CA2614272C - Water swellable polymers as lost circulation control agents - Google Patents
Water swellable polymers as lost circulation control agents Download PDFInfo
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- CA2614272C CA2614272C CA2614272A CA2614272A CA2614272C CA 2614272 C CA2614272 C CA 2614272C CA 2614272 A CA2614272 A CA 2614272A CA 2614272 A CA2614272 A CA 2614272A CA 2614272 C CA2614272 C CA 2614272C
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- Canada
- Prior art keywords
- wellbore
- polymer
- inverse emulsion
- emulsion polymer
- water
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- Expired - Fee Related
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- 229920000642 polymer Polymers 0.000 title claims description 150
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims description 92
- 239000003795 chemical substances by application Substances 0.000 title description 17
- 239000004908 Emulsion polymer Substances 0.000 claims abstract description 91
- 239000000203 mixture Substances 0.000 claims abstract description 91
- 239000012530 fluid Substances 0.000 claims abstract description 65
- 239000000565 sealant Substances 0.000 claims abstract description 56
- 238000000034 method Methods 0.000 claims abstract description 27
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 24
- 239000003921 oil Substances 0.000 claims description 45
- 125000006850 spacer group Chemical group 0.000 claims description 36
- 239000000463 material Substances 0.000 claims description 33
- 238000005553 drilling Methods 0.000 claims description 30
- 239000002245 particle Substances 0.000 claims description 11
- 239000002480 mineral oil Substances 0.000 claims description 5
- 235000010446 mineral oil Nutrition 0.000 claims description 5
- 229920002545 silicone oil Polymers 0.000 claims description 3
- 229920001059 synthetic polymer Polymers 0.000 claims description 3
- 229920005615 natural polymer Polymers 0.000 claims description 2
- 239000003208 petroleum Substances 0.000 claims description 2
- 239000007787 solid Substances 0.000 description 61
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 36
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 34
- 239000003995 emulsifying agent Substances 0.000 description 23
- 229910000029 sodium carbonate Inorganic materials 0.000 description 19
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 18
- 235000017550 sodium carbonate Nutrition 0.000 description 18
- 239000011780 sodium chloride Substances 0.000 description 17
- 239000004927 clay Substances 0.000 description 16
- 150000003839 salts Chemical class 0.000 description 16
- 239000000654 additive Substances 0.000 description 15
- 238000005755 formation reaction Methods 0.000 description 14
- 229920001732 Lignosulfonate Polymers 0.000 description 13
- 230000000996 additive effect Effects 0.000 description 13
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 13
- 239000010428 baryte Substances 0.000 description 13
- 229910052601 baryte Inorganic materials 0.000 description 13
- 239000004568 cement Substances 0.000 description 11
- 239000000243 solution Substances 0.000 description 11
- 239000000428 dust Substances 0.000 description 10
- 238000001914 filtration Methods 0.000 description 9
- 239000013505 freshwater Substances 0.000 description 9
- 239000007788 liquid Substances 0.000 description 9
- 239000002002 slurry Substances 0.000 description 9
- 238000012360 testing method Methods 0.000 description 9
- 230000000607 poisoning effect Effects 0.000 description 8
- 238000009472 formulation Methods 0.000 description 7
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 6
- 235000008733 Citrus aurantifolia Nutrition 0.000 description 6
- 235000011941 Tilia x europaea Nutrition 0.000 description 6
- 239000011575 calcium Substances 0.000 description 6
- 229910052791 calcium Inorganic materials 0.000 description 6
- 239000000839 emulsion Substances 0.000 description 6
- 238000001125 extrusion Methods 0.000 description 6
- 239000004571 lime Substances 0.000 description 6
- 235000011121 sodium hydroxide Nutrition 0.000 description 6
- 239000011800 void material Substances 0.000 description 6
- 238000010521 absorption reaction Methods 0.000 description 5
- 231100000572 poisoning Toxicity 0.000 description 5
- 238000005086 pumping Methods 0.000 description 5
- 239000013535 sea water Substances 0.000 description 5
- -1 alkylbenzene sulfonate Chemical class 0.000 description 4
- 150000001768 cations Chemical class 0.000 description 4
- 229920006037 cross link polymer Polymers 0.000 description 4
- 239000000178 monomer Substances 0.000 description 4
- 229920002401 polyacrylamide Polymers 0.000 description 4
- 229920000058 polyacrylate Polymers 0.000 description 4
- 230000008569 process Effects 0.000 description 4
- 239000003381 stabilizer Substances 0.000 description 4
- 239000000725 suspension Substances 0.000 description 4
- 239000000080 wetting agent Substances 0.000 description 4
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 description 3
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 3
- 229920002472 Starch Polymers 0.000 description 3
- NIXOWILDQLNWCW-UHFFFAOYSA-N acrylic acid group Chemical group C(C=C)(=O)O NIXOWILDQLNWCW-UHFFFAOYSA-N 0.000 description 3
- 150000001336 alkenes Chemical class 0.000 description 3
- 239000002199 base oil Substances 0.000 description 3
- 239000001110 calcium chloride Substances 0.000 description 3
- 229910001628 calcium chloride Inorganic materials 0.000 description 3
- 235000011148 calcium chloride Nutrition 0.000 description 3
- 239000003638 chemical reducing agent Substances 0.000 description 3
- 235000014113 dietary fatty acids Nutrition 0.000 description 3
- 239000012895 dilution Substances 0.000 description 3
- 238000010790 dilution Methods 0.000 description 3
- 238000002474 experimental method Methods 0.000 description 3
- 239000000194 fatty acid Substances 0.000 description 3
- 229930195729 fatty acid Natural products 0.000 description 3
- 150000004665 fatty acids Chemical class 0.000 description 3
- JEGUKCSWCFPDGT-UHFFFAOYSA-N h2o hydrate Chemical compound O.O JEGUKCSWCFPDGT-UHFFFAOYSA-N 0.000 description 3
- JRZJOMJEPLMPRA-UHFFFAOYSA-N olefin Natural products CCCCCCCC=C JRZJOMJEPLMPRA-UHFFFAOYSA-N 0.000 description 3
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 3
- 239000008107 starch Substances 0.000 description 3
- 235000019698 starch Nutrition 0.000 description 3
- 239000000126 substance Substances 0.000 description 3
- 239000000375 suspending agent Substances 0.000 description 3
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 description 2
- NIXOWILDQLNWCW-UHFFFAOYSA-M Acrylate Chemical compound [O-]C(=O)C=C NIXOWILDQLNWCW-UHFFFAOYSA-M 0.000 description 2
- CPELXLSAUQHCOX-UHFFFAOYSA-M Bromide Chemical compound [Br-] CPELXLSAUQHCOX-UHFFFAOYSA-M 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 description 2
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 2
- BDAGIHXWWSANSR-UHFFFAOYSA-M Formate Chemical compound [O-]C=O BDAGIHXWWSANSR-UHFFFAOYSA-M 0.000 description 2
- FYYHWMGAXLPEAU-UHFFFAOYSA-N Magnesium Chemical compound [Mg] FYYHWMGAXLPEAU-UHFFFAOYSA-N 0.000 description 2
- UIIMBOGNXHQVGW-UHFFFAOYSA-M Sodium bicarbonate Chemical compound [Na+].OC([O-])=O UIIMBOGNXHQVGW-UHFFFAOYSA-M 0.000 description 2
- 229940048053 acrylate Drugs 0.000 description 2
- 230000004888 barrier function Effects 0.000 description 2
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 description 2
- 239000012267 brine Substances 0.000 description 2
- 125000004181 carboxyalkyl group Chemical class 0.000 description 2
- 229920001577 copolymer Polymers 0.000 description 2
- 230000007423 decrease Effects 0.000 description 2
- 239000008367 deionised water Substances 0.000 description 2
- 229910021641 deionized water Inorganic materials 0.000 description 2
- 239000006185 dispersion Substances 0.000 description 2
- 239000012153 distilled water Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 150000002148 esters Chemical class 0.000 description 2
- 238000009533 lab test Methods 0.000 description 2
- 239000003077 lignite Substances 0.000 description 2
- 239000011777 magnesium Substances 0.000 description 2
- 229910052749 magnesium Inorganic materials 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- OGJPXUAPXNRGGI-UHFFFAOYSA-N norfloxacin Chemical compound C1=C2N(CC)C=C(C(O)=O)C(=O)C2=CC(F)=C1N1CCNCC1 OGJPXUAPXNRGGI-UHFFFAOYSA-N 0.000 description 2
- 239000000344 soap Substances 0.000 description 2
- JHJLBTNAGRQEKS-UHFFFAOYSA-M sodium bromide Chemical compound [Na+].[Br-] JHJLBTNAGRQEKS-UHFFFAOYSA-M 0.000 description 2
- 230000008961 swelling Effects 0.000 description 2
- VNDYJBBGRKZCSX-UHFFFAOYSA-L zinc bromide Chemical compound Br[Zn]Br VNDYJBBGRKZCSX-UHFFFAOYSA-L 0.000 description 2
- 239000004711 α-olefin Substances 0.000 description 2
- PQUXFUBNSYCQAL-UHFFFAOYSA-N 1-(2,3-difluorophenyl)ethanone Chemical compound CC(=O)C1=CC=CC(F)=C1F PQUXFUBNSYCQAL-UHFFFAOYSA-N 0.000 description 1
- SMZOUWXMTYCWNB-UHFFFAOYSA-N 2-(2-methoxy-5-methylphenyl)ethanamine Chemical compound COC1=CC=C(C)C=C1CCN SMZOUWXMTYCWNB-UHFFFAOYSA-N 0.000 description 1
- XHZPRMZZQOIPDS-UHFFFAOYSA-N 2-Methyl-2-[(1-oxo-2-propenyl)amino]-1-propanesulfonic acid Chemical compound OS(=O)(=O)CC(C)(C)NC(=O)C=C XHZPRMZZQOIPDS-UHFFFAOYSA-N 0.000 description 1
- NLHHRLWOUZZQLW-UHFFFAOYSA-N Acrylonitrile Chemical compound C=CC#N NLHHRLWOUZZQLW-UHFFFAOYSA-N 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 229920002134 Carboxymethyl cellulose Polymers 0.000 description 1
- 229910000604 Ferrochrome Inorganic materials 0.000 description 1
- 229920000881 Modified starch Polymers 0.000 description 1
- 239000004368 Modified starch Substances 0.000 description 1
- 239000004280 Sodium formate Substances 0.000 description 1
- 229920002125 Sokalan® Polymers 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 230000002745 absorbent Effects 0.000 description 1
- 239000002250 absorbent Substances 0.000 description 1
- 239000000440 bentonite Substances 0.000 description 1
- 229910000278 bentonite Inorganic materials 0.000 description 1
- 239000002981 blocking agent Substances 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- ATZQZZAXOPPAAQ-UHFFFAOYSA-M caesium formate Chemical compound [Cs+].[O-]C=O ATZQZZAXOPPAAQ-UHFFFAOYSA-M 0.000 description 1
- 229910001622 calcium bromide Inorganic materials 0.000 description 1
- WGEFECGEFUFIQW-UHFFFAOYSA-L calcium dibromide Chemical compound [Ca+2].[Br-].[Br-] WGEFECGEFUFIQW-UHFFFAOYSA-L 0.000 description 1
- 125000005587 carbonate group Chemical group 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-N carbonic acid Chemical compound OC(O)=O BVKZGUZCCUSVTD-UHFFFAOYSA-N 0.000 description 1
- 239000001768 carboxy methyl cellulose Substances 0.000 description 1
- 235000010948 carboxy methyl cellulose Nutrition 0.000 description 1
- 125000002057 carboxymethyl group Chemical class [H]OC(=O)C([H])([H])[*] 0.000 description 1
- 239000008112 carboxymethyl-cellulose Substances 0.000 description 1
- 239000001913 cellulose Substances 0.000 description 1
- 229920002678 cellulose Polymers 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 238000004132 cross linking Methods 0.000 description 1
- 230000018044 dehydration Effects 0.000 description 1
- 238000006297 dehydration reaction Methods 0.000 description 1
- 239000002283 diesel fuel Substances 0.000 description 1
- 150000005690 diesters Chemical class 0.000 description 1
- 239000000835 fiber Substances 0.000 description 1
- 235000013312 flour Nutrition 0.000 description 1
- 239000007789 gas Substances 0.000 description 1
- 239000003349 gelling agent Substances 0.000 description 1
- 239000010439 graphite Substances 0.000 description 1
- 229910002804 graphite Inorganic materials 0.000 description 1
- 238000003898 horticulture Methods 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
- 150000002500 ions Chemical class 0.000 description 1
- 239000003350 kerosene Substances 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 235000019426 modified starch Nutrition 0.000 description 1
- 238000001139 pH measurement Methods 0.000 description 1
- 239000012188 paraffin wax Substances 0.000 description 1
- 239000011236 particulate material Substances 0.000 description 1
- 230000037361 pathway Effects 0.000 description 1
- 239000008188 pellet Substances 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 150000003014 phosphoric acid esters Chemical class 0.000 description 1
- 239000004584 polyacrylic acid Substances 0.000 description 1
- 229920002239 polyacrylonitrile Polymers 0.000 description 1
- 229920001282 polysaccharide Polymers 0.000 description 1
- 239000005017 polysaccharide Substances 0.000 description 1
- WFIZEGIEIOHZCP-UHFFFAOYSA-M potassium formate Chemical compound [K+].[O-]C=O WFIZEGIEIOHZCP-UHFFFAOYSA-M 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 239000000377 silicon dioxide Substances 0.000 description 1
- 239000011734 sodium Substances 0.000 description 1
- 229940047670 sodium acrylate Drugs 0.000 description 1
- 235000017557 sodium bicarbonate Nutrition 0.000 description 1
- 229910000030 sodium bicarbonate Inorganic materials 0.000 description 1
- HLBBKKJFGFRGMU-UHFFFAOYSA-M sodium formate Chemical compound [Na+].[O-]C=O HLBBKKJFGFRGMU-UHFFFAOYSA-M 0.000 description 1
- 235000019254 sodium formate Nutrition 0.000 description 1
- 239000006104 solid solution Substances 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 238000010998 test method Methods 0.000 description 1
- 238000012549 training Methods 0.000 description 1
- 239000007762 w/o emulsion Substances 0.000 description 1
- 239000003643 water by type Substances 0.000 description 1
- 229920001285 xanthan gum Polymers 0.000 description 1
- 239000010457 zeolite Substances 0.000 description 1
- 229940102001 zinc bromide Drugs 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
- C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
- C09K8/44—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing organic binders only
-
- 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
- C09K8/02—Well-drilling compositions
- C09K8/04—Aqueous well-drilling compositions
- C09K8/14—Clay-containing compositions
- C09K8/18—Clay-containing compositions characterised by the organic compounds
- C09K8/20—Natural organic compounds or derivatives thereof, e.g. polysaccharides or lignin derivatives
-
- 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
- C09K8/02—Well-drilling compositions
- C09K8/04—Aqueous well-drilling compositions
- C09K8/14—Clay-containing compositions
- C09K8/18—Clay-containing compositions characterised by the organic compounds
- C09K8/22—Synthetic organic compounds
- C09K8/24—Polymers
-
- 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
- C09K8/02—Well-drilling compositions
- C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
-
- 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
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/502—Oil-based compositions
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
Abstract
A sealant composition comprising an inverse emulsion polymer and methods of servicing a wellbore using the same are disclosed. In one embodiment, a method of servicing a wellbore that penetrates a subterranean formation is disclosed.
