US20070163779A1 - Compositions containing a buffer and a peroxide or peracid useful for treating wells - Google Patents
Compositions containing a buffer and a peroxide or peracid useful for treating wells Download PDFInfo
- Publication number
- US20070163779A1 US20070163779A1 US11/607,285 US60728506A US2007163779A1 US 20070163779 A1 US20070163779 A1 US 20070163779A1 US 60728506 A US60728506 A US 60728506A US 2007163779 A1 US2007163779 A1 US 2007163779A1
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- US
- United States
- Prior art keywords
- acid
- composition
- cell
- weight percent
- mud
- 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.)
- Abandoned
Links
- 239000000203 mixture Substances 0.000 title claims abstract description 57
- 150000004965 peroxy acids Chemical class 0.000 title claims abstract description 16
- 239000000872 buffer Substances 0.000 title claims abstract description 13
- 150000002978 peroxides Chemical class 0.000 title abstract description 5
- QTBSBXVTEAMEQO-UHFFFAOYSA-N Acetic acid Chemical compound CC(O)=O QTBSBXVTEAMEQO-UHFFFAOYSA-N 0.000 claims description 69
- MHAJPDPJQMAIIY-UHFFFAOYSA-N Hydrogen peroxide Chemical compound OO MHAJPDPJQMAIIY-UHFFFAOYSA-N 0.000 claims description 34
- KFSLWBXXFJQRDL-UHFFFAOYSA-N Peracetic acid Chemical compound CC(=O)OO KFSLWBXXFJQRDL-UHFFFAOYSA-N 0.000 claims description 31
- 238000011282 treatment Methods 0.000 claims description 27
- 235000011054 acetic acid Nutrition 0.000 claims description 23
- VMHLLURERBWHNL-UHFFFAOYSA-M Sodium acetate Chemical group [Na+].CC([O-])=O VMHLLURERBWHNL-UHFFFAOYSA-M 0.000 claims description 18
- KRKNYBCHXYNGOX-UHFFFAOYSA-N citric acid Chemical compound OC(=O)CC(O)(C(O)=O)CC(O)=O KRKNYBCHXYNGOX-UHFFFAOYSA-N 0.000 claims description 18
- 239000001632 sodium acetate Substances 0.000 claims description 18
- 235000017281 sodium acetate Nutrition 0.000 claims description 18
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 13
- 239000003112 inhibitor Substances 0.000 claims description 12
- 239000003795 chemical substances by application Substances 0.000 claims description 7
- 230000007797 corrosion Effects 0.000 claims description 7
- 238000005260 corrosion Methods 0.000 claims description 7
- BDAGIHXWWSANSR-UHFFFAOYSA-N methanoic acid Natural products OC=O BDAGIHXWWSANSR-UHFFFAOYSA-N 0.000 claims description 6
- 239000003638 chemical reducing agent Substances 0.000 claims description 4
- SCVFZCLFOSHCOH-UHFFFAOYSA-M potassium acetate Chemical compound [K+].CC([O-])=O SCVFZCLFOSHCOH-UHFFFAOYSA-M 0.000 claims description 4
- OSWFIVFLDKOXQC-UHFFFAOYSA-N 4-(3-methoxyphenyl)aniline Chemical compound COC1=CC=CC(C=2C=CC(N)=CC=2)=C1 OSWFIVFLDKOXQC-UHFFFAOYSA-N 0.000 claims description 3
- 102000003992 Peroxidases Human genes 0.000 claims description 3
- 159000000021 acetate salts Chemical class 0.000 claims description 3
- 150000001860 citric acid derivatives Chemical class 0.000 claims description 3
- 235000019253 formic acid Nutrition 0.000 claims description 3
- 150000004675 formic acid derivatives Chemical class 0.000 claims description 3
- 239000003381 stabilizer Substances 0.000 claims description 3
- USFZMSVCRYTOJT-UHFFFAOYSA-N Ammonium acetate Chemical compound N.CC(O)=O USFZMSVCRYTOJT-UHFFFAOYSA-N 0.000 claims description 2
- 239000005695 Ammonium acetate Substances 0.000 claims description 2
- ABLZXFCXXLZCGV-UHFFFAOYSA-N Phosphorous acid Chemical class OP(O)=O ABLZXFCXXLZCGV-UHFFFAOYSA-N 0.000 claims description 2
- 239000004280 Sodium formate Substances 0.000 claims description 2
- 235000019257 ammonium acetate Nutrition 0.000 claims description 2
- 229940043376 ammonium acetate Drugs 0.000 claims description 2
- VZTDIZULWFCMLS-UHFFFAOYSA-N ammonium formate Chemical compound [NH4+].[O-]C=O VZTDIZULWFCMLS-UHFFFAOYSA-N 0.000 claims description 2
- 239000004927 clay Substances 0.000 claims description 2
- 239000002270 dispersing agent Substances 0.000 claims description 2
- 125000002467 phosphate group Chemical class [H]OP(=O)(O[H])O[*] 0.000 claims description 2
- 235000011056 potassium acetate Nutrition 0.000 claims description 2
- 239000001508 potassium citrate Substances 0.000 claims description 2
- 229960002635 potassium citrate Drugs 0.000 claims description 2
- QEEAPRPFLLJWCF-UHFFFAOYSA-K potassium citrate (anhydrous) Chemical compound [K+].[K+].[K+].[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O QEEAPRPFLLJWCF-UHFFFAOYSA-K 0.000 claims description 2
- 235000011082 potassium citrates Nutrition 0.000 claims description 2
- WFIZEGIEIOHZCP-UHFFFAOYSA-M potassium formate Chemical compound [K+].[O-]C=O WFIZEGIEIOHZCP-UHFFFAOYSA-M 0.000 claims description 2
- 239000001509 sodium citrate Substances 0.000 claims description 2
- NLJMYIDDQXHKNR-UHFFFAOYSA-K sodium citrate Chemical group O.O.[Na+].[Na+].[Na+].[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O NLJMYIDDQXHKNR-UHFFFAOYSA-K 0.000 claims description 2
- HLBBKKJFGFRGMU-UHFFFAOYSA-M sodium formate Chemical group [Na+].[O-]C=O HLBBKKJFGFRGMU-UHFFFAOYSA-M 0.000 claims description 2
- 235000019254 sodium formate Nutrition 0.000 claims description 2
- YWYZEGXAUVWDED-UHFFFAOYSA-N triammonium citrate Chemical compound [NH4+].[NH4+].[NH4+].[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O YWYZEGXAUVWDED-UHFFFAOYSA-N 0.000 claims description 2
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 abstract description 46
- 229920000642 polymer Polymers 0.000 abstract description 24
- 229910000019 calcium carbonate Inorganic materials 0.000 abstract description 23
- -1 organic acid salt Chemical class 0.000 abstract description 4
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 64
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 54
- 238000012360 testing method Methods 0.000 description 35
- 238000000034 method Methods 0.000 description 34
- 108090000790 Enzymes Proteins 0.000 description 33
- 102000004190 Enzymes Human genes 0.000 description 33
- 229940088598 enzyme Drugs 0.000 description 33
- 239000012530 fluid Substances 0.000 description 33
- 239000001103 potassium chloride Substances 0.000 description 32
- 235000011164 potassium chloride Nutrition 0.000 description 32
- 229920002472 Starch Polymers 0.000 description 29
- 235000019698 starch Nutrition 0.000 description 29
- 239000008107 starch Substances 0.000 description 28
- 229910052757 nitrogen Inorganic materials 0.000 description 27
- 239000002253 acid Substances 0.000 description 21
- 239000012065 filter cake Substances 0.000 description 20
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 19
- 238000006243 chemical reaction Methods 0.000 description 19
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 15
- 230000035699 permeability Effects 0.000 description 15
- 239000012267 brine Substances 0.000 description 13
- 230000006378 damage Effects 0.000 description 13
- 239000004576 sand Substances 0.000 description 13
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 13
- 208000005156 Dehydration Diseases 0.000 description 12
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 description 12
- 239000000243 solution Substances 0.000 description 12
- 239000007787 solid Substances 0.000 description 10
- VYZAMTAEIAYCRO-UHFFFAOYSA-N Chromium Chemical compound [Cr] VYZAMTAEIAYCRO-UHFFFAOYSA-N 0.000 description 9
- PNEYBMLMFCGWSK-UHFFFAOYSA-N Alumina Chemical compound [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 8
- 229920001285 xanthan gum Polymers 0.000 description 8
- ZCYVEMRRCGMTRW-UHFFFAOYSA-N 7553-56-2 Chemical compound [I] ZCYVEMRRCGMTRW-UHFFFAOYSA-N 0.000 description 7
- 238000009472 formulation Methods 0.000 description 7
- 239000011630 iodine Substances 0.000 description 7
- 229910052740 iodine Inorganic materials 0.000 description 7
- KKADPXVIOXHVKN-UHFFFAOYSA-N 4-hydroxyphenylpyruvic acid Chemical compound OC(=O)C(=O)CC1=CC=C(O)C=C1 KKADPXVIOXHVKN-UHFFFAOYSA-N 0.000 description 6
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical class [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 6
- 238000005553 drilling Methods 0.000 description 6
- 238000011156 evaluation Methods 0.000 description 6
- 238000005086 pumping Methods 0.000 description 6
- 150000003839 salts Chemical class 0.000 description 6
- GJCOSYZMQJWQCA-UHFFFAOYSA-N 9H-xanthene Chemical compound C1=CC=C2CC3=CC=CC=C3OC2=C1 GJCOSYZMQJWQCA-UHFFFAOYSA-N 0.000 description 5
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 4
- 230000015572 biosynthetic process Effects 0.000 description 4
- 229920002678 cellulose Polymers 0.000 description 4
- 235000010980 cellulose Nutrition 0.000 description 4
- 239000013505 freshwater Substances 0.000 description 4
- LNOPIUAQISRISI-UHFFFAOYSA-N n'-hydroxy-2-propan-2-ylsulfonylethanimidamide Chemical compound CC(C)S(=O)(=O)CC(N)=NO LNOPIUAQISRISI-UHFFFAOYSA-N 0.000 description 4
