluid is removed from the formation. During the fracturing process, a proppant can be injected into the formation simultaneously with the fracturing fluid.
Preferably, the fracturing fluid has a pH around or above about 7, more preferably in the range of 2o about 8 to about 12.
[0041] It should be understood that the above-described method is only one way to carry out embodiments of the invention. The following U.S. Patents disclose various techniques for conducting hydraulic fracturing which may be employed in embodiments of the invention with or without modifications: 6,169,058; 6,135,205; 6,123,394; 6,016,871;
5,755,286; 5,722,490;
5,711,396; 5,551,516; 5,497,831; 5,488,083; 5,482,116; 5,472,049; 5,411,091;
5,402,846;
5,392,195; 5,363,919; 5,228,510; 5,074,359; 5,024,276; 5,005,645; 4,938,286;
4,926,940;
4,892,147; 4,869,322; 4,852,650; 4,848,468; 4,846,277; 4,830,106; 4,817,717;
4,779,680;
4,479,041; 4,739,834; 4,724,905; 4,718,490; 4,714,115; 4,705,113; 4,660,643;
4,657,081;
4,623,021; 4,549,608; 4,541,935; 4,378,845; 4,067,389; 4,007,792; 3,965,982;
and 3,933,205.
30 [0008] On the other hand, gelled fluids which break too slowly can cause slow recovery of the fracturing fluid from the produced fracture with attendant delay in resuming the production of formation fluids and severely impair anticipated hydrocarbon production.
Additional problems may occur, such as the tendency of proppant to become dislodged from the fracture, resulting in at least partial closing and decreased efficiency of the fracturing operation.
Preferably, the fracturing gel should begin to break when the pumping operations are concluded. For practical purposes, the gel preferably should be completely broken within about 24 hours after completion of the fracturing treatment.
[0009] U.S. Patent No. 3,960,736 (issued June 1, 1976) suggests the use of acetal esters and polysaccharides in well treatment compositions. The acetal esters hydrolyze to release the component alcohols and acids, which subsequently catalyze breakdown of the polysaccharides.
io This breakdown reduces the viscosity of the composition.
[0010] U.S. Patent No. 5,224,546 (issued June 6, 1993) offers the use of an esterified carboxylated chelator for the hydrolysis of metal crosslinked polymer gels used in oil and gas well applications. At elevated temperatures, the esterified chelator undergoes hydrolysis to form an acid and an active ligand which subsequently removes the crosslinking metal ion from the gel and hydrolyses the polymer. This reduces the viscosity of the gel and allows removal of the material after treatment of the well.
[0011 ] For the foregoing reasons, there is a continuing need for a well treatment fluid which could maintain a relatively high viscosity while it is injected into a wellbore. After a sufficient period of time to allow complete well treatment, the viscosity of the fluid should decrease to a level such that the fluid could be removed relatively easily.
SUMMARY OF THE INVENTION
[0012] Most fluid breakers either reduce the fluid viscosity too soon or, on the other extreme, provide incomplete viscosity reduction. It has been discovered that a synergistic effect occurs between certain inorganic oxidizing agents and certain organic esters.
Particularly, oxidizing salts having alkaline earth or transition metal cations and polycarboxylic esters are the most suitable mixtures. This combination of chemicals has been found to provide initial high viscosity fluids while also providing complete fluid degradation at later times. This combination allows for optimum fracture growth and proppant placement while enhancing the amount of treating fluid recovered after the well is placed back on production.
Ultimately, this effect significantly improves well productivity. U.S. Patent No. 5,224,546 (issued June 6, 1993) offers the use of an esterified carboxylated chelator for the hydrolysis of metal crosslinked polymer gels used in oil and gas well applications. At elevated temperatures, the esterified chelator undergoes hydrolysis to form an acid and an active ligand which subsequently removes the crosslinking metal ion from the gel and hydrolyses the polymer. This reduces the viscosity of the gel and allows removal of the material after treatment of the well.
[0012a] In accordance with an embodiment of the present invention there is provided a well treatment fluid composition comprising: a solvent; a polymer which is either soluble or hydratable in the solvent; a crosslinking agent; a breaking agent;
and an ester, wherein: the breaking agent is selected from the group consisting of an alkaline earth metal or zinc, percarbonate, perborate, peroxide and perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
[0012b] In accordance with another embodiment of the present invention there is provided a well treatment fluid composition comprising: water; a polymer selected from the group consisting of a galactomannan gum, a glucomannan gum, a guar, a derived guar, cellulose, a cellulose derivative, guar gum, a guar gum derivative, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose; a crosslinking agent selected from the group consisting of a boron compound, a titanium compound, and a zirconium compound;
a breaking agent selected from the group consisting of an alkaline earth metal persulfate, an alkaline earth metal percarbonate, an alkaline earth metal perborate, an alkaline earth metal peroxide, an alkaline earth metal perphosphate, a zinc peroxide, a zinc perphosphate, a zinc perborate, and a zinc percarbonate; and an ester selected from the group consisting of a C1-C11 alcohol oxalate ester, a C, -C>> alcohol citrate ester, a Ci-C>> alcohol ethylene diamine tetraacetate ester, a Cl-C11 alcohol nitrilotriacetate ester, a C1-C>> alcohol phosphate ester, a Cl-C11 alcohol phthalate ester, a CI-C1I
alcohol maleate ester, and a CI -CI1 alcohol tartrate ester.
[0012c] A further embodiment of the present invention provides a well treatment fluid composition comprising: water; a polysaccharide; a zirconium compound;
magnesium peroxide, calcium peroxide, or zinc peroxide; and acetyl triethyl citrate.
[0012d] A still further embodiment provides a well treatment fluid composition comprising; water; a polysaccharide at a concentration of about 0.2 wt% to about 0.8 wt% based on the weight of the composition; a zirconium compound at a concentration - 4a -of about 10 ppm metal to about 100 ppm metal; a breaking agent selected from the group consisting of magnesium peroxide, calcium peroxide, and zinc peroxide, wherein the breaking agent is at a concentration of about 0.25 lb/thousand gallons (PPTG) (0.146 kg/m3) to about 5 PPTG (2.91 kg/m3); and acetyl triethyl citrate at a concentration of about 0.25 gallons/thousand gallons (0.25 1/m) to about 3 gallons/thousand gallons (3 1/m).
[0012e] Another embodiment of the present invention provides a method of fracturing a subterranean formation, the method comprising: obtaining a well treatment fluid comprising a solvent, a polymer which is either soluble or hydratable in the solvent, a crosslinking agent, a breaking agent, and an ester; and contacting the well treatment fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation; wherein: the breaking agent is selected from the group consisting of an alkaline earth metal or zinc percarbonate, perborate, peroxide, and perphosphate; and the ester is an ester of a polycarboxylic acid and a CI -C>>
alcohol.
[0012f] Yet another embodiment provides a method of fracturing a subterranean formation, the method comprising: contacting water or brine with guar gum, hydroxypropyl guar, carboxymethyl guar, carboxymethyl hydroxypropyl guar, or carboxymethyl hydroxyethyl cellulose to form a base gel, contacting the base gel with:
a borate, titanate or zirconium crosslinking agent; an alkaline earth metal peroxide or zinc peroxide; and a citric acid ester to form a gelling fluid; and contacting the gelling fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation, wherein: the citric acid ester provides delayed breaking initially and substantially complete breaking after fracture formation is completed.
[0012g] A further embodiment of the present invention provides a well treatment fluid composition comprising: a solvent; a polymer which is either soluble or hydratable in the solvent; a crosslinking agent; a breaking agent; an enzyme; and an ester, wherein:
the breaking agent is an inorganic percarbonate, perborate, peroxide, or perphosphate;
and the ester is an ester of a polycarboxylic acid and a CI-C1 i alcohol.
DESCRIPTION OF THE FIGURES
[0013] The following figure forms part of the present specification and is included to further demonstrate certain aspects of the present invention. The invention may be - 4b -better understood by reference to the figure in combination with the detailed description of specific embodiments presented herein.
[0014] Figure 1 is a plot of viscosity curves as a function of time for various well treatment fluids.
DETAILED DESCRIPTION OF THE INVENTION
[0015] The aforementioned need is met by embodiments of the invention in one or more of the following aspects. In one aspect, the invention relates to a well treatment fluid composition. The composition comprises a solvent, a polymer soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, and an ester compound. Preferably, the solvent includes water, and the polymer is hydratable in water. The solvent may be an aqueous potassium chloride solution. The inorganic breaking agent may be a metal-based oxidizing agent, such as an alkaline earth metal or a transition metal. The inorganic breaking agent may be magnesium peroxide, calcium peroxide, or zinc peroxide. The ester compound may be an ester of a polycarboxylic acid. For example, the ester compound may be an ester of oxalate, citrate, or ethylene diamine tetraacetate. The ester compound having hydroxyl groups can also be acetylated. An example of this is that citric acid can be acetylated to form acetyl triethyl citrate. A presently preferred ester is acetyl triethyl citrate. The hydratable polymer may be a water soluble polysaccharide, such as galactomannan, cellulose, or derivatives thereof. The crosslinking agent may be a borate, titanate, or zirconium-containing compound. For example, the crosslinking agent can be sodium borate x H20 (varying waters of hydration), boric acid, borate crosslinkers (a mixture of a titanate constituent, preferably an organotitanate constituent, with a boron constituent. The organotitanate constituent can be TYZOR chelate esters from E.I. du Pont de Nemours & Company. The organotitanate constituent can be a mixture of a first organotitanate compound having a lactate base and a second organotitanate compound having s triethanolamine base. The boron constituent can be selected from the group consisting of boric acid, sodium tetraborate, and mixtures thereof. These are described in U.S.
