US20070284103A1 - Treatment Fluids Comprising Vitrified Shale and Methods of Using Such Fluids in Subterranean Formations - Google Patents
Treatment Fluids Comprising Vitrified Shale and Methods of Using Such Fluids in Subterranean Formations Download PDFInfo
- Publication number
- US20070284103A1 US20070284103A1 US11/844,188 US84418807A US2007284103A1 US 20070284103 A1 US20070284103 A1 US 20070284103A1 US 84418807 A US84418807 A US 84418807A US 2007284103 A1 US2007284103 A1 US 2007284103A1
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- Prior art keywords
- fluid
- spacer fluid
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- present
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- Prior art date
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Links
- 239000012530 fluid Substances 0.000 title claims abstract description 212
- 238000000034 method Methods 0.000 title abstract description 20
- 230000015572 biosynthetic process Effects 0.000 title abstract description 18
- 238000005755 formation reaction Methods 0.000 title abstract description 18
- 125000006850 spacer group Chemical group 0.000 claims abstract description 57
- 239000000203 mixture Substances 0.000 claims abstract description 50
- 239000003795 chemical substances by application Substances 0.000 claims description 40
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 20
- -1 allyl sulfonate Chemical compound 0.000 claims description 20
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 claims description 20
- 239000000654 additive Substances 0.000 claims description 16
- 239000004094 surface-active agent Substances 0.000 claims description 16
- 239000004113 Sepiolite Substances 0.000 claims description 14
- 229910052624 sepiolite Inorganic materials 0.000 claims description 14
- 235000019355 sepiolite Nutrition 0.000 claims description 14
- 239000010428 baryte Substances 0.000 claims description 12
- 229910052601 baryte Inorganic materials 0.000 claims description 12
- 239000002270 dispersing agent Substances 0.000 claims description 12
- 239000000463 material Substances 0.000 claims description 12
- 230000000996 additive effect Effects 0.000 claims description 11
- 229920001577 copolymer Polymers 0.000 claims description 11
- 239000002002 slurry Substances 0.000 claims description 11
- 229920002472 Starch Polymers 0.000 claims description 6
- 235000019698 starch Nutrition 0.000 claims description 6
- WSFSSNUMVMOOMR-NJFSPNSNSA-N methanone Chemical compound O=[14CH2] WSFSSNUMVMOOMR-NJFSPNSNSA-N 0.000 claims description 5
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 claims description 4
- 239000000839 emulsion Substances 0.000 claims description 4
- 150000003839 salts Chemical class 0.000 claims description 4
- BDHFUVZGWQCTTF-UHFFFAOYSA-M sulfonate Chemical compound [O-]S(=O)=O BDHFUVZGWQCTTF-UHFFFAOYSA-M 0.000 claims description 4
- SMZOUWXMTYCWNB-UHFFFAOYSA-N 2-(2-methoxy-5-methylphenyl)ethanamine Chemical compound COC1=CC=C(C)C=C1CCN SMZOUWXMTYCWNB-UHFFFAOYSA-N 0.000 claims description 3
- NIXOWILDQLNWCW-UHFFFAOYSA-N 2-Propenoic acid Natural products OC(=O)C=C NIXOWILDQLNWCW-UHFFFAOYSA-N 0.000 claims description 3
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 claims description 3
- 229920002907 Guar gum Polymers 0.000 claims description 3
- 239000005909 Kieselgur Substances 0.000 claims description 3
- 150000001336 alkenes Chemical class 0.000 claims description 3
- 229960000892 attapulgite Drugs 0.000 claims description 3
- 239000000440 bentonite Substances 0.000 claims description 3
- 229910000278 bentonite Inorganic materials 0.000 claims description 3
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 claims description 3
- 239000004927 clay Substances 0.000 claims description 3
- 239000000665 guar gum Substances 0.000 claims description 3
- 235000010417 guar gum Nutrition 0.000 claims description 3
- 229960002154 guar gum Drugs 0.000 claims description 3
- 229910052595 hematite Inorganic materials 0.000 claims description 3
- 239000011019 hematite Substances 0.000 claims description 3
- LIKBJVNGSGBSGK-UHFFFAOYSA-N iron(3+);oxygen(2-) Chemical compound [O-2].[O-2].[O-2].[Fe+3].[Fe+3] LIKBJVNGSGBSGK-UHFFFAOYSA-N 0.000 claims description 3
- 229920000847 nonoxynol Polymers 0.000 claims description 3
- 229910052625 palygorskite Inorganic materials 0.000 claims description 3
- 229920000642 polymer Polymers 0.000 claims description 3
- 239000008107 starch Substances 0.000 claims description 3
- 229920001732 Lignosulfonate Polymers 0.000 claims description 2
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 claims description 2
- 125000000217 alkyl group Chemical group 0.000 claims description 2
- 229910000019 calcium carbonate Inorganic materials 0.000 claims description 2
- GUJOJGAPFQRJSV-UHFFFAOYSA-N dialuminum;dioxosilane;oxygen(2-);hydrate Chemical compound O.[O-2].[O-2].[O-2].[Al+3].[Al+3].O=[Si]=O.O=[Si]=O.O=[Si]=O.O=[Si]=O GUJOJGAPFQRJSV-UHFFFAOYSA-N 0.000 claims description 2
- YDZQQRWRVYGNER-UHFFFAOYSA-N iron;titanium;trihydrate Chemical compound O.O.O.[Ti].[Fe] YDZQQRWRVYGNER-UHFFFAOYSA-N 0.000 claims description 2
- 229940094522 laponite Drugs 0.000 claims description 2
- 150000002632 lipids Chemical class 0.000 claims description 2
- XCOBTUNSZUJCDH-UHFFFAOYSA-B lithium magnesium sodium silicate Chemical compound [Li+].[Li+].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[OH-].[Na+].[Na+].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].[Mg+2].O1[Si](O2)([O-])O[Si]3([O-])O[Si]1([O-])O[Si]2([O-])O3.O1[Si](O2)([O-])O[Si]3([O-])O[Si]1([O-])O[Si]2([O-])O3.O1[Si](O2)([O-])O[Si]3([O-])O[Si]1([O-])O[Si]2([O-])O3.O1[Si](O2)([O-])O[Si]3([O-])O[Si]1([O-])O[Si]2([O-])O3.O1[Si](O2)([O-])O[Si]3([O-])O[Si]1([O-])O[Si]2([O-])O3.O1[Si](O2)([O-])O[Si]3([O-])O[Si]1([O-])O[Si]2([O-])O3 XCOBTUNSZUJCDH-UHFFFAOYSA-B 0.000 claims description 2
- LQKOJSSIKZIEJC-UHFFFAOYSA-N manganese(2+) oxygen(2-) Chemical compound [O-2].[O-2].[O-2].[O-2].[Mn+2].[Mn+2].[Mn+2].[Mn+2] LQKOJSSIKZIEJC-UHFFFAOYSA-N 0.000 claims description 2
- 229910052618 mica group Inorganic materials 0.000 claims description 2
- 239000000178 monomer Substances 0.000 claims description 2
- 229910052901 montmorillonite Inorganic materials 0.000 claims description 2
- POSICDHOUBKJKP-UHFFFAOYSA-N prop-2-enoxybenzene Chemical compound C=CCOC1=CC=CC=C1 POSICDHOUBKJKP-UHFFFAOYSA-N 0.000 claims description 2
- HIEHAIZHJZLEPQ-UHFFFAOYSA-M sodium;naphthalene-1-sulfonate Chemical compound [Na+].C1=CC=C2C(S(=O)(=O)[O-])=CC=CC2=C1 HIEHAIZHJZLEPQ-UHFFFAOYSA-M 0.000 claims description 2
- ONLRKTIYOMZEJM-UHFFFAOYSA-N n-methylmethanamine oxide Chemical compound C[NH+](C)[O-] ONLRKTIYOMZEJM-UHFFFAOYSA-N 0.000 claims 2
- IEORSVTYLWZQJQ-UHFFFAOYSA-N 2-(2-nonylphenoxy)ethanol Chemical compound CCCCCCCCCC1=CC=CC=C1OCCO IEORSVTYLWZQJQ-UHFFFAOYSA-N 0.000 claims 1
- CSCPPACGZOOCGX-UHFFFAOYSA-N Acetone Chemical class CC(C)=O CSCPPACGZOOCGX-UHFFFAOYSA-N 0.000 claims 1
- NLYAJNPCOHFWQQ-UHFFFAOYSA-N kaolin Chemical compound O.O.O=[Al]O[Si](=O)O[Si](=O)O[Al]=O NLYAJNPCOHFWQQ-UHFFFAOYSA-N 0.000 claims 1
- 229910052622 kaolinite Inorganic materials 0.000 claims 1
- 239000010445 mica Substances 0.000 claims 1
- KRKNYBCHXYNGOX-UHFFFAOYSA-N citric acid Chemical compound OC(=O)CC(O)(C(O)=O)CC(O)=O KRKNYBCHXYNGOX-UHFFFAOYSA-N 0.000 description 36
- 229920000663 Hydroxyethyl cellulose Polymers 0.000 description 14
- 239000004354 Hydroxyethyl cellulose Substances 0.000 description 14
- 235000019447 hydroxyethyl cellulose Nutrition 0.000 description 14
- 230000008901 benefit Effects 0.000 description 12
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 12
- 239000004568 cement Substances 0.000 description 10
- 238000005553 drilling Methods 0.000 description 8
- 229920005552 sodium lignosulfonate Polymers 0.000 description 8
- 238000002156 mixing Methods 0.000 description 7
- 150000003385 sodium Chemical class 0.000 description 7
- 238000000518 rheometry Methods 0.000 description 5
- 239000000377 silicon dioxide Substances 0.000 description 5
- 229910021536 Zeolite Inorganic materials 0.000 description 4
- HNPSIPDUKPIQMN-UHFFFAOYSA-N dioxosilane;oxo(oxoalumanyloxy)alumane Chemical compound O=[Si]=O.O=[Al]O[Al]=O HNPSIPDUKPIQMN-UHFFFAOYSA-N 0.000 description 4