- 239000003921 oil Substances 0.000 description 4
- 235000011118 potassium hydroxide Nutrition 0.000 description 4
- SUKJFIGYRHOWBL-UHFFFAOYSA-N sodium hypochlorite Chemical compound [Na+].Cl[O-] SUKJFIGYRHOWBL-UHFFFAOYSA-N 0.000 description 4
- 230000004580 weight loss Effects 0.000 description 4
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 3
- 150000007513 acids Chemical class 0.000 description 3
- 239000007853 buffer solution Substances 0.000 description 3
- 239000001913 cellulose Substances 0.000 description 3
- FYGDTMLNYKFZSV-MRCIVHHJSA-N dextrin Chemical compound O[C@@H]1[C@@H](O)[C@H](O)[C@@H](CO)OC1O[C@@H]1[C@@H](CO)OC(O[C@@H]2[C@H](O[C@H](O)[C@H](O)[C@H]2O)CO)[C@H](O)[C@H]1O FYGDTMLNYKFZSV-MRCIVHHJSA-N 0.000 description 3
- 239000007789 gas Substances 0.000 description 3
- 229940059442 hemicellulase Drugs 0.000 description 3
- 108010002430 hemicellulase Proteins 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 229920002401 polyacrylamide Polymers 0.000 description 3
- 238000010998 test method Methods 0.000 description 3
- QTBSBXVTEAMEQO-UHFFFAOYSA-M Acetate Chemical compound CC([O-])=O QTBSBXVTEAMEQO-UHFFFAOYSA-M 0.000 description 2
- 108010065511 Amylases Proteins 0.000 description 2
- 102000013142 Amylases Human genes 0.000 description 2
- FERIUCNNQQJTOY-UHFFFAOYSA-N Butyric acid Chemical compound CCCC(O)=O FERIUCNNQQJTOY-UHFFFAOYSA-N 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- VZCYOOQTPOCHFL-OWOJBTEDSA-N Fumaric acid Chemical compound OC(=O)\C=C\C(O)=O VZCYOOQTPOCHFL-OWOJBTEDSA-N 0.000 description 2
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- 229910019093 NaOCl Inorganic materials 0.000 description 2
- 239000005708 Sodium hypochlorite Substances 0.000 description 2
- 239000000654 additive Substances 0.000 description 2
- 238000004458 analytical method Methods 0.000 description 2
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 2
- 239000010428 baryte Substances 0.000 description 2
- 229910052601 baryte Inorganic materials 0.000 description 2
- 229920001222 biopolymer Polymers 0.000 description 2
- 239000002738 chelating agent Substances 0.000 description 2
- 239000000470 constituent Substances 0.000 description 2
- 230000001186 cumulative effect Effects 0.000 description 2
- 238000000354 decomposition reaction Methods 0.000 description 2
- 230000007423 decrease Effects 0.000 description 2
- 238000006911 enzymatic reaction Methods 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- WQYVRQLZKVEZGA-UHFFFAOYSA-N hypochlorite Chemical class Cl[O-] WQYVRQLZKVEZGA-UHFFFAOYSA-N 0.000 description 2
- 229910052500 inorganic mineral Inorganic materials 0.000 description 2
- 239000007788 liquid Substances 0.000 description 2
- 239000004579 marble Substances 0.000 description 2
- 238000005259 measurement Methods 0.000 description 2
- 229910052751 metal Inorganic materials 0.000 description 2
- 239000002184 metal Substances 0.000 description 2
- 235000010755 mineral Nutrition 0.000 description 2
- 239000011707 mineral Substances 0.000 description 2
- 150000007524 organic acids Chemical class 0.000 description 2
- 239000007800 oxidant agent Substances 0.000 description 2
- 239000000843 powder Substances 0.000 description 2
- 239000000047 product Substances 0.000 description 2
- 230000037380 skin damage Effects 0.000 description 2
- 235000017550 sodium carbonate Nutrition 0.000 description 2
- 229910000029 sodium carbonate Inorganic materials 0.000 description 2
- 229960001922 sodium perborate Drugs 0.000 description 2
- YKLJGMBLPUQQOI-UHFFFAOYSA-M sodium;oxidooxy(oxo)borane Chemical compound [Na+].[O-]OB=O YKLJGMBLPUQQOI-UHFFFAOYSA-M 0.000 description 2
- 239000000230 xanthan gum Substances 0.000 description 2
- 235000010493 xanthan gum Nutrition 0.000 description 2
- 229940082509 xanthan gum Drugs 0.000 description 2
- LJGHYPLBDBRCRZ-UHFFFAOYSA-N 3-(3-aminophenyl)sulfonylaniline Chemical compound NC1=CC=CC(S(=O)(=O)C=2C=C(N)C=CC=2)=C1 LJGHYPLBDBRCRZ-UHFFFAOYSA-N 0.000 description 1
- 239000004160 Ammonium persulphate Substances 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- 102000016938 Catalase Human genes 0.000 description 1
- 108010053835 Catalase Proteins 0.000 description 1
- 108010059892 Cellulase Proteins 0.000 description 1
- KZBUYRJDOAKODT-UHFFFAOYSA-N Chlorine Chemical compound ClCl KZBUYRJDOAKODT-UHFFFAOYSA-N 0.000 description 1
- RYGMFSIKBFXOCR-UHFFFAOYSA-N Copper Chemical compound [Cu] RYGMFSIKBFXOCR-UHFFFAOYSA-N 0.000 description 1
- 244000303965 Cyamopsis psoralioides Species 0.000 description 1
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 description 1
- 241001673102 Jaya Species 0.000 description 1
- 241000928591 Ochanostachys amentacea Species 0.000 description 1
- 108700020962 Peroxidase Proteins 0.000 description 1
- 244000166071 Shorea robusta Species 0.000 description 1
- 235000015076 Shorea robusta Nutrition 0.000 description 1
- UIIMBOGNXHQVGW-DEQYMQKBSA-M Sodium bicarbonate-14C Chemical compound [Na+].O[14C]([O-])=O UIIMBOGNXHQVGW-DEQYMQKBSA-M 0.000 description 1
- 244000061456 Solanum tuberosum Species 0.000 description 1
- 235000002595 Solanum tuberosum Nutrition 0.000 description 1
- 241000589634 Xanthomonas Species 0.000 description 1
- 240000008042 Zea mays Species 0.000 description 1
- 235000005824 Zea mays ssp. parviglumis Nutrition 0.000 description 1
- 235000002017 Zea mays subsp mays Nutrition 0.000 description 1
- 230000000996 additive effect Effects 0.000 description 1
- 239000000956 alloy Substances 0.000 description 1
- 229910045601 alloy Inorganic materials 0.000 description 1
- ROOXNKNUYICQNP-UHFFFAOYSA-N ammonium persulfate Chemical compound [NH4+].[NH4+].[O-]S(=O)(=O)OOS([O-])(=O)=O ROOXNKNUYICQNP-UHFFFAOYSA-N 0.000 description 1
- 235000019395 ammonium persulphate Nutrition 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 239000007900 aqueous suspension Substances 0.000 description 1
- 238000003556 assay Methods 0.000 description 1
- 239000000440 bentonite Substances 0.000 description 1
- 229910000278 bentonite Inorganic materials 0.000 description 1
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 description 1
- 229940106157 cellulase Drugs 0.000 description 1
- 239000000460 chlorine Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 230000001143 conditioned effect Effects 0.000 description 1
- 229910052802 copper Inorganic materials 0.000 description 1
- 239000010949 copper Substances 0.000 description 1
- 235000005822 corn Nutrition 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 239000013530 defoamer Substances 0.000 description 1
- XBDQKXXYIPTUBI-UHFFFAOYSA-N dimethylselenoniopropionate Natural products CCC(O)=O XBDQKXXYIPTUBI-UHFFFAOYSA-N 0.000 description 1
- 238000002845 discoloration Methods 0.000 description 1
- 238000005538 encapsulation Methods 0.000 description 1
- 230000007515 enzymatic degradation Effects 0.000 description 1
- 230000002349 favourable effect Effects 0.000 description 1
- 239000000706 filtrate Substances 0.000 description 1
- 239000001530 fumaric acid Substances 0.000 description 1
- 229910052739 hydrogen Inorganic materials 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 230000001771 impaired effect Effects 0.000 description 1
- 238000011534 incubation Methods 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- LWXVCCOAQYNXNX-UHFFFAOYSA-N lithium hypochlorite Chemical compound [Li+].Cl[O-] LWXVCCOAQYNXNX-UHFFFAOYSA-N 0.000 description 1
- 238000005461 lubrication Methods 0.000 description 1
- WPBNNNQJVZRUHP-UHFFFAOYSA-L manganese(2+);methyl n-[[2-(methoxycarbonylcarbamothioylamino)phenyl]carbamothioyl]carbamate;n-[2-(sulfidocarbothioylamino)ethyl]carbamodithioate Chemical compound [Mn+2].[S-]C(=S)NCCNC([S-])=S.COC(=O)NC(=S)NC1=CC=CC=C1NC(=S)NC(=O)OC WPBNNNQJVZRUHP-UHFFFAOYSA-L 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 150000002739 metals Chemical class 0.000 description 1
- 230000005012 migration Effects 0.000 description 1
- 238000013508 migration Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- DUWWHGPELOTTOE-UHFFFAOYSA-N n-(5-chloro-2,4-dimethoxyphenyl)-3-oxobutanamide Chemical compound COC1=CC(OC)=C(NC(=O)CC(C)=O)C=C1Cl DUWWHGPELOTTOE-UHFFFAOYSA-N 0.000 description 1
- 239000002736 nonionic surfactant Substances 0.000 description 1
- 235000005985 organic acids Nutrition 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- 239000006174 pH buffer Substances 0.000 description 1
- 239000011236 particulate material Substances 0.000 description 1
- 230000002688 persistence Effects 0.000 description 1
- 239000006187 pill Substances 0.000 description 1
- 229920000151 polyglycol Polymers 0.000 description 1
- 239000010695 polyglycol Substances 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- CZPZWMPYEINMCF-UHFFFAOYSA-N propaneperoxoic acid Chemical compound CCC(=O)OO CZPZWMPYEINMCF-UHFFFAOYSA-N 0.000 description 1