Patent No.
4,514,309.), borate based ores such as ulexite and colemanite, Ti(IV) acetylacetonate, Ti(IV) triethanolamine, Zr lactate, Zr triethanolamine, Zr lactate-triethanolamine, or Zr lactate-triethanolamine-triisopropanolamine. In some embodiments, the well treatment fluid io composition may further comprise a proppant.
[0016] In another aspect, the invention relates to a well treatment fluid composition. The composition includes a solvent, a polymer soluble or hydratable in the solvent, a crosslinking agent, an alkaline earth metal or a transition metal-based breaking agent, and an ester of a carboxylic acid. The breaking agent may be magnesium peroxide, calcium peroxide, or zinc 15 peroxide. A presently preferred ester is acetyl triethyl citrate. The solvent may include water, and the polymer is hydratable in water. The solvent may be an aqueous potassium chloride solution. The hydratable polymer may be a polysaccharide.
[0017] In still another aspect, the invention relates to a method of treating a subterranean formation. The method comprises: formulating a fracturing fluid comprising a solvent, a 20 polymer soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, and an ester compound; and injecting the fracturing fluid into a bore hole to contact at least a part of the formation by the fracturing fluid under a sufficient pressure to fracture the formation. The fracturing fluid has a viscosity that changes in response to a condition. The method may further comprise removing the fracturing fluid after the viscosity of the fracturing fluid is reduced. In 25 some embodiments, the method may further comprise injecting a proppant into the formation.
The proppant may be injected into the formation with the fracturing fluid. The fracturing fluid may have a pH at or above about 7. Preferably, the fracturing fluid should have a pH in the range of about 8 to about 12. The inorganic breaking agent may be a metal-based oxidizing agent. The metal may be an alkaline earth metal or a transition metal. The inorganic breaking 3o agent may be magnesium peroxide, calcium peroxide, or zinc peroxide. The ester compound may be an ester of an polycarboxylic acid, such as an ester of oxalate, citrate, or ethylene diamine tetraacetate. A presently preferred ester compound is acetyl triethyl citrate. Preferably, the solvent includes water, and the polymer is a water soluble polysaccharide, such as galactomannan, cellulose, or derivatives thereof. The solvent may be an aqueous potassium chloride solution. The crosslinking agent may be a borate, titanate, or zirconium-containing compound. The fracturing fluid can further comprise sodium thiosulfate.
[0018] Embodiments of the invention provide a well treatment fluid composition and a method of using the fluid composition to treat subterranean formations. The well treatment fluid composition can be used in hydraulic fracturing as a fracturing fluid, gravel packing operations, water blocking, temporary plugs for purposes of wellbore isolation and/or fluid loss control and other well completion operations. Most well treatment fluids are aqueous, although non-aqueous io fluids may be formulated and used as well.
[0019] The well treatment fluid composition comprises a solvent (such as water), a polymer soluble or hydratable in the solvent, a crosslinking agent, an inorganic breaking agent, and an ester compound. Optionally, the well treatment fluid composition may further include various other fluid additives, such as pH buffers, biocides, stabilizers, propping agents (i.e., proppants), mutual solvents, and surfactants designed to prevent emulsion with formation fluids, to reduce surface tension, to enhance load recovery, and/or to foam the fracturing fluid. The well treatment fluid composition may also contain one or more salts, such as potassium chloride, magnesium chloride, sodium chloride, calcium chloride, tetramethyl ammonium chloride, and mixtures thereof. It is found that a fracturing fluid made in accordance with embodiments of the invention exhibits reduced or minimal premature breaking and breaks completely or substantially completely after a well treatment is finished.
[0020] "Premature breaking" as used herein refers to a phenomenon in which a gel viscosity becomes diminished to an undesirable extent before all of the fluid is introduced into the formation to be fractured. Thus, to be satisfactory, the gel viscosity should preferably remain in the range from about 50% to about 75% of the initial viscosity of the gel for at least two hours of exposure to the expected operating temperature. Preferably the fluid should have a viscosity in excess of 100 centipoise (eP) at 100 sec 1 while injection into the reservoir as measured on a Fann 50 C viscometer in the laboratory.
[0021 ] "Complete breaking" as used herein refers to a phenomenon in which the viscosity of a gel is reduced to such a level that the gel can be flushed from the formation by the flowing formation fluids or that it can be recovered by a swabbing operation. In laboratory settings, a completely broken, non-crosslinked gel is one whose viscosity is about 10 cP
or less as measured on a Mode135 Fann viscometer having a R1B1 rotor and bob assembly rotating at 300 rpm.
[0022] An aqueous fracturing fluid may be prepared by blending a hydratable polymer with an aqueous base fluid. The base aqueous fluid can be, -for example, water or brine. Any suitable mixing apparatus may be used for this procedure. In the case of batch mixing, the hydratable polymer and aqueous fluid are blended for a period of time which is sufficient to form a hydrated sol.
[0023] Suitable hydratable polymers that may be used in embodiments of the invention include any of the hydratable polysaccharides which are capable of forming a gel in the presence of a io crosslinking agent. For instance, suitable hydratable polysaccharides include, but are not limited to, galactomannan gums, glucomannan gums, guars, derived guars, and cellulose derivatives.
Specific examples are guar gum, guar gum derivatives, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose.
Presently preferred gelling agents include, but are not limited to, guar gums, hydroxypropyl guar, carboxymethyl hydroxypropyl guar, carboxymethyl guar, and carboxymethyl hydroxyethyl cellulose. Suitable hydratable polymers may also include synthetic polymers, such as polyvinyl alcohol, polyacrylamides, poly-2-amino-2-methyl propane sulfonic acid, and various other synthetic polymers and copolymers. Other suitable polymers are known to those skilled in the art.
[0024] The hydratable polymer may be present in the fluid in concentrations ranging from about 0.10% to about 5.0% by weight of the aqueous fluid. A preferred range for the hydratable polymer is about 0.20% to about 0.80% by weight.
[0025] A suitable crosslinking agent can be any compound that increases the viscosity of the fluid by chemical crosslinking, physical crosslinking, or any other mechanisms. For example, the gellation of a hydratable polymer can be achieved by crosslinking the polymer with metal ions including boron, zirconium, and titanium containing compounds, or mixtures thereof. One class of suitable crosslinking agents is organotitanates. Another class of suitable crosslinking agents is borates as described, for example, in U.S. Patent No. 4,514,309. The selection of an appropriate crosslinking agent depends upon the type of treatment to be performed and the 3o hydratable polymer to be used. The amount of the crosslinking agent used also depends upon the well conditions and the type of treatment to be effected, but is generally in the range of from about 10 ppm to about 1000 ppm of metal ion of the crosslinking agent in the hydratable polymer fluid. In some applications, the aqueous polymer solution is crosslinked immediately upon addition of the crosslinking agent to form a highly viscous gel. In other applications, the reaction of the crosslinking agent can be retarded so that viscous gel formation does not occur until the desired time.
[0026] The pH of an aqueous fluid which contains a hydratable polymer can be adjusted if necessary to render the fluid compatible with a crosslinking agent.
Preferably, a pH adjusting material is added to the aqueous fluid after the addition of the polymer to the aqueous fluid.
Typical materials for adjusting the pH are commonly used acids, acid buffers, and mixtures of io acids and bases. For example, sodium bicarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, and sodium carbonate are typical pH adjusting agents.
Acceptable pH
values for the fluid may range from neutral to basic, i.e., from about 5 to about 14. Preferably, the pH is kept neutral or basic, i.e., from about 7 to about 14, more preferably between about 8 to about 12.
[0027] The term "breaking agent" or "breaker" refers to any chemical that is capable of reducing the viscosity of a gelled fluid. As described above, after a fracturing fluid is formed and pumped into a subterranean formation, it is generally desirable to convert the highly viscous gel to a lower viscosity fluid. This allows the fluid to be easily and effectively removed from the formation and to allow desired material, such as oil or gas, to flow into the well bore. This 2o reduction in viscosity of the treating fluid is commonly referred to as "breaking". Consequently, the chemicals used to break the viscosity of the fluid is referred to as a breaking agent or a breaker.
[0028] There are various methods available for breaking a fracturing fluid or a treating fluid.
Typically, fluids break after the passage of time and/or prolonged exposure to high temperatures.
However, it is desirable to be able to predict and control the breaking within relatively narrow limits. Mild oxidizing agents are useful as breakers when a fluid is used in a relatively high temperature formation, although formation temperatures of 300 F (149 C). or higher will generally break the fluid relatively quickly without the aid of an oxidizing agent.
[0029] Examples of inorganic breaking agents for use in this invention include, but are not limited to, persulfates, percarbonates, perborates, peroxides, perphosphates, permanganates, etc.
Specific examples of inorganic breaking agents include, but are not limited to, alkaline earth metal persulfates, alkaline earth metal percarbonates, alkaline earth metal perborates, alkaline earth metal peroxides, alkaline earth metal perphosphates, zinc salts of peroxide, perphosphate, perborate, and percarbonate, and so on. Additional suitable breaking agents are disclosed in U.S.
Patents No. 5,877,127; No. 5,649,596; No. 5,669,447; No. 5,624,886; No.
5,106,518; No.
6,162,766; and No. 5,807,812. In some embodiments, an inorganic breaking agent is selected from alkaline earth metal or transition metal-based oxidizing agents, such as magnesium peroxides, zinc peroxides, and calcium peroxides.