- 239000013505 freshwater Substances 0.000 description 4
- 229910021485 fumed silica Inorganic materials 0.000 description 4
- 238000012360 testing method Methods 0.000 description 4
- 239000010457 zeolite Substances 0.000 description 4
- DNIAPMSPPWPWGF-UHFFFAOYSA-N Propylene glycol Chemical compound CC(O)CO DNIAPMSPPWPWGF-UHFFFAOYSA-N 0.000 description 3
- 229920002310 Welan gum Polymers 0.000 description 3
- 229920001222 biopolymer Polymers 0.000 description 3
- 229920002678 cellulose Polymers 0.000 description 3
- 239000001913 cellulose Substances 0.000 description 3
- 125000000524 functional group Chemical group 0.000 description 3
- 229920001059 synthetic polymer Polymers 0.000 description 3
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 2
- SRBFZHDQGSBBOR-IOVATXLUSA-N D-xylopyranose Chemical compound O[C@@H]1COC(O)[C@H](O)[C@H]1O SRBFZHDQGSBBOR-IOVATXLUSA-N 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- 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 2
- UFWIBTONFRDIAS-UHFFFAOYSA-N Naphthalene Chemical compound C1=CC=CC2=CC=CC=C21 UFWIBTONFRDIAS-UHFFFAOYSA-N 0.000 description 2
- GWEVSGVZZGPLCZ-UHFFFAOYSA-N Titan oxide Chemical compound O=[Ti]=O GWEVSGVZZGPLCZ-UHFFFAOYSA-N 0.000 description 2
- 125000003277 amino group Chemical class 0.000 description 2
- PYMYPHUHKUWMLA-UHFFFAOYSA-N arabinose Natural products OCC(O)C(O)C(O)C=O PYMYPHUHKUWMLA-UHFFFAOYSA-N 0.000 description 2
- SRBFZHDQGSBBOR-UHFFFAOYSA-N beta-D-Pyranose-Lyxose Natural products OC1COC(O)C(O)C1O SRBFZHDQGSBBOR-UHFFFAOYSA-N 0.000 description 2
- 239000012267 brine Substances 0.000 description 2
- 150000001735 carboxylic acids Chemical class 0.000 description 2
- 125000002887 hydroxy group Chemical group [H]O* 0.000 description 2
- VMESOKCXSYNAKD-UHFFFAOYSA-N n,n-dimethylhydroxylamine Chemical class CN(C)O VMESOKCXSYNAKD-UHFFFAOYSA-N 0.000 description 2
- 229920000620 organic polymer Polymers 0.000 description 2
- 239000011734 sodium Substances 0.000 description 2
- 229910052708 sodium Inorganic materials 0.000 description 2
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 230000000638 stimulation Effects 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- 239000000725 suspension Substances 0.000 description 2
- 229920001285 xanthan gum Polymers 0.000 description 2
- 229920001661 Chitosan Polymers 0.000 description 1
- WQZGKKKJIJFFOK-QTVWNMPRSA-N D-mannopyranose Chemical compound OC[C@H]1OC(O)[C@@H](O)[C@@H](O)[C@@H]1O WQZGKKKJIJFFOK-QTVWNMPRSA-N 0.000 description 1
- 229930091371 Fructose Natural products 0.000 description 1
- 239000005715 Fructose Substances 0.000 description 1
- RFSUNEUAIZKAJO-ARQDHWQXSA-N Fructose Chemical compound OC[C@H]1O[C@](O)(CO)[C@@H](O)[C@@H]1O RFSUNEUAIZKAJO-ARQDHWQXSA-N 0.000 description 1
- IAJILQKETJEXLJ-UHFFFAOYSA-N Galacturonsaeure Natural products O=CC(O)C(O)C(O)C(O)C(O)=O IAJILQKETJEXLJ-UHFFFAOYSA-N 0.000 description 1
- 108010010803 Gelatin Proteins 0.000 description 1
- WQZGKKKJIJFFOK-GASJEMHNSA-N Glucose Natural products OC[C@H]1OC(O)[C@H](O)[C@@H](O)[C@@H]1O WQZGKKKJIJFFOK-GASJEMHNSA-N 0.000 description 1
- KKCBUQHMOMHUOY-UHFFFAOYSA-N Na2O Inorganic materials [O-2].[Na+].[Na+] KKCBUQHMOMHUOY-UHFFFAOYSA-N 0.000 description 1
- ABLZXFCXXLZCGV-UHFFFAOYSA-N Phosphorous acid Chemical class OP(O)=O ABLZXFCXXLZCGV-UHFFFAOYSA-N 0.000 description 1
- 229920002873 Polyethylenimine Polymers 0.000 description 1
- 229920002125 Sokalan® Polymers 0.000 description 1
- 238000002441 X-ray diffraction Methods 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- IAJILQKETJEXLJ-QTBDOELSSA-N aldehydo-D-glucuronic acid Chemical compound O=C[C@H](O)[C@@H](O)[C@H](O)[C@H](O)C(O)=O IAJILQKETJEXLJ-QTBDOELSSA-N 0.000 description 1
- WQZGKKKJIJFFOK-PHYPRBDBSA-N alpha-D-galactose Chemical compound OC[C@H]1O[C@H](O)[C@H](O)[C@@H](O)[C@H]1O WQZGKKKJIJFFOK-PHYPRBDBSA-N 0.000 description 1
- PNEYBMLMFCGWSK-UHFFFAOYSA-N aluminium oxide Inorganic materials [O-2].[O-2].[O-2].[Al+3].[Al+3] PNEYBMLMFCGWSK-UHFFFAOYSA-N 0.000 description 1
- PYMYPHUHKUWMLA-WDCZJNDASA-N arabinose Chemical compound OC[C@@H](O)[C@@H](O)[C@H](O)C=O PYMYPHUHKUWMLA-WDCZJNDASA-N 0.000 description 1
- 230000004888 barrier function Effects 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- WQZGKKKJIJFFOK-VFUOTHLCSA-N beta-D-glucose Chemical compound OC[C@H]1O[C@@H](O)[C@H](O)[C@@H](O)[C@@H]1O WQZGKKKJIJFFOK-VFUOTHLCSA-N 0.000 description 1
- 229910052792 caesium Inorganic materials 0.000 description 1
- TVFDJXOCXUVLDH-UHFFFAOYSA-N caesium atom Chemical compound [Cs] TVFDJXOCXUVLDH-UHFFFAOYSA-N 0.000 description 1
- 125000003178 carboxy group Chemical group [H]OC(*)=O 0.000 description 1
- 229920003090 carboxymethyl hydroxyethyl cellulose Polymers 0.000 description 1
- 229910052681 coesite Inorganic materials 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 230000003750 conditioning effect Effects 0.000 description 1
- 238000007596 consolidation process Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 229910052593 corundum Inorganic materials 0.000 description 1
- 229910052906 cristobalite Inorganic materials 0.000 description 1
- 239000013530 defoamer Substances 0.000 description 1
- 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 1
- 238000006073 displacement reaction Methods 0.000 description 1
- 230000009977 dual effect Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 150000002148 esters Chemical class 0.000 description 1
- 150000002170 ethers Chemical class 0.000 description 1
- 235000013312 flour Nutrition 0.000 description 1
- 230000004927 fusion Effects 0.000 description 1
- 229930182830 galactose Natural products 0.000 description 1
- 229920000159 gelatin Polymers 0.000 description 1
- 235000019322 gelatine Nutrition 0.000 description 1
- 235000011852 gelatine desserts Nutrition 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 239000008103 glucose Substances 0.000 description 1
- 229930182478 glucoside Natural products 0.000 description 1
- 150000008131 glucosides Chemical class 0.000 description 1
- 229940097043 glucuronic acid Drugs 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 239000003112 inhibitor Substances 0.000 description 1
- JEIPFZHSYJVQDO-UHFFFAOYSA-N iron(III) oxide Inorganic materials O=[Fe]O[Fe]=O JEIPFZHSYJVQDO-UHFFFAOYSA-N 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 238000012423 maintenance Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 150000002772 monosaccharides Chemical group 0.000 description 1
- SNQQPOLDUKLAAF-UHFFFAOYSA-N nonylphenol Chemical class CCCCCCCCCC1=CC=CC=C1O SNQQPOLDUKLAAF-UHFFFAOYSA-N 0.000 description 1
- 150000007524 organic acids Chemical class 0.000 description 1
- 125000002467 phosphate group Chemical class [H]OP(=O)(O[H])O[*] 0.000 description 1
- 229920003023 plastic Polymers 0.000 description 1
- 239000004033 plastic Substances 0.000 description 1
- 229920002401 polyacrylamide Polymers 0.000 description 1
- 229920000058 polyacrylate Polymers 0.000 description 1
- 229920000193 polymethacrylate Polymers 0.000 description 1
- 229920002451 polyvinyl alcohol Polymers 0.000 description 1
- WFIZEGIEIOHZCP-UHFFFAOYSA-M potassium formate Chemical compound [K+].[O-]C=O WFIZEGIEIOHZCP-UHFFFAOYSA-M 0.000 description 1
- 230000003134 recirculating effect Effects 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 239000002455 scale inhibitor Substances 0.000 description 1
- 239000013535 sea water Substances 0.000 description 1
- 239000003381 stabilizer Substances 0.000 description 1
- 229910052682 stishovite Inorganic materials 0.000 description 1
- 125000001273 sulfonato group Chemical class [O-]S(*)(=O)=O 0.000 description 1
- 239000008399 tap water Substances 0.000 description 1
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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
- C09K8/40—Spacer compositions, e.g. compositions used to separate well-drilling from cementing masses
Definitions
- the present invention relates to subterranean treatment operations, and more particularly, to improved treatment fluids comprising vitrified shale, and methods of using these improved treatment fluids in subterranean formations.