- 235000019260 propionic acid Nutrition 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 239000003352 sequestering agent Substances 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 238000002791 soaking Methods 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 229910052708 sodium Inorganic materials 0.000 description 1
- 235000011121 sodium hydroxide Nutrition 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- IIACRCGMVDHOTQ-UHFFFAOYSA-N sulfamic acid Chemical compound NS(O)(=O)=O IIACRCGMVDHOTQ-UHFFFAOYSA-N 0.000 description 1
- 239000011885 synergistic combination Substances 0.000 description 1
- VZCYOOQTPOCHFL-UHFFFAOYSA-N trans-butenedioic acid Natural products OC(=O)C=CC(O)=O VZCYOOQTPOCHFL-UHFFFAOYSA-N 0.000 description 1
- 150000003623 transition metal compounds 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
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B37/00—Methods or apparatus for cleaning boreholes or wells
- E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing, limiting or eliminating the deposition of paraffins or like substances
Definitions
- a family of mud removal systems for the simultaneous removal of all polymer-based drilling fluid damage is disclosed.
- the damage can include that caused by partially-hydrolyzed polyacrylamide (PHPA) polymer and particulates such as calcium carbonate.
- PHPA polyacrylamide
- the systems are based on the synergistic combination of organic salt buffers and either peroxides or per-acids.
- the systems can also include catalase enzymes.
- drilling muds drill-in fluids, kill fluids and kill-pills that contain, amongst other things, polymeric constituents.
- the latter may consist of a single polymer or may consist of mixtures of polymers in aqueous solution/suspension.
- These polymers may be added for the purposes of viscosification, leak-off control, lubrication, friction reduction and control of shales or other active clays.
- the polymers used for such purposes include xanthans (exo-polymers produced by Xanthomonas Camperstris and its relatives), starches (produced from corn, potato, etc), celluloses, guars, and derivatives of these main groups.
- Polyacrylamides may also be used, in particular so-called partially-hydrolyzed polyacrylamide (PHPA), which is used for shale encapsulation.
- PHPA partially-hydrolyzed polyacrylamide
- most of these fluids contain some form of particulate to impart density and to improve fluid-loss control.
- the most common of these particulates is calcium carbonate although, occasionally, salt or barite may be used.
- Acids can hydrolyze some polymers, and can dissolve calcium carbonate.
- calcium carbonate is often coated with polymer residue, and its removal has been shown to be non-uniform, possible due to wormholing of the acid through the cake. This results in non-optimal inflow performance, with higher drawdowns and, potentially, greater risk of early water breakthrough, fines migration, and formation failure.
- the acid is corrosive and inefficient, and large volumes must be used in extended reach wells.
- hypochlorites can destroy most polymers, they will not dissolve calcium carbonate and their high pH can cause problems if the formation contains any sensitive clays. Combining acids and hypochlorites generates chlorine gas, a potentially harmful material. Accordingly, prior treatments designed to target both polymers and calcium carbonate consisted of several steps. This complicates the operation, and causes additional expense due to the time involved.
- compositions comprising buffered hydrogen peroxide or per-acids are attractive for use in treating oil and/or gas wells that contain polymer deposits or calcium carbonate.
- An example per-acid is peroxyacetic acid.
- the compositions can further comprise enzymes such as peroxidases. Methods for treating wells can be performed as single step treatments.
- compositions and methods have been identified that are capable of removing all polymers encountered thus far while, simultaneously, dissolving calcium carbonate.
- the treatment methods include a single step treatment of a well, effective at reducing or eliminating the presence of polymer deposits and calcium carbonate.
- the methods improve the permeability of the well, preferably to at least the level observed prior to formation of polymer deposits.
- compositions can comprise, consist essentially of, or consist of water, a buffer, and hydrogen peroxide and/or a per-acid.
- the composition can further comprise iron-control agents, surface tension reducers, dispersants, corrosion inhibitors, clay stabilizers, and other components useful in treating wells.
- the water can generally be from any source.
- the water can be fresh water, brackish water, or salt water.
- the compositions can generally have any pH.
- the pH can be about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, or ranges between any two of these values. It is presently preferred that the pH be about 3.0 to about 5.0.
- the buffer can generally be any buffer system. Buffers commonly are a combination of an acid and its salt.
- a buffer can comprise acetic acid and an acetate salt (such as sodium acetate, potassium acetate, or ammonium acetate), formic acid and a formate salt (such as sodium formate, potassium formate, or ammonium formate), citric acid and a citrate salt (such as sodium citrate, potassium citrate, or ammonium citrate), and other acid / salt buffer combinations.
- the buffer system can generally be present at any concentration.
- the buffer system can be present at a concentration of about 1 weight percent to about 30 weight percent. Example concentrations include about 1 weight percent, about 5 weight percent, about 10 weight percent, about 15 weight percent, about 20 weight percent, about 25 weight percent, about 30 weight percent, and ranges between any two of these values.
- Hydrogen peroxide can generally be present in the composition at a concentration of about 1 weight percent to about 6 weight percent.
- Example concentrations include about 1 weight percent, about 2 weight percent, about 3 weight percent, about 4 weight percent, about 5 weight percent, about 6 weight percent, and ranges between any two of these values.
- a concentration of about 3 weight percent to about 5 weight percent is presently preferred.
- the per-acid can generally be any per-acid. Examples of per-acids include peracetic acid, performic acid, perpropanoic acid, and perbutanoic acid. It is presently preferred that the per-acid be peroxyacetic acid (ethaneperoxoic acid; peroxyacetic acid; CH 3 CO 3 H).
- the per-acid can generally be present in the composition at a concentration of about 1 weight percent to about 15 weight percent, with a concentration of about 3 weight percent to about 10 weight percent being presently preferred.
- concentrations include about 1 weight percent, about 2 weight percent, about 3 weight percent, about 4 weight percent, about 5 weight percent, about 6 weight percent, about 7 weight percent, about 8 weight percent, about 9 weight percent, about 10 weight percent, about 11 weight percent, about 12 weight percent, about 13 weight percent, about 14 weight percent, about 15 weight percent, and ranges between any two of these values.
- the compositions can comprise both hydrogen peroxide and a per-acid, or hydrogen peroxide and an organic acid (such as acetic acid, formic acid, propanoic acid, or butanoic acid).
- the composition can further comprise accelerants or inhibitors to modify the rate of reaction with polymer deposits or calcium carbonate.
- Accelerants increase the rate of decomposition of peroxides.
- accelerants include peroxidase enzymes, and transition metal compounds (e.g. compounds of manganese, iron, copper, etc.). Accelerants can generally be present in the composition at a concentration of about 1-2 ppm to about 1-2 weight percent.
- Inhibitors decrease the rate of decomposition of peroxides.
- inhibitors include phosphate salts and phosphonate salts. Inhibitors can generally be present in the composition at a concentration of about 1-2 ppm to about 5 weight percent.
- compositions are useful for treating oil and/or gas wells suspected of containing polymer deposits and/or calcium carbonate.
- Useful compositions include those comprising water, a buffer, and hydrogen peroxide and/or a per-acid.
- the methods can involve the use of a composition comprising water and hydrogen peroxide.
- the methods can comprise selecting an oil and/or gas well, and pumping one of the above described compositions into the well.
- the compositions are contacted with the well for a period of time sufficient to reduce or eliminate any polymer deposits and/or calcium carbonate.