[0030] In addition, enzymatic breakers may also be used in place of or in addition to a non-enzymatic breaker. Examples of suitable enzymatic breakers such as guar specific enzymes, jo alpha and beta amylases, amyloglucosidase, aligoglucosidase, invertase, maltase, cellulase, and hemi-cellulase are disclosed in U.S. Patents No. 5,806,597 and No. 5,067,566.
[0031] A breaking agent or breaker may be used "as is" or be encapsulated and activated by a variety of mechanisms including crushing by formation closure or dissolution by formation fluids. Such techniques are disclosed, for example, in U.S. Patents Nos.
4,506,734; 4,741,401;
5,110,486; and 3,163,219.
[0032] Suitable ester compounds include any ester which is capable of assisting the breaker in degrading the viscous fluid in a controlled manner, i.e., providing delayed breaking initially and substantially complete breaking after well treatment is completed. An ester compound is defined as a compound that includes one or more carboxylate groups: R-COO-, wherein R
is phenyl, methoxyphenyl, alkylphenyl, C1-C>> alkyl, C1-C>> substituted alkyl, substituted phenyl, or other organic radicals. Suitable esters include, but are not limited to, diesters, triesters, etc.
[0033] An ester is typically formed by a condensation reaction between an alcohol and an acid by eliminating one or more water molecules. Preferably, the acid is an organic acid, such as a carboxylic acid. A carboxylic acid refers to any of a family of organic acids characterized as polycarboxylic acids and by the presence of more than one carboxyl group. In additional to carbon, hydrogen, and oxygen, a carboxylic acid may include heteroatoms, such as S, N, P, B, Si, F, Cl, Br, and I. In some embodiments, a suitable ester compound is an ester of oxalic, malonic, succinic, malic, tartaric, citrate, phthalic, ethylenediaminetetraacetic (EDTA), nitrilotriacetic, phosphoric, etc. Moreover, suitable esters also include the esters of glycolic acid.
3o The alkyl group in an ester that comes from the corresponding alcohol includes any alkyl group, both substituted or unsubstituted. Preferably, the alkyl group has one to about ten carbon atoms per group. It was found that the number of carbon atoms on the alkyl group affects the water solubility of the resulting ester. For example, esters made from CI-C2 alcohols, such as methanol and ethanol, have relatively higher water solubility. Thus, application temperature range for these esters may range from about 120 F to about 250 F (about 49 C to about 121 C). For higher temperature applications, esters formed from C3-Clo alcohols, such as n-propanol, butanol, hexanol, and cyclohexanol, may be used. Of course, esters formed from C>> or higher alcohols may also be used. In some embodiments, mixed esters, such as acetyl methyl dibutyl citrate, may be used for high temperature applications. Mixed esters refer to those esters made from polycarboxylic acid with two or more different alcohols in a single condensation reaction.
io For example, acetyl methyl dibutyl citrate may be prepared by condensing citric acid with both methanol and butanol and then followed by acylation.
[0034] Specific examples of the alkyl groups originating from an alcohol include, but are not limited to, methyl, ethyl, propyl, butyl, iso-butyl, 2-butyl, t-butyl, benzyl, p-methoxybenzyl, m-methoxybenxyl, chlorobenzyl, p-chlorobenzyl, phenyl, hexyl, pentyl, etc.
Specific examples of suitable ester compounds include, but are not limited to, triethyl phosphate, diethyl oxalate, dimethyl phthalate, dibutyl phthalate, diethyl maleate, diethyl tartrate, 2-ethoxyethyl acetate, ethyl acetylacetate, triethyl citrate, acetyl triethyl citrate, tetracyclohexyl EDTA, tetra-l-octyl EDTA, tetra-n-butyl EDTA, tetrabenzyl EDTA, tetramethyl EDTA, etc. Additional suitable ester compounds are described, for example, in the following U.S. Patents:
3,990,978; 3,960,736;
2o 5,067,556; 5,224,546; 4,795,574; 5,693,837; 6,054,417; 6,069,118;
6,060,436; 6,035,936;
6,147,034; and 6,133,205.
[0035] When an ester of a polycarboxylic acid is used, total esterification of the acid functionality is preferred, although a partially esterified compound may also be used in place of or in addition to a totally esterified compound. In these embodiments, phosphate esters are not used alone. A phosphate ester refers to a condensation product between an alcohol and a phosphorus acid or a phosphoric acid and metal salts thereof. However, in these embodiments, combination of a polycarboxylic acid ester with a phosphate ester may be used to assist the degradation of a viscous gel.
[0036] When esters of polycarboxylic acids, such as esters of oxalic, malonic, succinic, malic, tartaric, citrate, phthalic, ethylenediaminetetraacetic (EDTA), nitrilotriacetic, and other carboxylic acids are used, it was observed that these esters assist metal based oxidizing agents (such as alkaline earth metal or zinc peroxide) in the degradation of fracturing fluids. It was found that the addition of 0.1 gal/Mgal (0.1 1/m3) to 5 gal/Mgal (5 1/m3) of these esters significantly improves the degradation of the fracturing fluid. More importantly, the degradation response is delayed, allowing the fracturing fluid ample time to create the fracture and place the proppant prior to the degradation reactions. The delayed reduction in viscosity is likely due to the relatively slow hydrolysis of the ester, which forms polycarboxylate anions as hydrolysis products. These polycarboxylate anions, in turn, improve the solubility of metal based oxidizing agents by sequestering the metal associated with the oxidizing agents. This may have promoted a relatively rapid decomposition of the oxidizing agent and caused the fracturing fluid degradation.
io [0037] Generally, the temperature and the pH of a fracturing fluid affects the rate of hydrolysis of an ester. For downhole operations, the bottom hole static temperature ("BHST") cannot be easily controlled or changed. The pH of a fracturing fluid usually is adjusted to a level to assure proper fluid performance during the fracturing treatment. Therefore, the rate of hydrolysis of an ester could not be easily changed by altering BHST or the pH of a fracturing fluid. However, the is rate of hydrolysis may be controlled by the amount of an ester used in a fracturing fluid. For higher temperature applications, the hydrolysis of an ester may be retarded or delayed by dissolving the ester in a hydrocarbon solvent. Moreover, the delay time may be adjusted by selecting esters that provide more or less water solubility. For example, for low temperature applications, polycarboxylic esters made from low molecular weight alcohols, such as methanol 2o or ethanol, are recommended. The application temperature range for these esters could range from about 120 F to about 250 F (about 49 C to about 121 C). On the other hand, for higher temperature applications or longer injection times, esters made from higher molecular weight alcohols should preferably be used. The higher molecular weight alcohols include, but are not limited to, C3-C6 alcohols, e.g., n-propanol, hexanol, and cyclohexanol.
25 [0038] In some embodiments, esters of citric acid are used in formulating a well treatment fluid.
A preferred ester of citric acid is acetyl triethyl citrate, which is available under the trade name Citroflex A2 from Morflex, Inc., Greensboro, North Carolina.
[0039] As described previously, propping agents or proppants are typically added to the fracturing fluid prior to the addition of a crosslinking agent. However, proppants may be 30 introduced in any manner which achieves the desired result. Any proppant may be used in embodiments of the invention. Examples of suitable proppants include, but are not limited to, quartz sand grains, glass and ceramic beads, walnut shell fragments, aluminum pellets, nylon pellets, and the like. Proppants are typically used in concentrations between about 1 to 8 lbs. per gallon of a fracturing fluid, although higher or lower concentrations may also be used as desired.
The fracturing fluid may also contain other additives, such as surfactants, corrosion inhibitors, mutual solvents, stabilizers, paraffin inhibitors, tracers to monitor fluid flow back, and so on.
[0040] The well treatment fluid composition in accordance with embodiments of the invention has many useful applications. For example, it may be used in hydraulic fracturing, gravel packing operations, water blocking, temporary plugs for purposes of wellbore isolation and/or fluid loss control, and other well completion operations. One application of the fluid composition is to use it as a fracturing fluid. Accordingly, embodiments of the invention also io provide a method of treating a subterranean formation. The method includes formulating a fracturing fluid comprising an aqueous fluid, a hydratable polymer, a crosslinking agent, an inorganic breaking agent, and an ester compound; and injecting the fracturing fluid into a bore hole to contact at least a part of the formation by the fracturing fluid under a sufficient pressure to fracture the formation. Initially, the viscosity of the fracturing fluid should be maintained above at least 200 cP at 40 sec 1 during injection and, afterwards, should be reduced to less than 200 cP at 40 sec"I . After the viscosity of the fracturing fluid is lowered to an acceptable level, at least a portion of the fracturing fluid is removed from the formation. During the fracturing process, a proppant can be injected into the formation simultaneously with the fracturing fluid.
Preferably, the fracturing fluid has a pH around or above about 7, more preferably in the range of 2o about 8 to about 12.
[0041] It should be understood that the above-described method is only one way to carry out embodiments of the invention. The following U.S. Patents disclose various techniques for conducting hydraulic fracturing which may be employed in embodiments of the invention with or without modifications: 6,169,058; 6,135,205; 6,123,394; 6,016,871;
5,755,286; 5,722,490;
5,711,396; 5,551,516; 5,497,831; 5,488,083; 5,482,116; 5,472,049; 5,411,091;
5,402,846;
5,392,195; 5,363,919; 5,228,510; 5,074,359; 5,024,276; 5,005,645; 4,938,286;
4,926,940;
4,892,147; 4,869,322; 4,852,650; 4,848,468; 4,846,277; 4,830,106; 4,817,717;
4,779,680;
4,479,041; 4,739,834; 4,724,905; 4,718,490; 4,714,115; 4,705,113; 4,660,643;
4,657,081;
4,623,021; 4,549,608; 4,541,935; 4,378,845; 4,067,389; 4,007,792; 3,965,982;
and 3,933,205.
