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WO2006111703A2 - Compositions et procedes d'utilisation d'un precipite polymere permettant de reduire la perte de fluide dans une formation souterraine - Google Patents

Compositions et procedes d'utilisation d'un precipite polymere permettant de reduire la perte de fluide dans une formation souterraine Download PDF

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Publication number
WO2006111703A2
WO2006111703A2 PCT/GB2006/001244 GB2006001244W WO2006111703A2 WO 2006111703 A2 WO2006111703 A2 WO 2006111703A2 GB 2006001244 W GB2006001244 W GB 2006001244W WO 2006111703 A2 WO2006111703 A2 WO 2006111703A2
Authority
WO
WIPO (PCT)
Prior art keywords
wellbore
activator
polymeric solution
precipitate
subterranean formation
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Ceased
Application number
PCT/GB2006/001244
Other languages
English (en)
Other versions
WO2006111703A3 (fr
Inventor
Kenneth W. Oyler
Carl J. Thaemilz
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Halliburton Energy Services Inc
Original Assignee
Halliburton Energy Services Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US11/109,150 external-priority patent/US7943555B2/en
Priority claimed from US11/109,354 external-priority patent/US7905287B2/en
Application filed by Halliburton Energy Services Inc filed Critical Halliburton Energy Services Inc
Priority to EP06726648A priority Critical patent/EP1891177A2/fr
Publication of WO2006111703A2 publication Critical patent/WO2006111703A2/fr
Publication of WO2006111703A3 publication Critical patent/WO2006111703A3/fr
Anticipated expiration legal-status Critical
Priority to NO20075890A priority patent/NO20075890L/no
Ceased legal-status Critical Current

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Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/426—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for plugging
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B24/00—Use of organic materials as active ingredients for mortars, concrete or artificial stone, e.g. plasticisers
    • C04B24/24—Macromolecular compounds
    • C04B24/26—Macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
    • C04B24/2652—Nitrogen containing polymers, e.g. polyacrylamides, polyacrylonitriles
    • C—CHEMISTRY; METALLURGY
    • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
    • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
    • C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
    • C04B28/02—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
    • 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
    • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
    • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
    • C09K8/467—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement containing additives for specific purposes
    • C09K8/487—Fluid loss control additives; Additives for reducing or preventing circulation loss
    • 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