- the methods can further comprise removing the compositions after the contacting period.
- the well is preferably treated with the compositions are in a single step.
- the pumping can be performed in a single pumping event, multiple pumping events, or as a continuous pumping process.
- the well can be “closed in”, allowing the compositions to contact the well for a period of time during which additional pumping or drilling is not performed.
- This analytic method was performed as follows. A magnetic funnel was mounted on an Erlenmeyer flask. A high permeability sand pack (k>10 D) was placed in the funnel and compacted. A brine solution was poured and the flow rate (by gravity) through the sand pack was measured. The mud was poured and vacuum was applied for 1 hour to form the mud cake. Any excess mud was removed. Brine was again poured to determine that no flow was achieved through the mud damaged sand pack by gravity and with vacuum applied. The permeability is essentially zeroed at this point. The treatment solution (warmed to 150 OF (66° C.) prior to use) was poured onto the sand pack.
- the treatment solution (warmed to 150 OF (66° C.) prior to use) was poured onto the sand pack.
- the vacuum was applied for about one minute to allow the treatment solution to absorb onto the cake.
- the sand pack was left to soak with the solution without vacuum and allowed to react with the mud cake for 1 hour. After the incubation period, the condition of the filter cake after the reaction was observed. Presence of any residual starch (for mud containing starch as viscosifying agent) in the sand pack was tested by the iodine spot test.
- the vacuum was applied to allow any remaining treatment solution to flow through the sand pack. A brine solution was again flowed (without vacuum) to determine the regain permeability.
- This analytic method was performed as follows. A fluid loss cell was fitted with an 80 US Mesh screen, and 100 g of 70-140 Mesh sand was placed on top of it. Water or brine solution (100 ml) was poured onto the sand and shut in to heat to 150° F. (66° C.) in about 20 minutes. Pressure was applied to the cell and the time to flow 100 ml of water/brine was noted. (In each case, the fluid passes straight through and could not be measured). The cell was drained leaving the sand saturated. The mud was conditioned to 150° F. (66° C.) in the atmospheric consistometer in 20 minutes before pouring into the pre-heated cell. Pressure was then applied to the cell. The bottom valve was opened and the fluid loss recorded.
- a formulation was prepared using the following components.
- Component Concentration Saturated NaCl brine 311.5 ml Thixsal-Plus viscosifier (TBC-Brinadd; Houston, TX) 4 g FL-7 Plus fluid loss control additive 3 g (TBC-Brinadd; Houston, TX) pH Buffer 3 g Watesal-A viscosifier (Kota Chemicals & 46 g Minerals; Petaling Jaya, Malaysia)
- Inhibisal polyglycol stabilizer 17.5 ml (TBC-Brinadd; Houston, TX) Defoam-2 defoamer (TBC-Brinadd; Houston, TX)
- TX Component Concentration Saturated NaCl brine 311.5 ml Thixsal-Plus viscosifier
- FL-7 Plus fluid loss control additive 3 g
- pH Buffer 3 g Watesal-A viscosifier Kelta Chemicals & 46 g Minerals; Petaling Jaya, Malaysia
- a formulation was prepared using the following components.
- a field sample of mud was obtained containing bentonite, barite, cypan, caustic potash, soda ash, starch, XCD xanthan polymer, PHPA, sodium bicarbonate, and potassium chloride.
- a mud sample was obtained containing PHPA, starch, xanthan, and sized calcium carbonate.
- test acid #4 peroxyacetic acid system containing 15% acetic acid and 1.5% hydrogen peroxide (buffered to pH 4)
- test acid #4 dissolved significantly more calcium carbonate than the other systems, including 15% acid alone (test acid #1).
- step 23 the presence of starch is indicated by the formation of a blue color being produced when one drop of dilute iodine solution is placed on the surface of a filter cake.
- the absence of a blue color indicates that all starch has been degraded.
- the iodine spot test can only be used to detect the presence of starch. If starch is not present in the fluid used to form the filter cake, this test will be valid.
- the following mud system was used: Component Concentration 2% KCl 7 ppb Caustic potash 0.25 ppb PAC-L/CMC low (Cellulose) 4-6 ppb PAC-R/CMC HV (Cellulose) 0.5-1 ppb XCD xanthan biopolymer 2-4 ppb CaCO 3 - fine 13 ppb CaCO 3 - coarse 7 ppb Dextrid (starch) 4-6 ppb
- hydrochloric acid The following 7.5% hydrochloric acid formulation was used.
- Component Concentration Fresh water 722 gpt CI-25 6 gpt NE-18 5 gpt Claytrol (Baker Hughes; Houston, TX) 3 gpt Fe-210 30 ppt Inflo-40 50 gpt Inflo-100 5 gpt 32% hydrochloric acid 209 gpt
- the Aloxite or berea disc was loaded into the cell.
- the cell was filled with filtered brine, 2% KCl.
- the cell was filled with the mud fluid.
- the disc was removed and examined for the presence of filter-cake. Iodine spot test was carried out for the presence of starch (presence of starch is indicated by a dark blue discoloration of the iodine). A few drops of HCl were placed onto the disc to determine the presence or absence of undissolved carbonate.
- the disc was flipped and placed in the cell in the opposite orientation.
- the cell was filled with filtered brine, and the time taken to flow 200 ml at 100 psi (689 KPa) was recorded.
- breaker fluids Six different breaker fluids were prepared or obtained for evaluation. They were a) buffered peroxyacetic acid; b) buffered mudzyme CS (a mixture of cellulase and amylase enzymes buffered with acetic acid and sodium acetate); c) Oxiclean (a mixture of oxidizing agents; generally ammonium persulphate, sodium perborate and fumaric acid); d) 1.2% sodium hypochlorite; e) 7.5% hydrochloric acid; and f) 7.5% hydrochloric acid with added sodium perborate.
- buffered peroxyacetic acid a mixture of cellulase and amylase enzymes buffered with acetic acid and sodium acetate
- Oxiclean a mixture of oxidizing agents; generally ammonium persulphate, sodium perborate and fumaric acid
- d) 1.2% sodium hypochlorite e
- e) 7.5% hydrochloric acid 7.5% hydrochloric acid with added sodium
- Muds A-D were assayed for their cumulative fluid loss volume over time. Cumulative volume, ml Test # Mud 1′ 4′ 9′ 16′ 25′ 30′ 1 A 6 7 8 9 9.5 10 2 A 6 6.5 7.5 8.5 9.5 10 3 A 5 6 7 8 9 9.5 4 A 5 6.5 7.5 8.5 10 10.5 5 A 3 4 5 6 7 7 6 A 3.5 4.5 5.5 6.5 7 7.5 7 B 9.5 10.5 12 13.5 15 15.5 8 C 2.5 3 3.5 4.5 5.5 6 9 D 8.5 10 11.5 13 14.5 15
- the breaker fluids were assayed for their ability to dissolve filter cakes.
- 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/or and in the steps or in the sequence of steps of the methods described herein without departing from the concept 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 scope and concept of the invention.
Abstract
Compositions containing a peroxide or peracid and an organic acid salt buffer are disclosed. The compositions are useful for removing polymers from oil and gas wells, while simultaneously dissolving encountered calcium carbonate deposits.
Description
- The present application claims priority to U.S. Provisional Patent Application Ser. No. 60/413,181 filed Sep. 24, 2002, the contents of which are incorporated herein by reference.
- 1. Field of the Invention
- A family of mud removal systems for the simultaneous removal of all polymer-based drilling fluid damage is disclosed. The damage can include that caused by partially-hydrolyzed polyacrylamide (PHPA) polymer and particulates such as calcium carbonate. The systems are based on the synergistic combination of organic salt buffers and either peroxides or per-acids. The systems can also include catalase enzymes.
- 2. Description of Related Art
- Many wells are damaged in the course of drilling and workover by the use of drilling muds, drill-in fluids, kill fluids and kill-pills that contain, amongst other things, polymeric constituents. The latter may consist of a single polymer or may consist of mixtures of polymers in aqueous solution/suspension. These polymers may be added for the purposes of viscosification, leak-off control, lubrication, friction reduction and control of shales or other active clays. Typically, the polymers used for such purposes include xanthans (exo-polymers produced by Xanthomonas Camperstris and its relatives), starches (produced from corn, potato, etc), celluloses, guars, and derivatives of these main groups. Polyacrylamides may also be used, in particular so-called partially-hydrolyzed polyacrylamide (PHPA), which is used for shale encapsulation. In addition, most of these fluids contain some form of particulate to impart density and to improve fluid-loss control. The most common of these particulates is calcium carbonate although, occasionally, salt or barite may be used.
- Subsequent well productivity can be significantly impaired by the use of these mixtures of polymers and particulate materials, due to the persistence of residues in the well. Their removal can result in substantial improvements in production. Historically, removal of these materials has involved the use of soaking with strong mineral acids (e.g. hydrochloric acid), strong organic acids (e.g. sulphamic acid), or oxidizing agents (e.g. sodium hypochlorite or lithium hypochlorite). More recently, enzymes have been used to remove the polymeric constituents. Some polymers, however, are largely immune to enzymatic degradation (e.g. PHPA).
