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WO2018128537A1 - Compositions de suspension de réticulant et applications - Google Patents

Compositions de suspension de réticulant et applications Download PDF

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Publication number
WO2018128537A1
WO2018128537A1 PCT/MY2017/000001 MY2017000001W WO2018128537A1 WO 2018128537 A1 WO2018128537 A1 WO 2018128537A1 MY 2017000001 W MY2017000001 W MY 2017000001W WO 2018128537 A1 WO2018128537 A1 WO 2018128537A1
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WIPO (PCT)
Prior art keywords
composition
weight
amount
total weight
present
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Application number
PCT/MY2017/000001
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English (en)
Inventor
Diankui Fu
Hai Liu
Jin Yu ZHAO
Kong Teng Ling
Soo Hui Goh
Original Assignee
Schlumberger Technology Corporation
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Technology B.V.
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.)
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Publication date
Application filed by Schlumberger Technology Corporation, Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Technology B.V. filed Critical Schlumberger Technology Corporation
Priority to CN201780082206.5A priority Critical patent/CN110139910A/zh
Priority to PCT/MY2017/000001 priority patent/WO2018128537A1/fr
Publication of WO2018128537A1 publication Critical patent/WO2018128537A1/fr

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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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/70—Compositions for forming crevices or fractures characterised by their form or by the form of their components, e.g. foams
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
    • C09K8/887—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material