- Treatment fluids are used in a variety of operations that may be performed in subterranean formations.
- the term “treatment fluid” will be understood to mean any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose.
- the term “treatment fluid” does not imply any particular action by the fluid.
- Treatment fluids often are used in, e.g., well drilling, completion, and stimulation operations. Examples of such treatment fluids include, inter alia, drilling fluids, well cleanup fluids, workover fluids, conformance fluids, gravel pack fluids, acidizing fluids, fracturing fluids, spacer fluids, and the like.
- Spacer fluids often are used in oil and gas wells to facilitate improved displacement efficiency when displacing multiple fluids into a well bore.
- spacer fluids often may be placed within a subterranean formation so as to physically separate incompatible fluids. Spacer fluids also may be placed between different drilling fluids during drilling-fluid changeouts, or between a drilling fluid and a completion brine.
- Spacer fluids also may be used in primary cementing operations to separate, inter alia, a drilling fluid from a cement composition that may be placed in an annulus between a casing string and the subterranean formation, whether the cement composition is placed in the annulus in either the conventional or reverse-circulation direction.
- the cement composition often is intended, inter alia, to set in the annulus, supporting and positioning the casing string, and bonding to both the casing string and the formation to form a substantially impermeable barrier, or cement sheath, which facilitates zonal isolation. If the spacer fluid does not adequately displace the drilling fluid from the annulus, the cement composition may fail to bond to the casing string and/or the formation to the desired extent.
- spacer fluids also may be placed in subterranean formations to ensure that all down hole surfaces are water-wetted before the subsequent placement of a cement composition, which may enhance the bonding that occurs between the cement composition and the water-wetted surfaces.
- Treatment fluids including spacer fluids, often comprise materials that are costly and that, in certain circumstances, may become unstable at elevated temperatures. This is problematic, inter alia, because it may increase the cost of subterranean operations involving the treatment fluid.
- the present invention relates to subterranean treatment operations, and more particularly, to improved treatment fluids comprising vitrified shale, and methods of using these improved treatment fluids in subterranean formations.
- An example of a method of the present invention is a method of displacing a fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; and placing a second fluid into the well bore to at least partially displace the first fluid therefrom, wherein the second fluid comprises vitrified shale and a base fluid.
- Another example of a method of the present invention is a method of separating fluids in a well bore in a subterranean formation, comprising: providing a well bore having a first fluid disposed therein; placing a spacer fluid in the well bore to separate the first fluid from a second fluid, the spacer fluid comprising vitrified shale and a base fluid; and placing a second fluid in the well bore.
- composition of the present invention is a spacer fluid comprising vitrified shale and a base fluid.
- the present invention relates to subterranean treatment operations, and more particularly, to improved treatment fluids comprising vitrified shale, and methods of using these improved treatment fluids in subterranean formations.
- the treatment fluids of the present invention are suitable for use in a variety of subterranean treatment applications, including well drilling, completion, and stimulation operations.
- the treatment fluids of the present invention generally comprise vitrified shale and a base fluid.
- the treatment fluids of the present invention may comprise additional additives as may be required or beneficial for a particular use.
- the treatment fluids of the present invention may include viscosifying agents, organic polymers, dispersants, surfactants, weighting agents, and the like.
- the vitrified shale utilized in the treatment fluids of the present invention generally comprises any partially vitrified silica-rich material.
- Vitrified shale includes any fine-grained rock formed by the consolidation of clay or mud that has been at least partially converted into a crystalline, glassy material by heat and fusion.
- the vitrified shale has a percent volume oxide content, as determined by quantitative x-ray diffraction, as set forth in Table 1 below.
- vitrified shale is commercially available under the trade name “PRESSUR-SEAL® FINE LCM” from TXI Energy Services, Inc., of Houston, Tex.
- the vitrified shale is present in the treatment fluids of the present invention in an amount in the range of from about 0.01% to about 90% by weight of the treatment fluid.
- the vitrified shale is present in the treatment fluids of the present invention in an amount in the range of from about 1% to about 20% by weight of the treatment fluid. In other embodiments of the present invention, the vitrified shale is present in the treatment fluids of the present invention in an amount in the range of from about 1% to about 10% by weight of the treatment fluid.
- One skilled in the art, with the benefit of this disclosure, will recognize a suitable amount of vitrified shale for a particular application.
- the base fluid utilized in the treatment fluids of the present invention may comprise an aqueous-based fluid, an oil-based fluid, a synthetic fluid, or an emulsion.
- the base fluid may be an aqueous-based fluid that comprises fresh water, salt water, brine, sea water, or a mixture thereof.
- the base fluid may be an aqueous-based fluid that may comprise cesium and/or potassium formate.
- the base fluid can be from any source provided that it does not contain compounds that may adversely affect other components in the treatment fluid.
- the base fluid may be from a natural or synthetic source.
- the base fluid may comprise a synthetic fluid such as, but not limited to, esters, ethers, and olefins.
- the base fluid will be present in the treatment fluids of the present invention in an amount sufficient to form a pumpable slurry.
- the base fluid will be present in the treatment fluids of the present invention in an amount in the range of from about 15% to about 95% by weight of the treatment fluid.
- the base fluid will be present in the treatment fluids of the present invention in an amount in the range of from about 25% to about 85% by weight of the treatment fluid.
- the treatment fluids of the present invention further may comprise a viscosifying agent.
- the viscosifying agent may be any component suitable for providing a desired degree of solids suspension. The choice of a viscosifying agent depends upon factors such as the desired viscosity and the desired chemical compatibility with other fluids (e.g., drilling fluids, cement compositions, and the like). In certain embodiments of the present invention, the viscosifying agent may be easily flocculated and filtered out of the treatment fluids of the present invention.
- Suitable viscosifying agents may include, but are not limited to, colloidal agents (e.g., clays, polymers, guar gum), emulsion forming agents, diatomaceous earth, starches, biopolymers, synthetic polymers, or mixtures thereof. Suitable viscosifying agents often are hydratable polymers that have one or more functional groups. These functional groups include, but are not limited to, hydroxyl groups, carboxyl groups, carboxylic acids, derivatives of carboxylic acids, sulfate groups, sulfonate groups, phosphate groups, phosphonate groups, and amino groups. In certain embodiments of the present invention, viscosifying agents may be used that comprise hydroxyl groups and/or amino groups.
- the viscosifying agents may be biopolymers, and derivatives thereof, that have one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate.
- suitable biopolymers include, but are not limited to, guar gum and derivatives thereof, such as hydroxypropyl guar and carboxymethyl hydroxypropyl guar, and cellulose derivatives, such as hydroxyethyl cellulose, welan gums, and xanthan gums. Additionally, synthetic polymers that contain the above-mentioned functional groups may be used.
- Such synthetic polymers include, but are not limited to, poly(acrylate), poly(methacrylate), poly(ethylene imine), poly(acrylamide), poly(vinyl alcohol), and poly(vinylpyrrolidone).
- suitable viscosifying agents include chitosans, starches and gelatins.
- Suitable clays include kaolinites, montmorillonite, bentonite, hydrous micas, attapulgite, sepiolite, and the like, as well as synthetic clays, such as laponite.
- An example of a suitable viscosifying agent is a hydroxyethyl cellulose that is commercially available under the trade name “WG-17” from Halliburton Energy Services, Inc., of Duncan, Okla.
- a suitable viscosifying agent is a welan gum that is commercially available under the trade name “BIOZAN” from Kelco Oilfield Services, Inc.