- Acids can hydrolyze some polymers, and can dissolve calcium carbonate. However, in practice, calcium carbonate is often coated with polymer residue, and its removal has been shown to be non-uniform, possible due to wormholing of the acid through the cake. This results in non-optimal inflow performance, with higher drawdowns and, potentially, greater risk of early water breakthrough, fines migration, and formation failure. Additionally, the acid is corrosive and inefficient, and large volumes must be used in extended reach wells. While hypochlorites can destroy most polymers, they will not dissolve calcium carbonate and their high pH can cause problems if the formation contains any sensitive clays. Combining acids and hypochlorites generates chlorine gas, a potentially harmful material. Accordingly, prior treatments designed to target both polymers and calcium carbonate consisted of several steps. This complicates the operation, and causes additional expense due to the time involved.
- Thus, there exists a need for clean-up compositions and methods that are effective at removing both polymer deposits and calcium carbonate. The methods preferably accomplish the removal of both materials in a single step.
- Compositions comprising buffered hydrogen peroxide or per-acids are attractive for use in treating oil and/or gas wells that contain polymer deposits or calcium carbonate. An example per-acid is peroxyacetic acid. The compositions can further comprise enzymes such as peroxidases. Methods for treating wells can be performed as single step treatments.
- Compositions and methods have been identified that are capable of removing all polymers encountered thus far while, simultaneously, dissolving calcium carbonate. The treatment methods include a single step treatment of a well, effective at reducing or eliminating the presence of polymer deposits and calcium carbonate. The methods improve the permeability of the well, preferably to at least the level observed prior to formation of polymer deposits.
- One embodiment of the invention relates to well treatment compositions. The compositions can comprise, consist essentially of, or consist of water, a buffer, and hydrogen peroxide and/or a per-acid. The composition can further comprise iron-control agents, surface tension reducers, dispersants, corrosion inhibitors, clay stabilizers, and other components useful in treating wells.
- The water can generally be from any source. The water can be fresh water, brackish water, or salt water. The compositions can generally have any pH. For example, the pH can be about 1, about 2, about 3, about 4, about 5, about 6, about 7, about 8, or ranges between any two of these values. It is presently preferred that the pH be about 3.0 to about 5.0.
- The buffer can generally be any buffer system. Buffers commonly are a combination of an acid and its salt. For example, a buffer can comprise acetic acid and an acetate salt (such as sodium acetate, potassium acetate, or ammonium acetate), formic acid and a formate salt (such as sodium formate, potassium formate, or ammonium formate), citric acid and a citrate salt (such as sodium citrate, potassium citrate, or ammonium citrate), and other acid / salt buffer combinations. The buffer system can generally be present at any concentration. The buffer system can be present at a concentration of about 1 weight percent to about 30 weight percent. Example concentrations include about 1 weight percent, about 5 weight percent, about 10 weight percent, about 15 weight percent, about 20 weight percent, about 25 weight percent, about 30 weight percent, and ranges between any two of these values.
- Hydrogen peroxide can generally be present in the composition at a concentration of about 1 weight percent to about 6 weight percent. Example concentrations include about 1 weight percent, about 2 weight percent, about 3 weight percent, about 4 weight percent, about 5 weight percent, about 6 weight percent, and ranges between any two of these values. A concentration of about 3 weight percent to about 5 weight percent is presently preferred. The per-acid can generally be any per-acid. Examples of per-acids include peracetic acid, performic acid, perpropanoic acid, and perbutanoic acid. It is presently preferred that the per-acid be peroxyacetic acid (ethaneperoxoic acid; peroxyacetic acid; CH3CO3H). The per-acid can generally be present in the composition at a concentration of about 1 weight percent to about 15 weight percent, with a concentration of about 3 weight percent to about 10 weight percent being presently preferred. Examples of concentrations include about 1 weight percent, about 2 weight percent, about 3 weight percent, about 4 weight percent, about 5 weight percent, about 6 weight percent, about 7 weight percent, about 8 weight percent, about 9 weight percent, about 10 weight percent, about 11 weight percent, about 12 weight percent, about 13 weight percent, about 14 weight percent, about 15 weight percent, and ranges between any two of these values. The compositions can comprise both hydrogen peroxide and a per-acid, or hydrogen peroxide and an organic acid (such as acetic acid, formic acid, propanoic acid, or butanoic acid).
- The composition can further comprise accelerants or inhibitors to modify the rate of reaction with polymer deposits or calcium carbonate. Accelerants increase the rate of decomposition of peroxides. Examples of accelerants include peroxidase enzymes, and transition metal compounds (e.g. compounds of manganese, iron, copper, etc.). Accelerants can generally be present in the composition at a concentration of about 1-2 ppm to about 1-2 weight percent. Inhibitors decrease the rate of decomposition of peroxides. Examples of inhibitors include phosphate salts and phosphonate salts. Inhibitors can generally be present in the composition at a concentration of about 1-2 ppm to about 5 weight percent.
- The above described compositions are useful for treating oil and/or gas wells suspected of containing polymer deposits and/or calcium carbonate. Useful compositions include those comprising water, a buffer, and hydrogen peroxide and/or a per-acid. Alternatively, the methods can involve the use of a composition comprising water and hydrogen peroxide.
- The methods can comprise selecting an oil and/or gas well, and pumping one of the above described compositions into the well. The compositions are contacted with the well for a period of time sufficient to reduce or eliminate any polymer deposits and/or calcium carbonate. The methods can further comprise removing the compositions after the contacting period. The well is preferably treated with the compositions are in a single step.
- The pumping can be performed in a single pumping event, multiple pumping events, or as a continuous pumping process. The well can be “closed in”, allowing the compositions to contact the well for a period of time during which additional pumping or drilling is not performed.
- The following examples are included to demonstrate preferred embodiments of the invention. If not otherwise indicated, percentages are weight percentages. It should be appreciated by those of skill in the art that the techniques disclosed in the examples which follow represent techniques discovered by the inventors to function well in the practice of the invention, and thus can be considered to constitute preferred modes for its practice. However, those of skill in the art should, in light of the present disclosure, appreciate that many changes can be made in the specific embodiments which are disclosed and still obtain a like or similar result without departing from the scope of the invention.
- This analytic method was performed as follows. A magnetic funnel was mounted on an Erlenmeyer flask. A high permeability sand pack (k>10 D) was placed in the funnel and compacted. A brine solution was poured and the flow rate (by gravity) through the sand pack was measured. The mud was poured and vacuum was applied for 1 hour to form the mud cake. Any excess mud was removed. Brine was again poured to determine that no flow was achieved through the mud damaged sand pack by gravity and with vacuum applied. The permeability is essentially zeroed at this point. The treatment solution (warmed to 150 OF (66° C.) prior to use) was poured onto the sand pack. The vacuum was applied for about one minute to allow the treatment solution to absorb onto the cake. The sand pack was left to soak with the solution without vacuum and allowed to react with the mud cake for 1 hour. After the incubation period, the condition of the filter cake after the reaction was observed. Presence of any residual starch (for mud containing starch as viscosifying agent) in the sand pack was tested by the iodine spot test. The vacuum was applied to allow any remaining treatment solution to flow through the sand pack. A brine solution was again flowed (without vacuum) to determine the regain permeability.
- This analytic method was performed as follows. A fluid loss cell was fitted with an 80 US Mesh screen, and 100 g of 70-140 Mesh sand was placed on top of it. Water or brine solution (100 ml) was poured onto the sand and shut in to heat to 150° F. (66° C.) in about 20 minutes. Pressure was applied to the cell and the time to flow 100 ml of water/brine was noted. (In each case, the fluid passes straight through and could not be measured). The cell was drained leaving the sand saturated. The mud was conditioned to 150° F. (66° C.) in the atmospheric consistometer in 20 minutes before pouring into the pre-heated cell. Pressure was then applied to the cell. The bottom valve was opened and the fluid loss recorded. Excess mud was removed while taking care not to disturb the filter cake and sand pack. The treatment was poured in and shut in for test period. After the shut in period, the bottom valve was opened and the flow measured. An iodine spot test was carried out on mud containing starch. The treatment solution was poured off and the flow measured.
- A formulation was prepared using the following components.
Component Concentration Saturated NaCl brine 311.5 ml Thixsal-Plus viscosifier (TBC-Brinadd; Houston, TX) 4 g FL-7 Plus fluid loss control additive 3 g (TBC-Brinadd; Houston, TX) pH Buffer 3 g Watesal-A viscosifier (Kota Chemicals & 46 g Minerals; Petaling Jaya, Malaysia) Inhibisal polyglycol stabilizer 17.5 ml (TBC-Brinadd; Houston, TX) Defoam-2 defoamer (TBC-Brinadd; Houston, TX) As required - A variety of mud removal systems were assayed with Method A (Example 1) and/or Method B (Example 2). The percent regained permeability is shown in the following table (ND=not determined), along with relevant comments. Enzyme S is an amylase enzyme commercially available from BJ Services Company (Houston, Tex.).