Definitions

  • Embodiments of the present disclosure relate to methods and compositions for treating a subterranean formation. Specifically, embodiments of this disclosure relate to methods and compositions for delivering and using a crosslinker for treating a subterranean formation.
  • Fluids with a viscosity that is individually tailored for a variety of physical and chemical conditions are needed to treat subterranean formations for the recovery of hydrocarbons.
  • a vicosifier will be introduced to a fluid, then pumped down a wellbore to fracture the formation rock.
  • the variety of viscosifiers commercially available for this purpose is vast.
  • a small subset of commodity grade viscosifiers is selected for use.
  • These viscosifiers may benefit from the presence of a crosslinker to increase or otherwise tailor the resulting fluid viscosity.
  • the crosslinkers are selected for their ability to encourage crosslinking of the viscosifier depending upon the formation conditions and viscosifier properties.
  • Borate crosslinked fluids are favored over metal-crosslinked fluids because the former are not sensitive to mechanical shearing and can recover their viscosity after shearing. It has been recognized by the industry that good shear recovery is important to the success of hydraulic fracturing treatment. It is known to the industry that guar-based fracturing fluid crosslinked with borate can significantly recover its viscosity after high shear. Lowering polymer loading is known to improve fracture conductivity, however it will also reduce fluid viscosity and the ability to recover after shear. One of the biggest challenges for formulating a low polymer loading guar fracturing fluid for use in low temperature environments is to secure both a reasonably high viscosity and a short shear recovery time.
  • Embodiments of the disclosure relate to a method of treating a subterranean formation penetrated by a wellbore, the method including: a. utilizing a composition including: boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay; b. combining the composition with a mixture including a viscosifier and an aqueous medium to form a treatment fluid; and c. contacting the formation with the treatment fluid to treat the formation.
  • a composition including: boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay
  • b. combining the composition with a mixture including a viscosifier and an aqueous medium to form a treatment fluid
  • c. contacting the formation with the treatment fluid to treat the formation.
  • Embodiments of the disclosure relate to a method of treating a subterranean formation penetrated by a wellbore, including: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; b. combining the dry mixture with a viscosified fluid medium including a hydrocarbon fluid and an organophilic clay to form a composition; c. combining the composition with a mixture including a viscosifier and aqueous medium to form a treatment fluid; and d. contacting the formation with the treatment fluid to treat the formation.
  • Embodiments of the disclosure relate to a method of preparing a composition, including: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and b. combining the dry mixture with a viscosified fluid medium including a hydrocarbon fluid and an organophilic clay to form the composition.
  • FIG. 1 is a plot of viscosity and shear rate as a function of time showing rheology profiles for various fracturing fluids with varying polymer loadings for an embodiment of the disclosure.
  • FIG. 2 is a plot of viscosity and shear rate as a function of time showing shear rate recovery for various fracturing fluids with varying polymer loadings for an embodiment of the disclosure.
  • FIG. 3 is a plot of viscosity and shear rate as a function of time for various crosslinked fracturing fluids including crushed and uncrushed breaker for an additional embodiment of the disclosure.
  • boron is delivered into the polymer solution for crosslinking in a number of forms, such as dissolved borax, slurry of solid borax or ulexite, boric acid solution, as well as other boron sources.
  • concentration of the boron-containing crosslinker becomes more important, the amount of material transported to location for a treatment as well as the rate at which it is added on-the-fly into the polymer solution becomes logistically significant. It is a logistical advantage to have the chemical additives for a fracturing treatment as compact and/or concentrated as practical.
  • a method of treating a subterranean formation penetrated by a wellbore comprising, consisting of, or consisting essentially of: a. utilizing a composition comprising, consisting of, or consisting essentially of boric acid; sodium tetraborate pentahydrate; a pH adjusting agent; a hydrocarbon fluid; and an organophilic clay; b. combining the composition with a mixture comprising a viscosifier and an aqueous medium to form a treatment fluid; and c. contacting the formation with the treatment fluid to treat the formation.
  • the pH adjusting agent can be selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and the hydrocarbon fluid can be diesel or any other nonaqueous fluid medium.
  • the pH of the composition may be tailored to maximize the transportation, stability, and/or crosslinking properties of the compositions; and can range from pH of 8.90 to about 9.80 for low temperature applications (68 to 80 °F) and can range from pH of 12.12 to 12.74 for high temperature applications (200 to 290°F).
  • the boric acid can be present in the composition in an amount of from about 6% to about 13% or about 7% to about 10% or about 7% to about 8%, by weight, based upon total weight of the composition.
  • the sodium tetraborate pentahydrate can be present in the composition in an amount of from about 6% to about 13% or about 7% to about 10% or about 7% to about 8%, by weight, based upon total weight of the composition.
  • the pH adjusting agent can be present in the composition in an amount of from about 2% to about 5% or about 2% to about 4% or about 2% to about 3%, by weight, based upon total weight of the composition.