[0042] As described above, a well treatment fluid may include a number of components. Table 1 below exemplifies some preferred compositional ranges for the fluid. It should be understood that compositions outside the indicated ranges are also within the scope of the invention.
Table 1. Exemplary Composition Ranges Component Presently Preferred Presently More Presently Most Range Preferred Range Preferred Range Hydratable Polymer 0.1 - 5.0 wt% 0.14 - 1.0 wt% 0.2 - 0.8 wt%
Crosslinking Agent 0.1 - 1000 ppm 1- 500 ppm 10 - 100 ppm Inorganic Breaking Agent 0.025 - 251b/Mgal 0.05 - 101b/Mgal 0.25 - 5 lb/Mgal (0.0146 - 14.55 (0.0291 - 5.82 (0.146 - 2.91 kg/m3) kg/m3) kg/m3) Ester 0.01 - 10 gal/Mgal 0.1 - 5 gal/Mgal 0.25 - 3 gal/Mgal (0.01 - 101/m). (0.1 - 5 1/m) (0.25 - 3 1/m3) Proppant 0 - 301b/gal 0 - 201b/gal 0 - 101b/gal (0 - 3595 kg/m3) (0 - 2397 kg/m3) (0 - 1198 kg/m3) pH Buffer 5- 14 7- 13 8- 12 [0043] In Table 1, the wt% of polymer is the weight of polymer divided by the total weight of the well treatment fluid, converted to percent. The crosslinking agent is in parts per million parts well treatment fluid. The breaking agent is in pounds per thousand gallons of well treatment fluid. The ester is in gallons per thousand gallons of well treatment fluid.
The proppant is in io pounds per gallon of well treatment fluid.
[0044] The following examples are presented to illustrate embodiments of the invention. None of the examples is intended, nor should it be construed, to limit the invention as otherwise described and claimed herein. All numerical values are approximate. Numerical ranges, if given, are merely exemplary. Embodiments outside the given numerical ranges may 1s nevertheless fall within the scope of the invention as claimed.
EXAMPLES
ExamWe 1: Fracturing fluid lacking both breaker and ester [0045] In this example the viscosity of a fracturing fluid that did not contain either a breaker or an ester was obtained to provide a reference point for comparison. A
fracturing fluid was prepared by adding 2.64 g of carboxymethyl guar to 1 L of water. Afterwards, 1 ml of a 50%
aqueous tetramethylammonium chloride solution, 1 ml of a surfactant designed to assist fluid flowback from the well after treatment and 0.25 ml of a surfactant blend designed to prevent emulsions between the fracturing fluid and formation fluids were added to the hydrating polymer s solution. After about 30 minutes, the pH of the fluid was adjusted to 10.45 with a potassium hydroxide and potassium carbonate solution followed by the addition of 1.5 ml of a zirconium based crosslinker solution having a Zr02 content of about 5.8 wt%.
[0046] About 45 g of this solution was weighed into a Fann 50C cup. The cup was then placed on the Fann 50C viscometer and pressured to about 200 psi with N2. The sample in the cup was io sheared at 450 sec 1 for 2 minutes followed by a rate sweep using 105, 85, 64 and 42 sec ' for about 2 minutes. Afterwards, a preset oil bath set to 250 F (121 C) was raised to heat the sample to the 250 F (121 C) test conditions. The rate sweep was repeated every 30 minutes and the interim rate between sweeps was 105 sec-1. The stresses associated with each rate used in the sweep together with the rates were used to calculate the power low indices n' and K'. The 15 n' is referred to as the flow behavior index, and the K' is the consistency index in the American Petroleum Institute ("API") Bulletin RP-39. The bulletin also provides a method to calculate the viscosity of pseudoplastic fracturing fluid using the n' and K' values. The calculated viscosities of the fluid described in this example and the following examples are presented at 40 sec-1.
[0047] The fluid in this example showed an initial viscosity of 935 cP at 40 sec-I and a 20 temperature of 249 F (120 C). After two hours, the fluid viscosity slightly increased to 960 cP
at 40 sec"1 and a fluid pH of 9.4. Generally, a viscosity of 200 cP at 40 sec 1 is considered necessary to transport proppant during the fracturing treatment. This fluid shows no sign of degrading in the first two hours.
Example 2: Fracturing fluid containingmagnesium peroxide 25 [0048] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide. The initial viscosity of this fluid at the tested temperature was found to be 755 cP at 40 sec 1, and the viscosity declined to less than 200 cP at 40 sec 1 in about 2 hours; but the fluid retained a viscosity of about 50 cP at 40 sec-1 for 16 hours.
Example 3: Fracturing fluid containiniz magnesium peroxide and acetyl triethyl citrate [0049] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 0.25 mL of acetyl triethyl citrate (acetyl triethyl citrate is a liquid with a density of 9.47 lb/gal). The initial viscosity of this fluid was found to be 892 cP at 40 sec' and the viscosity declined to less than 200 cP at 40 sec 1 in about 5.5 hours; but the fluid retained a viscosity of about 35 cP at 40 sec"1 for 16 hours, and the fluid pH was about 8.80.
Example 4: Fracturing fluid containing magnesium peroxide and acetyl triethyl citrate [0050] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 0.50 mL of acetyl triethyl citrate. The initial viscosity of this fluid was found to be io 659 cP at 40 sec 1, and the viscosity declined to less than 200 cP at 40 sec 1 in about 7 hours; but the fluid retained a viscosity of about 46 cP at 40 sec'1 for 16 hours and the fluid pH was about 8.20.
Example 5: Fracturing fluid containing magnesium peroxide and acetyl triethyl citrate [0051] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 0.75 mL of acetyl triethyl citrate. The initial viscosity of this fluid was found to be 795 cP at 40 sec'1, and the viscosity declined to less than 200 cP at 40 sec-l in about 5 hours; but the fluid retained a viscosity of about 45 cP at 40 sec-I for 16 hours and the fluid pH was 7.67.
Example 6: Fracturing fluid containingmagnesium peroxide and acetyl triethyl citrate [0052] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 1.0 mL of acetyl triethyl citrate. The initial viscosity of this fluid was found to be 565 cP at 40 sec-l, and the viscosity declined to less than 200 cP at 40 sec'1 in about 4 hours, but the fluid retained the viscosity of about 7 cP at 40 sec"1 for 10 hours and the fluid pH was 7.26.
Table 1. Exemplary Composition Ranges Component Presently Preferred Presently More Presently Most Range Preferred Range Preferred Range Hydratable Polymer 0.1 - 5.0 wt% 0.14 - 1.0 wt% 0.2 - 0.8 wt%
Crosslinking Agent 0.1 - 1000 ppm 1- 500 ppm 10 - 100 ppm Inorganic Breaking Agent 0.025 - 251b/Mgal 0.05 - 101b/Mgal 0.25 - 5 lb/Mgal (0.0146 - 14.55 (0.0291 - 5.82 (0.146 - 2.91 kg/m3) kg/m3) kg/m3) Ester 0.01 - 10 gal/Mgal 0.1 - 5 gal/Mgal 0.25 - 3 gal/Mgal (0.01 - 101/m). (0.1 - 5 1/m) (0.25 - 3 1/m3) Proppant 0 - 301b/gal 0 - 201b/gal 0 - 101b/gal (0 - 3595 kg/m3) (0 - 2397 kg/m3) (0 - 1198 kg/m3) pH Buffer 5- 14 7- 13 8- 12 [0043] In Table 1, the wt% of polymer is the weight of polymer divided by the total weight of the well treatment fluid, converted to percent. The crosslinking agent is in parts per million parts well treatment fluid. The breaking agent is in pounds per thousand gallons of well treatment fluid. The ester is in gallons per thousand gallons of well treatment fluid.
The proppant is in io pounds per gallon of well treatment fluid.
[0044] The following examples are presented to illustrate embodiments of the invention. None of the examples is intended, nor should it be construed, to limit the invention as otherwise described and claimed herein. All numerical values are approximate. Numerical ranges, if given, are merely exemplary. Embodiments outside the given numerical ranges may 1s nevertheless fall within the scope of the invention as claimed.
EXAMPLES
ExamWe 1: Fracturing fluid lacking both breaker and ester [0045] In this example the viscosity of a fracturing fluid that did not contain either a breaker or an ester was obtained to provide a reference point for comparison. A
fracturing fluid was prepared by adding 2.64 g of carboxymethyl guar to 1 L of water. Afterwards, 1 ml of a 50%
aqueous tetramethylammonium chloride solution, 1 ml of a surfactant designed to assist fluid flowback from the well after treatment and 0.25 ml of a surfactant blend designed to prevent emulsions between the fracturing fluid and formation fluids were added to the hydrating polymer s solution. After about 30 minutes, the pH of the fluid was adjusted to 10.45 with a potassium hydroxide and potassium carbonate solution followed by the addition of 1.5 ml of a zirconium based crosslinker solution having a Zr02 content of about 5.8 wt%.