- the viscosifying agent may be present in the treatment fluids of the present invention in an amount sufficient to provide a desired degree of solids suspension.
- the viscosifying agent may be present in an amount in the range from about 0.01% to about 35% by weight of the treatment fluid. In other embodiments, the viscosifying agent may be present in an amount in the range from about 0.5% to about 2% by weight of the treatment fluid.
- viscosifying agents such as welan gum, cellulose (and cellulose derivatives), and xanthan gum may be particularly suitable.
- welan gum cellulose (and cellulose derivatives), and xanthan gum
- xanthan gum may be particularly suitable.
- the treatment fluids of the present invention further may comprise a fluid loss control additive.
- a fluid loss control additive suitable for use in a subterranean application may be suitable for use in the compositions and methods of the present invention.
- the fluid loss control additive may comprise organic polymers, starches, or fine silica.
- An example of a fine silica that may be suitable is commercially available from Halliburton Energy Services, Inc. under the trade name “WAC-9.”
- An example of a starch that may be suitable is commercially available from Halliburton Energy Services, Inc.
- the fluid loss control additive may be present in the treatment fluids of the present invention in an amount in the range from about 0.01% to about 6% by weight of the treatment fluid. In other embodiments, the fluid loss control additive may be present in the treatment fluids of the present invention in an amount in the range from about 0.05% to about 0.1% by weight of the treatment fluid.
- a fluid loss control additive may be present in the treatment fluids of the present invention in an amount in the range from about 0.05% to about 0.1% by weight of the treatment fluid.
- the treatment fluids of the present invention may comprise a dispersant.
- Suitable examples of dispersants include, but are not limited to, sulfonated styrene maleic anhydride copolymer, sulfonated vinyl toluene maleic anhydride copolymer, sodium naphthalene sulfonate condensed with formaldehyde, sulfonated acetone condensed with formaldehyde, lignosulfonates (e.g., modified sodium lignosulfonate), allyloxybenzene sulfonate, allyl sulfonate and non-ionic monomers, and interpolymers of acrylic acid.
- dispersant that may be suitable is commercially available from National Starch & Chemical Company of Newark, N.J. under the trade name “Alcosperse 602 ND,” and is a mixture of 6 parts sulfonated styrene maleic anhydride copolymer to 3.75 parts interpolymer of acrylic acid.
- a dispersant that may be suitable is a modified sodium lignosulfonate that is commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., under the trade name “HR®-5.” Where included, the dispersant may be present in an amount in the range from about 0.0001% to about 4% by weight of the treatment fluid.
- the dispersant may be present in an amount in the range from about 0.0003% to about 0.1% by weight of the treatment fluid.
- the treatment fluids of the present invention may comprise surfactants.
- surfactants include, but are not limited to, nonylphenol ethoxylates, alcohol ethoxylates, sugar lipids, ⁇ -olefinsulfonates, alkylpolyglycosides, alcohol sulfates, salts of ethoxylated alcohol sulfates, alkyl amidopropyl dimethylamine oxides, and alkene amidopropyl dimethylamine oxides.
- An example of a surfactant that may be suitable comprises an oxyalkylatedsulfonate, and is commercially available from Halliburton Energy Services, Inc.
- surfactant may be suitable in an amount in the range from about 0.01% to about 10% by weight of the treatment fluid. In other embodiments of the present invention, the surfactant may be present in an amount in the range from about 0.01% to about 6% by weight of the treatment fluid.
- the surfactant may be present in an amount in the range from about 0.01% to about 6% by weight of the treatment fluid.
- the treatment fluids of the present invention may comprise weighting agents.
- any weighting agent may be used with the treatment fluids of the present invention.
- Suitable weighting materials may include barium sulfate, hematite, manganese tetraoxide, ilmenite, calcium carbonate, and the like.
- An example of a suitable hematite is commercially available under the trade name “Hi-Dense® No. 4” from Halliburton Energy Services, Inc.
- the weighting agent may be present in the treatment fluid in an amount sufficient to provide a desired density to the treatment fluid.
- the weighting agent may be present in the treatment fluids of the present invention in the range from about 0.01% to about 85% by weight.
- the weighting agent may be present in the treatment fluids of the present invention in the range from about 15% to about 70% by weight.
- One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of weighting agent to use for a chosen application.
- additives may be added to the treatment fluids of the present invention as deemed appropriate by one skilled in the art with the benefit of this disclosure.
- additives include, inter alia, defoamers, curing agents, salts, corrosion inhibitors, scale inhibitors, and formation conditioning agents.
- defoamers include, inter alia, defoamers, curing agents, salts, corrosion inhibitors, scale inhibitors, and formation conditioning agents.
- Certain embodiments of the fluids of the present invention may demonstrate improved “300/3” ratios.
- the term “300/3” ratio will be understood to mean the value that results from dividing the shear stress that a fluid demonstrates at 300 rpm by the shear stress that the same fluid demonstrates at 3 rpm.
- an ideal “300/3” ratio would closely approximate 1.0, indicating that the rheology of such fluid is flat.
- Flat rheology will facilitate, inter alia, maintenance of nearly uniform fluid velocities across a subterranean annulus, and also may result in a near-constant shear stress profile.
- flat rheology may reduce the volume of a spacer fluid that is required to effectively clean a subterranean well bore.
- Certain embodiments of the fluids of the present invention may demonstrate 300/3 ratios in the range of from about 2.7 to about 4.2.
- Certain embodiments of the fluids of the present invention may maintain a nearly flat rheology across a wide temperature range.
- the fluids of the present invention may be prepared in a variety of ways.
- the well fluids of the present invention may be prepared by first pre-blending the vitrified shale with certain optional dry additives.
- the blended dry materials may be mixed with base fluid in the field, either by batch mixing or continuous (“on-the-fly”) mixing.
- a weak organic acid and defoamers typically will be premixed into the base fluid.
- the dry blend then may be added to the base fluid using, e.g., an additive hopper with venturi effects; the mixture of the dry blend and the base fluid also may be agitated, after which the weighting material may be added and agitated.
- Surfactants may be added to the spacer fluid shortly before it is placed down hole.
- the blended dry materials typically will be further blended with a weighting material, and the resulting mixture may be metered into, e.g., recirculating cement mixing equipment while the base fluid is metered in separately.
- the base fluid typically will comprise defoamers pre-blended therein. Shortly before the spacer fluid is placed down hole, surfactants may be added to the spacer fluid.
- An example of a method of the present invention is a method of displacing a fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; and placing a second fluid into the well bore to at least partially displace the first fluid therefrom, wherein the second fluid comprises vitrified shale and a base fluid.
- Another example of a method of the present invention is a method of separating fluids in a well bore in a subterranean formation, comprising: providing a well bore having a first fluid disposed therein; placing a spacer fluid in the well bore to separate the first fluid from a second fluid, the spacer fluid comprising a vitrified shale and a base fluid; and placing a second fluid in the well bore.
- composition of the present invention comprises 51.39% water by weight, 3.19% vitrified shale by weight, 43.81% barite by weight, 0.94% sepiolite by weight, 0.034% hydroxyethyl cellulose by weight, 0.08% BIOZAN by weight, 0.006% modified sodium lignosulfonate by weight, and 0.55% citric acid by weight.
- Rheological testing was performed on a variety of sample compositions that were prepared as follows. First, all dry components (e.g., vitrified shale, or zeolite, or fumed silica, plus dry additives such as, for example, hydroxyethylcellulose, BIOZAN, and sodium lignosulfonate were weighed into a glass container having a clean lid, and thoroughly agitated by hand until well blended. Tap water then was weighed into a Waring blender jar, and the blender turned on at 4,000 rpm. While the blender continued to turn, citric acid was added to the mixing water, and then the blended dry components were added, followed by the barite. The blender speed then was increased to 12,000 rpm for about 35 seconds. Afterwards, the blender was stopped, and about 2 drops of a standard, glycol-based defoamer were added.
- dry additives such as, for example, hydroxyethylcellulose, BIOZAN, and sodium lignosulfonate
- Rheological values then were determined using a Fann Model 35 viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100, 200, 300, and 600 RPM with a B1 bob, an R1 rotor, and a 1.0 spring.
- Sample Composition No. 1 comprised a 10 pound per gallon slurry of 75.6% water, 4.83% zeolite, 1.63% sepiolite, 0.04% hydroxyethylcellulose, 0.11% BIOZAN, 0.71% sulfonated styrene copolymer, 0.72% citric acid, and 16.36% barite.
- Sample Composition No. 2 comprised a 10 pound per gallon slurry of 75.6% water, 4.83% fumed silica, 1.63% sepiolite, 0.04% hydroxyethylcellulose, 0.11% BIOZAN, 0.71% sulfonated styrene copolymer, 0.72% citric acid, and 16.36% barite.
- Sample Composition No. 3 comprised a 10 pound per gallon slurry of 75.6% water, 5.49% vitrified shale, 1.61% sepiolite, 0.07% hydroxyethylcellulose, 0.14% BIOZAN, 0.01% modified sodium lignosulfonate, 0.72% citric acid, and 16.36% barite.