The method comprises placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of the fluid in the wellbore.
The method comprises placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of the fluid in the wellbore.
Description
WATER SWELLABLE POLYMERS AS LOST CIRCULATION CONTROL AGENTS
BACKGROUND OF THE INVENTION
Field of the Invention This invention relates to the field of sealant compositions and more specifically to sealant compositions comprising inverse emulsion polymers as well as methods for using such compositions to service a wellbore.
Background of the Invention Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe, e.g., casing, is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore. Next, primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (e.g., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus. Subsequent secondary cementing operations may also be performed.
One example of a secondary cementing operation is squeeze cementing whereby a cement slurry is employed to plug and seal off undesirable flow passages in the cement sheath and/or the casing.
While a cement slurry is one type of sealant composition used in primary and secondary cementing operations, other non-cement containing sealant compositions may also be employed.
For instance, a process known as gunk-squeeze involves placing a gunk plug in a lost circulation zone to reduce fluid loss. Gunk-squeeze involves mixing a clay such as bentonite with a diesel and placing the mixture in the wellbore where the clay contacts water to form a sealant composition. Drawbacks include downhole delivery problems such as mixing the water with the clay in the wellbore. Further drawbacks include the gunk-squeeze process typically being insufficient for vugular losses because the composition has a slow reacting chemistry.
Other processes include using particles to seal lost circulation zones.
Drawbacks to such processes include operating costs (e.g., increased pumping costs). Further drawbacks include insufficient plugging of large lost circulation zones.
BACKGROUND OF THE INVENTION
Field of the Invention This invention relates to the field of sealant compositions and more specifically to sealant compositions comprising inverse emulsion polymers as well as methods for using such compositions to service a wellbore.
Background of the Invention Natural resources such as gas, oil, and water residing in a subterranean formation or zone are usually recovered by drilling a wellbore down to the subterranean formation while circulating a drilling fluid in the wellbore. After terminating the circulation of the drilling fluid, a string of pipe, e.g., casing, is run in the wellbore. The drilling fluid is then usually circulated downward through the interior of the pipe and upward through the annulus, which is located between the exterior of the pipe and the walls of the wellbore. Next, primary cementing is typically performed whereby a cement slurry is placed in the annulus and permitted to set into a hard mass (e.g., sheath) to thereby attach the string of pipe to the walls of the wellbore and seal the annulus. Subsequent secondary cementing operations may also be performed.
One example of a secondary cementing operation is squeeze cementing whereby a cement slurry is employed to plug and seal off undesirable flow passages in the cement sheath and/or the casing.
While a cement slurry is one type of sealant composition used in primary and secondary cementing operations, other non-cement containing sealant compositions may also be employed.
For instance, a process known as gunk-squeeze involves placing a gunk plug in a lost circulation zone to reduce fluid loss. Gunk-squeeze involves mixing a clay such as bentonite with a diesel and placing the mixture in the wellbore where the clay contacts water to form a sealant composition. Drawbacks include downhole delivery problems such as mixing the water with the clay in the wellbore. Further drawbacks include the gunk-squeeze process typically being insufficient for vugular losses because the composition has a slow reacting chemistry.
Other processes include using particles to seal lost circulation zones.
Drawbacks to such processes include operating costs (e.g., increased pumping costs). Further drawbacks include insufficient plugging of large lost circulation zones.
Consequently, there is a need for an improved sealant composition. Further needs include a sealant composition that is sufficient for plugging lost circulation zones and that is easily delivered downhole.
BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS
These and other needs in the art are addressed in one embodiment by a method of servicing a wellbore that penetrates a subterranean formation. The method comprises placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of the fluid in the wellbore.
In another embodiment, these and other needs in the art are addressed by a sealant composition comprising an inverse emulsion polymer. The inverse emulsion polymer comprises particles having a particle size from about 0.01 microns to about 30 microns.
In one embodiment, these and other needs in the art are addressed by a sealant composition comprising an oil dispersed polymer comprising particles having an average particle size from about 0.01 microns to about 30 microns.
The sealant composition comprising an inverse emulsion polymer overcomes problems in the art. For instance, the sealant composition may be easily delivered downhole. In addition, the sealant composition may reduce fluid loss in large permeable zones such as a vugular fracture.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
FIGURE 1 illustrates a FLEXPLUG lost circulation material profile for an extrusion rheometer run;
Trademark FIGURE 2 illustrates an inverse emulsion polymer and NaCl profile for an extrusion rheometer run;
FIGURE 3 illustrates an inverse emulsion polymer and sea water profile for an extrusion rheometer run;
FIGURE 4 illustrates a calculated Bagley coefficient for an inverse emulsion polymer and NaCl mixture; and FIGURE 5 illustrates a calculated Bagley coefficient for an inverse emulsion polymer and NaCl mixture.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
In an embodiment, a sealant composition comprises an inverse emulsion polymer.
The sealant composition is a mixture that can viscosify in wellbore zones where a fluid (e.g., drilling fluid) is being lost. For instance, the sealant composition may viscosify in a lost circulation zone and thereby restore circulation. The viscosified mixture can set into a flexible, resilient and tough material, which may prevent further fluid losses when circulation is resumed. The inverse emulsion polymer may have similar characteristics to a liquid and therefore may be suitable for delivery downhole in a wellbore.
The sealant composition is for use in a wellbore that penetrates a subterranean formation. It is to be understood that "subterranean formation" encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water. The sealant composition can be used for any purpose. For instance, the sealant composition can be used to service the wellbore. Without limitation, servicing the wellbore includes positioning the sealant composition in the wellbore to isolate the subterranean formation from a portion of the wellbore; to support a conduit in the wellbore; to plug a void or crack in the conduit; to plug a void or crack in a cement sheath disposed in an annulus of the wellbore; to plug an opening between the cement sheath and the conduit; to prevent the loss of aqueous or non-aqueous drilling fluids into lost circulation zones such as a void, vugular zone, or fracture; to be used as a fluid in front of cement slurry in cementing operations; to seal an annulus between the wellbore and an expandable pipe or pipe string; and combinations thereof.
The inverse emulsion polymer includes a water-in-oil emulsion with a water swellable polymer dispersed in the emulsion. The emulsion contains a continuous phase of oil and a dispersed phase of water. The oil may be any oil that is immiscible with water and suitable for use in a wellbore. Without limitation, examples of suitable oils include a petroleum oil, a natural oil, a synthetically derived oil, a mineral oil, silicone oil, or combinations thereof In some embodiments, the oil may be an alpha olefin, an internal olefin, an ester, a diester of carbonic acid, a paraffin, a kerosene oil, a diesel oil, a mineral oil, silicone oil, or combinations thereof. The water may be any suitable water for forming the dispersed phase and for use in a wellbore. Without limitation, examples of suitable waters include deionized water, municipal treated water; fresh water; sea water; naturally-occurring brine; a chloride-based, bromide-based, or formate-based brine containing monovalent and/or polyvalent cations;
or combinations thereof. Examples of suitable chloride-based brines include without limitation sodium chloride and calcium chloride. Further without limitation, examples of suitable bromide-based brines include sodium bromide, calcium bromide, and zinc bromide. In addition, examples of formate-based brines include without limitation sodium formate, potassium formate, and cesium formate.
The inverse emulsion polymer may contain any suitable amount of oil and water to form an inverse emulsion suitable for dispersion of the water swellable polymer and for placement in a wellbore. In an embodiment, the inverse emulsion polymer contains from about wt.% to about 80 wt.% oil, alternatively from about 30 wt.% to about 50 wt.%
oil by total weight of the inverse emulsion polymer. In addition, the inverse emulsion polymer contains from about 0 wt. % to about 70 wt. % water, alternatively from about 30 wt. %
to about 70 wt.
% water by total weight of the inverse emulsion polymer.
In some embodiments, the inverse emulsion polymer contains an emulsifier. The emulsifier may be any emulsifier suitable for holding the oil and water in suspension. In an embodiment, the inverse emulsion polymer contains water-soluble and oil-soluble emulsifiers (e.g,, emulsifying agents or surfactants) to stabilize the inverse emulsion polymer. Without limitation, examples of suitable emulsifiers include polyvalent metal soaps, phosphate esters, fatty acids, fatty acid soaps, alkylbenzene sulfonate, or combinations thereof The inverse emulsion polymer may contain any amount of emulsifier suitable for holding the oil and water in suspension. In an embodiment, the inverse emulsion polymer contains from about 1 wt.% to about 10 wt.% emulsifier, alternatively from about 1 wt.% to about 20 wt.%
emulsifier by total weight of the inverse emulsion polymer.
The inverse emulsion polymer may contain any desired amount of the water swellable polymer effective for the intended wellbore service. In an embodiment, the inverse emulsion polymer contains from about 30 wt.% to about 50 wt.% water swellable polymer, alternatively from about 30 wt.% to about 70 wt.% water swellable polymer, and alternatively from about 5 wt.% to about 100 wt.% water swellable polymer by total weight of the inverse emulsion polymer. A water swellable polymer refers to any polymer that is capable of absorbing water and swelling, i.e., increasing in size as it absorbs the water. In an embodiment, upon swelling of the water swellable polymer, the inverse emulsion polymer forms a paste-like mass that is effective for blocking a flow pathway of a fluid. In some embodiments, the paste-like mass has a relatively low permeability to fluids used to service a wellbore such as a drilling fluid, a fracturing fluid, a cement, an acidizing fluid, an injectant, and the like, thus creating a barrier to the flow of such fluids. A paste-like mass refers to a soft, viscous mass of solids (e.g., the swelled water swellable polymer) dispersed in a liquid (the inverse emulsion).
In an alternative embodiment, the inverse emulsion forms a substantially hard, viscous mass when mixed with mud. Without limitation, examples of suitable water swellable polymers include synthetic polymers, superabsorbers, natural polymers, or combinations thereof. Examples of suitable synthetic polymers include crosslinked polyacrylamide, polyacrylate, or combinations thereof.
In an embodiment, the water swellable polymer includes superabsorbers.
Superabsorbers are commonly used in absorbent products such as horticulture products, wipe and spill control agents, wire and cable water-blocking agents, ice shipping packs, diapers, training pants, feminine care products, and a multitude of industrial uses.
Superabsorbers are swellable, crosslinked polymers that have the ability to absorb and store many times their own weight of aqueous liquids. Superabsorbers retain the liquid that they absorb and typically do not release the absorbed liquid, even under pressure. Examples of superabsorbers include sodium acrylate-based polymers having three dimensional, network-like molecular structures.
Without being limited by theory, the polymer chains are formed by the reaction/joining of hundreds of thousands to millions of identical units of acrylic acid monomers, which have been substantially neutralized with sodium hydroxide (caustic soda). Further, without being limited by theory, the crosslinking chemicals tie the chains together to form a three-dimensional network, which enable the superabsorbers to absorb water or water-based solutions into the spaces in the molecular network and thus form a gel that locks up the liquid.
Additional examples of suitable superabsorbers include but are not limited to crosslinked polyacrylamide;
crosslinked polyacrylate; crosslinked hydrolyzed polyacrylonitrile; salts of carboxyalkyl starch, for example, salts of carboxymethyl starch; salts of carboxyalkyl cellulose, for example, salts of carboxymethyl cellulose; salts of any crosslinked carboxyalkyl polysaccharide;
crosslinked copolymers of acrylamide and acrylate monomers; starch grafted with acrylonitrile and acrylate monomers; crosslinked polymers of two or more of allylsulfonate, 2-acrylamido-2-methyl-l-propanesulfonic acid, 'I-allyloxy-2-hydroxy-l-propane-sulfonic acid, acrylamide, and acrylic acid monomers; or combinations thereof. In an embodiment, the water swellable polymer comprises a crosslinked polyacrylamide and/or polyacrylate. In one embodiment, the superabsorber absorbs not only many times its weight of water but also increases in volume upon absorption of water many times the volume of the dry material. In an embodiment, the superabsorber increases from about 10 to about 800 times its original weight.
In an embodiment, the water swellable polymer has a particle size (i.e., diameter) from about 0.01 microns to about 30 microns, alternatively from about 1 micron to about 3 microns, before it absorbs water (i.e., in its solid form). The swell time of the water sweUable polymer may be in a range from about 5 seconds to about 5 hours, alternatively from about 1 second to about 48 hours.
Without being limited by theory, the micron size of the water swellable polymer allows the inverse emulsion polymer to behave as a liquid (e.g, has similar flow characteristics to a liquid) that is sufficient for delivery downhole in a wellbore. Further, without being limited by theory, the micron size also allows a dehydrated form of the inverse emulsion polymer (e.g., the oil dispersed polymer) to behave as a liquid. The inverse emulsion polymer has a density from about 1.1 g/ml to about 1.7 g/ml, alternatively from about 1.0 g/ml to about 2.5 g/ml. In addition, the inverse emulsion polymer has an absorption capacity from about 10 to about 100 times of its own weight, alternatively from about 1 to about 1,000 times of its own weight.
A suitable commercial example of the inverse emulsion polymer is AE 200 polymer, which is available from Hychem, Inc. AE 200 polymer contains about 30 wt %
water swellable polymers, about 30 wt % mineral oil, about 30 wt. % water, and about 10 wt. %
emulsifier. The water swellable polymer is comprised of about 30 wt. %
polyacrylic acid and about 70 wt.% polyacrylanmide cross linked polymers. The particle size of the water sweUable polymer is about I to about 3 microns. The inverse emulsion polymer may have a pH of from about 5.0 to about 8.0, preferably from about 6.0 to about 7.5. The inverse emulsion polymer may have a density of from about 1.0 g/ml to about 2.5 g/ml, preferably from about 1.1 g/ml to about 1.7 g/ml.