[0046] About 45 g of this solution was weighed into a Fann 50C cup. The cup was then placed on the Fann 50C viscometer and pressured to about 200 psi with N2. The sample in the cup was io sheared at 450 sec 1 for 2 minutes followed by a rate sweep using 105, 85, 64 and 42 sec ' for about 2 minutes. Afterwards, a preset oil bath set to 250 F (121 C) was raised to heat the sample to the 250 F (121 C) test conditions. The rate sweep was repeated every 30 minutes and the interim rate between sweeps was 105 sec-1. The stresses associated with each rate used in the sweep together with the rates were used to calculate the power low indices n' and K'. The 15 n' is referred to as the flow behavior index, and the K' is the consistency index in the American Petroleum Institute ("API") Bulletin RP-39. The bulletin also provides a method to calculate the viscosity of pseudoplastic fracturing fluid using the n' and K' values. The calculated viscosities of the fluid described in this example and the following examples are presented at 40 sec-1.
[0047] The fluid in this example showed an initial viscosity of 935 cP at 40 sec-I and a 20 temperature of 249 F (120 C). After two hours, the fluid viscosity slightly increased to 960 cP
at 40 sec"1 and a fluid pH of 9.4. Generally, a viscosity of 200 cP at 40 sec 1 is considered necessary to transport proppant during the fracturing treatment. This fluid shows no sign of degrading in the first two hours.
Example 2: Fracturing fluid containingmagnesium peroxide 25 [0048] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide. The initial viscosity of this fluid at the tested temperature was found to be 755 cP at 40 sec 1, and the viscosity declined to less than 200 cP at 40 sec 1 in about 2 hours; but the fluid retained a viscosity of about 50 cP at 40 sec-1 for 16 hours.
Example 3: Fracturing fluid containiniz magnesium peroxide and acetyl triethyl citrate [0049] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 0.25 mL of acetyl triethyl citrate (acetyl triethyl citrate is a liquid with a density of 9.47 lb/gal). The initial viscosity of this fluid was found to be 892 cP at 40 sec' and the viscosity declined to less than 200 cP at 40 sec 1 in about 5.5 hours; but the fluid retained a viscosity of about 35 cP at 40 sec"1 for 16 hours, and the fluid pH was about 8.80.
Example 4: Fracturing fluid containing magnesium peroxide and acetyl triethyl citrate [0050] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 0.50 mL of acetyl triethyl citrate. The initial viscosity of this fluid was found to be io 659 cP at 40 sec 1, and the viscosity declined to less than 200 cP at 40 sec 1 in about 7 hours; but the fluid retained a viscosity of about 46 cP at 40 sec'1 for 16 hours and the fluid pH was about 8.20.
Example 5: Fracturing fluid containing magnesium peroxide and acetyl triethyl citrate [0051] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 0.75 mL of acetyl triethyl citrate. The initial viscosity of this fluid was found to be 795 cP at 40 sec'1, and the viscosity declined to less than 200 cP at 40 sec-l in about 5 hours; but the fluid retained a viscosity of about 45 cP at 40 sec-I for 16 hours and the fluid pH was 7.67.
Example 6: Fracturing fluid containingmagnesium peroxide and acetyl triethyl citrate [0052] The experiment in Example 1 was repeated but also included 0.12 g of magnesium peroxide and 1.0 mL of acetyl triethyl citrate. The initial viscosity of this fluid was found to be 565 cP at 40 sec-l, and the viscosity declined to less than 200 cP at 40 sec'1 in about 4 hours, but the fluid retained the viscosity of about 7 cP at 40 sec"1 for 10 hours and the fluid pH was 7.26.
Example 7: Composition of example fluids [0053] The content of the fracturing fluids from Examples 1-6 are summarized in Table 2 below.
Table 2. Composition of fracturing fluids Component Ex.1 Ex.2 Ex.3 Ex.4 Ex.5 Ex.6 Polymer 0.264% 0.264% 0.264% 0.264% 0.264% 0.264%
Crosslinker 87 ppm 87 ppm 87 ppm 87 ppm 87 ppm 87 ppm Breaker - 1]b/Mgal 1 lb/Mgal 1 lb/Mgal I lb/Mgal 1]b/Mgal 0.582 kg/m3 0.582 kg/m3 0.582 kg/m3 0.582 kg/m3 0.582 kg/m3 Ester - - 0.25 gal/Mgal 0.5 gal/Mgal 0.75 gal/Mgal 1.0 gaUMgal 0.25 11m3 0.5 1/m3 0.75 1/m3 1.0 I/m3 Proppant - - - - - -pH 10.45 10.45 10.45 10.45 10.45 10.45 Example 8: Compilation of viscosity data [0054] The data obtained from Examples 1-6 are summarized in Table 3 below.
Table 3. Viscosity Data for Various Fracturing Fluids Time Example 1 Example 2 Example 3 Example 4 Example 5 Example 6 (min) (cP) (cP) (cP) (cP) (cP) (cP) viscosity data were obtained at 250 F (121 C) and 40 sec .
[0055] Figure 1 is a plot of viscosity curves as a function of time for the fracturing fluids of lo Examples 1-6. Both the figure and the data show that the citrate ester initially stabilized the gel followed by complete or substantially complete breaks, especially as the ester concentration approaches 0.1% by volume. The figure indicates that initial stability of the fluid and improved fluid degradation were achieved. This should allow the fracturing fluid to generate desired fracture geometry and provide adequate proppant transport and placement.
Example 9: Effects of butyl citrate and magnesium peroxide on fracturing fluid degradation [0056] Three fracturing fluids were individually prepared by adding 3.36 g of carboxymethyl guar to 1 L of water. Afterwards, 1 ml of a 50% aqueous tetramethylammonium chloride solution was added to each fluid. After about 30 minutes, 0.36 g of sodium thiosulfate was added to each fluid and the pH of the fluids were adjusted to 10.45 with a potassium hydroxide and potassium carbonate solution followed by the addition of 1.5 ml of a zirconium based crosslinker solution having a Zr02 content of about 5.8%. The fluids also treated with breakers.
lo The first fluid contained 0.12 g magnesium peroxide, the second fluid contained 1 ml of tributyl citrate, and the third fluid contained 0.12 g magnesium peroxide and 1 ml of acetyltributyl citrate (ATBC, density of 8.75 lb/gal). The viscosity in cP at 100 sec-1 of each fluid at 275 F (135 C) is shown in Table 4.
Table 4. Viscosity of fluids Time (minutes) Fluid 1 Fluid 2 Fluid 3 0.12g Mg02 I ml ATBC 0.12g Mg02 + 1 ml ATBC
[0057] These results show that Fluid 1 containing 0.12 g MgOz has a limited pump time of about 90 minutes. Pump time is defined as the time the fluid viscosity exceeds 100 cP at 100 sec-1.
Although the ester by itself has longer pump time in excess of 3.5 hours, it does not completely degrade. However, the mixture of the peroxide and ester gives a longer pump time than does the peroxide alone, in excess of 2.5 hours, and it also completely degrades the fluid to about 1 cP.
Table 2. Composition of fracturing fluids Component Ex.1 Ex.2 Ex.3 Ex.4 Ex.5 Ex.6 Polymer 0.264% 0.264% 0.264% 0.264% 0.264% 0.264%
Crosslinker 87 ppm 87 ppm 87 ppm 87 ppm 87 ppm 87 ppm Breaker - 1]b/Mgal 1 lb/Mgal 1 lb/Mgal I lb/Mgal 1]b/Mgal 0.582 kg/m3 0.582 kg/m3 0.582 kg/m3 0.582 kg/m3 0.582 kg/m3 Ester - - 0.25 gal/Mgal 0.5 gal/Mgal 0.75 gal/Mgal 1.0 gaUMgal 0.25 11m3 0.5 1/m3 0.75 1/m3 1.0 I/m3 Proppant - - - - - -pH 10.45 10.45 10.45 10.45 10.45 10.45 Example 8: Compilation of viscosity data [0054] The data obtained from Examples 1-6 are summarized in Table 3 below.
Table 3. Viscosity Data for Various Fracturing Fluids Time Example 1 Example 2 Example 3 Example 4 Example 5 Example 6 (min) (cP) (cP) (cP) (cP) (cP) (cP) viscosity data were obtained at 250 F (121 C) and 40 sec .
[0055] Figure 1 is a plot of viscosity curves as a function of time for the fracturing fluids of lo Examples 1-6. Both the figure and the data show that the citrate ester initially stabilized the gel followed by complete or substantially complete breaks, especially as the ester concentration approaches 0.1% by volume. The figure indicates that initial stability of the fluid and improved fluid degradation were achieved. This should allow the fracturing fluid to generate desired fracture geometry and provide adequate proppant transport and placement.
Example 9: Effects of butyl citrate and magnesium peroxide on fracturing fluid degradation [0056] Three fracturing fluids were individually prepared by adding 3.36 g of carboxymethyl guar to 1 L of water. Afterwards, 1 ml of a 50% aqueous tetramethylammonium chloride solution was added to each fluid. After about 30 minutes, 0.36 g of sodium thiosulfate was added to each fluid and the pH of the fluids were adjusted to 10.45 with a potassium hydroxide and potassium carbonate solution followed by the addition of 1.5 ml of a zirconium based crosslinker solution having a Zr02 content of about 5.8%. The fluids also treated with breakers.
lo The first fluid contained 0.12 g magnesium peroxide, the second fluid contained 1 ml of tributyl citrate, and the third fluid contained 0.12 g magnesium peroxide and 1 ml of acetyltributyl citrate (ATBC, density of 8.75 lb/gal). The viscosity in cP at 100 sec-1 of each fluid at 275 F (135 C) is shown in Table 4.