- Sample Composition No. 4 comprised a 13 pound per gallon slurry of 51.39% water, 2.81% zeolite, 0.95% sepiolite, 0.02% hydroxyethylcellulose, 0.06% BIOZAN, 0.41% sulfonated styrene copolymer, 0.55% citric acid, and 43.81% barite.
- Sample Composition No. 5 comprised a 13 pound per gallon slurry of 51.39% water, 2.81% fumed silica, 0.95% sepiolite, 0.02% hydroxyethylcellulose, 0.06% BIOZAN, 0.41% sulfonated styrene copolymer, 0.55% citric acid, and 43.81% barite.
- Sample Composition No. 7 comprised a 16 pound per gallon slurry of 36.22% water, 1.54% zeolite, 0.52% sepiolite, 0.01% hydroxyethylcellulose, 0.04% BIOZAN, 0.23% sulfonated styrene copolymer, 0.45% citric acid, and 60.98% barite.
- Sample Composition No. 8 comprised a 16 pound per gallon slurry of 36.22% water, 1.54% fumed silica, 0.52% sepiolite, 0.01% hydroxyethylcellulose, 0.04% BIOZAN, 0.23% sulfonated styrene copolymer, 0.45% citric acid, and 60.98% barite.
- Sample Composition No. 9 comprised a 16 pound per gallon slurry of 36.22% water, 1.76% vitrified shale, 0.52% sepiolite, 0.023% hydroxyethylcellulose, 0.044% BIOZAN, 0.003% modified sodium lignosulfonate, 0.45% citric acid, and 60.98% barite.
- Sample Composition No. 10 a well fluid of the present invention, comprised 60.98% fresh water by weight, 1.76% vitrified shale by weight, 36.22% barium sulfate by weight, 0.52% sepiolite by weight, 0.023% hydroxyethyl cellulose by weight, 0.044% BIOZAN by weight, 0.003% modified sodium lignosulfonate by weight, and 0.45% citric acid by weight.
- Sample Composition No. 11 comprised 0.97% bentonite by weight, 27.79% silica flour by weight, 0.2% carboxymethyl hydroxyethyl cellulose by weight, 40.04% barium sulfate by weight, 0.37% by weight of sodium napthalene sulfonate condensed with formaldehyde, and 31.63% fresh water by weight.
- Sample Composition No. 12 comprised 2.03% diatomaceous earth by weight, 1.82% coarse silica by weight, 0.1% attapulgite by weight, 0.63% sepiolite by weight, 0.52% by weight of sodium napthalene sulfonate condensed with formaldehyde, 0.1% propylene glycol by weight, 59.1% barium sulfate by weight, and 35.7% fresh water by weight.
- compositions were tested to determine their “300/3” ratios.
- a viscometer using an R-1 rotor, a B-1 bob, and an F-1 spring was used.
- the dial readings at 300 RPM (511 sec ⁇ 1 of shear) were divided by dial readings obtained at 3 RPM (5.11 sec ⁇ 1 of shear).
- the results of the testing are set forth in the table below. TABLE 5 Sample Sample Sample Composition Composition Composition Composition Rheology No. 10 No. 11 No. 12 300/3 ratio at 80° F. 4.2 11.0 9.0 300/3 ratio at 135° F. 2.7 7.8 5.8 300/3 ratio at 190° F. 3.0 5.3 5.6
Abstract
Methods and compositions for the treatment of subterranean formations, and more specifically, treatment fluids containing vitrified shale and methods of using these treatment fluids in subterranean formations, are provided. An example of a method is a method of displacing a fluid in a well bore. Another example of a method is a method of separating fluids in a well bore in a subterranean formation. An example of a composition is a spacer fluid comprising vitrified shale and a base fluid.
Description
- This application is a divisional application of U.S. patent application Ser. No. 10/969,570, entitled “Methods of Treating Particulates and Use in Subterranean Formations,” filed on Oct. 20, 2004, the entirety of which is herein incorporated by reference.
- The present invention relates to subterranean treatment operations, and more particularly, to improved treatment fluids comprising vitrified shale, and methods of using these improved treatment fluids in subterranean formations.
- Treatment fluids are used in a variety of operations that may be performed in subterranean formations. As referred to herein, the term “treatment fluid” will be understood to mean any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid. Treatment fluids often are used in, e.g., well drilling, completion, and stimulation operations. Examples of such treatment fluids include, inter alia, drilling fluids, well cleanup fluids, workover fluids, conformance fluids, gravel pack fluids, acidizing fluids, fracturing fluids, spacer fluids, and the like.
- Spacer fluids often are used in oil and gas wells to facilitate improved displacement efficiency when displacing multiple fluids into a well bore. For example, spacer fluids often may be placed within a subterranean formation so as to physically separate incompatible fluids. Spacer fluids also may be placed between different drilling fluids during drilling-fluid changeouts, or between a drilling fluid and a completion brine.
- Spacer fluids also may be used in primary cementing operations to separate, inter alia, a drilling fluid from a cement composition that may be placed in an annulus between a casing string and the subterranean formation, whether the cement composition is placed in the annulus in either the conventional or reverse-circulation direction. The cement composition often is intended, inter alia, to set in the annulus, supporting and positioning the casing string, and bonding to both the casing string and the formation to form a substantially impermeable barrier, or cement sheath, which facilitates zonal isolation. If the spacer fluid does not adequately displace the drilling fluid from the annulus, the cement composition may fail to bond to the casing string and/or the formation to the desired extent. In certain circumstances, spacer fluids also may be placed in subterranean formations to ensure that all down hole surfaces are water-wetted before the subsequent placement of a cement composition, which may enhance the bonding that occurs between the cement composition and the water-wetted surfaces.
- Conventional treatment fluids, including spacer fluids, often comprise materials that are costly and that, in certain circumstances, may become unstable at elevated temperatures. This is problematic, inter alia, because it may increase the cost of subterranean operations involving the treatment fluid.
- The present invention relates to subterranean treatment operations, and more particularly, to improved treatment fluids comprising vitrified shale, and methods of using these improved treatment fluids in subterranean formations.
- An example of a method of the present invention is a method of displacing a fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; and placing a second fluid into the well bore to at least partially displace the first fluid therefrom, wherein the second fluid comprises vitrified shale and a base fluid.
- Another example of a method of the present invention is a method of separating fluids in a well bore in a subterranean formation, comprising: providing a well bore having a first fluid disposed therein; placing a spacer fluid in the well bore to separate the first fluid from a second fluid, the spacer fluid comprising vitrified shale and a base fluid; and placing a second fluid in the well bore.
- An example of a composition of the present invention is a spacer fluid comprising vitrified shale and a base fluid.
- The features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.
- The present invention relates to subterranean treatment operations, and more particularly, to improved treatment fluids comprising vitrified shale, and methods of using these improved treatment fluids in subterranean formations. The treatment fluids of the present invention are suitable for use in a variety of subterranean treatment applications, including well drilling, completion, and stimulation operations.
- The treatment fluids of the present invention generally comprise vitrified shale and a base fluid. Optionally, the treatment fluids of the present invention may comprise additional additives as may be required or beneficial for a particular use. For example, the treatment fluids of the present invention may include viscosifying agents, organic polymers, dispersants, surfactants, weighting agents, and the like.
- The vitrified shale utilized in the treatment fluids of the present invention generally comprises any partially vitrified silica-rich material. Vitrified shale includes any fine-grained rock formed by the consolidation of clay or mud that has been at least partially converted into a crystalline, glassy material by heat and fusion. In certain embodiments of the present invention, the vitrified shale has a percent volume oxide content, as determined by quantitative x-ray diffraction, as set forth in Table 1 below.
TABLE 1 Oxide Volume % SiO2 57-73 Al2O3 15-25 Fe2O3 3-7 CaO 2-6 K2O 1-5 SO3 1-3 MnO, SrO, TiO2, BaO, and each <1% Na2O
An example of a suitable vitrified shale is commercially available under the trade name “PRESSUR-SEAL® FINE LCM” from TXI Energy Services, Inc., of Houston, Tex. In certain embodiments of the present invention, the vitrified shale is present in the treatment fluids of the present invention in an amount in the range of from about 0.01% to about 90% by weight of the treatment fluid. In other embodiments of the present invention, the vitrified shale is present in the treatment fluids of the present invention in an amount in the range of from about 1% to about 20% by weight of the treatment fluid. In other embodiments of the present invention, the vitrified shale is present in the treatment fluids of the present invention in an amount in the range of from about 1% to about 10% by weight of the treatment fluid. One skilled in the art, with the benefit of this disclosure, will recognize a suitable amount of vitrified shale for a particular application. - The base fluid utilized in the treatment fluids of the present invention may comprise an aqueous-based fluid, an oil-based fluid, a synthetic fluid, or an emulsion. In certain embodiments of the present invention, the base fluid may be an aqueous-based fluid that comprises fresh water, salt water, brine, sea water, or a mixture thereof. In certain embodiments of the present invention, the base fluid may be an aqueous-based fluid that may comprise cesium and/or potassium formate. The base fluid can be from any source provided that it does not contain compounds that may adversely affect other components in the treatment fluid. The base fluid may be from a natural or synthetic source. In certain embodiments of the present invention, the base fluid may comprise a synthetic fluid such as, but not limited to, esters, ethers, and olefins. Generally, the base fluid will be present in the treatment fluids of the present invention in an amount sufficient to form a pumpable slurry. In certain embodiments, the base fluid will be present in the treatment fluids of the present invention in an amount in the range of from about 15% to about 95% by weight of the treatment fluid. In other embodiments, the base fluid will be present in the treatment fluids of the present invention in an amount in the range of from about 25% to about 85% by weight of the treatment fluid. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of base fluid to use for a chosen application.