In an embodiment, a dehydrated inverse emulsion polymer is placed in the wellbore.
The inverse emulsion polymer is suitably dehydrated to remove at least a portion of the water x Trademark and provide an oil dispersed polymer. In an embodiment, the inverse emulsion polymer is dehydrated to form an oil dispersed polymer comprising from about 0 wt.% to about 10 wt.%
water, alternatively from about 0 wt.% to about 5 wt.% water, and alternatively from about 3 wt.% to about 5 wt.% water. Without being limited by theory, the inverse emulsion polymer is dehydrated because dehydration provides a higher percentage of the water swellable polymer in the polymer. Further, without being limited by theory, the inverse emulsion polymer is dehydrated to reduce the possibility of substantially changing the original oil-based drilling fluid properties. The inverse emulsion polymer may be dehydrated to provide the oil dispersed polymer by any suitable method. In an embodiment, the oil dispersed polymer comprises from about 45 wt.% to about 50 wt.% oil, alternatively from about 30 wt.% to about 70 wt. % oil by total weight of the oil dispersed polymer. In addition, the oil dispersed polymer comprises from about 45 wt.% to about 50 wt.% water swellable polymer, alternatively from about 30 to about 70 wt.% water swellable polymer by total weight of the oil dispersed polymer.
The oil dispersed polymer has a density from about 1.2 g/ml to about 1.7 g/ml, alternatively from about 1.0 g/ml to about 2.5 g/ml. In addition, the oil dispersed polymer has an absorption capacity from about 10 to about 200 times of its own weight, alternatively from about 1 to about 1,000 times of its own weight.
Without limitation, a commercial example of a dehydrated inverse emulsion polymer (e.g., oil dispersed polymer) is AD 200 polymer, which is available from Hychem, Inc. AD 200 polymer is a crosslinked polymer that contains about 1-3 wt. % water and about 50 wt. %
active components, which includes water swellable polymers in an amount of about 30 wt. %
polyacrylate and about 70 wt. % polyacrylamide by total weight of the polymer.
polymer has a density of 1.25 g/ml ( 10%). In addition, AD 200 polymer has an absorption capacity (in distilled water) of 20 g distilled water/l g AD 200 polymer and further has an absorption capacity (in 3 % NaCl solution) of 5 g 3% NaCl solution/l g AD 200 polymer. AD
200 polymer also has a percent of non volatile residues at 150 C for 16 hours at 63% (d 10%).
[00011 In some embodiments, the sealant composition includes additives that may be suitable for improving or changing its properties. Without limitation, examples of suitable additives include particulate materials, viscosifying agents, weighting materials, or combinations thereof.
The weighting materials may be used to increase the density of the sealant composition. In one embodiment, a sufficient amount of weighting material is mixed with the sealant composition to increase the density of the composition at which it passes down through the welibore.
Without being limited by theory, the increased density may increase the rate at which the sealant composition passes down through the fluid in the wellbore. Further, without being limited by theory, the density is increased to reduce the possibility of a wellbore blow out Without limitation, examples of suitable weighting materials include barite, silica flour, zeolites, lead pellets, sand, fibers, polymeric material, or combinations thereof. The density may increase to any desired density. In one embodiment, the density is increased to a density from about 10 ppg to about 20 ppg.
In one embodiment, the inverse emulsion polymer is introduced to the wellbore to prevent the loss of aqueous or non-aqueous drilling fluids into lost circulation zones such as voids, vugular zones, and natural or induced fractures while drilling. During the wellbore treatment, various components may be pumped sequentially down the workstring and/or simultaneous down the annulus as appropriate for a given treatment. In an embodiment, the inverse emulsion polymer is pumped in the wellbore to service the wellbore.
Before the inverse emulsion polymer is pumped into the wellbore, a spacer fluid may be pumped into the wellbore. In some embodiments, the spacer fluid is suitable for removing water (i.e., from the pipes). For instance, the spacer fluid may contain a wetting agent such as LE
SUPERMUL
emulsifier. LE SUPERMUL emulsifier is commercially available from Halliburton Energy Services, Inc. The inverse emulsion polymer is then pumped into the wellbore.
In some embodiments, weighting material such as barite is added to the inverse emulsion polymer prior to pumping the inverse emulsion polymer into the wellbore. After such pumping, additional spacer fluid may be pumped into the wellbore. The sealant composition is formed and provides a relatively viscous mass inside the lost circulation zone. Drilling fluid may then be pumped into the wellbore under suitable pressure to squeeze the sealant composition into the lost circulation zone. The sealant composition can also form a non-flowing, intact mass inside the lost circulation zone. This mass plugs the zone and inhibits loss of subsequently pumped drilling fluid, which allows for further drilling. In an embodiment wherein the drilling fluid is non-aqueous, a treating composition may be pumped into the wellbore after the inverse emulsion polymer and additional spacer are pumped. In an embodiment, a sufficient amount of the treating composition may be pumped to reduce the amounts of calcium and magnesium in the drilling fluid in contact with the inverse emulsion polymer. In an embodiment, the treating composition comprises soda ash, NaHCO3, a monovalent salt, a divalent salt, or combinations thereof. Without limitation, examples of such salts include Nat, K+, Ca2+ and Mae}. Without ~~ Trademark being limited by theory, the calcium and magnesium are reduced to prevent salt poisoning in the inverse emulsion polymer or oil dispersed polymer, which may prevent the formation of the desired solid paste to plug the void in the formation. In such an embodiment, a spacer fluid may then be pumped into the wellbore followed by the drilling fluid. It is to be understood that non-aqueous drilling fluids may include a diesel, a mineral oil, an internal olefin, a linear alpha-olefin, an ester, or combinations thereof. In alternative embodiments, no spacer fluid is pumped into the wellbore before and/or after the inverse emulsion polymer is pumped into the wellbore. In some embodiments, the inverse emulsion polymer is dehydrated to form the oil dispersed polymer, and the sealant composition is formed therefrom.
In one embodiment, the sealant composition is placed in the wellbore with a water-based mud. The method for placement includes pumping a treated and active drilling mud into the wellbore. Any suitable amount of the drilling mud may be pumped into the wellbore. For instance, an amount of drilling mud comprising from about 15 to about 20 barrels may be pumped into the wellbore. In an instance in which soluble calcium is present in the mud, the mud may be treated with a treating composition to treat out at least a portion of the calcium. In an embodiment, the mud is treated when the calcium is present in an amount greater than 200 mg/l. Any suitable amount of the treating composition may be used. A spacer (e.g., LE
SUPERMUL emulsifier) is pumped into the wellbore following the mud. Any suitable amount of spacer may be pumped into the wellbore. For instance, an amount of spacer comprising from about 5 barrels to about 10 barrels may be pumped into the wellbore, alternatively from about 6 barrels to about 7 barrels may be pumped into the wellbore. The inverse emulsion polymer is pumped into the wellbore following the spacer. An amount of the inverse emulsion polymer comprising from about 15 to about 20 barrels, alternatively from about 16 to about 17 barrels may be pumped into the wellbore. The inverse emulsion polymer may be weighted with a weighting material. An amount of spacer is then pumped into the wellbore. The amount of spacer may include from about 5 barrels to about 10 barrels, alternatively from about 6 barrels to about 7 barrels is pumped into the wellbore. A suitable amount of the mud is then pumped into the wellbore. In an embodiment, the amount of mud is 20 barrels or less. After the mud is pumped into the wellbore, a light squeeze pressure is maintained for a suitable time for the sealant composition to form the non-flowing, intact mass inside the lost circulation zone.
Any suitable pressure is maintained. For instance, the pressure may be from about 175 to about 225 psi. It is to be understood that in some embodiments an oil dispersed polymer is placed in the wellbore with the water-based mud instead of the inverse emulsion polymer.
In another embodiment, the sealant composition is placed in the wellbore with a non-aqueous mud. The method for placement includes pumping a spacer into the wellbore. Any suitable amount of spacer may be used. For instance, about 1 barrel of spacer may be pumped in the wellbore. The inverse emulsion polymer is pumped into the wellbore following the spacer. An amount of the inverse emulsion polymer comprising from about 10 to about 20 barrels, alternatively from about 16 to about 17 barrels, and alternatively about 11 barrels may be pumped into the wellbore. The inverse emulsion polymer may be weighted with a weighting material. An amount of spacer is pumped into the wellbore following the inverse emulsion polymer. In one embodiment, an amount of the spacer comprising from about I to about 5 barrels, alternatively from 3 to about 5 barrels, and alternatively about 2 barrels is pumped into the wellbore. A treating composition (e.g., soda ash) is pumped into the wellbore following the spacer. For instance, soda ash may be mixed with a spacer, drilling mud, or AD
200 polymer and pumped into the wellbore. Any suitable amount of the treating composition may be pumped to prevent salt poisoning of the inverse emulsion polymer. In some embodiments, from about 30 to about 70 barrels of the treating composition, alternatively from about 35 to about 40 barrels, and alternatively from about 50 to about 70 barrels are pumped into the wellbore. An amount of spacer fluid is pumped into the wellbore following the treating composition. In one embodiment, an amount of the spacer from about 1 to about 5 barrels is pumped into the wellbore, alternatively from about 3 to about 5 barrels, and alternatively about 3.5 barrels. A suitable amount of the mud is pumped into the wellbore following the spacer. In an embodiment, the amount of mud is 20 barrels or less. After the mud is pumped into the wellbore, a light squeeze pressure is maintained for a suitable time for the sealant composition to form the non-flowing, intact mass inside the lost circulation zone. Any suitable pressure is maintained. For instance, the pressure may be from about 175 to about 225 psi.
It is to be understood that in some embodiments an oil dispersed polymer is placed in the wellbore with the nonaqueous mud instead of the inverse emulsion polymer.
In an embodiment, sealant compositions that include an inverse emulsion polymer may be employed in well completion operations such as primary and secondary cementing operations. In one embodiment, a spacer fluid is pumped through the drill pipe. The inverse emulsion polymer is then pumped through the drill pipe and forms the sealant composition. An additional amount of spacer fluid may then be pumped through the drill pipe.
In alternative embodiments, no spacer fluid is pumped into the drill pipe before and/or after the inverse emulsion polymer. In primary cementing, such a sealant composition may be placed into an annulus of the wellbore and allowed to set such that it isolates the subterranean formation from a different portion of the wellbore. The sealant composition thus forms a barrier that prevents fluids in that subterranean formation from migrating into other subterranean formations.
Within the annulus, the sealant composition also serves to support a conduit, e.g., casing, in the wellbore. In one embodiment, the welibore in which the sealant composition is positioned belongs to a multilateral wellbore configuration. It is to be understood that a multilateral wellbore configuration includes at least two principal wellbores connected by one or more ancillary wellbores. In secondary cementing (often referred to as squeeze cementing), the sealant composition may be strategically positioned in the wellbore to plug a void or crack in the conduit, to plug a void or crack in the hardened sealant (e.g., cement sheath) residing in the annulus, to plug a relatively small opening known as a microannulus between the hardened sealant and the conduit, and so forth. In some embodiments, the inverse emulsion polymer is dehydrated to form the oil dispersed polymer, and the sealant composition is formed therefrom.
Various procedures that may be followed to use the sealant composition in a wellbore are described in U.S. Patent Nos. 5,346,012 and 5,588,489.
To further illustrate various illustrative embodiments of the present invention, the following examples are provided.
In this Example 1, Runs were conducted (Runs 1-9) comparing a conventional lost circulation material, FLEXPLUG lost circulation material (Run 1), to an inverse emulsion polymer, AE 200 polymer (Runs 2-9). FLEXPLUG lost circulation material uses particles to prevent fluid loss. and is commercially available from Halliburton Energy Services, Inc.
Different ratios of AE 200 polymer were mixed with deionized water, a 1% NaCl solution, or sea water. An extrusion rheometer was used to test each mixture.
The main components of the extrusion rheometer consisted of a core, which had a slit with an opening of 1 mm, 2 mm or 3 mm in width. The rheometer was 2, 4 or 6 inches long.
# #
For each Run, the rheometer was filled with the material (AE 200 polymer or FLEXPLUG
material) to be tested. A pressure was applied to push the material out of the different sizes of ~` Trademark cores. It was observed that different forces were needed to push different materials out of the same core under the same conditions. Such force was measured in pounds and recorded. The results are listed below in Table I, wherein the samples are identified by length of the rheometer in inches by the width of the rheometer in millimeters (e.g., 2 in L by 1 mm W
=
2INLXlMMW).
Table I.
polymer-.D1 polymer:l% polymer:l% polymer:Sea FLEXPLUG Water NaCl NaCl Water Sample ID Material (1:9) (1:6) 1:3 (1:3) 2INLXIMMW Ave: 209 N/A N/A N/A SD: 2.38 N/A
COV:1.1%
4INLXIMMW Ave: 134.7 Ave: 136.3 Ave: 283 Ave: 248 N/A SD: 5.67 SD: 5.7 SD: 1.15 SD: 1.16 COV: 4.2% COV:4.2% COV: 0.5% COV: 0.5%
6E` LX1NIMW Ave: 517 N/A N/A N/A SD: 6.56 N/A
COV: 1.3%
2INLX2MMW Ave: 46.1 Ave: 41.3 Ave: 90.6 Ave: 82.0 N/A SD: 2.61 SD: 3.27 SD: 1.88 SD: 1.76 COV: 5.7% COV: 7.9% COV:2.1% COV:2.1%
41NLX2MMW Ave: 166.8 N/A N/A N/A SD: 2.15 N/A
COV: 1.3%
6INLX2MNIW Ave: 231 N/A N/A N/A SD: 4.85 N/A
COV: 2.1%
21NLX3MMW Ave:52.6 N/A N/A N/A SD: 3.01 N/A
COV: 5.7%
4INLX3MIMIW Ave:80.9 N/A N/A N/A SD: 1.87 N/A
COV: 2.3%
6INLX3MMW Ave: 526 Ave: 57.2 Ave: 62.1 Ave: 114.4 Ave: 108.8 SD:69 SD: 8.9 SD: 1.19 SD: 8.34 SD:7.82 COV: 13.1% COV: COV: 1.9% COV: 7.3% COV: 7.2%
15.6%
In the Table I, the rheometer readings are listed in pounds. The listed number is an average of the recorded results for each Run. "SD" represents standard deviation, and "COV"
represents the coefficient of variance, and is calculated by SD/XAve.