Table 4. Viscosity of fluids Time (minutes) Fluid 1 Fluid 2 Fluid 3 0.12g Mg02 I ml ATBC 0.12g Mg02 + 1 ml ATBC
[0057] These results show that Fluid 1 containing 0.12 g MgOz has a limited pump time of about 90 minutes. Pump time is defined as the time the fluid viscosity exceeds 100 cP at 100 sec-1.
Although the ester by itself has longer pump time in excess of 3.5 hours, it does not completely degrade. However, the mixture of the peroxide and ester gives a longer pump time than does the peroxide alone, in excess of 2.5 hours, and it also completely degrades the fluid to about 1 cP.
Sodium thiosulfate appears to control, in part, the length of time that the fluid maintains front end stability.
[0058] The composition of the three fluids was as shown below in Table 5.
Table 5. Composition of Fluids 1-3 Component Fluid 1 Fluid 2 Fluid 3 Polymer 0.336% 0.336% 0.336%
Crosslinker, Zr02 87 ppm 87 ppm 87 ppm Breaker, Mg02 1 lb/Mgal - 1 lb/Mgal 0.582 kg/m3 0.582 kg/rn3 Ester, acetyltributyl citrate - 1 gal/Mgal 1 gal/Mgal 1 1/m3 1 1/m3 Proppant - - -Gel stabilizer, sodium thiosulfate 3 lb/Mgal 3 lb/Mgal 31b/Mgal 1.746 kg/m3 1.746 kg/m3 1.746 kg/m3 pH 10.45 10.45 10.45 Example 10: Relationship between inor anic peroxide and ester in a fracturing fluid [0059] To better understand the relationship between the inorganic peroxide and the ester in a fracturing fluid, a Design of Experiments (DOE) process was employed. This DOE
process is described by George E.P. Box, William G. Hunter and J. Stuart Hunter in their book Statistics io for Experimenters, published by John Wiley & Sons in 1978. In the design used in this example, the fracturing fluid was composed of DI water, 22 lb/Mgal (12.8 kg/m3) of carboxymethylguar supplied by BJ Services Company as GW-45, I gal/Mgal (1 1/m3) of 50 wt%
aqueous tetramethylammonium chloride, and 1 gal/Mgal (1 1/m) of a zirconium crosslinker having a zirconium content of about 5.8 wt% as Zr02. The parameters and their ranges are defined in Table 6.
[0058] The composition of the three fluids was as shown below in Table 5.
Table 5. Composition of Fluids 1-3 Component Fluid 1 Fluid 2 Fluid 3 Polymer 0.336% 0.336% 0.336%
Crosslinker, Zr02 87 ppm 87 ppm 87 ppm Breaker, Mg02 1 lb/Mgal - 1 lb/Mgal 0.582 kg/m3 0.582 kg/rn3 Ester, acetyltributyl citrate - 1 gal/Mgal 1 gal/Mgal 1 1/m3 1 1/m3 Proppant - - -Gel stabilizer, sodium thiosulfate 3 lb/Mgal 3 lb/Mgal 31b/Mgal 1.746 kg/m3 1.746 kg/m3 1.746 kg/m3 pH 10.45 10.45 10.45 Example 10: Relationship between inor anic peroxide and ester in a fracturing fluid [0059] To better understand the relationship between the inorganic peroxide and the ester in a fracturing fluid, a Design of Experiments (DOE) process was employed. This DOE
process is described by George E.P. Box, William G. Hunter and J. Stuart Hunter in their book Statistics io for Experimenters, published by John Wiley & Sons in 1978. In the design used in this example, the fracturing fluid was composed of DI water, 22 lb/Mgal (12.8 kg/m3) of carboxymethylguar supplied by BJ Services Company as GW-45, I gal/Mgal (1 1/m3) of 50 wt%
aqueous tetramethylammonium chloride, and 1 gal/Mgal (1 1/m) of a zirconium crosslinker having a zirconium content of about 5.8 wt% as Zr02. The parameters and their ranges are defined in Table 6.
Table 6. DOE Parameters and Ranges Parameter Low Value(-1) Center Value High Value(+1) Temperature 200 F (93 C) 237.5 F (114 C) 275 F (135 C) Magnesium Peroxide 1 lb/Mgal 21b/Mgal 31b/Mgal (0.582 kg/m3) (1.164 kg/m3) (1.746 kg/m3) Acetyltriethyl citrate 0.5 gal/Mgal 1.25 gal/Mgal 2.0 gal/Mgal (0.51/m) (1.251/m) (2.01/m3) Sodium Thiosulfate 0.51b/Mgal 2.75 lb/Mgal 5 lb/Mgal (0.291 kg/m3) (1.60 kg/m3) (2.91 kg/m3) [0060] This DOE was a two level factorial with six center point measurements requiring 22 Fann 50C runs conducted as described in Example 1. Each Fann run required 8 hours of continuous shear with the rate sweeps occurring as also defined in Example 1. The viscosity data at 40 sec'1 was transformed to their logarithmic values for better interpretation. The results of the analysis is presented in Table 7.
Table 7. DOE Analysis Parameter 1 Hour 2 Hours 4 Hours 8 Hours Grand Mean 2.11 1.88 1.59 1.35 Temperature -0.43 -0.53 -0.58 -0.53 MgO2 -0.01 - - Ester -0.23 -0.22 -0.21 -0.22 Na Thiosulfate 0.26 0.31 0.34 0.32 Temp*Na 0.20 - - -Thiosulfate MgO2*Ester 0.19 - - -io [0061] The fluid viscosity can be determined by taking the anti-log of the calculated value. The values presented in Table 6 are the coefficients associated to parameter. The Grand Mean is the base line value negating the effect of the important parameters.
[0062] The effect of temperature can be determined from the sign and magnitude of the coefficient. The high range of temperature is considered +1 so that +1 *-0.43 equals a -0.43 so that at high temperatures, the baseline viscosity 2.11 is reduced by -0.43 to yield 1.68 and the anti-log is 48 cP at 40 sec-1. The low temperature is a-1 so that -1 *_-0.43 equals +0.43 and is added to the Grand Mean to yield 2.54 or a viscosity of 347 cP at 40 sec 1.
Each parameter can be evaluated in a likewise manner. The last two effects in Table 6 are referred to as two-parameter interactions and are responsible, in part, for the initial, early time fluid stability. The algebraic product of high levels of Mg02, ester and the coefficient (+1 *+1 *+0.19) yields 0.19 and is added to the Grand Mean. Also algebraic product of low levels of Mg02, ester and coefficient (-1*-1*0.19) also yields 0.19 and is added to the Grand Mean. This effect shows strong synergy between the alkaline earth peroxide and the ester giving the fluid early enhanced io viscosity. Later, the effect diminishes allowing complete degradation of the fluid. A more complete explanation of DOE interpretation can be found in Box, Hunter and Hunter's book.
The design also shows that the length of time of high viscosity can also be regulated by manipulating the concentration of the sodium thiosulfate.
[0063] As demonstrated above, embodiments of the invention provide a well treatment fluid is composition and a method of treating subterranean formations using the composition. A
fracturing fluid in accordance with embodiments of the invention is capable of maintaining a relatively high viscosity initially for a sufficient period of time to avoid or minimize premature breaking. After the delayed period is over, the viscosity of the fracturing fluid decreases to a lower level in a relatively short period of time and maintains a lower viscosity for an extended 20 period of time to allow complete or substantially complete breaking of the fracturing fluid. As a result, the fracturing fluid can be removed from the formation and the production of the well may resume. Due to the desirable breaking characteristics of the fracturing fluid, well production may be carried out in an efficient and economic manner. Embodiments of the invention may be carried out without using enzymatic breakers. This would lead to cost savings and less 25 production complexity. Moreover, embodiments of the invention may provide better control of the timing and extent of the breaking of a fracturing fluid. Therefore, process consistency may be obtained. Additional characteristics and advantages provided by embodiments of the invention are apparent to a person skilled in the art.
[0064] While the invention has been described with respect to a limited number of embodiments, 30 these embodiments are not intended to limit the scope of the invention as otherwise described and claimed herein. Variations and modification from the described embodiments exist. For example, although it may be economical not to use enzyme breakers in embodiments of the invention, it is entirely acceptable and feasible to combine an enzymatic breaker with an inorganic breaker, along with an ester compound which assists in the degradation of a fracturing fluid so formulated. Similarly, although an inorganic breaking agent is preferred, this does not preclude the use of an organic breaking agent in place of or in addition to an inorganic breaking agent. As described previously, in some embodiments, only esters of polycarboxylic acids are used. This does not preclude use of other types of esters, such as phosphate esters, in other embodiments of the invention where their use is desirable. Moreover, polysaccharides are only one type of hydratable polymers. Any hydratable polymer may be used. In describing the method of treating a subterranean formation, various steps are disclosed.
These steps may be io practiced in any order or sequence unless otherwise described. Moreover, one or more steps may be combined into one single step. Conversely, one step may be practiced in two or more sub-steps. The appended claims intend to cover all such variations and modifications as falling within the scope of the invention.
[0065] All of the compositions and/or methods disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure.
While the compositions and methods of this invention have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions and/or methods and in the steps or in the sequence of steps of the methods 2o described herein without departing from the concept, spirit and scope of the invention. More specifically, it will be apparent that certain agents which are chemically related may be substituted for the agents described herein while the same or similar results would be achieved.
All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope and concept of the invention.