- Optionally, the treatment fluids of the present invention further may comprise a viscosifying agent. The viscosifying agent may be any component suitable for providing a desired degree of solids suspension. The choice of a viscosifying agent depends upon factors such as the desired viscosity and the desired chemical compatibility with other fluids (e.g., drilling fluids, cement compositions, and the like). In certain embodiments of the present invention, the viscosifying agent may be easily flocculated and filtered out of the treatment fluids of the present invention. Suitable viscosifying agents may include, but are not limited to, colloidal agents (e.g., clays, polymers, guar gum), emulsion forming agents, diatomaceous earth, starches, biopolymers, synthetic polymers, or mixtures thereof. Suitable viscosifying agents often are hydratable polymers that have one or more functional groups. These functional groups include, but are not limited to, hydroxyl groups, carboxyl groups, carboxylic acids, derivatives of carboxylic acids, sulfate groups, sulfonate groups, phosphate groups, phosphonate groups, and amino groups. In certain embodiments of the present invention, viscosifying agents may be used that comprise hydroxyl groups and/or amino groups. In certain embodiments of the present invention, the viscosifying agents may be biopolymers, and derivatives thereof, that have one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Examples of suitable biopolymers include, but are not limited to, guar gum and derivatives thereof, such as hydroxypropyl guar and carboxymethyl hydroxypropyl guar, and cellulose derivatives, such as hydroxyethyl cellulose, welan gums, and xanthan gums. Additionally, synthetic polymers that contain the above-mentioned functional groups may be used. Examples of such synthetic polymers include, but are not limited to, poly(acrylate), poly(methacrylate), poly(ethylene imine), poly(acrylamide), poly(vinyl alcohol), and poly(vinylpyrrolidone). Other suitable viscosifying agents include chitosans, starches and gelatins. Suitable clays include kaolinites, montmorillonite, bentonite, hydrous micas, attapulgite, sepiolite, and the like, as well as synthetic clays, such as laponite. An example of a suitable viscosifying agent is a hydroxyethyl cellulose that is commercially available under the trade name “WG-17” from Halliburton Energy Services, Inc., of Duncan, Okla. Another example of a suitable viscosifying agent is a welan gum that is commercially available under the trade name “BIOZAN” from Kelco Oilfield Services, Inc. Where included, the viscosifying agent may be present in the treatment fluids of the present invention in an amount sufficient to provide a desired degree of solids suspension. In certain embodiments, the viscosifying agent may be present in an amount in the range from about 0.01% to about 35% by weight of the treatment fluid. In other embodiments, the viscosifying agent may be present in an amount in the range from about 0.5% to about 2% by weight of the treatment fluid. In certain embodiments of the present invention wherein the treatment fluids will be exposed to elevated pH conditions (e.g., when the treatment fluids will be contacted with cement compositions), viscosifying agents such as welan gum, cellulose (and cellulose derivatives), and xanthan gum may be particularly suitable. One of ordinary skill in the art, with the benefit of this disclosure, will be able to identify a suitable viscosifying agent, as well as the appropriate amount to include, for a particular application.
- Optionally, the treatment fluids of the present invention further may comprise a fluid loss control additive. Any fluid loss control additive suitable for use in a subterranean application may be suitable for use in the compositions and methods of the present invention. In certain embodiments, the fluid loss control additive may comprise organic polymers, starches, or fine silica. An example of a fine silica that may be suitable is commercially available from Halliburton Energy Services, Inc. under the trade name “WAC-9.” An example of a starch that may be suitable is commercially available from Halliburton Energy Services, Inc. under the trade name “DEXTRID.” In certain embodiments where the treatment fluids of the present invention comprise a fluid loss control additive, the fluid loss control additive may be present in the treatment fluids of the present invention in an amount in the range from about 0.01% to about 6% by weight of the treatment fluid. In other embodiments, the fluid loss control additive may be present in the treatment fluids of the present invention in an amount in the range from about 0.05% to about 0.1% by weight of the treatment fluid. One skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of a fluid loss control additive to use for a particular application.
- Optionally, the treatment fluids of the present invention may comprise a dispersant. Suitable examples of dispersants include, but are not limited to, sulfonated styrene maleic anhydride copolymer, sulfonated vinyl toluene maleic anhydride copolymer, sodium naphthalene sulfonate condensed with formaldehyde, sulfonated acetone condensed with formaldehyde, lignosulfonates (e.g., modified sodium lignosulfonate), allyloxybenzene sulfonate, allyl sulfonate and non-ionic monomers, and interpolymers of acrylic acid. An example of a dispersant that may be suitable is commercially available from National Starch & Chemical Company of Newark, N.J. under the trade name “Alcosperse 602 ND,” and is a mixture of 6 parts sulfonated styrene maleic anhydride copolymer to 3.75 parts interpolymer of acrylic acid. Another example of a dispersant that may be suitable is a modified sodium lignosulfonate that is commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., under the trade name “HR®-5.” Where included, the dispersant may be present in an amount in the range from about 0.0001% to about 4% by weight of the treatment fluid. In other embodiments, the dispersant may be present in an amount in the range from about 0.0003% to about 0.1% by weight of the treatment fluid. One skilled in the art, with the benefit of this disclosure, will recognize the appropriate amount of dispersant for inclusion in the treatment fluids of the present invention for a particular application.
- Optionally, the treatment fluids of the present invention may comprise surfactants. Suitable examples of surfactants include, but are not limited to, nonylphenol ethoxylates, alcohol ethoxylates, sugar lipids, α-olefinsulfonates, alkylpolyglycosides, alcohol sulfates, salts of ethoxylated alcohol sulfates, alkyl amidopropyl dimethylamine oxides, and alkene amidopropyl dimethylamine oxides. An example of a surfactant that may be suitable comprises an oxyalkylatedsulfonate, and is commercially available from Halliburton Energy Services, Inc. under the trade name “STABILIZER 434C.” Another surfactant that may be suitable comprises an alkylpolysaccharide, and is commercially available from Seppic, Inc. of Fairfield, N.J. under the trade designation “SIMUSOL-10.” Another surfactant that may be suitable comprises ethoxylated nonylphenols, and is commercially available under the trade name “DUAL SPACER SURFACTANT A” from Halliburton Energy Services, Inc. Where included, the surfactant may be present in an amount in the range from about 0.01% to about 10% by weight of the treatment fluid. In other embodiments of the present invention, the surfactant may be present in an amount in the range from about 0.01% to about 6% by weight of the treatment fluid. One skilled in the art, with the benefit of this disclosure will recognize the appropriate amount of surfactant for a particular application.
- Optionally, the treatment fluids of the present invention may comprise weighting agents. Generally, any weighting agent may be used with the treatment fluids of the present invention. Suitable weighting materials may include barium sulfate, hematite, manganese tetraoxide, ilmenite, calcium carbonate, and the like. An example of a suitable hematite is commercially available under the trade name “Hi-Dense® No. 4” from Halliburton Energy Services, Inc. Where included, the weighting agent may be present in the treatment fluid in an amount sufficient to provide a desired density to the treatment fluid. In certain embodiments, the weighting agent may be present in the treatment fluids of the present invention in the range from about 0.01% to about 85% by weight. In other embodiments, the weighting agent may be present in the treatment fluids of the present invention in the range from about 15% to about 70% by weight. One of ordinary skill in the art, with the benefit of this disclosure, will recognize the appropriate amount of weighting agent to use for a chosen application.
- Optionally, other additives may be added to the treatment fluids of the present invention as deemed appropriate by one skilled in the art with the benefit of this disclosure. Examples of such additives include, inter alia, defoamers, curing agents, salts, corrosion inhibitors, scale inhibitors, and formation conditioning agents. One of ordinary skill in the art with the benefit of this disclosure will recognize the appropriate type of additive for a particular application.
- Certain embodiments of the fluids of the present invention may demonstrate improved “300/3” ratios. As referred to herein, the term “300/3” ratio will be understood to mean the value that results from dividing the shear stress that a fluid demonstrates at 300 rpm by the shear stress that the same fluid demonstrates at 3 rpm. When treatment fluids are used as spacer fluids, an ideal “300/3” ratio would closely approximate 1.0, indicating that the rheology of such fluid is flat. Flat rheology will facilitate, inter alia, maintenance of nearly uniform fluid velocities across a subterranean annulus, and also may result in a near-constant shear stress profile. In certain embodiments, flat rheology may reduce the volume of a spacer fluid that is required to effectively clean a subterranean well bore. Certain embodiments of the fluids of the present invention may demonstrate 300/3 ratios in the range of from about 2.7 to about 4.2. Certain embodiments of the fluids of the present invention may maintain a nearly flat rheology across a wide temperature range.