Definitions

  • the present invention generally relates to downhole operations, and more particularly to methods of forming a polymeric precipitate in a subterranean formation to reduce the loss of fluid to the formation.
  • Natural resources such as oil or gas residing in a subterranean formation can be recovered via the formation of wells that penetrate the formation.
  • a wellbore is typically drilled down to the formation while circulating a drilling fluid (also known as a drilling mud) through the wellbore.
  • a drilling fluid also known as a drilling mud
  • the drilling fluid carries the drill cuttings in a return flow stream back to the well drilling platform.
  • a string of pipe e.g., casing
  • the drilling fluid is then usually circulated downwardly through the interior of the pipe and upwardly through the annulus, which is located between the exterior of the pipe and the walls of the well bore.
  • Primary cementing is then usually performed whereby a cement slurry is pumped down through the string of pipe and into the annulus between the string of pipe and the walls of the wellbore to allow the cement slurry to set into an impermeable cement column and thereby seal the annulus.
  • Secondary cementing operations i.e., cementing operations occurring after the primary cementing operation, may also be performed.
  • One example of a secondary cementing operation is squeeze cementing whereby a cement slurry is forced under pressure to areas of lost integrity in the annulus to seal off those areas.
  • the fluids used in such downhole operations may be lost to the subterranean formation while circulating the fluids in the wellbore.
  • the fluids may enter the subterranean formation via depleted zones, zones of relatively low pressure, naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the drilling fluid, and so forth.
  • lost circulation may occur in which the circulation of the drilling fluid in the wellbore drops due to it being lost to the formation. Its circulation may eventually become too low to allow for further drilling of the wellbore.
  • a cement slurry may be lost to the formation as it is being placed in the annulus, thereby rendering it ineffective in isolating the adjacent subterranean formation.
  • the amount of cement slurry may be insufficient to fill the annulus from top to bottom during primary cementing or to fill areas of lost integrity in a pre-existing cement column during secondary cementing. Further, dehydration of the cement slurry may result, compromising the strength of the cement that forms in the annulus.
  • methods of treating a subterranean formation comprise contacting a polymeric solution and an activator in the subterranean formation, thereby forming a precipitate to at least partially block a flow of a wellbore servicing fluid further into the formation.
  • the wellbore servicing fluid may be, for example, a drilling fluid, a cement composition, a workover fluid, or combinations thereof.
  • the polymeric solution may comprise, for example, a poly vinyl pyrrolidone aqueous solution
  • the activator may comprise, for example, a formate brine.
  • the polymeric solution and the activator are contacted before completing a drilling operation in the wellbore.
  • they are contacted before completing a primary cementing operation in the wellbore.
  • they are contacted before completing a secondary cementing operation in the wellbore.
  • the precipitate may be easily and quickly removed from the subterranean formation by dissolving it in fresh water.
  • methods of treating a wellbore that penetrates a subterranean formation comprise: introducing an activator to the wellbore; introducing a polymeric solution in situ with the activator, thereby forming a hard precipitate to at least partially block a flow pathway into the subterranean formation; circulating a wellbore servicing fluid through the wellbore; and dissolving the precipitate to prepare for hydrocarbon production.
  • methods of drilling a wellbore at least partially through a subterranean formation comprise: introducing an activator to the wellbore; introducing a polymeric solution in situ with the activator, thereby forming a hard precipitate to at least partially block a flow pathway into the subterranean formation; and applying torque to a bit within the wellbore while applying force to urge the bit to extend through the wellbore; and circulating a drilling fluid past the bit to remove cuttings therefrom.
  • FIG. IA is a side plan view of a drilling rig and a wellbore in the earth for recovering oil from a subterranean formation.
  • FIG. IB is a detailed view of a section of the wellbore depicted in FIG. IA 5 showing a precipitate blocking a flow pathway into the subterranean formation.
  • a polymeric solution and an activator may be contacted in a subterranean formation in such a manner as to form a hard precipitate in the formation.
  • a "polymeric solution” is defined as a solution comprising a polymer, an oligomer, or combinations thereof.
  • an "activator” is defined as a material that, when present in a sufficient amount, can cause the polymer and/or oligomer to precipitate out of the solution, wherein the activator may be a liquid in which the polymer and/or oligomer is insoluble. It is understood that "subterranean formation” encompasses both areas below exposed earth or areas below earth covered by water such as sea or ocean water.
  • the resulting polymeric precipitate is typically impermeable to fluid and thus may form a barrier in the formation that at least partially blocks one or more flow pathways through which a fluid could undesirably migrate into the formation.
  • flow pathways include natural or induced fractures, depleted zones, zones of relatively low pressure, weak zones having fracture gradients exceeded by the hydrostatic pressure of the fluid being used to service the wellbore, perforations formed by a perforating gun, and combinations thereof.
  • FIGS. IA and IB illustrate how the precipitate forms a barrier to at least partially reduce the flow of fluid far into a subterranean formation.
  • FIG. IA depicts a wellbore 10 that has been drilled in the earth such that it penetrates a subterranean formation.
  • An oil rig 30 positioned near the surface of the earth 20 may be used to recover oil from the formation.
  • a pipe 40 e.g., a drill pipe or tubing, may extend down through wellbore 10 for delivering fluid to and/or from the wellbore.
  • FIG. IB illustrates a section 50 of wellbore 10 in detail.
  • a precipitate 60 forms a solid coating across a flow pathway 70 such as a crack within wellbore 10 and thereby seals flow pathway 70.
  • the coating may have a thickness ranging from about 1 millimeter to about 10 millimeters.
  • precipitate 60 may extend across flow pathway 70.
  • Precipitate 60 is desirably impermeable to fluid and thus inhibits fluid from passing through pathway 70 and deeper into the adjacent subterranean formation.
  • precipitate 60 serves to reduce the loss of such fluid to the formation, allowing it to be primarily retained within wellbore 10 as it is pumped therethrough.
  • the coating formed by the precipitate will be effective in cracks that are both larger and smaller than the coating thickness near the wall of the wellbore. That is, cracks within the subterranean formation usually decrease in size at greater depths within the formation. Thus, the polymer solution may be pumped into cracks larger than the ensuing coating thickness to a depth where the cracks become sufficiently narrow to allow the coating to plug the entire crack.
  • a spacer separates the polymeric solution and the activator as they are being pumped downhole.