From Table I, it can be seen that the standard deviation and COV for the AE
inverse emulsion polymer was much better than the FLEXPLUG material. In various embodiments, rheometer readings for the inverse emulsion polymer have a SD of less than 9, 8, 7, 6, 5, 4, 3, or 2 and a COV of less than 8%, 7%, 6%, 5%, 4%, 3%, or 2%.
FIGURE 1 shows the FLEXPLUG material profile for its initial pressure, which is the initial pressure required to push the FLEXPLUG material into the vugular, cavernous formations. From FIGURE 1, it can be seen that the FLEXPLUG3 material exhibits pressure drops. As shown in FIGURES 2 and 3, there were no such pressure drops for the polymer sample. FIGURES 1-3 show position in inches on the x-axis and load in pounds-force on the y-axis.
The extrusion rheometer data from EXAMPLE 1 was used in EXAMPLE 2 to derive Bagley factors for each Run. In order to derive the Bagley factor, the width of the slit remained the same. The different forces were. obtained by changing the lengths of the core under the same conditions as illustrated in FIGURE 4.
The Bagley factor is defined as: Bagley factor = FO I FL2. Fo is defined as the force when X = 0. Fu is defined as the force obtained using the 4 inch core ixthis particular case. In general, the Bagley factor is between 0 and 80%. For FLEXPLUG material, the Bagley coefficient is generally between 25 and 80% and more typically between 35 and 55%. The smaller the Bagley factor, the easier the material is to be replaced by pressure or other materials.
FIGURES 4 and 5 illustrate calculated Bagley factors for different cores of AE
polymer: l% NaCl (1:3). From FIGURES 4 and 5, it can be seen that the Bagley factors are lower than such for FLEXPLUG material. By having such lower Bagley factors, the AE 200 polymer and 1% NaCl mixture may be more easily pushed into the fracture formations than the FLEXPLUG material.
AE 200 polymer was tested with a water based mud (lignosulfonate mud). Table II
shows how the. mud was formulated. AQUAGEL viscosifier is a viscosity and gelling agent that is commercially available from Halliburton Energy Services, Inc. QUIK-THIN thinner is a ferrochrome lignosulfonate that is commercially available from Halliburton Energy Services, Inc. CARBONOX filtration control agent is a lignite material that is commercially available Trademark from Halliburton Energy Services, Inc. REV-DUST additive is a calcium montnlorillonite clay that is commercially available from Milwhite, Inc.
Table II. Lignosulfonate Mud Formulation.
Sample, (lb/gal) 14.0 Fresh water, bbl 0.76 viscosifier, lb/bbl QUEK thinner, 6 lb/bbl NaOH, lb/bbl 3 (pH -11 -11.5) CARBONOX agent, 4 lb/bbl REV DUST dditive, 30.0 lb/bbl Barite, lb/bbl 271.6 After hot roll in a 150 F oven for 16 hrs, different concentrations of AE 200 polymer in the mud were tested with the results shown in Tables M and N. The concentrations were tested by adding 1.0 mL of AE 200 polymer and different amounts of lignosulfonate mud (e.g., as required by the experiment such as 1X, 2X or 50X) to a beaker. The mixture was mixed well. The time needed for the mixture to harden and the conditions of the mixture were recorded.
Table III. Test Results of AE 200 polymer with Lignosulfonate Mud Sample 1:1(v/v) 1:2 1:10 1:20 1:30 1:50 AE 200 Thicken Thicken Thicken Thicken within Slightly Slurry polymer with within 1 within I within 1 1 min. Forms slurry, and Lignosulfonat min. min. min. clay like solids. more water e Mud (with Forms Forms clay Forms Slightly wetter cement y Fresh Water) loose like solids clay like than 1:10 like solids solids # Trademark Table N. Test Results of AE 200 polymer with Lignosulfonate Mud Sample 1:5(v/v) 1:10 1:15 1:20 AE 20 polymer Thicken within Thicken Slurry at first, Slurry at first, with I min Forms within 1 min. then harden after then harden after Lignosulfonate rubbery clay Forms clay 1 hr 1.5 hr Mud (with Sea like solids Water) As can be seen from Tables III and IV, even with the dilution factor of 1:30 (AE 200 polymer: mud), the solid forms from the mixture of the two are still cement-like slurry paste. It can be further seen from such Tables that the dilution factor decreases to 10 instead of 20 when using the sea water version of the lignosulfonate mud. The cations in the sea water (e.g., Na+, K+, Cat+, Mg2+ and etc.) may be affecting the performance of AE 200 polymer by salt poisoning. In this case, the salt poisoning effect was observed to be more serious for Cat than Na+. To treat out the Ca2+ ions, 0.2 lb/bbl of soda ash (Na2CO3) was added to the mud with excellent results. It was observed that the dilution factor increased back to 20, and the texture of the solid was also more like the fresh water mud.
In EXAMPLE 4, the salinity, pH and density effects on the performance of AE
polymer was observed. Different salinity, pH and density muds were formulated as shown in Table V. BARAZAN D#Plus suspension agent/viscosifier is a dispersion enhanced xanthum gum that is commercially available from Halliburton Energy Services, Inc.
FILTER-CHECK
filtration control agent is a modified starch that is commercially available from Halliburton Energy Services, Inc. CLAY SYNC shale stabilizer is a clay inhibitor for water-based mud commercially available from Halliburton Energy Services, Inc. CLAY GRABBER
flocculant is a polymeric additive for water-based drilling fluids commercially available from Halliburton Energy Services, Inc. CLAY SEAL shale stabilizer is a chemical drilling fluid additive commercially available from Halliburton Energy Services, Inc.
# Trademark Table V. Mud Formulations Fresh 10% (w/w) 24% (w/w) NaCI
Water NaCI
Sample, (lb/gal) 13 13 10 13 13(w/o 16 NaOH) Fresh Water, bbl 0.826 _ _ _ 10%(w/w), NaCl, _ 0.845 - _ - -bbl 24%(w/w), NaCl, - - 0.994 0.875 0.875 0.756 bbl NaOH, lb 0.25 0.25 0.25 0.25 - 0.25 BARAZAN D 0.75 0.75 1.0 0.75 0.75 0.25 PLUS suspension agent/ viscosifier, lb FILTER-CHECK 4.0 4.0 4.0 4.0 4.0 4.0 filtration control agent, lb CLAY SYNC 3.25 2.75 2.0 2.0 2.0 2.0 shale stabilizer, lb CLAY 0.50 0.5 0.5 0.5 0.5 0.5 GRABBER
flocculant (active), lb CLAY SEAL 4.0 4.0 4.0 4.0 4.0 4.0 shale stabilizer, lb Barite, lb 256.3 228.3 81.5 183.2 183.2 358.3 All the muds from Table V were hot rolled at 150 F in an oven for 16 hrs. The pH
measurements were taken after the hot roll. The densities of the muds as mixed with the 24%
(w/w) NaCI were measured as shown in Table VI. The mud from Table V (24% (w/w) NaCI
(density =13) was added a different amount of NaOH to adjust the pH of the muds and to determine how much mud was needed to achieve the same results.
Table VI. How Density and PH Affect the Performance of AE 200 Polymer 24% (w/w) NaCI
Density, 10 13 13 13 16 (lb/gal) Mud vol. 10 10 10 10 10 mL
pH 9.05 7.66 9.06 11.0 9.05 polymer mL
Observation It needs the It takes the It takes the There is no It takes only s most AE 200 longest time same amount significant 2 mL of AE
polymer to (1.5 min. vs. of AE 200 difference 200 polymer form polymer - 1 min.) to polymer to when pH to form paste/ solids. harden form changes paste/solids.
The texture of compared solids/paste from 9 to The the paste is with all other when the it. texture/streng also the most mud with the density is the th of the solid loose one same same formed also among all density, but regardless of is the best.
other different pH. the samples. differences in pH.
Density may play an important role on the quality of the solid after mixing mud with AE 200 polymer and may also determine the amount of AE 200 polymer needed to form the solid. As shown in Table VI, under the same conditions, the lower the density, the more AE
200 polymer may be used to form the solid (4 mL of AE 200 polymer for D = 10 vs. 2 mL AE
200 polymer for D = 16, that is 50% decrease in volume.).
It was observed that the solid forms using the mud with density of 16 was noticeably thicker and stronger than the mud with a density of 10. Under the same conditions, by comparing the mud with pH = 7.66 and 11, it was observed that it takes 1.5 min. to form the solid at pH = 7.66 vs. I min. for pH = It, which may be attributed to "salt poisoning" (e.g., cation poisoning effect) on AE 200 polymer. The lower the pH, the more free W
ions that may be in the solution, and the worse the salt poisoning effect AE 200 polymer may have.
However, there was no observed difference when the pH was changed from 9 to 11.
Salinity of the muds from EXAMPLE 4 were tested. It was observed that salinity had a greater effect on the performance of AE 200 polymer than pH. Table VII shows the salinity results.
Table VII. How Salinity Affects the Performance of AE 200 Polymer Freshwater 10% (w/w) NaCl 24% (w/w) NaCl Density, 13 13 13 lb/gal Mud vol. 10 10 10 (mL) H 9.03 9.05 9.06 polymer (mL) Observatio It needs only I mL AE The texture and AE 200 polymer still us 200 polymer to form strength of the solid is works in 24 % NaCl polymer paste/ solid. between freshwater (w/w) mud. It just needs The texture of the paste and 24% (w/w) NaCl. more AE 200 polymer to is also the best among form solid/paste.
all other samples.
The freshwater mud from Table VII performed the best in terms of the amount of AE
200 polymer used, and the quality of the solid forms after mixing. Again, with more cations in the solution, more AE 200 polymer was needed to form the solid. Therefore, the increasing amount of AE 200 polymer used when the salinity increases can be seen in Table VII. In order to find out if the presence of KCl would affect the performance of AE 200 polymer, two experiments were done with the results shown in Table VIII.
Table VIII.
Sample 10% KCI 3% KCI + 24% NaCl AE 200 polymer (3mL) : Salt Forms solid Forms solid Solution (10 mL) The results show that there are no problems forming solid whether it is in 10%
KCI
solution or 24% NaCI with 3% KCl solution, as long as there is enough AE 200 polymer in the mixture (in this case, 3 mL AE 200 polymer).
AD 200 polymer was tested with various muds, and the results are shown in Table IX.
AD 200 polymer is the dehydrated form of AE 200 polymer. The test method here is similar to the test noted above. I mL of AD 200 polymer and 20 mL of mud were mixed in a beaker.
The time it took for the mixture to harden was recorded. The texture of the solid pastes were compared.
Table IX. AD 200 polymer with Various Water Based Muds Sample 1:20(v/v) (AD 20 polymer: Mud) HYDRO-GUARD system Thicken and form polymer solid within I min.
Lignosulfonate Mud Thicken and form polymer solid within I min.
Lignosulfonate Mud with 6 ppb Lime Thicken and form polymer solid within 1 min.
Lignosulfonate Mud with 6 ppb Lime Thicken and form polymer solid within 1 min.
(0.5 g of Na=C03 was added before However, the time required to form a polymer adding AD 200 polymer) solid for this mud is shorter than the one from above. The strength and texture of the polymer solid are also better than the one obtained from above.
GEM GP Mud Thicken and form polymer solid within 1 min.
HYDRO-GUARD system is a mud that is commercially available from Halliburton Energy Services, Inc. and is a water-based mud. GEM GP (general purpose) is a glycol enhanced mud that is commercially available from Halliburton Energy Services, Inc. and is also a water-based mud. It was observed that AD 200 polymer worked very well with different water-based muds. In addition, it was observed that there was no problem forming a solid even with high lime mud. The result is even better when soda ash was added to the high lime mud before adding AD 200 polymer.
In. order to find a safe way to deliver AD 200 polymer down hole, an appropriated spacer for the job was used. Table X summarized the results of such finding.
AD 200 polymer in a mud was tested with an emulsifier (e.g., LE SUPERMUL emulsifier), which was used as the spacer. The results of the tests are shown in Table X.
Trademark Table X. Wetting Agent, Spacer, Mud, AD 200 polymer and their Compatibility and Stability Sample Comments LE SUPERMUL emulsifier Wetting agent (polyaminated fatty acid) SF Base oil Main component of the spacer 2%(v/v) LE SUPERMUL emulsifier Spacers will be used in water mud systems. It in SF Base oil should be used before and after delivering AD
# 200p of er down hole.
Spacer : AD 200 polymer (10 mL:10 No problems on stability or compatibility.
It mL) ti takes 25 mL of water to invert the emulsion.
Lignosulfonate Mud : Spacer : AD 200 No problem forming polymer solids.
polymer 1:1:0.5 GEM G Mud: Spacer : AD 200 No problem forming polymer solids.
polymer (1:1:0.5) SF Base oil is an internal olefin available from Halliburton Energy Services, Inc. It was observed that no problem occurred when AD 200 polymer was weighted up to 19 lb/gal with barite.
AD 200 polymer was tested with ACCOLADE drilling fluid. ACCOLADE fluid is a clay-free synthetic based drilling fluid that is commercially available from Halliburton Energy Services, Inc. The formulation of the mud is listed in Table XI. Table XII
shows results of different mixes of AD 200 polymer with the ACCOLADE fluid. The ACCOLADE fluid was formulated as in Table XI and then hot rolled at 150 IF in an oven for 16 hours. ADAPTA
filtration reducer is a copolymer that provides HPHT filtration control in non-aqueous fluid systems that is commercially available from Halliburton Energy Services, Inc.
BARACARB
bridging agent is carbonate particles commercially available from Halliburton Energy Services, Inc. RHEMOD L viscosifier is commercially available from Halliburton Energy Services, Inc.
Trademark Table M. ACCOLADE Mud Formulation.