- The fluids of the present invention may be prepared in a variety of ways. In certain embodiments of the present invention, the well fluids of the present invention may be prepared by first pre-blending the vitrified shale with certain optional dry additives. Next, the blended dry materials may be mixed with base fluid in the field, either by batch mixing or continuous (“on-the-fly”) mixing. In certain embodiments of the present invention wherein the blended dry materials are mixed with base fluid by batch mixing, a weak organic acid and defoamers typically will be premixed into the base fluid. The dry blend then may be added to the base fluid using, e.g., an additive hopper with venturi effects; the mixture of the dry blend and the base fluid also may be agitated, after which the weighting material may be added and agitated. Surfactants may be added to the spacer fluid shortly before it is placed down hole. In certain embodiments of the present invention wherein the blended dry materials are mixed with base fluid by continuous mixing, the blended dry materials typically will be further blended with a weighting material, and the resulting mixture may be metered into, e.g., recirculating cement mixing equipment while the base fluid is metered in separately. The base fluid typically will comprise defoamers pre-blended therein. Shortly before the spacer fluid is placed down hole, surfactants may be added to the spacer fluid.
- An example of a method of the present invention is a method of displacing a fluid in a well bore, comprising: providing a well bore having a first fluid disposed therein; and placing a second fluid into the well bore to at least partially displace the first fluid therefrom, wherein the second fluid comprises vitrified shale and a base fluid.
- Another example of a method of the present invention is a method of separating fluids in a well bore in a subterranean formation, comprising: providing a well bore having a first fluid disposed therein; placing a spacer fluid in the well bore to separate the first fluid from a second fluid, the spacer fluid comprising a vitrified shale and a base fluid; and placing a second fluid in the well bore.
- An example of a composition of the present invention comprises 51.39% water by weight, 3.19% vitrified shale by weight, 43.81% barite by weight, 0.94% sepiolite by weight, 0.034% hydroxyethyl cellulose by weight, 0.08% BIOZAN by weight, 0.006% modified sodium lignosulfonate by weight, and 0.55% citric acid by weight.
- To facilitate a better understanding of the present invention, the following examples of preferred embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention.
- Rheological testing was performed on a variety of sample compositions that were prepared as follows. First, all dry components (e.g., vitrified shale, or zeolite, or fumed silica, plus dry additives such as, for example, hydroxyethylcellulose, BIOZAN, and sodium lignosulfonate were weighed into a glass container having a clean lid, and thoroughly agitated by hand until well blended. Tap water then was weighed into a Waring blender jar, and the blender turned on at 4,000 rpm. While the blender continued to turn, citric acid was added to the mixing water, and then the blended dry components were added, followed by the barite. The blender speed then was increased to 12,000 rpm for about 35 seconds. Afterwards, the blender was stopped, and about 2 drops of a standard, glycol-based defoamer were added.
- Rheological values then were determined using a Fann Model 35 viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100, 200, 300, and 600 RPM with a B1 bob, an R1 rotor, and a 1.0 spring.
- In the Sample Compositions described below, all concentrations are in weight percent.
- Sample Composition No. 1 comprised a 10 pound per gallon slurry of 75.6% water, 4.83% zeolite, 1.63% sepiolite, 0.04% hydroxyethylcellulose, 0.11% BIOZAN, 0.71% sulfonated styrene copolymer, 0.72% citric acid, and 16.36% barite.
- Sample Composition No. 2 comprised a 10 pound per gallon slurry of 75.6% water, 4.83% fumed silica, 1.63% sepiolite, 0.04% hydroxyethylcellulose, 0.11% BIOZAN, 0.71% sulfonated styrene copolymer, 0.72% citric acid, and 16.36% barite.
- Sample Composition No. 3 comprised a 10 pound per gallon slurry of 75.6% water, 5.49% vitrified shale, 1.61% sepiolite, 0.07% hydroxyethylcellulose, 0.14% BIOZAN, 0.01% modified sodium lignosulfonate, 0.72% citric acid, and 16.36% barite.
- Sample Composition No. 4 comprised a 13 pound per gallon slurry of 51.39% water, 2.81% zeolite, 0.95% sepiolite, 0.02% hydroxyethylcellulose, 0.06% BIOZAN, 0.41% sulfonated styrene copolymer, 0.55% citric acid, and 43.81% barite.
- Sample Composition No. 5 comprised a 13 pound per gallon slurry of 51.39% water, 2.81% fumed silica, 0.95% sepiolite, 0.02% hydroxyethylcellulose, 0.06% BIOZAN, 0.41% sulfonated styrene copolymer, 0.55% citric acid, and 43.81% barite.
- Sample Composition No. 6 comprised a 13 pound per gallon slurry of 51.39% water, 3.19% vitrified shale, 0.94% sepiolite, 0.034% hydroxyethylcellulose, 0.08% BIOZAN, 0.006% modified sodium lignosulfonate, 0.55% citric acid, and 43.81% barite.
- Sample Composition No. 7 comprised a 16 pound per gallon slurry of 36.22% water, 1.54% zeolite, 0.52% sepiolite, 0.01% hydroxyethylcellulose, 0.04% BIOZAN, 0.23% sulfonated styrene copolymer, 0.45% citric acid, and 60.98% barite.
- Sample Composition No. 8 comprised a 16 pound per gallon slurry of 36.22% water, 1.54% fumed silica, 0.52% sepiolite, 0.01% hydroxyethylcellulose, 0.04% BIOZAN, 0.23% sulfonated styrene copolymer, 0.45% citric acid, and 60.98% barite.
- Sample Composition No. 9 comprised a 16 pound per gallon slurry of 36.22% water, 1.76% vitrified shale, 0.52% sepiolite, 0.023% hydroxyethylcellulose, 0.044% BIOZAN, 0.003% modified sodium lignosulfonate, 0.45% citric acid, and 60.98% barite.
- The results of the testing are set forth in the tables below. The abbreviation “PV” stands for plastic viscosity , while the abbreviation “YP” refers to yield point.
TABLE 2 Sample Viscometer RPM Composition Temp. 600 300 200 100 60 30 6 3 PV YP 1 80 F. 43 30 25 19 15 12 7 6 19.5 11.9 1 135 F. 35 26 21 16 13 11 7 5 16.4 10.5 1 190 F. 31 23 20 16 14 12 9 8 12 12.2 2 80 F. 40 27 23 19 16 14 9 7 14.1 14.2 2 135 F. 32 24 21 18 15 12.5 9 8 12.1 13.4 2 190 F. 29 21 18 15 13 12 9 7.5 9.9 11.9 3 80 F. 49 35 29 21 17 13 8 7 18.0 15.0 3 135 F. 49 36 30 23 19 16 10 9 17 18 3 190 F. 39 29 24 18 15 12 8 7 14 14 -
TABLE 3 Sample Viscometer RPM Composition Temp. 600 300 200 100 60 30 6 3 PV YP 4 80 F. 102 72 59 43 35 28 17 15 48.1 26.8 4 135 F. 77 55 46 36 30 25 16 14 32.5 24.9 4 190 F. 55 40 33 25 21 17 11 10 24.9 16.7 5 80 F. 89 63 51 37 30 23 14 12 43.3 22.2 5 135 F. 63 46 38 29 24 19 12 11 29 19 5 190 F. 45 34 27 20 18 15 10 8 20.6 14.1 6 80 F. 84 59 49 37 32 24 16 14 30.0 28.0 6 135 F. 65 46 38 28 23 18 12 10 24 20 6 190 F. 51 37 31 24 20 17 11 10 18 19 -
TABLE 4 Sample Viscometer RPM Composition Temp. 600 300 200 100 60 30 6 3 PV YP 7 80 F. 172 123 101 75 62 50 36 31 79.5 48.5 7 135 F. 127 92 77 58 49 41 28 26 56 40 7 190 F. 105 76 65 51 45 37 27 23 41.9 37.8 8 80 F. 177 127 105 79 65 52 37 34 81.3 51.2 8 135 F. 114 82 69 53 46 39 28 25 47 38.4 8 190 F. 95 69 57 44 37 31 22 20 41.2 30.4 9 80 F. 109 82 69 52 44 36 26 23 38.0 40.0 9 135 F. 92 67 56 44 37 31 23 21 31 34 9 190 F. 75 56 48 39 34 29 22 21 23 32 - The above Example demonstrates, inter alia, that the improved treatment fluids of the present invention comprising vitrified shale and a base fluid may be suitable for use in treating subterranean formations.
- Additional Theological testing was carried out on several fluids having the following compositions.
- Sample Composition No. 10, a well fluid of the present invention, comprised 60.98% fresh water by weight, 1.76% vitrified shale by weight, 36.22% barium sulfate by weight, 0.52% sepiolite by weight, 0.023% hydroxyethyl cellulose by weight, 0.044% BIOZAN by weight, 0.003% modified sodium lignosulfonate by weight, and 0.45% citric acid by weight.