  • spacer is defined as a fluid that prevents the polymeric solution and the activator from interacting with each other as they pass down the wellbore and that is inert with respect to the polymeric solution and the activator.
  • suitable fluids to use as spacers include natural hydrocarbons, synthetic hydrocarbons, surfactants, glycols, fresh water, and combinations thereof.
  • the amount of the spacer employed in this embodiment may range from about 1 to about 5 barrels or alternatively may be about 2 barrels.
  • the polymeric solution, the spacer, and the activator are sequentially pumped to the formation.
  • the activator is pumped first and the polymeric solution is pumped behind the spacer. Within the subterranean formation, the polymeric solution and the activator are no longer separated and thus contact each other, resulting in the formation of the precipitate.
  • the polymeric solution and the activator may be displaced into the wellbore before or during the circulation/squeezing of a wellbore servicing fluid in the wellbore. hi an embodiment, they may be pumped downhole after the discovery that at least a portion of the wellbore servicing fluid is being lost to the subterranean formation. At this point, the circulation/squeezing of the wellbore servicing fluid in the wellbore may be terminated to allow for the formation of the precipitate within the formation. Once the precipitate has been formed, the circulation/squeezing of the fluid in the wellbore may then be resumed. The formation of the precipitate may occur within 1 minute of the initial contact between the polymeric solution and the activator. However, typically one waits for a period of in a range of from about 30 minutes to about 4 hours before passing the wellbore servicing fluid into the wellbore again.
  • the precipitate may be used to reduce a pre-completion loss to a subterranean formation.
  • a "pre-completion loss" refers to a loss of fluid to a subterranean formation that occurs before the wellbore is completed, i.e., before the annulus of the wellbore has been sealed by a sealant composition, e.g., a cement composition.
  • the pre-completion loss is the loss of a drilling fluid during its circulation through a wellbore both during and after the drilling of the wellbore.
  • the pre- completion loss is the loss of a cement slurry (or other type of sealant composition) during primary cementing.
  • the precipitate may be used to prevent a post-completion loss to the subterranean formation.
  • a post-completion loss refers to a loss of fluid to a subterranean formation that occurs after the wellbore is completed, i.e., after the annulus of the wellbore has been sealed by a sealant composition, e.g., a cement composition.
  • the post-completion loss may be that of a secondary sealant composition such as a cement composition.
  • the secondary sealant composition may be placed in one or more permeable zones present in the wellbore using a squeeze technique known in the art.
  • the permeable zones may extend, for example, through the wall of a conduit positioned in the wellbore, a sealant/cement column in the annulus of the wellbore, a microannulus of the wellbore, or combinations thereof.
  • Examples of those permeable zones include a fissure, a crack, a fracture, a streak, a flow channel, a void, and combinations thereof.
  • the post-completion loss may be the loss of a fluid, e.g., a workover fluid, during a production enhancement operation, e.g., a workover operation.
  • the precipitate may be removed to prepare the formation for the production of oil, gas, and/or water. That is, the precipitate may be removed to prevent it from blocking the flow of such natural resources from the formation. It may also be removed to avoid contaminating any water produced by the formation.
  • the precipitate may be removed by dissolving it in a fluid in which it is soluble such as fresh water, thereby providing a simple and inexpensive way to eliminate the precipitate.
  • the precipitate may be removed by water that is initially produced by the formation, or alternatively, it may be removed by water that is intentionally pumped into the wellbore. Examples of compounds that may be employed to dissolve the precipitate include but are not limited to fresh water and brines such as halide brines, e.g., sodium chloride brine.
  • the methods described above for reducing the loss of a wellbore servicing fluid to the subterranean formation utilize a polymeric solution and an activator.
  • the volume ratio of the polymeric solution to the activator may be in a range of from about 50:50 to about 70:30.
  • the polymeric solution comprises a polymer and a fluid in which the polymer has a relatively high solubility.
  • the polymeric solution may also include but is not limited to lost circulation materials, weighting agents such as barite, acid soluble particles, and combinations thereof.
  • An example of a suitable polymeric solution includes polyvinylpyrrolidone (PVP) in water, which is commercially available from ISP Technologies, Lie.
  • VTVTPRINT 540 solution (10% PVP by weight of the aqueous solution) and from Halliburton Energy Services, Inc. under the tradename of PERFORMATROL polymer (10% PVP by weight of the aqueous solution).
  • the amount of the polymer in the polymeric solution may be a range of from about 1% to about 90%, alternatively from about 5% to about 50 %, by weight of the polymeric solution.
  • Suitable activators include formate brines (e.g., potassium formate, sodium formate, and cesium formate), acetate brines (e.g., potassium acetate, sodium acetate, and cesium acetate), oxalate brines (e.g., potassium oxalate, sodium oxalate, and cesium oxalate), halide brines (e.g., zinc bromide), and combinations thereof.
  • the amount of the potassium formate in the activator may be in a range of from about 10% to about 78%, or alternatively from about 50% to about 78%, by weight of the total formate brine. Modifications to the Foregoing Embodiments
  • the activator may also serve as the solvent in which the polymer is dissolved.
  • the polymer may be coated with a material that prevents it from initially contacting the activator/solvent.
  • the polymer and the activator may be concurrently pumped downhole without forming a precipitate.
  • the coating may eventually dissolve such that the activator/solvent contacts the polymer and thus forms the precipitate.
  • the period of time required for the coating to completely dissolve may be sufficient to allow the polymer to be pumped into a crack or void in a subterranean formation. As a result, the formation of the precipitate is time delayed.
  • PERFORMATROL solution i.e., the PVP solution
  • PVP solution a PERFORMATROL solution
  • 16 lbs/gal of barite weighting agent were added to each PERFORMATROL solution sample.
  • the PERFORMATROL solution samples remained pumpable after the addition of the barite weighting agent.
  • the precipitate withstood a 500 psi differential such that no mud could pass through the precipitate at this pressure.
  • the thickness of the seal was measured as 1/8 inch.
  • the precipitate was also heated on a hotplate to determine the temperatures at which it is stable. The precipitate exhibited no apparent decomposition at temperatures less than or equal to 250 0 F.
  • the precipitate can be dissolved relatively quickly with freshwater or sodium chloride brine. Further, it may also be removed at a relatively slow rate with calcium chloride brine or calcium bromide brine. It is desirably insoluble in the ACCOLADE drilling mud.
  • Example 1 The procedure followed in Example 1 was repeated with different activators. More specifically, the potassium formate brines were replaced with sodium formate brines, cesium formate brines, and zinc bromide brines. AU of those brines caused the PVP to precipitate out of solution.