% regained permea- Mud removal system Method bility Comments 2% KCl A 29 Positive starch test. 1% Enzyme S 280L 2% KCl A 88 SKIN DAMAGE. The 1% Enzyme S 280L permeability decreases 0.5% Acetic acid with time. Eight hours 0.5% Sodium acetate after the enzyme reaction, the regain is zero. 2% KCl B ND Cake still present. Starch 1% Enzyme S 280L test positive. Fluid 0.5% Acetic acid passes straight through 0.5% Sodium acetate before damage and after treatment 2% KCl A 90 Some residual cake 1% Enzyme S 120L remained. Starch test 0.5% Acetic acid positive. 0.5% Sodium acetate 1% Enzyme S 120L B ND No cake left after 1% H2O2 treatment. Fluid passes 0.5% Acetic acid straight through before 0.5% Sodium acetate damage and after treatment. 2% KCl A 100 All cake removed. Starch 1% enzyme S 120L test negative. 0.5% Acetic acid 0.5% Sodium acetate 1% H2O2 2% KCl B ND A thin skin of mud left. 2.3% Enzyme S 120L Starch test positive. 0.5% Acetic acid Fluid passes straight 0.5% Sodium acetate through before damage and after treatment 2% KCl A 93 SKIN DAMAGE. The 0.3% Enzyme S 280L permeability decreased 0.5% Acetic acid with time. Eight hours 0.5% Sodium acetate after the enzyme reaction, the regain is zero. 3% H2O2 A 100 Very fast reaction. Within 45 minutes, no cake was observed. 3% H2O2 B ND All cake was removed. Negative starch test. Fluid passes straight through before damage and after treatment. 5% HCl A 12.5 Most of the cake still remained unreacted. Oxiclean oxidizing and A 100 After 2 hours of contact sequestering agents between mud and (BJ Services Oxiclean system, no Company; Houston, reaction was observed. TX) After leaving to react overnight, the mud cake was completely dissolved. Saturated NaCl A 0 Cake remained intact 4.5% Sulfamic acid after reaction. 1.5% Citric acid Saturated NaCl B ND Major portion of filter 4.5% Sulfamic acid cake remained after 1.5% Citric acid reaction. Large worm hole in the middle of the cake. Starch test positive. - A formulation was prepared using the following components.
Component Concentration Potassium chloride 7-8% Soda ash 0.5 ppb Caustic soda 1.0 ppb PAC-R fluid loss agent (SA Mud Services 1.0 ppb Pty; Johannesburg, South Africa) XCD xanthan biopolymer (Kelco Oil Field 0.5 ppb Group; Houston, TX) Starch 2.0 ppb PAC-UL fluid loss agent (SA Mud 1.5 ppb Services Pty; Johannesburg, South Africa) PHPA (Excess) 1.5 ppb Glycol 3-5% Calcium carbonate As required for density - A variety of mud removal systems were assayed with Method A (Example 1) and/or Method B (Example 2). The percent regained permeability is shown in the following table, along with relevant comments. Enzyme C is a cellulose-specific enzyme breaker commercially available from BJ Services Company (Houston, Tex.).
Mud removal % regained system Method permeability Comments 1% Sodium acetate A 0 Cake remained intact 1% Enzyme S 280L after reaction. 1% Sodium acetate A 0 Cake remained intact 1.5% Acetate acid after reaction. 1% Enzyme S 280L 1% Sodium acetate A 0 Cake remained intact 1% Enzyme S 280L after reaction. 1% Enzyme C 1% Enzyme S 280L A 0 Cake remained intact 1% Enzyme C after reaction. 1% Enzyme S 280L A 0 Cake remained intact 1% Enzyme C after reaction. 0.1% NaOCl 12% 1% Enzyme S 280L A 0 Cake remained intact 1% Enzyme C after reaction. 1% Enzyme GBW- 12 1% Hemicellulase 1 A 0 Cake remained intact 2% KCl after reaction. Hemicellulase A 30 The enzyme was laid on powder the cake for 1 hour, then 2% KCl at 150° F. (66° C.) was added and left to react for 2.5 hours. 3% H2O2 A 86 The cake was disintegrated. Oxiclean A 89 Large holes breaking through the cake could be observed. - A field sample of mud was obtained containing bentonite, barite, cypan, caustic potash, soda ash, starch, XCD xanthan polymer, PHPA, sodium bicarbonate, and potassium chloride.
- A variety of mud removal systems were assayed with Method A (Example 1) and/or Method B (Example 2). The percent regained permeability is shown in the following table (ND=not determined), along with relevant comments.
% regained Mud removal system Method permeability Comments 2% KCl A 0 Cake remained intac 1% Enzyme S 280L after reaction. Hemicellulase powder A 0 The enzyme was lai on the cake for 1 hour then 2% KCl at 150° (66° C.) was added an left reacting for 2. hours. No flow wa achieved. 2% KCl A 0 Cake remained intac 0.5% Sodium acetate after reaction. 0.5% Acetic acid 1% Enzyme S 280L 2% KCl B ND Cake remained intac 0.5% Sodium acetate after reaction. Flui 0.5% Acetic acid passes straight throug 1% Enzyme S 280L before damage. Afte treatment, sand pacl was severely damage with only 2 ml passin through within 3 minutes. 3% H2O2 A 100 Complete removal o filter cake. 3% H2O2 B ND Complete removal o filter cake. Flui passes straight throug before damage an after treatment. Hyderase 15 A 100% Complete removal o 3% H2O2 mud cake. Oxiclean B ND All cake was removed Fluid passes straigh through before damag and after treatment. Saturated NaCl B ND Major portion of filter 4.5% Sulfamic acid cake remained after 1.5% Citric acid reaction. Fluid passes straight through before damage and took 9 minutes to flow through after treatment. 10% Ethaneperoxoic A 0 Cake remained intact acid after reaction. 10% Ethaneperoxoic A 100 Complete removal of acid filter cake. 1% Sodium acetate - A mud sample was obtained containing PHPA, starch, xanthan, and sized calcium carbonate. A variety of mud removal systems were assayed using Method A (Example 1) and/or Method B (Example 2). The percent regained permeability is shown in the following table (ND=not determined), along with relevant comments.
% regained Mud removal system Method permeability Comments 2% KCl B ND Fluid passes straight 0.5% Sodium acetate through before damage 0.5% Acetate acid and after treatment. 1% Enzyme S 280L Some residual cake remained but starch test is negative. 1% Sodium acetate A 100 Complete removal of 1.5% Acetic acid filter cake. 1% Enzyme S 280L 3% H2O2 B ND Complete removal of filter cake. Fluid passes straight through before damage and after treatment. Saturated NaCl B ND Major portion of filter 4.5% Sulfamic acid cake remained after 1.5% Citric acid reaction. Positive starch test. Fluid passes straight through before damage and after treatment. - Chrome 13 and Super Chrome 13 metals can be obtained from Savik Super-Chrome Inc. (Three Rivers, West Quebec, Canada). Metal corrosion tests were performed at 4000 psi (281 kg/cm2), with a contact time of 8 hours at room temperature. Test results were determined at 130° C., 150° C., and 170° C. as follows. Three acid systems were used, where LPCM =liters per cubic meter, and KPCM=kilograms per cubic meter. Ferrotrol chelating/reducing agent, D4GB, CI-27 acid inhibitor, and HY-Temp corrosion inhibitor products are commercially available from BJ Services Company (Houston, Tex.).
- (1) 15% Acetic acid+2 LPCM D4GB+6 KPCM Ferrotrol 300+3 KPCM Ferrotrol 210.
- (2)Peroxyacetic system 2 (1.5% H2O2 with 10% acetic acid buffered to pH 4)+6 KPCM of Ferrotrol 300+3 KPCM of Ferrotrol 1000.
- (3)Peroxyacetic system 3 (1.5% H2O2 with 15% acetic acid buffered to pH 4)+6 KPCM of Ferrotrol 300+KPCM of Ferrotrol 100.