- Sample Composition No. 11 comprised 0.97% bentonite by weight, 27.79% silica flour by weight, 0.2% carboxymethyl hydroxyethyl cellulose by weight, 40.04% barium sulfate by weight, 0.37% by weight of sodium napthalene sulfonate condensed with formaldehyde, and 31.63% fresh water by weight.
- Sample Composition No. 12 comprised 2.03% diatomaceous earth by weight, 1.82% coarse silica by weight, 0.1% attapulgite by weight, 0.63% sepiolite by weight, 0.52% by weight of sodium napthalene sulfonate condensed with formaldehyde, 0.1% propylene glycol by weight, 59.1% barium sulfate by weight, and 35.7% fresh water by weight.
- The compositions were tested to determine their “300/3” ratios. A viscometer using an R-1 rotor, a B-1 bob, and an F-1 spring was used. The dial readings at 300 RPM (511 sec−1 of shear) were divided by dial readings obtained at 3 RPM (5.11 sec−1 of shear). The results of the testing are set forth in the table below.
TABLE 5 Sample Sample Sample Composition Composition Composition Rheology No. 10 No. 11 No. 12 300/3 ratio at 80° F. 4.2 11.0 9.0 300/3 ratio at 135° F. 2.7 7.8 5.8 300/3 ratio at 190° F. 3.0 5.3 5.6 - Therefore, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the invention has been depicted and described by reference to exemplary embodiments of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alternation, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the invention are exemplary only, and are not exhaustive of the scope of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.
Claims (20)
1. A spacer fluid comprising a vitrified shale and a base fluid, wherein the spacer fluid is not settable.
2. The spacer fluid of claim 1 wherein the vitrified shale comprises any partially vitrified silica-rich material.
3. The spacer fluid of claim 1 wherein the vitrified shale is present in the spacer fluid an amount in the range of from about 0.01% to about 90% by weight of the spacer fluid.
4. The spacer fluid of claim 1 wherein the vitrified shale is present in an amount in the range of from about 1% to about 10% by weight of the spacer fluid.
5. The spacer fluid of claim 1 wherein the base fluid comprises at least one base fluid selected from the group consisting of: an aqueous-based fluid, an emulsion, a synthetic fluid, and an oil-based fluid.
6. The spacer fluid of claim 1 wherein the base fluid is present in the spacer fluid in an amount sufficient to form a pumpable slurry.
7. The spacer fluid of claim 1 further comprising a viscosifying agent.
8. The spacer fluid of claim 8 wherein the viscosifying agent comprises at least one viscosifying agent selected from the group consisting of: a colloidal agent, an emulsion forming agent, a diatomaceous earth, a starch, and a mixture thereof.
9. The spacer fluid of claim 9 wherein the viscosifying agent comprises at least one colloidal agent selected from the group consisting of: a clay, a polymer, a guar gum, and a mixture thereof.
10. The spacer fluid of claim 10 wherein the viscosifying agent comprises at least one clay selected from the group consisting of: kaolinite, montmorillonite, bentonite, a hydrous mica, attapulgite, sepiolite, laponite, and a mixture thereof.
11. The spacer fluid of claim 8 wherein the viscosifying agent is present in the spacer fluid in an amount in the range of from about 0.05% to about 10% by weight of the spacer fluid.
12. The spacer fluid of claim 1 wherein the spacer fluid further comprises at least one of the following: a dispersant, a surfactant, a weighting agent, a fluid loss control additive, or a mixture thereof.
13. The spacer fluid of claim 14 wherein the spacer fluid comprises at least one dispersant selected from the group consisting of: a sulfonated styrene maleic anhydride copolymer, a sulfonated vinyltoluene maleic anhydride copolymer, a sodium naphthalene sulfonate condensed with formaldehyde, a sulfonated acetone condensed with formaldehyde, a lignosulfonate, an allyloxybenzene sulfonate, an allyl sulfonate, a non-ionic monomer, an interpolymer of acrylic acid, and a mixture thereof.
14. The spacer fluid of claim 15 wherein the dispersant is present in the spacer fluid in an amount in the range of from about 0.0001% to about 4% by weight of the spacer fluid.
15. The spacer fluid of claim 14 wherein the spacer fluid comprises at least surfactant selected from the group consisting of: a nonylphenol ethoxylate, an alcohol ethoxylate, a sugar lipid, an α-olefinsulfonate, an alkylpolyglycoside, an alcohol sulfate, a salt of ethoxylated alcohol sulfate, an alkyl amidopropyl dimethylamine oxide, an alkene amidopropyl dimethylamine oxide, and a mixture thereof.
16. The spacer fluid of claim 17 wherein the surfactant is present in the spacer fluid in an amount in the range from about 0.01% to about 10% by weight of the spacer fluid.
17. The spacer fluid of claim 14 wherein the spacer fluid comprises at least one weighting agent selected from the group consisting of: barite, hematite, manganese tetraoxide, ilmenite, calcium carbonate, and a mixture thereof.
18. A spacer fluid comprising:
a vitrified shale in an amount in the range of from about 1% to about 10% by weight of the spacer fluid, and
a base fluid,
wherein the spacer fluid is not settable.
19. The spacer fluid of claim 18 wherein the vitrified shale comprises any partially vitrified silica-rich material.
20. The spacer fluid of claim 18 wherein the spacer fluid further comprises at least one of the following: a dispersant, a surfactant, a weighting agent, a fluid loss control additive, or a mixture thereof.
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US12/613,788 US20100044057A1 (en) | 2004-10-20 | 2009-11-06 | Treatment Fluids Comprising Pumicite and Methods of Using Such Fluids in Subterranean Formations |
US12/836,309 US20110172130A1 (en) | 2004-10-20 | 2010-07-14 | Treatment Fluids Comprising Vitrified Shale and Methods of Using Such Fluids in Subterranean Formations |
US13/494,558 US20120252705A1 (en) | 2004-10-20 | 2012-06-12 | Treatment Fluids Comprising Vitrified Shale and Methods of Using Such Fluids in Subterranean Formations |
US13/596,905 US20120322698A1 (en) | 2004-10-20 | 2012-08-28 | Treatment fluids comprising pumicite and methods of using such fluids in subterranean formations |
US13/630,507 US9512345B2 (en) | 2004-10-20 | 2012-09-28 | Settable spacer fluids comprising pumicite and methods of using such fluids in subterranean formations |
US15/251,874 US20160369152A1 (en) | 2004-10-20 | 2016-08-30 | Settable spacer fluids comprising pumicite and methods of using such fluids in subterranean formations |
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US20110172130A1 (en) * | 2004-10-20 | 2011-07-14 | Girish Dinkar Sarap | Treatment Fluids Comprising Vitrified Shale and Methods of Using Such Fluids in Subterranean Formations |
US20120252705A1 (en) * | 2004-10-20 | 2012-10-04 | Halliburton Energy Services, Inc. | Treatment Fluids Comprising Vitrified Shale and Methods of Using Such Fluids in Subterranean Formations |
US20110053812A1 (en) * | 2009-08-31 | 2011-03-03 | Ezell Ryan G | Polymeric Additives for Enhancement of Treatment Fluids Comprising Viscoelastic Surfactants and Methods of Use |
US20110048718A1 (en) * | 2009-08-31 | 2011-03-03 | Van Zanten Ryan | Treatment Fluids Comprising Entangled Equilibrium Polymer Networks |
US8813845B2 (en) | 2009-08-31 | 2014-08-26 | Halliburton Energy Services, Inc. | Polymeric additives for enhancement of treatment fluids comprising viscoelastic surfactants and methods of use |
US8881820B2 (en) | 2009-08-31 | 2014-11-11 | Halliburton Energy Services, Inc. | Treatment fluids comprising entangled equilibrium polymer networks |
US20110160103A1 (en) * | 2009-12-30 | 2011-06-30 | Halliburton Energy Services, Inc | Compressible Packer Fluids and Methods of Making and Using Same |
US8207096B2 (en) | 2009-12-30 | 2012-06-26 | Halliburton Energy Services Inc. | Compressible packer fluids and methods of making and using same |
US8148303B2 (en) | 2010-06-30 | 2012-04-03 | Halliburton Energy Services Inc. | Surfactant additives used to retain producibility while drilling |
US8592350B2 (en) | 2010-06-30 | 2013-11-26 | Halliburton Energy Services, Inc. | Surfactant additives used to retain producibility while drilling |
US8418761B2 (en) | 2010-07-29 | 2013-04-16 | Halliburton Energy Services, Inc. | Stimuli-responsive high viscosity pill |
US8453741B2 (en) | 2010-09-23 | 2013-06-04 | Halliburton Energy Services, Inc. | Tethered polymers used to enhance the stability of microemulsion fluids |
Also Published As
Publication number | Publication date |
---|---|
CA2584272A1 (en) | 2006-04-27 |
EP1814958B1 (en) | 2015-05-27 |
US20060081372A1 (en) | 2006-04-20 |
US7293609B2 (en) | 2007-11-13 |
EP1814958A1 (en) | 2007-08-08 |
CA2584272C (en) | 2010-03-30 |
MX2007004826A (en) | 2008-01-24 |
WO2006043022A1 (en) | 2006-04-27 |
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