Sample, lb/gal) (12.0 lb/gal) 70/30 Oil : Water Water phase salinity 250,000 ppm ACCOLADE fluid base, 0.436 bbl emulsifier, lb/bbl Water, bbl 0.24 Lime, lb/bbl 1 ADAPTA HP filtration 2 reducer, lb/bbl Barite, lb/bbl 188.96 REV-DUST additive, 20.0 Ib/bbl BARACARB 25 agent, 7.5 lb/bbl BARACARB 50 agent, 7.5 lb/bbl CaC12, lb/bbI 29.09 RHEMOD L suspension 1 agent/viscosifier, Ib/bbI
Table XII. Preliminary Lab Test Results of AD 200 polymer with ACCOLADE Mud Sample 0.1 g of Na2CO3 in Different Amount of Water 1.0 g Na2CO3 in mL Water (mL) polymer:Mud 2mL:1mL
Observations Solid Solid Solid Solid No solid form for at forms in forms in forms in forms in 1 least 3 hrs. After less than 1 less than 1 less than 1 min. overnight, a paste min. min. min. forms, but it is not as thick as using 0.1 g of Na2CO3 in mL water.
It was observed that 1 mL of AD 200 polymer mixed with 20 mL of mud and was able to form a solid/paste mixture. It was also observed that a 2:1 (AD 200 polymer : mud) mixing ratio, plus 20 mL of soda ash solution was used to form the solid/paste as shown in Table XII.
When 2 mL of AD 200 polymer was mixed with 1 mL of mud, the concentration of polymer changed from 50% to 33.33% (e.g., 33% active AD 200 polymer reacted with 20 mL
of soda ash solution to form a solid). The amount of Na2CO3 used (0.1 g) was calculated based on the stoichiometric amount of Ca2+ in the solution. 1.0 g of Na2CO3 was used instead of 0.1 g to observe whether excess Na2CO3 affected the performance of AD 200 polymer.
Excess Na2C03 functioned as salt poisoning for AD 200 polymer, therefore the mixture had a harder time forming the solid.
It was observed that the texture of the solids from the oil mud was not as good as the water-based mud. Therefore, additional solid was added as shown in Table XIII.
STEEL
SEAL is a graphite that is commercially available form Halliburton Energy Services, Inc.
Table XIII Preliminary Lab Test Results of AD 200 polymer with ACCOLADE Mud Sampl% 0.1 g of NaZCO3 in 10 mL Water AD 200 3.0 g Barite 3.0 g REV DUST 3.0 g STEEL SEAL
polymer:Mud additive lost circulation 2mL:1mL additive Observations Solid forms in less than . min for Solid forms in less than both cases. REV-DUST additive 1 min. The texture of may be slightly better although no the solid is the best of differences were observed on the the three.
texture of the solid b%ween barite and REV-DUST additive, It was observed that the added solid provided a better final paste both on the texture and the strength Two more oil-based muds were tested with AD 20S polymer (PETROFREE SF fluid and ENVIROMUL fluid). PETROFREE drilling fluid is commercially available from Halliburton Energy Services, Inc. ENVIROMUL drilling fluid is commercially available from Halliburton Energy Services, Inc. Their formulations are shown in Tables XIV
and XV.
GELTONE II viscosifier and GELTONE V viscosifier are gelling and viscosifying agents comprising ground organophillic clay, which are available from Halliburton Energy Services, Inc. Both muds were hot rolled in a 150 F oven for 16 hrs. ESCAID fluid is an oil that is commercially available from Exxon Chemical Company. SUSPENTONE suspension agent is an organophilic clay commercially available from Halliburton Energy Services, Inc. EZ MUL
NT emulsifier is a synthetic-based mud emulsifier commercially available from Halliburton Energy Services, Inc. DURATONE HT (high temperature) oil mud filtration control agent # Trademark comprises an organophillic lignite blend and is commercially available from Halliburton Energy Services, Inc. DEEP-TREAT thinner is a wetting agent commercially available from Halliburton Energy Services, Inc., and COLDTROt, thinner is commercially available from Halliburton Energy Services, Inc. The tests involved adding 20 mL water to a beaker, followed h by Na2CO3. STEELSEAL additive, barite or REV-DUST additive were also added if needed.
2 mL of AD 200 polymer and 1 mL of mud were then added to the beaker. The contents of the beaker were then mixed. The time needed for the mixture to harden was recorded. The results of the tests are shown in Table XVI.
Table XIV. PETROFREE SF Mud Formulation.
Sample, (lb/gal) (12.0 lb/gal) 70/30 Oil : Water Water phase salinity 250,000 ppm SF Base (1O), bbi 0.426 LE SUPERMUL# 8 emulsifier, lb/bbl ADAPT HP filtration 1 reducer, lb/bbl Water, bbl 0.257 RHEMODIL suspension 0.25 a ent/viscosifier Barite, lb/bbl 208.1 CaCl2, lb/bbl 29.11 REV :DUST additive, 10.0 Ib/bbl BARACARIf 5 agent, 10.0 lb/bbl GELTONE II viscosifier, 4.0 lb/bbl '~ Trademark Table XV. ENVIROMUL Mud Formulation.
Sample, (!k/gal) (12.0 lb/gal) 70/30 Oil : Water Water phase salinity 250,000 ppm ESCAID fluid 110, 0.524 bbl Water, bbl 0.233 GELTONE V 12.0 viscosifier, lb/bbl SUSPENTONE 4.0 agent, Ib/bbl EZMULNT 5.0 emulsifier, lb/bbl INVERMUL NT 4.0 emulsifier, lb/bbl Lime, lb/bbl 2 DURATONE HT 8.0 filtration control agent DEEP-TREAT 5.0 thinner, lb/bbl COLDTROL thinner, 2.5 lb/bbl CaCl2, lb/bbl 28.4 Barite, lb/bbl 209.8 Table XVI. Test Results of AD 200 polymer with PETROFREE SF and ENVIROMUL
Mud Sample 0.1 g 1.0 g 0.1 g 0.1 g 0.1 g Nat Na2C Na2CO3 and Na2CO3 Na2CO3 and CO3* 03 3g and 3g 3g STEELSEA barite REV-DUST
L additive material AD 200 Solid Solid Solid forms in 1.5 min. The texture and the polymer:PETROFRE form forms strength of the paste are better than without E mud SF (2:1) s in in 15 adding any solid. The ones with 1.5 min STEELSEAL material and REV-DUST
min additive look better than barite.
AD 200 Solid Solid Solid forms in lmin. The texture and the polymer:ENVIROM form forms strength of the paste are better than without UL mud (2:1) s in in 5 adding any solid. The one with I min min STEELSEAL material looks the best.
* All experiments in this table are done with 20 mL of water.
From EXAMPLES 8 and 9, it can be seen that the tests results of AD 200*
polymer with PETROFREE* SF and ENVIROMUL` muds are similar to ACCOLADE* mud.
While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about I to about 10 includes, 2, 3, 4, etc.;
greater than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of the term "optionally" with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required.
Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. The discussion of a reference in the Background of the Invention is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application.
* Trademark
BRIEF SUMMARY OF SOME OF THE PREFERRED EMBODIMENTS
These and other needs in the art are addressed in one embodiment by a method of servicing a wellbore that penetrates a subterranean formation. The method comprises placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of the fluid in the wellbore.
In another embodiment, these and other needs in the art are addressed by a sealant composition comprising an inverse emulsion polymer. The inverse emulsion polymer comprises particles having a particle size from about 0.01 microns to about 30 microns.
In one embodiment, these and other needs in the art are addressed by a sealant composition comprising an oil dispersed polymer comprising particles having an average particle size from about 0.01 microns to about 30 microns.
The sealant composition comprising an inverse emulsion polymer overcomes problems in the art. For instance, the sealant composition may be easily delivered downhole. In addition, the sealant composition may reduce fluid loss in large permeable zones such as a vugular fracture.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
FIGURE 1 illustrates a FLEXPLUG lost circulation material profile for an extrusion rheometer run;
Trademark FIGURE 2 illustrates an inverse emulsion polymer and NaCl profile for an extrusion rheometer run;
FIGURE 3 illustrates an inverse emulsion polymer and sea water profile for an extrusion rheometer run;
FIGURE 4 illustrates a calculated Bagley coefficient for an inverse emulsion polymer and NaCl mixture; and FIGURE 5 illustrates a calculated Bagley coefficient for an inverse emulsion polymer and NaCl mixture.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
In an embodiment, a sealant composition comprises an inverse emulsion polymer.
The sealant composition is a mixture that can viscosify in wellbore zones where a fluid (e.g., drilling fluid) is being lost. For instance, the sealant composition may viscosify in a lost circulation zone and thereby restore circulation. The viscosified mixture can set into a flexible, resilient and tough material, which may prevent further fluid losses when circulation is resumed. The inverse emulsion polymer may have similar characteristics to a liquid and therefore may be suitable for delivery downhole in a wellbore.
The sealant composition is for use in a wellbore that penetrates a subterranean formation. It is to be understood that "subterranean formation" encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water. The sealant composition can be used for any purpose. For instance, the sealant composition can be used to service the wellbore. Without limitation, servicing the wellbore includes positioning the sealant composition in the wellbore to isolate the subterranean formation from a portion of the wellbore; to support a conduit in the wellbore; to plug a void or crack in the conduit; to plug a void or crack in a cement sheath disposed in an annulus of the wellbore; to plug an opening between the cement sheath and the conduit; to prevent the loss of aqueous or non-aqueous drilling fluids into lost circulation zones such as a void, vugular zone, or fracture; to be used as a fluid in front of cement slurry in cementing operations; to seal an annulus between the wellbore and an expandable pipe or pipe string; and combinations thereof.
The inverse emulsion polymer includes a water-in-oil emulsion with a water swellable polymer dispersed in the emulsion. The emulsion contains a continuous phase of oil and a dispersed phase of water. The oil may be any oil that is immiscible with water and suitable for use in a wellbore. Without limitation, examples of suitable oils include a petroleum oil, a natural oil, a synthetically derived oil, a mineral oil, silicone oil, or combinations thereof In some embodiments, the oil may be an alpha olefin, an internal olefin, an ester, a diester of carbonic acid, a paraffin, a kerosene oil, a diesel oil, a mineral oil, silicone oil, or combinations thereof. The water may be any suitable water for forming the dispersed phase and for use in a wellbore. Without limitation, examples of suitable waters include deionized water, municipal treated water; fresh water; sea water; naturally-occurring brine; a chloride-based, bromide-based, or formate-based brine containing monovalent and/or polyvalent cations;
or combinations thereof. Examples of suitable chloride-based brines include without limitation sodium chloride and calcium chloride. Further without limitation, examples of suitable bromide-based brines include sodium bromide, calcium bromide, and zinc bromide. In addition, examples of formate-based brines include without limitation sodium formate, potassium formate, and cesium formate.
The inverse emulsion polymer may contain any suitable amount of oil and water to form an inverse emulsion suitable for dispersion of the water swellable polymer and for placement in a wellbore. In an embodiment, the inverse emulsion polymer contains from about wt.% to about 80 wt.% oil, alternatively from about 30 wt.% to about 50 wt.%
oil by total weight of the inverse emulsion polymer. In addition, the inverse emulsion polymer contains from about 0 wt. % to about 70 wt. % water, alternatively from about 30 wt. %
to about 70 wt.
% water by total weight of the inverse emulsion polymer.
In some embodiments, the inverse emulsion polymer contains an emulsifier. The emulsifier may be any emulsifier suitable for holding the oil and water in suspension. In an embodiment, the inverse emulsion polymer contains water-soluble and oil-soluble emulsifiers (e.g,, emulsifying agents or surfactants) to stabilize the inverse emulsion polymer. Without limitation, examples of suitable emulsifiers include polyvalent metal soaps, phosphate esters, fatty acids, fatty acid soaps, alkylbenzene sulfonate, or combinations thereof The inverse emulsion polymer may contain any amount of emulsifier suitable for holding the oil and water in suspension. In an embodiment, the inverse emulsion polymer contains from about 1 wt.% to about 10 wt.% emulsifier, alternatively from about 1 wt.% to about 20 wt.%
emulsifier by total weight of the inverse emulsion polymer.
The inverse emulsion polymer may contain any desired amount of the water swellable polymer effective for the intended wellbore service. In an embodiment, the inverse emulsion polymer contains from about 30 wt.% to about 50 wt.% water swellable polymer, alternatively from about 30 wt.% to about 70 wt.% water swellable polymer, and alternatively from about 5 wt.% to about 100 wt.% water swellable polymer by total weight of the inverse emulsion polymer. A water swellable polymer refers to any polymer that is capable of absorbing water and swelling, i.e., increasing in size as it absorbs the water. In an embodiment, upon swelling of the water swellable polymer, the inverse emulsion polymer forms a paste-like mass that is effective for blocking a flow pathway of a fluid. In some embodiments, the paste-like mass has a relatively low permeability to fluids used to service a wellbore such as a drilling fluid, a fracturing fluid, a cement, an acidizing fluid, an injectant, and the like, thus creating a barrier to the flow of such fluids. A paste-like mass refers to a soft, viscous mass of solids (e.g., the swelled water swellable polymer) dispersed in a liquid (the inverse emulsion).
In an alternative embodiment, the inverse emulsion forms a substantially hard, viscous mass when mixed with mud. Without limitation, examples of suitable water swellable polymers include synthetic polymers, superabsorbers, natural polymers, or combinations thereof. Examples of suitable synthetic polymers include crosslinked polyacrylamide, polyacrylate, or combinations thereof.
In an embodiment, the water swellable polymer includes superabsorbers.
Superabsorbers are commonly used in absorbent products such as horticulture products, wipe and spill control agents, wire and cable water-blocking agents, ice shipping packs, diapers, training pants, feminine care products, and a multitude of industrial uses.
Superabsorbers are swellable, crosslinked polymers that have the ability to absorb and store many times their own weight of aqueous liquids. Superabsorbers retain the liquid that they absorb and typically do not release the absorbed liquid, even under pressure. Examples of superabsorbers include sodium acrylate-based polymers having three dimensional, network-like molecular structures.
Without being limited by theory, the polymer chains are formed by the reaction/joining of hundreds of thousands to millions of identical units of acrylic acid monomers, which have been substantially neutralized with sodium hydroxide (caustic soda). Further, without being limited by theory, the crosslinking chemicals tie the chains together to form a three-dimensional network, which enable the superabsorbers to absorb water or water-based solutions into the spaces in the molecular network and thus form a gel that locks up the liquid.