  • the diesel can be present in the composition in an amount of from about 65% to about 85% or about 70% to about 85% or about 75% to about 80%, by weight, based upon total weight of the composition.
  • the organophilic clay can be present in the composition in an amount of from about 3% to about 4.5% or about 3.5% to about 4.5% or about 3.5% to about 4%, by weight, based upon total weight of the composition.
  • the composition can be free or substantially free of water, or can comprise less than about 10% or less than 5% or less than 2% or less than 1% or less than 0.5% water, by weight, based upon total weight of the composition.
  • the composition can be added to the mixture in an amount of from about 0.5 to about 3 or about 1 to about 3 or about 1 to about 2 gallons per thousand gallons of the mixture.
  • the viscosifier can be present in the treatment fluid in an amount of at most about 18 or at most about 16 or at most about 14 or from about 14 to about 18 or from about 14 to about 16 pounds per thousand gallons of the treatment fluid.
  • the temperature of the subterranean formation treated with the treatment fluid can be at most about 30°C or at most about 25°C or at most about 20°C or from about 15°C to about 20°C.
  • the boric acid, the sodium tetraborate pentahydrate, and the pH adjusting agent can be dry mixed to form a dry mixture, the organophilic clay can be added to the hydrocarbon fluid to form a viscosified fluid medium; and the dry mixture can be combined with the viscosified fluid medium to form the composition described herein.
  • the viscosifier can comprise a hydrated polymer selected from the group consisting of guar, high-molecular weight polysaccharides composed of mannose and galactose sugars, guar derivatives such as hydroxypropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG), synthetic polymer.
  • guar derivatives such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose (CMHEC) may also be used. Any useful polymer may be used in either crosslinked form, or without crosslinker in linear form.
  • Xanthan, diutan, and scleroglucan, three biopolymers have been shown to be useful as viscosifying agents.
  • Another viscosifying agent is schizophyllan, which in some cases crosslinks with boron on a very slow kinetic: order of >10 hours in some conditions.
  • Synthetic polymers such as, but not limited to, polyvinylalcohol, polyacrylamide and polyacrylate polymers and copolymers, are used typically for high-temperature applications, but could also be used herein.
  • viscosifier is a water-dispersible, nonionic, hydroxyalkyl galactomannan polymer or a substituted hydroxyalkyl galactomannan polymer.
  • hydroxyalkyl galactomannan polymers include, but are not limited to, hydroxy-Cl -C4- alkyl galactomannans, such as hydroxy-Cl-C4-alkyl guars.
  • hydroxyalkyl guars include hydroxyethyl guar (HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixed C2-C4, C2/C3, C3/C4, or C2/C4 hydroxyalkyl guars. Hydroxymethyl groups can also be present in any of these.
  • substituted hydroxyalkyl galactomannan polymers are obtainable as substituted derivatives of the hydroxy-Cl-C4-alkyl galactomannans, which include: 1) hydrophobically-modified hydroxyalkyl galactomannans, e.g., Cl-C18-alkyl-substituted hydroxyalkyl galactomannans, e.g., wherein the amount of alkyl substituent groups can be about 2% by weight or less of the hydroxyalkyl galactomannan; and 2) poly(oxyalkylene)- grafted galactomannans.
  • Poly(oxyalkylene)-grafts thereof can comprise two or more than two oxyalkylene residues; and the oxyalkylene residues can be C1-C4 oxyalkylenes.
  • Mixed- substitution polymers comprising alkyl substituent groups and poly(oxyalkylene) substituent groups on the hydroxyalkyl galactomannan are also useful herein.
  • the ratio of alkyl and/or poly(oxyalkylene) substituent groups to mannosyl backbone residues can be about 1 :25 or less, i.e.
  • the ratio can be: at least or about 1 :2000, 1 :500, 1 : 100, or 1 :50; or up to or about 1 :50, 1 :40, 1:35, or 1 :30.
  • Combinations of galactomannan polymers can also be used.
  • galactomannans comprise a polymannose backbone attached to galactose branches that are present at an average ratio of from 1 : 1 to 1 :5 galactose branches:mannose residues.
  • Galactomannans useful herein can comprise a l ⁇ 4-linked 13-D- mannopyranose backbone that is l ⁇ 6-linked to a-D-galactopyranose branches.
  • Galactose branches can comprise from 1 to about 5 galactosyl residues; in various embodiments, the average branch length can be from 1 to 2, or from 1 to about 1.5 residues.
  • Branches can be monogalactosyl branches.
  • the ratio of galactose branches to backbone mannose residues can be, approximately, from 1 : 1 to 1 :3, from 1 : 1.5 to 1 :2.5, or from 1 : 1.5 to 1 :2, on average.
  • the galactomannan can have a linear polymannose backbone.
  • the galactomannan can be natural or synthetic. Natural galactomannans useful herein include plant and microbial (e.g., fungal) galactomannans.
  • legume seed galactomannans can be used, examples of which include, but are not limited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum (e.g., from Cyamopsis tetragonoloba seeds).
  • tara gum e.g., from Cesalpinia spinosa seeds
  • guar gum e.g., from Cyamopsis tetragonoloba seeds.
  • embodiments may be described or exemplified with reference to guar, such as by reference to hydroxy-Cl-C4-alkyl guars, such descriptions apply equally to other galactomannans, as well.
  • the mixture can further comprise any one or combination of the following: an alcohol having from 1 1 to 14 carbon atoms per molecule, and which is both ethoxylated and butoxylated; tetramethyl ammonium chloride; and an ammonium persulfate breaker.
  • the ammonium persulfate breaker can be selected from the group consisting of diammonium peroxidisulphate, encapsulated ammonium persulfate, and combinations thereof.
  • a method of treating a subterranean formation penetrated by a wellbore comprising, consisting of or consisting essentially of: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; b. combining the dry mixture with a viscosified fluid medium comprising a hydrocarbon fluid and an organophilic clay to form the composition as described herein; c. combining the composition with the mixture comprising a viscosifier and aqueous medium, as described herein, to form the treatment fluid as described herein; and d. contacting the formation with the treatment fluid to treat the formation.