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Organic Chemistry (AREA)
  • Materials Engineering (AREA)
  • Ceramic Engineering (AREA)
  • Inorganic Chemistry (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Structural Engineering (AREA)
  • Dispersion Chemistry (AREA)
  • Compositions Of Macromolecular Compounds (AREA)
  • Processes Of Treating Macromolecular Substances (AREA)
  • Curing Cements, Concrete, And Artificial Stone (AREA)

Abstract

L'invention concerne des procédés permettant de réduire la perte d'un fluide d'entretien d'un puits de forage dans une formation souterraine. Une solution polymère et un activateur peuvent être mis en contact dans la formation, formant ainsi un précipité permettant de bloquer au moins partiellement l'écoulement ultérieur du fluide dans la formation. Le fluide peut être, par exemple, un fluide de forage, une composition de ciment, un fluide de reconditionnement ou des combinaisons de ceux-ci. La solution polymère peut comprendre une solution aqueuse de polyvinylpyrrolidone et l'activateur peut comprendre une saumure de formiate. Dans un mode de réalisation, la solution polymère et l'activateur sont mis en contact avant l'achèvement d'une opération de forage dans le puits de forage. Dans un autre mode de réalisation, ils sont mis en contact avant l'achèvement d'une opération de cimentatation principale dans le puits de forage. Encore dans un autre mode de réalisation, ils sont mis en contact avant l'achèvement d'une opération de cimentation secondaire dans le puits de forage. En fonction des besoins, le précipité peut être retiré facilement et rapidement de la formation souterraine par dissolution de celui-ci dans de l'eau douce.
PCT/GB2006/001244 2005-04-19 2006-04-05 Compositions et procedes d'utilisation d'un precipite polymere permettant de reduire la perte de fluide dans une formation souterraine Ceased WO2006111703A2 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
EP06726648A EP1891177A2 (fr) 2005-04-19 2006-04-05 Compositions et procedes d'utilisation d'un precipite polymere permettant de reduire la perte de fluide dans une formation souterraine
NO20075890A NO20075890L (no) 2005-04-19 2007-11-16 Fremgangsmate og polymer losning til behandling av underjordiske formasjoner for a redusere fluidtap