Table 7. DOE Analysis Parameter 1 Hour 2 Hours 4 Hours 8 Hours Grand Mean 2.11 1.88 1.59 1.35 Temperature -0.43 -0.53 -0.58 -0.53 MgO2 -0.01 - - Ester -0.23 -0.22 -0.21 -0.22 Na Thiosulfate 0.26 0.31 0.34 0.32 Temp*Na 0.20 - - -Thiosulfate MgO2*Ester 0.19 - - -io [0061] The fluid viscosity can be determined by taking the anti-log of the calculated value. The values presented in Table 6 are the coefficients associated to parameter. The Grand Mean is the base line value negating the effect of the important parameters.
[0062] The effect of temperature can be determined from the sign and magnitude of the coefficient. The high range of temperature is considered +1 so that +1 *-0.43 equals a -0.43 so that at high temperatures, the baseline viscosity 2.11 is reduced by -0.43 to yield 1.68 and the anti-log is 48 cP at 40 sec-1. The low temperature is a-1 so that -1 *_-0.43 equals +0.43 and is added to the Grand Mean to yield 2.54 or a viscosity of 347 cP at 40 sec 1.
Each parameter can be evaluated in a likewise manner. The last two effects in Table 6 are referred to as two-parameter interactions and are responsible, in part, for the initial, early time fluid stability. The algebraic product of high levels of Mg02, ester and the coefficient (+1 *+1 *+0.19) yields 0.19 and is added to the Grand Mean. Also algebraic product of low levels of Mg02, ester and coefficient (-1*-1*0.19) also yields 0.19 and is added to the Grand Mean. This effect shows strong synergy between the alkaline earth peroxide and the ester giving the fluid early enhanced io viscosity. Later, the effect diminishes allowing complete degradation of the fluid. A more complete explanation of DOE interpretation can be found in Box, Hunter and Hunter's book.
The design also shows that the length of time of high viscosity can also be regulated by manipulating the concentration of the sodium thiosulfate.
[0063] As demonstrated above, embodiments of the invention provide a well treatment fluid is composition and a method of treating subterranean formations using the composition. A
fracturing fluid in accordance with embodiments of the invention is capable of maintaining a relatively high viscosity initially for a sufficient period of time to avoid or minimize premature breaking. After the delayed period is over, the viscosity of the fracturing fluid decreases to a lower level in a relatively short period of time and maintains a lower viscosity for an extended 20 period of time to allow complete or substantially complete breaking of the fracturing fluid. As a result, the fracturing fluid can be removed from the formation and the production of the well may resume. Due to the desirable breaking characteristics of the fracturing fluid, well production may be carried out in an efficient and economic manner. Embodiments of the invention may be carried out without using enzymatic breakers. This would lead to cost savings and less 25 production complexity. Moreover, embodiments of the invention may provide better control of the timing and extent of the breaking of a fracturing fluid. Therefore, process consistency may be obtained. Additional characteristics and advantages provided by embodiments of the invention are apparent to a person skilled in the art.
[0064] While the invention has been described with respect to a limited number of embodiments, 30 these embodiments are not intended to limit the scope of the invention as otherwise described and claimed herein. Variations and modification from the described embodiments exist. For example, although it may be economical not to use enzyme breakers in embodiments of the invention, it is entirely acceptable and feasible to combine an enzymatic breaker with an inorganic breaker, along with an ester compound which assists in the degradation of a fracturing fluid so formulated. Similarly, although an inorganic breaking agent is preferred, this does not preclude the use of an organic breaking agent in place of or in addition to an inorganic breaking agent. As described previously, in some embodiments, only esters of polycarboxylic acids are used. This does not preclude use of other types of esters, such as phosphate esters, in other embodiments of the invention where their use is desirable. Moreover, polysaccharides are only one type of hydratable polymers. Any hydratable polymer may be used. In describing the method of treating a subterranean formation, various steps are disclosed.
These steps may be io practiced in any order or sequence unless otherwise described. Moreover, one or more steps may be combined into one single step. Conversely, one step may be practiced in two or more sub-steps. The appended claims intend to cover all such variations and modifications as falling within the scope of the invention.
[0065] All of the compositions and/or methods disclosed and claimed herein can be made and executed without undue experimentation in light of the present disclosure.
While the compositions and methods of this invention have been described in terms of preferred embodiments, it will be apparent to those of skill in the art that variations may be applied to the compositions and/or methods and in the steps or in the sequence of steps of the methods 2o described herein without departing from the concept, spirit and scope of the invention. More specifically, it will be apparent that certain agents which are chemically related may be substituted for the agents described herein while the same or similar results would be achieved.
All such similar substitutes and modifications apparent to those skilled in the art are deemed to be within the spirit, scope and concept of the invention.
Claims (43)
1. A well treatment fluid composition comprising:
a solvent;
a polymer which is either soluble or hydratable in the solvent;
a crosslinking agent;
a breaking agent; and an ester, wherein:
the breaking agent is selected from the group consisting of an alkaline earth metal or zinc, percarbonate, perborate, peroxide and perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
a solvent;
a polymer which is either soluble or hydratable in the solvent;
a crosslinking agent;
a breaking agent; and an ester, wherein:
the breaking agent is selected from the group consisting of an alkaline earth metal or zinc, percarbonate, perborate, peroxide and perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
2. The composition of claim 1, wherein the solvent is water.
3. The composition of claim 1, wherein the polymer is a galactomannan gum, a glucomannan gum, a guar, a derived guar, cellulose, a cellulose derivative, guar gum, a guar gum derivative, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, or hydroxyethyl cellulose.
4. The composition of claim 1, wherein the polymer is polyvinyl alcohol, polyacrylamide, or poly-2-amino-2-methyl propane sulfonic acid.
5. The composition of claim 1, wherein the crosslinking agent is a boron compound, a titanium compound, a zirconium compound, or mixtures thereof.
6. The composition of claim 1, wherein the crosslinking agent is a borate compound, a titanium compound, a zirconium compound, or mixtures thereof.
7. The composition of claim 1, wherein the crosslinking agent is sodium borate x H2O, boric acid, ulexite, colemanite, Ti(IV) acetylacetonate, Ti(IV) triethanolamine, Zr lactate, Zr triethanolamine, Zr lactate-triethanolamine, or Zr lactate-triethanolamine-triisopropanolamine.
8. The composition of claim 1, wherein the breaking agent is selected from the group consisting of calcium peroxide, magnesium peroxide and zinc peroxide.
9. The composition of claim 1, wherein the breaking agent further comprises an enzyme.
10. The composition of claim 1, wherein the ester is a C1-C11 alcohol oxalate ester, a C1-C11 alcohol citrate ester, a C1-C11 alcohol ethylene diamine tetraacetate ester, a C1-C11 alcohol nitrilotriacetate ester, a C1-C11 alcohol phosphate ester, a C1-C11 alcohol phthalate ester, a C1-C11 alcohol maleate ester, a C1-C11 alcohol malonate ester, or a C1-C11 alcohol tartrate ester.
11. The composition of claim 1, wherein the ester is dimethyl oxalate, dimethyl malonate, dimethyl succinate, dimethyl maleate, dimethyl tartrate, trimethyl citrate, dimethyl phthalate, tetramethyl ethylene diamine tetraacetate, trimethyl nitriloacetate, diethyl oxalate, diethyl malonate, diethyl succinate, diethyl maleate, diethyl tartrate, triethyl citrate, diethyl phthalate, tetraethyl ethylene diamine tetraacetate, triethyl nitriloacetate, dipropyl oxalate, dipropyl malonate, dipropyl succinate, dipropyl maleate, dipropyl tartrate, tripropyl citrate, dipropyl phthalate, tetrapropyl ethylene diamine tetraacetate, tripropyl nitriloacetate, dibutyl oxalate, dibutyl malonate, dibutyl succinate, dibutyl maleate, dibutyl tartrate, tributyl citrate, dibutyl phthalate, tetrabutyl ethylene diamine tetraacetate, or tributyl nitriloacetate.
12. The composition of claim 1, wherein the ester is acetyl trimethyl citrate, acetyl triethyl citrate, acetyl tripropyl citrate, or acetyl tributyl citrate.
13. The composition of claim 1, wherein the ester is acetyl triethyl citrate.
14. The composition of claim 1, further comprising sodium thiosulfate.
15. The composition of claim 1, further comprising a pH adjusting material.
16. The composition of claim 1, further comprising sodium bicarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide, or sodium carbonate.
17. The composition of claim 1, further comprising a surfactant.
18. The composition of claim 1, further comprising a salt.
19. The composition of claim 1, further comprising a potassium chloride, magnesium chloride, sodium chloride, calcium chloride, or tetramethylammonium chloride.
20. The composition of claim 1, further comprising a proppant.
21. The composition of claim 1, further comprising quartz sand grains, glass beads, ceramic beads, walnut shell fragments, aluminum pellets, or nylon pellets.
22. The composition of claim 1, wherein the concentration of polymer in the composition is about 0.10 wt% to about 5.0 wt% based on the weight of the composition.
23. The composition of claim 1, wherein the concentration of polymer in the composition is about 0.20 wt% to about 0.80 wt% based on the weight of the composition.