  • a method of preparing the composition as described herein comprising: a. preparing a dry mixture of boric acid; sodium tetraborate pentahydrate; and a pH adjusting agent selected from the group consisting of calcium hydroxide, potassium hydroxide, sodium hydroxide, potassium carbonate, an amine containing compound, or a combination thereof; and b. combining the dry mixture with a viscosified fluid medium comprising the hydrocarbon fluid and the organophilic clay to form the composition.
  • Fluids incorporating polymer based viscosifiers may have any suitable viscosity, such as a viscosity value of about 50 mPa-s or greater at a shear rate of about 100 s— 1, or about 75 mPa-s or greater at a shear rate of about 100 s-1, or about 100 mPa-s or greater at a shear rate of about 100 s-1 , at treatment temperature as described herein.
  • the fluid may be nonfoamed, foamed, or energized, depending upon the particular formation properties and treatment objective.
  • a gas component can be included and can be produced from any suitable gas that forms a foam or an energized fluid when introduced into the aqueous medium.
  • the gas component comprises a gas selected from the group consisting of nitrogen, air, carbon dioxide and any mixtures thereof.
  • the gas component may in some cases assist in a fracturing operation and/or well clean-up process.
  • the fluid may contain from about 10% to about 90% volume gas component based upon total fluid volume percent, or from about 30% to about 80% volume gas component based upon total fluid volume percent, or from about 40% to about 70% volume gas component based upon total fluid volume percent.
  • the treatment fluid may further contain other additives and chemicals. These include, but are not necessarily limited to, materials such as surfactants, breakers, breaker aids, oxygen scavengers, alkaline pH adjusting agents, clay stabilizers (i.e.
  • KC1, TMAC high temperature stabilizers
  • alcohols proppant, scale inhibitors, corrosion inhibitors, fluid-loss additives, bactericides, and the like.
  • one, a portion, or all of these components may be encapsulated. Also, they may include a co-surfactant to optimize viscosity or to minimize the formation of stable emulsions that contain components of crude oil.
  • the treatment of the subten anean formation can be a hydraulic fracturing treatment of the subterranean formation.
  • Techniques for hydraulically fracturing a subterranean formation will be known to persons of ordinary skill in the art, and will involve pumping the fracturing fluid into the borehole and out into the surrounding formation. The fluid pressure is above the minimum in situ rock stress, thus creating or extending fractures in the formation. See Stimulation Engineering Handbook, John W. Ely, Pennwell Publishing Co., Tulsa, Okla. (1994), U.S. Pat. No. 5,551,516 (Normal et al.), "Oilfield Applications", Encyclopedia of Polymer Science and Engineering, vol. 10, pp. 328-366 (John Wiley & Sons, Inc. New York, N.Y., 1987) and references cited therein, the disclosures of which are incorporated herein by reference thereto.
  • a hydraulic fracturing consists of pumping a proppant-free viscous fluid, or pad, usually water with some fluid additives to generate high viscosity, into a well faster than the fluid can escape into the formation so that the pressure rises and the rock breaks, creating artificial fractures and/or enlarging existing fractures. Then, proppant particles are added to the fluid to form a slurry that is pumped into the fracture to prevent it from closing when the pumping pressure is released.
  • the proppant suspension and transport ability of the treatment base fluid traditionally depends on the type of viscosifying agent added.
  • fluids such as the treatment fluids described hererin may be used in the pad treatment, the proppant stage, or both.
  • the components of the treatment fluid may be mixed on the surface.
  • a portion of the treatment fluid may be prepared on the surface (such as the composition and/or the mixture as described herein) and pumped down tubing while another portion could be pumped down the annular to mix down hole.
  • Another embodiment includes the use of treatment fluids as described herein for cleanup.
  • cleaning or "fracture cleanup” refers to the process of removing the fracture fluid (without the proppant) from the fracture and wellbore after the fracturing process has been completed.
  • Techniques for promoting fracture cleanup traditionally involve reducing the viscosity of the fracture fluid as much as practical so that it will more readily flow back toward the wellbore.
  • slurries and fluids as described herein are useful for gravel packing a wellbore.
  • a gravel packing fluid it can comprise gravel or sand and other optional additives such as filter cake clean up reagents such as chelating agents referred to above or acids (e.g. hydrochloric, hydrofluoric, formic, acetic, citric acid) corrosion inhibitors, scale inhibitors, biocides, leak-off control agents, among others.
  • suitable gravel or sand is typically having a mesh size between 8 and 70 U.S. Standard Sieve Series mesh.
  • a slurry crosslinker composition was prepared in accordance with the disclosure, and with the component amounts as shown in Table 1 below.
  • FIG. 1 shows the fluid rheology profiles of the fracturing fluid formulations A, B and 5 C using polymer loading varying from 14 lb m /1000gal to 181b m /1000gal.
  • the fluid formulations each show a viscosity higher than lOOcP @100sec-l when tested at 68°F (20°C).
  • FIG. 2 shows that fracturing fluid formulations A, B and C (each having low polymer loadings) have acceptable shear recovery.
  • FIG. 3 shows that the crosslinked fluid formulations D, E and F can be broken by0 using encapsulated ammonium persulfate breakers which have been crushed (formulation F) and by using unencapsulated ammonium persulfate breakers (formulation C) when tested at 68°F (20°C).