Test results at 130° C. with Chrome 13 Inhibitor at Intensifier at Weight loss Test Acid LPCM KPCM lb/ft2 Pitting 1 1 CI-27 @ 10 NONE 0.0175 0 2 1 CI-27 @ 5 HY-Temp I 0.0098 0 @ 1.2 3 1 CI-27 @ 10 HY-Temp I 0.0055 0 @ 1.2 4 1 CI-27 @ 5 HY-Temp I 0.0069 0 @ 2.4 5 1 CI-27 @ 10 HY-Temp I 0.0064 0 @ 2.4 6 2 CI-27 @ 5 NONE 0.0048 0 7 2 CI-27 @ 7 NONE 0.0059 0 8 2 CI-27 @ 10 NONE 0.0081 0 9 2 CI-27 @ 5 HY-Temp I 0.0058 0 @ 1.2 10 2 CI-27 @ 7 HY-Temp I 0.0037 0 @ 1.2 11 3 CI-27 @ 5 NONE 0.0129 0 12 3 CI-27 @ 7 NONE 0.0143 0 13 3 CI-27 @ 10 NONE 0.0189 0 14 3 CI-27 @ 5 HY-Temp I 0.0283 0 @ 1.2 15 3 CI-27 @ 7 HY-Temp I 0.0097 0 @ 1.2 -
Test results at 150° C. with Super Chrome 13 Inhibitor at Intensifier at Weight loss Test Acid LPCM KPCM (lb/ft2) Pitting 16 1 CI-27 @ 8 NONE 0.0233 0 17 1 CI-27 @ 10 NONE 0.0228 0 18 1 CI-27 @ 5 HY-Temp I 0.0105 0 @ 1.2 19 1 CI-27 @ 10 HY-Temp 0.0072 0 @ 1.2 20 2 CI-27 @ 8 NONE 0.0053 0 21 2 CI-27 @ 10 NONE 0.0058 0 22 2 CI-27 @ 5 HY-Temp I 0.0036 0 @ 1.2 23 2 CI-27 @ 10 HY-Temp I 0.0037 0 @ 1.2 24 3 CI-27 @ 8 NONE 0.0183 0 25 3 CI-27 @ 10 NONE 0.0062 0 26 3 CI-27 @ 5 HY-Temp I 0.0034 0 @ 1.2 27 3 CI-27 @ 10 HY-Temp I 0.0036 0 @ 1.2 -
Test results at 170° C. with Super Chrome 13 Inhibitor at Intensifier at Weight loss Test Acid LPCM KPCM (lb/ft2) Pitting 28 1 CI-27 @ 8 NONE 0.0299 0 29 1 CI-27 @ 10 NONE 0.0219 0 30 1 CI-27 @ 15 NONE 0.0193 0 31 1 CI-27 @ 20 NONE 0.0237 0 32 1 CI-27 @ 20 HY-Temp I 0.0114 0 @ 2.4 33 1 CI-27 @ 10 HY-Temp I 0.0190 0 @ 1.2 34 2 CI-27 @ 8 NONE 0.0085 0 35 2 CI-27 @ 10 NONE 0.0096 0 36 2 CI-27 @ 15 NONE 0.0086 0 37 2 CI-27 @ 10 HY-Temp I 0.0062 0 @ 1.2 38 3 CI-27 @ 8 NONE 0.0119 0 39 3 CI-27 @ 10 NONE 0.0129 0 40 3 CI-27 @ 15 NONE 0.0171 0 41 3 CI-27 @ 10 HY-Temp I 0.0052 0 @ 1.2 42 3 CI-27 @ 15 HY-Temp I 0.0062 0 @ 1.2 - The results show that corrosion of Chrome 13 and Super Chrome 13 tubing with mild pH (buffered) peroxyacetic acid systems were within acceptacle limits in each case and at high temperatures. Acetic acid alone is not strongly corrosive, but in certain cases, corrosion levels were above 0.02 lb/ft (0.1 kg/m ), the maximum acceptable weight loss limit for high alloy tubing.
- Weighted portions of calcium carbonate chips (approximately 20/40 mesh size) were placed into a known volume of each test fluid. After 6 hours at atmospheric pressure and 180-200° F. (82-93° C.), the amount of dissolved calcium carbonate was determined. Four test acid systems were assayed, where LPCM=liters per cubic meter, and KPCM=kilograms per cubic meter.
- System 1: 15% Acetic acid+2 LPCM D4GB+6 KPCM Ferrotrol 300+3 KPCM Ferrotrol 210.
- System 2: Peroxyacetic system 1 (3% H 2O2 with 3.9% acetic acid buffered to pH 4)+6 KPCM of Ferrotrol 300+3 KPCM of Ferrotrol 1000.
- System 3: Peroxyacetic system 2 (1.5% H2O2 with 10% acetic acid buffered to pH 4)+6 KPCM of Ferrotrol 300+3 KPCM of Ferrotrol 1000.
- System 4: Peroxyacetic system 3 (1.5% H2O2 with 15% acetic acid buffered to pH of 4)+6 KPCM of Ferrotrol 300+KPCM of Ferrotrol 100.
Calcium carbonate solubility Acid Solubility (g/l) Solubility (lb/gal) Solubility (kg/m3) 1 80 0.67 80.5 2 15 0.13 15.6 3 68 0.57 68.5 4 107 0.89 106.9 - The results show that the peroxyacetic acid system containing 15% acetic acid and 1.5% hydrogen peroxide (buffered to pH 4) (test acid #4) dissolved significantly more calcium carbonate than the other systems, including 15% acid alone (test acid #1).
- The following test procedure was used.
- 1. Mount the berea core or aloxite disk into the bottom of the HTHP fluid loss cell and close the bottom of the cell. Note an alternative to this is to build a +/±0.25 inch (0.635 cm) silica sand bed as the base to the drilling mud cake upon.
- 2. Pour 100 ml of filtered 2% KCl brine into the cell. Close the top of the cell and attach the nitrogen manifold. Set the pressure to 20 psi (1.4 kg/cm2).
- 3. Open the top valve of the cell and apply 20 psi (1.4 kg/cm2 ) of nitrogen pressure to the cell.
- 4. Open the bottom valve and record the time taken to collect 100 ml of brine in a graduated beaker (i.e. when nitrogen break through occurs) (Q1).
- 5. Shut off the nitrogen, remove the nitrogen manifold, and open the top of cell.
- 6. Close the bottom valve and pour 100 ml of the fluid containing the polymer (drilling mud) into the cell.
- 7. Close the top of the cell and attach the nitrogen manifold. Set the nitrogen pressure to 20 psi (1.4 kg/cm2).
- 8.Open the top valve of the cell and apply 20 psi (1.4 kg/cm2) of nitrogen pressure to the cell.
- 9. Heat the cell to the required bottom hole temperature.
- 10. After shut in at bottom hole temperature for 30 minutes open the bottom valve and conduct a fluid loss test recording the volume of filtrate collected at 1, 4, 9, 16, 25, and 36 minutes (Q2). Close the bottom valve of the cell.
- 11. Release the pressure from the top of the cell and remove the nitrogen manifold. Cool the cell to room temperature and open the top of the cell.
- 12. Extract any liquid remaining in the cell, leaving the filter cake intact.
- 13. Add 100 ml of 2% KCl fluid to the cell.
- 14. Close the top of the cell and attach the nitrogen manifold. Set nitrogen pressure to 20 psi (1.4 kg/cm2).
- 15. Open the top valve of the cell and apply 20 psi (1.4 kg/cm2) of nitrogen pressure to the cell.
- 16. Open the bottom valve and record the time taken to collect 100 ml of brine in a graduated beaker (Q3).
- 17. Shut off the nitrogen, remove the nitrogen manifold, and open the top of cell. Extract any liquid remaining in the cell.
- 18. Add 100 ml treating fluid containing the desired enzyme and others additives to the cell.
- 19. Close the top of the cell and attach the nitrogen manifold. Set nitrogen pressure to 20 psi (1.4 kg/cm2).
- 20. Open the top valve of the cell and apply 20 psi (1.4 kg/cm2) of nitrogen pressure to the cell.
- 21. Heat the cell to 200° F. (93° C.) and allow the fluid to soak at this temperature for 12 hours.
- 22. Release the pressure from the top of the cell and remove the nitrogen manifold. Cool the cell to room temperature and open the top of the cell. Extract the remaining fluid from the cell.
- 23. Visually examine the disc for presence of filter cake. Where applicable, perform the iodine spot test for presence of starch.
- 24. Add 100 ml of 7.5% hydrochloric acid to the cell. Close the top of the cell and attach the nitrogen manifold. Set nitrogen pressure to 20 psi (1.4 kg/cm2).
- 25. Heat the cell to 200° F. (93° C.) and allow the fluid to soak at this temperature for 30 minutes.
- 26. Release the pressure from the top of the cell and remove the nitrogen manifold. Cool the cell to room temperature and open the top of the cell. Extract the remaining fluid from the cell.
- 27. Add 100 ml of 2% potassium chloride fluid to the cell. Close the top of the cell and attach the nitrogen manifold. Set nitrogen pressure to 20 psi (1.4 kg/cm2). Open the top valve of the cell and apply 20 psi (1.4 kg/cm2) of nitrogen pressure to the cell.
- 28. Open the bottom valve and record the time taken to collect 100 ml of brine in a graduated beaker (i.e. when nitrogen break through occurs) (Q4).
- 29. Shut off the nitrogen, remove the nitrogen manifold, dismantle/clean the cell, and prepared for further testing.
- Regarding step 23, the presence of starch is indicated by the formation of a blue color being produced when one drop of dilute iodine solution is placed on the surface of a filter cake. The absence of a blue color indicates that all starch has been degraded. The iodine spot test can only be used to detect the presence of starch. If starch is not present in the fluid used to form the filter cake, this test will be valid.
- The following mud system was used:
Component Concentration 2% KCl 7 ppb Caustic potash 0.25 ppb PAC-L/CMC low (Cellulose) 4-6 ppb PAC-R/CMC HV (Cellulose) 0.5-1 ppb XCD xanthan biopolymer 2-4 ppb CaCO3 - fine 13 ppb CaCO3 - coarse 7 ppb Dextrid (starch) 4-6 ppb - The following mudzyme formulation was used. Ferrotrol chelating/reducing agent, Inflo acid-mutual solvent, GBW enzyme breaker, Cl acid inhibitor, and NE non-ionic surfactant products are commercially available from BJ Services Company (Houston, Tex.). Gpt stands for gallons per thousand gallons (liters per thousand liters).
Component Concentration Filtered water 758 gpt Potassium chloride 167 ppt Ferrotrol-210 20 ppt Inflo-100 2 gpt Inflo-40 100 gpt GBW-16C 10 gpt GBW-26C 10 gpt H2O2 (6%) 120 gpt - The following 7.5% hydrochloric acid formulation was used.