Additional examples of suitable superabsorbers include but are not limited to crosslinked polyacrylamide;
crosslinked polyacrylate; crosslinked hydrolyzed polyacrylonitrile; salts of carboxyalkyl starch, for example, salts of carboxymethyl starch; salts of carboxyalkyl cellulose, for example, salts of carboxymethyl cellulose; salts of any crosslinked carboxyalkyl polysaccharide;
crosslinked copolymers of acrylamide and acrylate monomers; starch grafted with acrylonitrile and acrylate monomers; crosslinked polymers of two or more of allylsulfonate, 2-acrylamido-2-methyl-l-propanesulfonic acid, 'I-allyloxy-2-hydroxy-l-propane-sulfonic acid, acrylamide, and acrylic acid monomers; or combinations thereof. In an embodiment, the water swellable polymer comprises a crosslinked polyacrylamide and/or polyacrylate. In one embodiment, the superabsorber absorbs not only many times its weight of water but also increases in volume upon absorption of water many times the volume of the dry material. In an embodiment, the superabsorber increases from about 10 to about 800 times its original weight.
In an embodiment, the water swellable polymer has a particle size (i.e., diameter) from about 0.01 microns to about 30 microns, alternatively from about 1 micron to about 3 microns, before it absorbs water (i.e., in its solid form). The swell time of the water sweUable polymer may be in a range from about 5 seconds to about 5 hours, alternatively from about 1 second to about 48 hours.
Without being limited by theory, the micron size of the water swellable polymer allows the inverse emulsion polymer to behave as a liquid (e.g, has similar flow characteristics to a liquid) that is sufficient for delivery downhole in a wellbore. Further, without being limited by theory, the micron size also allows a dehydrated form of the inverse emulsion polymer (e.g., the oil dispersed polymer) to behave as a liquid. The inverse emulsion polymer has a density from about 1.1 g/ml to about 1.7 g/ml, alternatively from about 1.0 g/ml to about 2.5 g/ml. In addition, the inverse emulsion polymer has an absorption capacity from about 10 to about 100 times of its own weight, alternatively from about 1 to about 1,000 times of its own weight.
A suitable commercial example of the inverse emulsion polymer is AE 200 polymer, which is available from Hychem, Inc. AE 200 polymer contains about 30 wt %
water swellable polymers, about 30 wt % mineral oil, about 30 wt. % water, and about 10 wt. %
emulsifier. The water swellable polymer is comprised of about 30 wt. %
polyacrylic acid and about 70 wt.% polyacrylanmide cross linked polymers. The particle size of the water sweUable polymer is about I to about 3 microns. The inverse emulsion polymer may have a pH of from about 5.0 to about 8.0, preferably from about 6.0 to about 7.5. The inverse emulsion polymer may have a density of from about 1.0 g/ml to about 2.5 g/ml, preferably from about 1.1 g/ml to about 1.7 g/ml.
In an embodiment, a dehydrated inverse emulsion polymer is placed in the wellbore.
The inverse emulsion polymer is suitably dehydrated to remove at least a portion of the water x Trademark and provide an oil dispersed polymer. In an embodiment, the inverse emulsion polymer is dehydrated to form an oil dispersed polymer comprising from about 0 wt.% to about 10 wt.%
water, alternatively from about 0 wt.% to about 5 wt.% water, and alternatively from about 3 wt.% to about 5 wt.% water. Without being limited by theory, the inverse emulsion polymer is dehydrated because dehydration provides a higher percentage of the water swellable polymer in the polymer. Further, without being limited by theory, the inverse emulsion polymer is dehydrated to reduce the possibility of substantially changing the original oil-based drilling fluid properties. The inverse emulsion polymer may be dehydrated to provide the oil dispersed polymer by any suitable method. In an embodiment, the oil dispersed polymer comprises from about 45 wt.% to about 50 wt.% oil, alternatively from about 30 wt.% to about 70 wt. % oil by total weight of the oil dispersed polymer. In addition, the oil dispersed polymer comprises from about 45 wt.% to about 50 wt.% water swellable polymer, alternatively from about 30 to about 70 wt.% water swellable polymer by total weight of the oil dispersed polymer.
The oil dispersed polymer has a density from about 1.2 g/ml to about 1.7 g/ml, alternatively from about 1.0 g/ml to about 2.5 g/ml. In addition, the oil dispersed polymer has an absorption capacity from about 10 to about 200 times of its own weight, alternatively from about 1 to about 1,000 times of its own weight.
Without limitation, a commercial example of a dehydrated inverse emulsion polymer (e.g., oil dispersed polymer) is AD 200 polymer, which is available from Hychem, Inc. AD 200 polymer is a crosslinked polymer that contains about 1-3 wt. % water and about 50 wt. %
active components, which includes water swellable polymers in an amount of about 30 wt. %
polyacrylate and about 70 wt. % polyacrylamide by total weight of the polymer.
polymer has a density of 1.25 g/ml ( 10%). In addition, AD 200 polymer has an absorption capacity (in distilled water) of 20 g distilled water/l g AD 200 polymer and further has an absorption capacity (in 3 % NaCl solution) of 5 g 3% NaCl solution/l g AD 200 polymer. AD
200 polymer also has a percent of non volatile residues at 150 C for 16 hours at 63% (d 10%).
[00011 In some embodiments, the sealant composition includes additives that may be suitable for improving or changing its properties. Without limitation, examples of suitable additives include particulate materials, viscosifying agents, weighting materials, or combinations thereof.
The weighting materials may be used to increase the density of the sealant composition. In one embodiment, a sufficient amount of weighting material is mixed with the sealant composition to increase the density of the composition at which it passes down through the welibore.
Without being limited by theory, the increased density may increase the rate at which the sealant composition passes down through the fluid in the wellbore. Further, without being limited by theory, the density is increased to reduce the possibility of a wellbore blow out Without limitation, examples of suitable weighting materials include barite, silica flour, zeolites, lead pellets, sand, fibers, polymeric material, or combinations thereof. The density may increase to any desired density. In one embodiment, the density is increased to a density from about 10 ppg to about 20 ppg.
In one embodiment, the inverse emulsion polymer is introduced to the wellbore to prevent the loss of aqueous or non-aqueous drilling fluids into lost circulation zones such as voids, vugular zones, and natural or induced fractures while drilling. During the wellbore treatment, various components may be pumped sequentially down the workstring and/or simultaneous down the annulus as appropriate for a given treatment. In an embodiment, the inverse emulsion polymer is pumped in the wellbore to service the wellbore.
Before the inverse emulsion polymer is pumped into the wellbore, a spacer fluid may be pumped into the wellbore. In some embodiments, the spacer fluid is suitable for removing water (i.e., from the pipes). For instance, the spacer fluid may contain a wetting agent such as LE
SUPERMUL
emulsifier. LE SUPERMUL emulsifier is commercially available from Halliburton Energy Services, Inc. The inverse emulsion polymer is then pumped into the wellbore.
In some embodiments, weighting material such as barite is added to the inverse emulsion polymer prior to pumping the inverse emulsion polymer into the wellbore. After such pumping, additional spacer fluid may be pumped into the wellbore. The sealant composition is formed and provides a relatively viscous mass inside the lost circulation zone. Drilling fluid may then be pumped into the wellbore under suitable pressure to squeeze the sealant composition into the lost circulation zone. The sealant composition can also form a non-flowing, intact mass inside the lost circulation zone. This mass plugs the zone and inhibits loss of subsequently pumped drilling fluid, which allows for further drilling. In an embodiment wherein the drilling fluid is non-aqueous, a treating composition may be pumped into the wellbore after the inverse emulsion polymer and additional spacer are pumped. In an embodiment, a sufficient amount of the treating composition may be pumped to reduce the amounts of calcium and magnesium in the drilling fluid in contact with the inverse emulsion polymer. In an embodiment, the treating composition comprises soda ash, NaHCO3, a monovalent salt, a divalent salt, or combinations thereof. Without limitation, examples of such salts include Nat, K+, Ca2+ and Mae}. Without ~~ Trademark being limited by theory, the calcium and magnesium are reduced to prevent salt poisoning in the inverse emulsion polymer or oil dispersed polymer, which may prevent the formation of the desired solid paste to plug the void in the formation. In such an embodiment, a spacer fluid may then be pumped into the wellbore followed by the drilling fluid. It is to be understood that non-aqueous drilling fluids may include a diesel, a mineral oil, an internal olefin, a linear alpha-olefin, an ester, or combinations thereof. In alternative embodiments, no spacer fluid is pumped into the wellbore before and/or after the inverse emulsion polymer is pumped into the wellbore. In some embodiments, the inverse emulsion polymer is dehydrated to form the oil dispersed polymer, and the sealant composition is formed therefrom.
In one embodiment, the sealant composition is placed in the wellbore with a water-based mud. The method for placement includes pumping a treated and active drilling mud into the wellbore. Any suitable amount of the drilling mud may be pumped into the wellbore. For instance, an amount of drilling mud comprising from about 15 to about 20 barrels may be pumped into the wellbore. In an instance in which soluble calcium is present in the mud, the mud may be treated with a treating composition to treat out at least a portion of the calcium. In an embodiment, the mud is treated when the calcium is present in an amount greater than 200 mg/l. Any suitable amount of the treating composition may be used. A spacer (e.g., LE
SUPERMUL emulsifier) is pumped into the wellbore following the mud. Any suitable amount of spacer may be pumped into the wellbore. For instance, an amount of spacer comprising from about 5 barrels to about 10 barrels may be pumped into the wellbore, alternatively from about 6 barrels to about 7 barrels may be pumped into the wellbore. The inverse emulsion polymer is pumped into the wellbore following the spacer. An amount of the inverse emulsion polymer comprising from about 15 to about 20 barrels, alternatively from about 16 to about 17 barrels may be pumped into the wellbore. The inverse emulsion polymer may be weighted with a weighting material. An amount of spacer is then pumped into the wellbore. The amount of spacer may include from about 5 barrels to about 10 barrels, alternatively from about 6 barrels to about 7 barrels is pumped into the wellbore. A suitable amount of the mud is then pumped into the wellbore. In an embodiment, the amount of mud is 20 barrels or less. After the mud is pumped into the wellbore, a light squeeze pressure is maintained for a suitable time for the sealant composition to form the non-flowing, intact mass inside the lost circulation zone.
Any suitable pressure is maintained. For instance, the pressure may be from about 175 to about 225 psi. It is to be understood that in some embodiments an oil dispersed polymer is placed in the wellbore with the water-based mud instead of the inverse emulsion polymer.
In another embodiment, the sealant composition is placed in the wellbore with a non-aqueous mud. The method for placement includes pumping a spacer into the wellbore. Any suitable amount of spacer may be used. For instance, about 1 barrel of spacer may be pumped in the wellbore. The inverse emulsion polymer is pumped into the wellbore following the spacer. An amount of the inverse emulsion polymer comprising from about 10 to about 20 barrels, alternatively from about 16 to about 17 barrels, and alternatively about 11 barrels may be pumped into the wellbore. The inverse emulsion polymer may be weighted with a weighting material. An amount of spacer is pumped into the wellbore following the inverse emulsion polymer. In one embodiment, an amount of the spacer comprising from about I to about 5 barrels, alternatively from 3 to about 5 barrels, and alternatively about 2 barrels is pumped into the wellbore. A treating composition (e.g., soda ash) is pumped into the wellbore following the spacer. For instance, soda ash may be mixed with a spacer, drilling mud, or AD
200 polymer and pumped into the wellbore. Any suitable amount of the treating composition may be pumped to prevent salt poisoning of the inverse emulsion polymer. In some embodiments, from about 30 to about 70 barrels of the treating composition, alternatively from about 35 to about 40 barrels, and alternatively from about 50 to about 70 barrels are pumped into the wellbore. An amount of spacer fluid is pumped into the wellbore following the treating composition. In one embodiment, an amount of the spacer from about 1 to about 5 barrels is pumped into the wellbore, alternatively from about 3 to about 5 barrels, and alternatively about 3.5 barrels. A suitable amount of the mud is pumped into the wellbore following the spacer. In an embodiment, the amount of mud is 20 barrels or less. After the mud is pumped into the wellbore, a light squeeze pressure is maintained for a suitable time for the sealant composition to form the non-flowing, intact mass inside the lost circulation zone. Any suitable pressure is maintained. For instance, the pressure may be from about 175 to about 225 psi.
It is to be understood that in some embodiments an oil dispersed polymer is placed in the wellbore with the nonaqueous mud instead of the inverse emulsion polymer.
In an embodiment, sealant compositions that include an inverse emulsion polymer may be employed in well completion operations such as primary and secondary cementing operations. In one embodiment, a spacer fluid is pumped through the drill pipe. The inverse emulsion polymer is then pumped through the drill pipe and forms the sealant composition. An additional amount of spacer fluid may then be pumped through the drill pipe.
In alternative embodiments, no spacer fluid is pumped into the drill pipe before and/or after the inverse emulsion polymer. In primary cementing, such a sealant composition may be placed into an annulus of the wellbore and allowed to set such that it isolates the subterranean formation from a different portion of the wellbore. The sealant composition thus forms a barrier that prevents fluids in that subterranean formation from migrating into other subterranean formations.
Within the annulus, the sealant composition also serves to support a conduit, e.g., casing, in the wellbore. In one embodiment, the welibore in which the sealant composition is positioned belongs to a multilateral wellbore configuration. It is to be understood that a multilateral wellbore configuration includes at least two principal wellbores connected by one or more ancillary wellbores. In secondary cementing (often referred to as squeeze cementing), the sealant composition may be strategically positioned in the wellbore to plug a void or crack in the conduit, to plug a void or crack in the hardened sealant (e.g., cement sheath) residing in the annulus, to plug a relatively small opening known as a microannulus between the hardened sealant and the conduit, and so forth. In some embodiments, the inverse emulsion polymer is dehydrated to form the oil dispersed polymer, and the sealant composition is formed therefrom.
Various procedures that may be followed to use the sealant composition in a wellbore are described in U.S. Patent Nos. 5,346,012 and 5,588,489.
To further illustrate various illustrative embodiments of the present invention, the following examples are provided.
In this Example 1, Runs were conducted (Runs 1-9) comparing a conventional lost circulation material, FLEXPLUG lost circulation material (Run 1), to an inverse emulsion polymer, AE 200 polymer (Runs 2-9). FLEXPLUG lost circulation material uses particles to prevent fluid loss. and is commercially available from Halliburton Energy Services, Inc.
Different ratios of AE 200 polymer were mixed with deionized water, a 1% NaCl solution, or sea water. An extrusion rheometer was used to test each mixture.
The main components of the extrusion rheometer consisted of a core, which had a slit with an opening of 1 mm, 2 mm or 3 mm in width. The rheometer was 2, 4 or 6 inches long.