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  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Lubricants (AREA)
  • Compositions Of Macromolecular Compounds (AREA)

Abstract

L'invention concerne un procédé de traitement d'une formation souterraine pénétrée par un puits de forage, comprenant : a. l'utilisation d'une composition comprenant : de l'acide borique ; du tétraborate de sodium pentahydraté ; un agent de réglage du pH ; un fluide hydrocarboné ; et une argile organophile ; b. la combinaison de la composition avec un mélange comprenant un viscosifiant et un milieu aqueux pour former un fluide de traitement ; et c. la mise en contact de la formation avec le fluide de traitement pour traiter la formation.
PCT/MY2017/000001 2017-01-05 2017-01-05 Compositions de suspension de réticulant et applications WO2018128537A1 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
CN201780082206.5A CN110139910A (zh) 2017-01-05 2017-01-05 交联剂浆料组合物及应用
PCT/MY2017/000001 WO2018128537A1 (fr) 2017-01-05 2017-01-05 Compositions de suspension de réticulant et applications

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Application Number Priority Date Filing Date Title
PCT/MY2017/000001 WO2018128537A1 (fr) 2017-01-05 2017-01-05 Compositions de suspension de réticulant et applications

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Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0594363A1 (fr) * 1992-10-20 1994-04-27 Halliburton Company Fluide de fracturation réticulé au borate
US6024170A (en) * 1998-06-03 2000-02-15 Halliburton Energy Services, Inc. Methods of treating subterranean formation using borate cross-linking compositions
US20110030962A1 (en) * 2009-08-07 2011-02-10 Parris Michael D Aqueous crosslinker slurry compositions and applications
US20140290943A1 (en) * 2013-03-29 2014-10-02 Schlumberger Technology Corporation Stabilized Fluids In Well Treatment
WO2016033533A1 (fr) * 2014-08-29 2016-03-03 Independence Oilfield Chemicals, LLC Procédé et matériaux de fracturation hydraulique avec retard de réticulation des agents gélifiants

Family Cites Families (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN106062306A (zh) * 2014-01-24 2016-10-26 斯伦贝谢技术有限公司 再利用水力压裂中未处理的产出水的方法

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0594363A1 (fr) * 1992-10-20 1994-04-27 Halliburton Company Fluide de fracturation réticulé au borate
US6024170A (en) * 1998-06-03 2000-02-15 Halliburton Energy Services, Inc. Methods of treating subterranean formation using borate cross-linking compositions
US20110030962A1 (en) * 2009-08-07 2011-02-10 Parris Michael D Aqueous crosslinker slurry compositions and applications
US20140290943A1 (en) * 2013-03-29 2014-10-02 Schlumberger Technology Corporation Stabilized Fluids In Well Treatment
WO2016033533A1 (fr) * 2014-08-29 2016-03-03 Independence Oilfield Chemicals, LLC Procédé et matériaux de fracturation hydraulique avec retard de réticulation des agents gélifiants

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