24. The composition of claim 1, wherein the pH of the composition is about to about 14.
25. The composition of claim 1, wherein the pH of the composition is about 7 to about 13.
26. The composition of claim 1, wherein the pH of the composition is about 8 to about 12.
27. A well treatment fluid composition comprising:
water;
a polymer selected from the group consisting of a galactomannan gum, a glucomannan gum, a guar, a derived guar, cellulose, a cellulose derivative, guar gum, a guar gum derivative, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose;
a crosslinking agent selected from the group consisting of a boron compound, a titanium compound, and a zirconium compound;
a breaking agent selected from the group consisting of an alkaline earth metal persulfate, an alkaline earth metal percarbonate, an alkaline earth metal perborate, an alkaline earth metal peroxide, an alkaline earth metal perphosphate, a zinc peroxide, a zinc perphosphate, a zinc perborate, and a zinc percarbonate; and an ester selected from the group consisting of a C1-C11 alcohol oxalate ester, a C1-C11 alcohol citrate ester, a C1-C11 alcohol ethylene diamine tetraacetate ester, a C1-C11 alcohol nitrilotriacetate ester, a C1-C11 alcohol phosphate ester, a C1-C11 alcohol phthalate ester, a C1-C11 alcohol maleate ester, and a C1-C11 alcohol tartrate ester.
water;
a polymer selected from the group consisting of a galactomannan gum, a glucomannan gum, a guar, a derived guar, cellulose, a cellulose derivative, guar gum, a guar gum derivative, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, and hydroxyethyl cellulose;
a crosslinking agent selected from the group consisting of a boron compound, a titanium compound, and a zirconium compound;
a breaking agent selected from the group consisting of an alkaline earth metal persulfate, an alkaline earth metal percarbonate, an alkaline earth metal perborate, an alkaline earth metal peroxide, an alkaline earth metal perphosphate, a zinc peroxide, a zinc perphosphate, a zinc perborate, and a zinc percarbonate; and an ester selected from the group consisting of a C1-C11 alcohol oxalate ester, a C1-C11 alcohol citrate ester, a C1-C11 alcohol ethylene diamine tetraacetate ester, a C1-C11 alcohol nitrilotriacetate ester, a C1-C11 alcohol phosphate ester, a C1-C11 alcohol phthalate ester, a C1-C11 alcohol maleate ester, and a C1-C11 alcohol tartrate ester.
28. A well treatment fluid composition comprising:
water;
a polysaccharide;
a zirconium compound;
magnesium peroxide, calcium peroxide, or zinc peroxide; and acetyl triethyl citrate.
water;
a polysaccharide;
a zirconium compound;
magnesium peroxide, calcium peroxide, or zinc peroxide; and acetyl triethyl citrate.
29. A well treatment fluid composition comprising:
water;
a polysaccharide at a concentration of about 0.2 wt% to about 0.8 wt% based on the weight of the composition;
a zirconium compound at a concentration of about 10 ppm metal to about 100 ppm metal;
a breaking agent selected from the group consisting of magnesium peroxide, calcium peroxide, and zinc peroxide, wherein the breaking agent is at a concentration of about 0.25 lb/thousand gallons (PPTG) (0.146 kg/m3) to about 5 PPTG (2.91 kg/m3);
and acetyl triethyl citrate at a concentration of about 0.25 gallons/thousand gallons (0.25 l/m3) to about 3 gallons/thousand gallons (3 1/m3).
water;
a polysaccharide at a concentration of about 0.2 wt% to about 0.8 wt% based on the weight of the composition;
a zirconium compound at a concentration of about 10 ppm metal to about 100 ppm metal;
a breaking agent selected from the group consisting of magnesium peroxide, calcium peroxide, and zinc peroxide, wherein the breaking agent is at a concentration of about 0.25 lb/thousand gallons (PPTG) (0.146 kg/m3) to about 5 PPTG (2.91 kg/m3);
and acetyl triethyl citrate at a concentration of about 0.25 gallons/thousand gallons (0.25 l/m3) to about 3 gallons/thousand gallons (3 1/m3).
30. A method of fracturing a subterranean formation, the method comprising:
obtaining a well treatment fluid comprising a solvent, a polymer which is either soluble or hydratable in the solvent, a crosslinking agent, a breaking agent, and an ester; and contacting the well treatment fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation;
wherein:
the breaking agent is selected from the group consisting of an alkaline earth metal or zinc percarbonate, perborate, peroxide, and perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
obtaining a well treatment fluid comprising a solvent, a polymer which is either soluble or hydratable in the solvent, a crosslinking agent, a breaking agent, and an ester; and contacting the well treatment fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation;
wherein:
the breaking agent is selected from the group consisting of an alkaline earth metal or zinc percarbonate, perborate, peroxide, and perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
31. The method of claim 30, wherein the solvent is water.
32. The method of claim 30, wherein the polymer is a galactomannan gum, a glucomannan gum, a guar, a derived guar, cellulose, a cellulose derivative, guar gum, a guar gum derivative, locust bean gum, Karaya gum, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, or hydroxyethyl cellulose.
33. The method of claim 30, wherein the polymer is polyvinyl alcohol, polyacrylamide, or poly-2-amino-2-methyl propane sulfonic acid.
34. The method of claim 30, wherein the crosslinking agent is a boron compound, a titanium compound, a zirconium compound, or mixtures thereof.
35. The method of claim 30, wherein the breaking agent is calcium peroxide, magnesium peroxide, or zinc peroxide.
36. The method of claim 30, wherein the ester is a C1-C11 alcohol oxalate ester, a C1-C11 alcohol citrate ester, a C1-C11 alcohol ethylene diamine tetraacetate ester, a C1-C11 alcohol nitrilotriacetate ester, a C1-C11 alcohol phosphate ester, a alcohol phthalate ester, a C1-C11 alcohol maleate ester, a C1-C11 alcohol malonate ester, or a C1-C11 alcohol tartrate ester.
37. The method of claim 30, wherein the ester is dimethyl oxalate, dimethyl malonate, dimethyl succinate, dimethyl maleate, dimethyl tartrate, trimethyl citrate, dimethyl phthalate, tetramethyl ethylene diamine tetraacetate, trimethyl nitriloacetate, diethyl oxalate, diethyl malonate, diethyl succinate, diethyl maleate, diethyl tartrate, triethyl citrate, diethyl phthalate, tetraethyl ethylene diamine tetraacetate, triethyl nitriloacetate, dipropyl oxalate, dipropyl malonate, dipropyl succinate, dipropyl maleate, dipropyl tartrate, tripropyl citrate, dipropyl phthalate, tetrapropyl ethylene diamine tetraacetate, tripropyl nitriloacetate, dibutyl oxalate, dibutyl malonate, dibutyl succinate, dibutyl maleate, dibutyl tartrate, tributyl citrate, dibutyl phthalate, tetrabutyl ethylene diamine tetraacetate, or tributyl nitriloacetate.
38. The method of claim 30, wherein the ester is acetyl trimethyl citrate, acetyl triethyl citrate, acetyl tripropyl citrate, or acetyl tributyl citrate.
39. The method of claim 30, wherein the ester is acetyl triethyl citrate.
40. A method of fracturing a subterranean formation, the method comprising:
contacting water or brine with guar gum, hydroxypropyl guar, carboxymethyl guar, carboxymethyl hydroxypropyl guar, or carboxymethyl hydroxyethyl cellulose to form a base gel, contacting the base gel with:
a borate, titanate or zirconium crosslinking agent;
an alkaline earth metal peroxide or zinc peroxide; and a citric acid ester to form a gelling fluid; and contacting the gelling fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation, wherein:
the citric acid ester provides delayed breaking initially and substantially complete breaking after fracture formation is completed.
contacting water or brine with guar gum, hydroxypropyl guar, carboxymethyl guar, carboxymethyl hydroxypropyl guar, or carboxymethyl hydroxyethyl cellulose to form a base gel, contacting the base gel with:
a borate, titanate or zirconium crosslinking agent;
an alkaline earth metal peroxide or zinc peroxide; and a citric acid ester to form a gelling fluid; and contacting the gelling fluid and at least a portion of the subterranean formation at pressures sufficient to form fractures in the formation, wherein:
the citric acid ester provides delayed breaking initially and substantially complete breaking after fracture formation is completed.
41. The method of claim 40, wherein the citric acid ester is trimethyl citrate, triethyl citrate, tripropyl citrate, or tributyl citrate.
42. The method of claim 40, wherein the citric acid ester is acetyl trimethyl citrate, acetyl triethyl citrate, acetyl tripropyl citrate, or acetyl tributyl citrate.
43. A well treatment fluid composition comprising:
a solvent;
a polymer which is either soluble or hydratable in the solvent;
a crosslinking agent;
a breaking agent;
an enzyme; and an ester, wherein:
the breaking agent is an inorganic percarbonate, perborate, peroxide, or perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
a solvent;
a polymer which is either soluble or hydratable in the solvent;
a crosslinking agent;
a breaking agent;
an enzyme; and an ester, wherein:
the breaking agent is an inorganic percarbonate, perborate, peroxide, or perphosphate; and the ester is an ester of a polycarboxylic acid and a C1-C11 alcohol.
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PCT/US2002/000676 WO2002055843A1 (en) | 2001-01-09 | 2002-01-08 | Well treatment fluid compositions and methods for their use |
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CN103498655A (en) * | 2013-09-05 | 2014-01-08 | 延长油田股份有限公司 | Micro powder silt fracturing method |
CN103498655B (en) * | 2013-09-05 | 2016-05-18 | 延长油田股份有限公司 | Micro mist sand fracturing process |
Also Published As
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CA2432160A1 (en) | 2002-07-18 |
US6983801B2 (en) | 2006-01-10 |
US20020125012A1 (en) | 2002-09-12 |
WO2002055843A1 (en) | 2002-07-18 |
US20050016733A1 (en) | 2005-01-27 |
AR035415A1 (en) | 2004-05-26 |
US6793018B2 (en) | 2004-09-21 |
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