Component Concentration Fresh water 722 gpt CI-25 6 gpt NE-18 5 gpt Claytrol (Baker Hughes; Houston, TX) 3 gpt Fe-210 30 ppt Inflo-40 50 gpt Inflo-100 5 gpt 32% hydrochloric acid 209 gpt - The following test results were obtained following the method of Example 9.
Measurement Value 2% KCl initial flow (Q1) 5.56 cc/sec Mud flow (Q2) 0.003 cc/sec 2% KCl flow after mud (Q3) 0 cc/sec 2% KCl flow after Mudzyme and acid 4.55 cc/sec (Q4) Return permeability (Q4/Q1) × 100% 81.8% pH Mudzyme solution before treatment 4 pH Mudzyme solution after treatment 4.5 - The following mudzyme formulation was used.
Component Concentration Filtered water 858 gpt Potassium chloride 167 ppt Ferrotrol-210 20 ppt Inflo-100 2 gpt Inflo-40 100 gpt GBW-16C 10 gpt GBW-26C 10 gpt GBW-5 30 ppt GBW-7 30 ppt - The following 7.5% hydrochloric acid formulation was used.
Component Concentration Fresh water 722 gpt CI-25 6 gpt NE-18 5 gpt Claytrol 3 gpt Fe-210 30 ppt Inflo-40 50 gpt Inflo-100 5 gpt 32% HCl 209 gpt - The following test results were obtained following the method of Example 9.
Measurement Value 2% KCl initial flow (Q1) 6.67 cc/sec Mud flow (Q2) 0.007 cc/sec 2% KCl flow after mud (Q3) 0 cc/sec 2% KCl flow after Mudzyme and acid (Q4) 1.06 cc/sec Return permeability (Q4/Q1) × 100% 15.9% pH Mudzyme solution before treatment 3.5 - 1. The Aloxite or berea disc was loaded into the cell.
- 2. The cell was filled with filtered brine, 2% KCl.
- 3. Pressure was applied and the cell allowed to come to temperature.
- 4. The bottom valve was opened and the time taken for 200 ml to pass through the disc at 100 psi (689 KPa) was recorded.
- 5. The pressure was bled from the cell slowly excess brine removed.
- 6. The cell was filled with the mud fluid.
- 7. The pressure was applied and the cell allowed to come to temperature.
- 8. After reaching temperature, open the bottom valve and record fluid loss at 1″, 4″, 9″, 16″, 25″ and 30″. Close the bottom valve of the cell.
- 9. The cell was shut-in until the desired time.
- 10. After the required shut-in time, excess mud was from the cell leaving the filter-cake intact.
- 11. The desired breaker fluid was added to the cell.
- 12. The pressure was applied, the cell allowed to come to temperature and the system was shut-in for four hours.
- 13. After the four hours shut-in period, the pressure was bled from the cell, and the treatment fluid extracted.
- 14. The disc was removed and examined for the presence of filter-cake. Iodine spot test was carried out for the presence of starch (presence of starch is indicated by a dark blue discoloration of the iodine). A few drops of HCl were placed onto the disc to determine the presence or absence of undissolved carbonate.
- 15. The disc was flipped and placed in the cell in the opposite orientation.
- 16. The cell was filled with filtered brine, and the time taken to flow 200 ml at 100 psi (689 KPa) was recorded.
- Four mud systems were used to evaluated the ability of various formulations to remove filter-cakes, as measured by the procedure of the previous Example. Two lacked drill solids, and two were the corresponding muds containing drill solids.
Label Contents A Mud from Rig BN-3 containing drill solids. B Freshly prepared mud, no drill solids. 2% KCl, 8 ppb dextrid starch, 2.5 ppb xanthan gum, 30 ppb ground marble fine, and 0.1 ppb potassium hydroxide. C Freshly prepared mud containing drill solids. D Freshly prepared mud, no drill solids. 2% KCl, 8 ppb dextrid starch, 2.5 ppb xanthan gum, 10 ppb baracarb 5 (Halilburton; Houston, TX), 20 ppb ground marble fine, and 0.3 ppb potassium hydroxide. - Six different breaker fluids were prepared or obtained for evaluation. They were a) buffered peroxyacetic acid; b) buffered mudzyme CS (a mixture of cellulase and amylase enzymes buffered with acetic acid and sodium acetate); c) Oxiclean (a mixture of oxidizing agents; generally ammonium persulphate, sodium perborate and fumaric acid); d) 1.2% sodium hypochlorite; e) 7.5% hydrochloric acid; and f) 7.5% hydrochloric acid with added sodium perborate.
- Muds A-D were assayed for their cumulative fluid loss volume over time.
Cumulative volume, ml Test # Mud 1′ 4′ 9′ 16′ 25′ 30′ 1 A 6 7 8 9 9.5 10 2 A 6 6.5 7.5 8.5 9.5 10 3 A 5 6 7 8 9 9.5 4 A 5 6.5 7.5 8.5 10 10.5 5 A 3 4 5 6 7 7 6 A 3.5 4.5 5.5 6.5 7 7.5 7 B 9.5 10.5 12 13.5 15 15.5 8 C 2.5 3 3.5 4.5 5.5 6 9 D 8.5 10 11.5 13 14.5 15 - The breaker fluids were assayed for their ability to dissolve filter cakes. First, mud A was tested using all six breaker fluids. The results were as follows, showing that the buffered peroxyacetic acid was clearly more effective than the other compositions at removing the filter cake. Note, tests 5 and 6 were performed using berea discs instead of aloxite.
(A) MUD FROM RIG BN-3 (with drill solids) Initial Final flow rate Flow rate % Filter # Breaker ml/s ml/s Efficiency cake Starch CaC 1 Buffered 14 25 178% None None Trace peroxyacetic acid 2 Mudzyme CS 17 NA — Yes Yes Yes 3 Oxiclean 25 NA — Partially Yes Yes 4 1.2% NaOCl 18 NA — Partially Yes Yes 5 7.5% HCl 5 NA — Yes Yes None 6 7.5% HCl + sodium 3 NA — Yes Yes Yes perborate - Next, muds B, C, and D were evaluated with the buffered peroxyacetic acid. The results were as follows, showing favorable results obtained by use of the buffered peroxyacetic acid compositions. Note, test 8 was performed using berea discs instead of aloxite.
Initial Final flow rate Flow rate % Filter # Breaker ml/s ml/s Efficiency cake Starch CaC (B) Freshly prepared mud, no drill solids 7 buffered 19 20 105% None None Trace peroxyacetic acid (C) Freshly prepared mud, with drill solids 8 buffered 2.7 Disc — None None None peroxyacetic acid cracked (D) Freshly prepared mud, no drill solids 9 buffered 14.3 15.4 108% None None None peroxyacetic acid - 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/or and in the steps or in the sequence of steps of the methods described herein without departing from the concept 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 scope and concept of the invention.
Claims (15)
1-17. (canceled)
18. A well treatment composition comprising:
water;
a buffer; and
hydrogen peroxide or a per-acid.
19. The composition of claim 18 , further comprising an iron-control agent, a surface tension reducer, a dispersant, a corrosion inhibitor, or a clay stabilizer.
20. The composition of claim 18 , wherein the composition has a pH of about 3 to about 5.
21. The composition of claim 18 , wherein the buffer comprises acetic acid and an acetate salt.
22. The composition of claim 21 , wherein the acetate salt is sodium acetate, potassium acetate, or ammonium acetate.
23. The composition of claim 18 , wherein the buffer comprises formic acid and a formate salt.
24. The composition of claim 23 , wherein the formate salt is sodium formate, potassium formate, or ammonium formate.
25. The composition of claim 18 , wherein the buffer comprises citric acid and a citrate salt.
26. The composition of claim 25 , wherein the citrate salt is sodium citrate, potassium citrate, or ammonium citrate.
27. The composition of claim 18 , wherein the per-acid is peroxyacetic acid.
28. The composition of claim 18 , wherein the concentration of hydrogen peroxide is about 1 weight percent to about 6 weight percent.
29. The composition of claim 18 , wherein the concentration of per-acid is about 1 weight percent to about 15 weight percent.
30. The composition of claim 18 , further comprising a peroxidase enzyme.
31. The composition of claim 18 , further comprising a phosphate salt or a phosphonate salt.
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US10/605,337 US7156178B2 (en) | 2002-09-24 | 2003-09-23 | Compositions containing a buffer and a peroxide or peracid useful for treating wells |
US11/607,285 US20070163779A1 (en) | 2002-09-24 | 2006-12-01 | Compositions containing a buffer and a peroxide or peracid useful for treating wells |
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RU2611796C1 (en) * | 2015-12-31 | 2017-03-01 | Публичное акционерное общество "Татнефть" имени В.Д. Шашина | Acid composition for treatment of bottomhole formation zone (versions) |
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Also Published As
Publication number | Publication date |
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CA2442240A1 (en) | 2004-03-24 |
NO20034260D0 (en) | 2003-09-24 |
US20040200619A1 (en) | 2004-10-14 |
GB2393464B (en) | 2006-10-18 |
GB0322359D0 (en) | 2003-10-22 |
US7156178B2 (en) | 2007-01-02 |
GB2393464A (en) | 2004-03-31 |
NO20034260L (en) | 2004-03-25 |
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