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US11/109,354 2005-04-19
US11/109,150 2005-04-19
US11/109,150 US7943555B2 (en) 2005-04-19 2005-04-19 Wellbore treatment kits for forming a polymeric precipitate to reduce the loss of fluid to a subterranean formation
US11/109,354 US7905287B2 (en) 2005-04-19 2005-04-19 Methods of using a polymeric precipitate to reduce the loss of fluid to a subterranean formation

Publications (2)

Publication Number Publication Date
WO2006111703A2 true WO2006111703A2 (fr) 2006-10-26
WO2006111703A3 WO2006111703A3 (fr) 2007-03-29

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Application Number Title Priority Date Filing Date
PCT/GB2006/001244 Ceased WO2006111703A2 (fr) 2005-04-19 2006-04-05 Compositions et procedes d'utilisation d'un precipite polymere permettant de reduire la perte de fluide dans une formation souterraine
PCT/GB2006/001286 Ceased WO2006111708A1 (fr) 2005-04-19 2006-04-10 Compositions et procedes pour l’utilisation d’un precipite de polymeres pour reduire la perte de fluides vers une formation souterraine

Family Applications After (1)

Application Number Title Priority Date Filing Date
PCT/GB2006/001286 Ceased WO2006111708A1 (fr) 2005-04-19 2006-04-10 Compositions et procedes pour l’utilisation d’un precipite de polymeres pour reduire la perte de fluides vers une formation souterraine

Country Status (3)

Country Link
EP (1) EP1891177A2 (fr)
NO (1) NO20075890L (fr)
WO (2) WO2006111703A2 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7786049B2 (en) 2003-04-10 2010-08-31 Halliburton Energy Services, Inc. Drilling fluids with improved shale inhibition and methods of drilling in subterranean formations

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
DK3041910T3 (da) * 2013-09-06 2020-06-08 Isp Investments Llc Fluidsammensætning omfattende tværbunden polyvinylpyrrolidon til oliefeltsapplikationer

Family Cites Families (7)

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Publication number Priority date Publication date Assignee Title
US2294078A (en) * 1934-03-14 1942-08-25 Dow Chemical Co Method of treating wells
US3554287A (en) * 1966-11-07 1971-01-12 Dow Chemical Co Gelable composition, resulting gelled polymer composition and use thereof
US4018286A (en) * 1975-11-06 1977-04-19 Phillips Petroleum Company Controlled well plugging with dilute polymer solutions
US4098337A (en) * 1977-07-01 1978-07-04 Marathon Oil Company Method of improving injectivity profiles and/or vertical conformance in heterogeneous formations
US4792412A (en) * 1982-08-31 1988-12-20 Mobil Oil Corporation High temperature stable aqueous brine fluids viscosified by polyvinylpyrrolidone
IE850114L (en) * 1985-01-18 1986-07-18 Cities Service Oil & Gas Gels for retarding fluid flow
WO1996004348A1 (fr) * 1994-07-29 1996-02-15 Baker Hughes Incorporated Additifs de fluide de forage pour environnements enclins aux formations hydriques comportant des materiaux sensibles a l'eau, fluides de forage contenant lesdits additifs et procede de forage dans lesdits environnements

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7786049B2 (en) 2003-04-10 2010-08-31 Halliburton Energy Services, Inc. Drilling fluids with improved shale inhibition and methods of drilling in subterranean formations

Also Published As

Publication number Publication date
NO20075890L (no) 2008-01-16
WO2006111708A1 (fr) 2006-10-26
EP1891177A2 (fr) 2008-02-27
WO2006111703A3 (fr) 2007-03-29

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