# #
For each Run, the rheometer was filled with the material (AE 200 polymer or FLEXPLUG
material) to be tested. A pressure was applied to push the material out of the different sizes of ~` Trademark cores. It was observed that different forces were needed to push different materials out of the same core under the same conditions. Such force was measured in pounds and recorded. The results are listed below in Table I, wherein the samples are identified by length of the rheometer in inches by the width of the rheometer in millimeters (e.g., 2 in L by 1 mm W
=
2INLXlMMW).
Table I.
polymer-.D1 polymer:l% polymer:l% polymer:Sea FLEXPLUG Water NaCl NaCl Water Sample ID Material (1:9) (1:6) 1:3 (1:3) 2INLXIMMW Ave: 209 N/A N/A N/A SD: 2.38 N/A
COV:1.1%
4INLXIMMW Ave: 134.7 Ave: 136.3 Ave: 283 Ave: 248 N/A SD: 5.67 SD: 5.7 SD: 1.15 SD: 1.16 COV: 4.2% COV:4.2% COV: 0.5% COV: 0.5%
6E` LX1NIMW Ave: 517 N/A N/A N/A SD: 6.56 N/A
COV: 1.3%
2INLX2MMW Ave: 46.1 Ave: 41.3 Ave: 90.6 Ave: 82.0 N/A SD: 2.61 SD: 3.27 SD: 1.88 SD: 1.76 COV: 5.7% COV: 7.9% COV:2.1% COV:2.1%
41NLX2MMW Ave: 166.8 N/A N/A N/A SD: 2.15 N/A
COV: 1.3%
6INLX2MNIW Ave: 231 N/A N/A N/A SD: 4.85 N/A
COV: 2.1%
21NLX3MMW Ave:52.6 N/A N/A N/A SD: 3.01 N/A
COV: 5.7%
4INLX3MIMIW Ave:80.9 N/A N/A N/A SD: 1.87 N/A
COV: 2.3%
6INLX3MMW Ave: 526 Ave: 57.2 Ave: 62.1 Ave: 114.4 Ave: 108.8 SD:69 SD: 8.9 SD: 1.19 SD: 8.34 SD:7.82 COV: 13.1% COV: COV: 1.9% COV: 7.3% COV: 7.2%
15.6%
In the Table I, the rheometer readings are listed in pounds. The listed number is an average of the recorded results for each Run. "SD" represents standard deviation, and "COV"
represents the coefficient of variance, and is calculated by SD/XAve.
From Table I, it can be seen that the standard deviation and COV for the AE
inverse emulsion polymer was much better than the FLEXPLUG material. In various embodiments, rheometer readings for the inverse emulsion polymer have a SD of less than 9, 8, 7, 6, 5, 4, 3, or 2 and a COV of less than 8%, 7%, 6%, 5%, 4%, 3%, or 2%.
FIGURE 1 shows the FLEXPLUG material profile for its initial pressure, which is the initial pressure required to push the FLEXPLUG material into the vugular, cavernous formations. From FIGURE 1, it can be seen that the FLEXPLUG3 material exhibits pressure drops. As shown in FIGURES 2 and 3, there were no such pressure drops for the polymer sample. FIGURES 1-3 show position in inches on the x-axis and load in pounds-force on the y-axis.
The extrusion rheometer data from EXAMPLE 1 was used in EXAMPLE 2 to derive Bagley factors for each Run. In order to derive the Bagley factor, the width of the slit remained the same. The different forces were. obtained by changing the lengths of the core under the same conditions as illustrated in FIGURE 4.
The Bagley factor is defined as: Bagley factor = FO I FL2. Fo is defined as the force when X = 0. Fu is defined as the force obtained using the 4 inch core ixthis particular case. In general, the Bagley factor is between 0 and 80%. For FLEXPLUG material, the Bagley coefficient is generally between 25 and 80% and more typically between 35 and 55%. The smaller the Bagley factor, the easier the material is to be replaced by pressure or other materials.
FIGURES 4 and 5 illustrate calculated Bagley factors for different cores of AE
polymer: l% NaCl (1:3). From FIGURES 4 and 5, it can be seen that the Bagley factors are lower than such for FLEXPLUG material. By having such lower Bagley factors, the AE 200 polymer and 1% NaCl mixture may be more easily pushed into the fracture formations than the FLEXPLUG material.
AE 200 polymer was tested with a water based mud (lignosulfonate mud). Table II
shows how the. mud was formulated. AQUAGEL viscosifier is a viscosity and gelling agent that is commercially available from Halliburton Energy Services, Inc. QUIK-THIN thinner is a ferrochrome lignosulfonate that is commercially available from Halliburton Energy Services, Inc. CARBONOX filtration control agent is a lignite material that is commercially available Trademark from Halliburton Energy Services, Inc. REV-DUST additive is a calcium montnlorillonite clay that is commercially available from Milwhite, Inc.
Table II. Lignosulfonate Mud Formulation.
Sample, (lb/gal) 14.0 Fresh water, bbl 0.76 viscosifier, lb/bbl QUEK thinner, 6 lb/bbl NaOH, lb/bbl 3 (pH -11 -11.5) CARBONOX agent, 4 lb/bbl REV DUST dditive, 30.0 lb/bbl Barite, lb/bbl 271.6 After hot roll in a 150 F oven for 16 hrs, different concentrations of AE 200 polymer in the mud were tested with the results shown in Tables M and N. The concentrations were tested by adding 1.0 mL of AE 200 polymer and different amounts of lignosulfonate mud (e.g., as required by the experiment such as 1X, 2X or 50X) to a beaker. The mixture was mixed well. The time needed for the mixture to harden and the conditions of the mixture were recorded.
Table III. Test Results of AE 200 polymer with Lignosulfonate Mud Sample 1:1(v/v) 1:2 1:10 1:20 1:30 1:50 AE 200 Thicken Thicken Thicken Thicken within Slightly Slurry polymer with within 1 within I within 1 1 min. Forms slurry, and Lignosulfonat min. min. min. clay like solids. more water e Mud (with Forms Forms clay Forms Slightly wetter cement y Fresh Water) loose like solids clay like than 1:10 like solids solids # Trademark Table N. Test Results of AE 200 polymer with Lignosulfonate Mud Sample 1:5(v/v) 1:10 1:15 1:20 AE 20 polymer Thicken within Thicken Slurry at first, Slurry at first, with I min Forms within 1 min. then harden after then harden after Lignosulfonate rubbery clay Forms clay 1 hr 1.5 hr Mud (with Sea like solids Water) As can be seen from Tables III and IV, even with the dilution factor of 1:30 (AE 200 polymer: mud), the solid forms from the mixture of the two are still cement-like slurry paste. It can be further seen from such Tables that the dilution factor decreases to 10 instead of 20 when using the sea water version of the lignosulfonate mud. The cations in the sea water (e.g., Na+, K+, Cat+, Mg2+ and etc.) may be affecting the performance of AE 200 polymer by salt poisoning. In this case, the salt poisoning effect was observed to be more serious for Cat than Na+. To treat out the Ca2+ ions, 0.2 lb/bbl of soda ash (Na2CO3) was added to the mud with excellent results. It was observed that the dilution factor increased back to 20, and the texture of the solid was also more like the fresh water mud.
In EXAMPLE 4, the salinity, pH and density effects on the performance of AE
polymer was observed. Different salinity, pH and density muds were formulated as shown in Table V. BARAZAN D#Plus suspension agent/viscosifier is a dispersion enhanced xanthum gum that is commercially available from Halliburton Energy Services, Inc.
FILTER-CHECK
filtration control agent is a modified starch that is commercially available from Halliburton Energy Services, Inc. CLAY SYNC shale stabilizer is a clay inhibitor for water-based mud commercially available from Halliburton Energy Services, Inc. CLAY GRABBER
flocculant is a polymeric additive for water-based drilling fluids commercially available from Halliburton Energy Services, Inc. CLAY SEAL shale stabilizer is a chemical drilling fluid additive commercially available from Halliburton Energy Services, Inc.
# Trademark Table V. Mud Formulations Fresh 10% (w/w) 24% (w/w) NaCI
Water NaCI
Sample, (lb/gal) 13 13 10 13 13(w/o 16 NaOH) Fresh Water, bbl 0.826 _ _ _ 10%(w/w), NaCl, _ 0.845 - _ - -bbl 24%(w/w), NaCl, - - 0.994 0.875 0.875 0.756 bbl NaOH, lb 0.25 0.25 0.25 0.25 - 0.25 BARAZAN D 0.75 0.75 1.0 0.75 0.75 0.25 PLUS suspension agent/ viscosifier, lb FILTER-CHECK 4.0 4.0 4.0 4.0 4.0 4.0 filtration control agent, lb CLAY SYNC 3.25 2.75 2.0 2.0 2.0 2.0 shale stabilizer, lb CLAY 0.50 0.5 0.5 0.5 0.5 0.5 GRABBER
flocculant (active), lb CLAY SEAL 4.0 4.0 4.0 4.0 4.0 4.0 shale stabilizer, lb Barite, lb 256.3 228.3 81.5 183.2 183.2 358.3 All the muds from Table V were hot rolled at 150 F in an oven for 16 hrs. The pH
measurements were taken after the hot roll. The densities of the muds as mixed with the 24%
(w/w) NaCI were measured as shown in Table VI. The mud from Table V (24% (w/w) NaCI
(density =13) was added a different amount of NaOH to adjust the pH of the muds and to determine how much mud was needed to achieve the same results.
Table VI. How Density and PH Affect the Performance of AE 200 Polymer 24% (w/w) NaCI
Density, 10 13 13 13 16 (lb/gal) Mud vol. 10 10 10 10 10 mL
pH 9.05 7.66 9.06 11.0 9.05 polymer mL
Observation It needs the It takes the It takes the There is no It takes only s most AE 200 longest time same amount significant 2 mL of AE
polymer to (1.5 min. vs. of AE 200 difference 200 polymer form polymer - 1 min.) to polymer to when pH to form paste/ solids. harden form changes paste/solids.
The texture of compared solids/paste from 9 to The the paste is with all other when the it. texture/streng also the most mud with the density is the th of the solid loose one same same formed also among all density, but regardless of is the best.
other different pH. the samples. differences in pH.
Density may play an important role on the quality of the solid after mixing mud with AE 200 polymer and may also determine the amount of AE 200 polymer needed to form the solid. As shown in Table VI, under the same conditions, the lower the density, the more AE
200 polymer may be used to form the solid (4 mL of AE 200 polymer for D = 10 vs. 2 mL AE
200 polymer for D = 16, that is 50% decrease in volume.).
It was observed that the solid forms using the mud with density of 16 was noticeably thicker and stronger than the mud with a density of 10. Under the same conditions, by comparing the mud with pH = 7.66 and 11, it was observed that it takes 1.5 min. to form the solid at pH = 7.66 vs. I min. for pH = It, which may be attributed to "salt poisoning" (e.g., cation poisoning effect) on AE 200 polymer. The lower the pH, the more free W
ions that may be in the solution, and the worse the salt poisoning effect AE 200 polymer may have.
However, there was no observed difference when the pH was changed from 9 to 11.
Salinity of the muds from EXAMPLE 4 were tested. It was observed that salinity had a greater effect on the performance of AE 200 polymer than pH. Table VII shows the salinity results.
Table VII. How Salinity Affects the Performance of AE 200 Polymer Freshwater 10% (w/w) NaCl 24% (w/w) NaCl Density, 13 13 13 lb/gal Mud vol. 10 10 10 (mL) H 9.03 9.05 9.06 polymer (mL) Observatio It needs only I mL AE The texture and AE 200 polymer still us 200 polymer to form strength of the solid is works in 24 % NaCl polymer paste/ solid. between freshwater (w/w) mud. It just needs The texture of the paste and 24% (w/w) NaCl. more AE 200 polymer to is also the best among form solid/paste.
all other samples.
The freshwater mud from Table VII performed the best in terms of the amount of AE
200 polymer used, and the quality of the solid forms after mixing. Again, with more cations in the solution, more AE 200 polymer was needed to form the solid. Therefore, the increasing amount of AE 200 polymer used when the salinity increases can be seen in Table VII. In order to find out if the presence of KCl would affect the performance of AE 200 polymer, two experiments were done with the results shown in Table VIII.
Table VIII.
Sample 10% KCI 3% KCI + 24% NaCl AE 200 polymer (3mL) : Salt Forms solid Forms solid Solution (10 mL) The results show that there are no problems forming solid whether it is in 10%
KCI
solution or 24% NaCI with 3% KCl solution, as long as there is enough AE 200 polymer in the mixture (in this case, 3 mL AE 200 polymer).
AD 200 polymer was tested with various muds, and the results are shown in Table IX.
AD 200 polymer is the dehydrated form of AE 200 polymer. The test method here is similar to the test noted above. I mL of AD 200 polymer and 20 mL of mud were mixed in a beaker.
The time it took for the mixture to harden was recorded. The texture of the solid pastes were compared.
Table IX. AD 200 polymer with Various Water Based Muds Sample 1:20(v/v) (AD 20 polymer: Mud) HYDRO-GUARD system Thicken and form polymer solid within I min.
Lignosulfonate Mud Thicken and form polymer solid within I min.
Lignosulfonate Mud with 6 ppb Lime Thicken and form polymer solid within 1 min.
Lignosulfonate Mud with 6 ppb Lime Thicken and form polymer solid within 1 min.
(0.5 g of Na=C03 was added before However, the time required to form a polymer adding AD 200 polymer) solid for this mud is shorter than the one from above. The strength and texture of the polymer solid are also better than the one obtained from above.
GEM GP Mud Thicken and form polymer solid within 1 min.
HYDRO-GUARD system is a mud that is commercially available from Halliburton Energy Services, Inc. and is a water-based mud. GEM GP (general purpose) is a glycol enhanced mud that is commercially available from Halliburton Energy Services, Inc. and is also a water-based mud. It was observed that AD 200 polymer worked very well with different water-based muds. In addition, it was observed that there was no problem forming a solid even with high lime mud. The result is even better when soda ash was added to the high lime mud before adding AD 200 polymer.
In. order to find a safe way to deliver AD 200 polymer down hole, an appropriated spacer for the job was used. Table X summarized the results of such finding.
AD 200 polymer in a mud was tested with an emulsifier (e.g., LE SUPERMUL emulsifier), which was used as the spacer. The results of the tests are shown in Table X.
Trademark Table X. Wetting Agent, Spacer, Mud, AD 200 polymer and their Compatibility and Stability Sample Comments LE SUPERMUL emulsifier Wetting agent (polyaminated fatty acid) SF Base oil Main component of the spacer 2%(v/v) LE SUPERMUL emulsifier Spacers will be used in water mud systems. It in SF Base oil should be used before and after delivering AD
# 200p of er down hole.
Spacer : AD 200 polymer (10 mL:10 No problems on stability or compatibility.
It mL) ti takes 25 mL of water to invert the emulsion.
Lignosulfonate Mud : Spacer : AD 200 No problem forming polymer solids.
polymer 1:1:0.5 GEM G Mud: Spacer : AD 200 No problem forming polymer solids.
polymer (1:1:0.5) SF Base oil is an internal olefin available from Halliburton Energy Services, Inc. It was observed that no problem occurred when AD 200 polymer was weighted up to 19 lb/gal with barite.
AD 200 polymer was tested with ACCOLADE drilling fluid. ACCOLADE fluid is a clay-free synthetic based drilling fluid that is commercially available from Halliburton Energy Services, Inc. The formulation of the mud is listed in Table XI. Table XII
shows results of different mixes of AD 200 polymer with the ACCOLADE fluid. The ACCOLADE fluid was formulated as in Table XI and then hot rolled at 150 IF in an oven for 16 hours. ADAPTA
filtration reducer is a copolymer that provides HPHT filtration control in non-aqueous fluid systems that is commercially available from Halliburton Energy Services, Inc.
BARACARB
bridging agent is carbonate particles commercially available from Halliburton Energy Services, Inc. RHEMOD L viscosifier is commercially available from Halliburton Energy Services, Inc.
Trademark Table M. ACCOLADE Mud Formulation.
Sample, lb/gal) (12.0 lb/gal) 70/30 Oil : Water Water phase salinity 250,000 ppm ACCOLADE fluid base, 0.436 bbl emulsifier, lb/bbl Water, bbl 0.24 Lime, lb/bbl 1 ADAPTA HP filtration 2 reducer, lb/bbl Barite, lb/bbl 188.96 REV-DUST additive, 20.0 Ib/bbl BARACARB 25 agent, 7.5 lb/bbl BARACARB 50 agent, 7.5 lb/bbl CaC12, lb/bbI 29.09 RHEMOD L suspension 1 agent/viscosifier, Ib/bbI
Table XII. Preliminary Lab Test Results of AD 200 polymer with ACCOLADE Mud Sample 0.1 g of Na2CO3 in Different Amount of Water 1.0 g Na2CO3 in mL Water (mL) polymer:Mud 2mL:1mL
Observations Solid Solid Solid Solid No solid form for at forms in forms in forms in forms in 1 least 3 hrs. After less than 1 less than 1 less than 1 min. overnight, a paste min. min. min. forms, but it is not as thick as using 0.1 g of Na2CO3 in mL water.
It was observed that 1 mL of AD 200 polymer mixed with 20 mL of mud and was able to form a solid/paste mixture. It was also observed that a 2:1 (AD 200 polymer : mud) mixing ratio, plus 20 mL of soda ash solution was used to form the solid/paste as shown in Table XII.
When 2 mL of AD 200 polymer was mixed with 1 mL of mud, the concentration of polymer changed from 50% to 33.33% (e.g., 33% active AD 200 polymer reacted with 20 mL
of soda ash solution to form a solid). The amount of Na2CO3 used (0.1 g) was calculated based on the stoichiometric amount of Ca2+ in the solution. 1.0 g of Na2CO3 was used instead of 0.1 g to observe whether excess Na2CO3 affected the performance of AD 200 polymer.
Excess Na2C03 functioned as salt poisoning for AD 200 polymer, therefore the mixture had a harder time forming the solid.
It was observed that the texture of the solids from the oil mud was not as good as the water-based mud. Therefore, additional solid was added as shown in Table XIII.
STEEL
SEAL is a graphite that is commercially available form Halliburton Energy Services, Inc.
Table XIII Preliminary Lab Test Results of AD 200 polymer with ACCOLADE Mud Sampl% 0.1 g of NaZCO3 in 10 mL Water AD 200 3.0 g Barite 3.0 g REV DUST 3.0 g STEEL SEAL
polymer:Mud additive lost circulation 2mL:1mL additive Observations Solid forms in less than . min for Solid forms in less than both cases. REV-DUST additive 1 min. The texture of may be slightly better although no the solid is the best of differences were observed on the the three.
texture of the solid b%ween barite and REV-DUST additive, It was observed that the added solid provided a better final paste both on the texture and the strength Two more oil-based muds were tested with AD 20S polymer (PETROFREE SF fluid and ENVIROMUL fluid). PETROFREE drilling fluid is commercially available from Halliburton Energy Services, Inc. ENVIROMUL drilling fluid is commercially available from Halliburton Energy Services, Inc. Their formulations are shown in Tables XIV
and XV.
GELTONE II viscosifier and GELTONE V viscosifier are gelling and viscosifying agents comprising ground organophillic clay, which are available from Halliburton Energy Services, Inc. Both muds were hot rolled in a 150 F oven for 16 hrs. ESCAID fluid is an oil that is commercially available from Exxon Chemical Company. SUSPENTONE suspension agent is an organophilic clay commercially available from Halliburton Energy Services, Inc. EZ MUL
NT emulsifier is a synthetic-based mud emulsifier commercially available from Halliburton Energy Services, Inc. DURATONE HT (high temperature) oil mud filtration control agent # Trademark comprises an organophillic lignite blend and is commercially available from Halliburton Energy Services, Inc. DEEP-TREAT thinner is a wetting agent commercially available from Halliburton Energy Services, Inc., and COLDTROt, thinner is commercially available from Halliburton Energy Services, Inc. The tests involved adding 20 mL water to a beaker, followed h by Na2CO3. STEELSEAL additive, barite or REV-DUST additive were also added if needed.
2 mL of AD 200 polymer and 1 mL of mud were then added to the beaker. The contents of the beaker were then mixed. The time needed for the mixture to harden was recorded. The results of the tests are shown in Table XVI.
Table XIV. PETROFREE SF Mud Formulation.
Sample, (lb/gal) (12.0 lb/gal) 70/30 Oil : Water Water phase salinity 250,000 ppm SF Base (1O), bbi 0.426 LE SUPERMUL# 8 emulsifier, lb/bbl ADAPT HP filtration 1 reducer, lb/bbl Water, bbl 0.257 RHEMODIL suspension 0.25 a ent/viscosifier Barite, lb/bbl 208.1 CaCl2, lb/bbl 29.11 REV :DUST additive, 10.0 Ib/bbl BARACARIf 5 agent, 10.0 lb/bbl GELTONE II viscosifier, 4.0 lb/bbl '~ Trademark Table XV. ENVIROMUL Mud Formulation.
Sample, (!k/gal) (12.0 lb/gal) 70/30 Oil : Water Water phase salinity 250,000 ppm ESCAID fluid 110, 0.524 bbl Water, bbl 0.233 GELTONE V 12.0 viscosifier, lb/bbl SUSPENTONE 4.0 agent, Ib/bbl EZMULNT 5.0 emulsifier, lb/bbl INVERMUL NT 4.0 emulsifier, lb/bbl Lime, lb/bbl 2 DURATONE HT 8.0 filtration control agent DEEP-TREAT 5.0 thinner, lb/bbl COLDTROL thinner, 2.5 lb/bbl CaCl2, lb/bbl 28.4 Barite, lb/bbl 209.8 Table XVI. Test Results of AD 200 polymer with PETROFREE SF and ENVIROMUL
Mud Sample 0.1 g 1.0 g 0.1 g 0.1 g 0.1 g Nat Na2C Na2CO3 and Na2CO3 Na2CO3 and CO3* 03 3g and 3g 3g STEELSEA barite REV-DUST
L additive material AD 200 Solid Solid Solid forms in 1.5 min. The texture and the polymer:PETROFRE form forms strength of the paste are better than without E mud SF (2:1) s in in 15 adding any solid. The ones with 1.5 min STEELSEAL material and REV-DUST
min additive look better than barite.
AD 200 Solid Solid Solid forms in lmin. The texture and the polymer:ENVIROM form forms strength of the paste are better than without UL mud (2:1) s in in 5 adding any solid. The one with I min min STEELSEAL material looks the best.
* All experiments in this table are done with 20 mL of water.
From EXAMPLES 8 and 9, it can be seen that the tests results of AD 200*
polymer with PETROFREE* SF and ENVIROMUL` muds are similar to ACCOLADE* mud.
While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about I to about 10 includes, 2, 3, 4, etc.;
greater than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of the term "optionally" with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required.
Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.
Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. The discussion of a reference in the Background of the Invention is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application.
* Trademark
Claims (13)
1. A method of servicing a wellbore that penetrates a subterranean formation, comprising:
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore, wherein the inverse emulsion polymer comprises from about 10 wt.% to about 80 wt.% by oil by total weight of the inverse emulsion polymer, wherein the inverse emulsion polymer comprises from about 0 wt.% to about 70 wt.% water by total weight of the inverse emulsion polymer, wherein the sealant composition has a density of from about ppg to about 20 ppg, and wherein the inverse emulsion polymer is dehydrated before placement in the wellbore to comprise from about 0 wt.% to about 10 wt.%
water.
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore, wherein the inverse emulsion polymer comprises from about 10 wt.% to about 80 wt.% by oil by total weight of the inverse emulsion polymer, wherein the inverse emulsion polymer comprises from about 0 wt.% to about 70 wt.% water by total weight of the inverse emulsion polymer, wherein the sealant composition has a density of from about ppg to about 20 ppg, and wherein the inverse emulsion polymer is dehydrated before placement in the wellbore to comprise from about 0 wt.% to about 10 wt.%
water.
2. The method of claim 1, wherein the inverse emulsion polymer comprises a petroleum oil, a natural oil, a synthetically derived oil, a mineral oil, a silicone oil, or combinations thereof.
3. The method of claim 1, wherein the inverse emulsion polymer comprises a water swellable polymer.
4. The method of claim 3, wherein the inverse emulsion polymer comprises from about 5 wt.% to about 90 wt.% water swellable polymer by total weight of the inverse emulsion polymer.
5. The method of claim 3, wherein the water swellable polymer comprises a synthetic polymer, a superabsorber, a natural polymer, or combinations thereof.
6. The method of claim 3, wherein the water swellable polymer comprises particles having particle sizes from about 0.01 microns to about 30 microns.
7. A method of servicing a wellbore that penetrates a subterranean formation comprising:
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore, wherein the inverse emulsion polymer is dehydrated before placement in the wellbore to comprise from about 0 wt.% to about 10 wt.% water and wherein the sealant composition has a density of from about 10 ppg to about 20 ppg.
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore, wherein the inverse emulsion polymer is dehydrated before placement in the wellbore to comprise from about 0 wt.% to about 10 wt.% water and wherein the sealant composition has a density of from about 10 ppg to about 20 ppg.
8. A method of servicing a wellbore that penetrates a subterranean formation comprising:
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore and adding a weighting material to the inverse emulsion polymer prior to placement of the inverse emulsion polymer in the wellbore, wherein the sealant composition has a density of from about 10 ppg to about 20 ppg, and wherein the inverse emulsion polymer is dehydrated prior to placement in the wellbore to comprise from about 0 wt.% to about 10 wt.% water.
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore and adding a weighting material to the inverse emulsion polymer prior to placement of the inverse emulsion polymer in the wellbore, wherein the sealant composition has a density of from about 10 ppg to about 20 ppg, and wherein the inverse emulsion polymer is dehydrated prior to placement in the wellbore to comprise from about 0 wt.% to about 10 wt.% water.
9. The method of claim 1, further comprising placing a spacer fluid into the wellbore prior to placement of the sealant composition.
10. The method of claim 1, further comprising placing a drilling fluid into the wellbore after placement of the sealant composition in the wellbore.
11. The method of claim 1, wherein the fluid comprises a water-based drilling fluid or a nonaqueous drilling fluid.
12. The method of claim 1, further comprising placing a treating composition in the wellbore after placement of the sealant composition in the wellbore.
13. A method of servicing a wellbore that penetrates a subterranean formation comprising:
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore, wherein the inverse emulsion polymer comprises from about 10 wt.% to about 80 wt.% oil by total weight of the inverse emulsion polymer, wherein the inverse emulsion polymer is dehydrated before placement in the wellbore to comprise from about 0 wt.% to about 10 wt.% water and wherein the sealant composition has a density of from about 10 ppg to about 20 ppg.
placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of a fluid in the wellbore, wherein the inverse emulsion polymer comprises from about 10 wt.% to about 80 wt.% oil by total weight of the inverse emulsion polymer, wherein the inverse emulsion polymer is dehydrated before placement in the wellbore to comprise from about 0 wt.% to about 10 wt.% water and wherein the sealant composition has a density of from about 10 ppg to about 20 ppg.
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US11/180,767 US7870903B2 (en) | 2005-07-13 | 2005-07-13 | Inverse emulsion polymers as lost circulation material |
US11/180,767 | 2005-07-13 | ||
PCT/GB2006/002659 WO2007007118A1 (en) | 2005-07-13 | 2006-07-11 | Water swellable polymers as lost circulation control agents material |
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CA2614272C true CA2614272C (en) | 2011-09-13 |
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EP (1) | EP1902115B1 (en) |
CN (1) | CN101263211B (en) |
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AU (2) | AU2006268023B2 (en) |
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NO (1) | NO20080203L (en) |
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WO (1) | WO2007007118A1 (en) |
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US20110118381A1 (en) | 2011-05-19 |
AU2012200222B2 (en) | 2012-06-28 |
CN101263211A (en) | 2008-09-10 |
AR091303A2 (en) | 2015-01-28 |
US7870903B2 (en) | 2011-01-18 |
CN101263211B (en) | 2015-04-15 |
MX2008000432A (en) | 2008-03-10 |
AU2006268023A1 (en) | 2007-01-18 |
RU2008105311A (en) | 2009-08-20 |
CA2614272A1 (en) | 2007-01-18 |
WO2007007118A1 (en) | 2007-01-18 |
US8703657B2 (en) | 2014-04-22 |
RU2436946C2 (en) | 2011-12-20 |
NO20080203L (en) | 2008-04-14 |
EP1902115B1 (en) | 2014-03-19 |
EP1902115A1 (en) | 2008-03-26 |
AR056670A1 (en) | 2007-10-17 |
AU2006268023B2 (en) | 2011-12-01 |
DK1902115T3 (en) | 2014-05-26 |
US20070012447A1 (en) | 2007-01-18 |
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