WO2013043243A1 - Compositions et procédés de traitement de formations souterraines à température élevée - Google Patents

Compositions et procédés de traitement de formations souterraines à température élevée Download PDF

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Publication number
WO2013043243A1
WO2013043243A1 PCT/US2012/043308 US2012043308W WO2013043243A1 WO 2013043243 A1 WO2013043243 A1 WO 2013043243A1 US 2012043308 W US2012043308 W US 2012043308W WO 2013043243 A1 WO2013043243 A1 WO 2013043243A1
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Prior art keywords
well treatment
treatment fluid
high temperature
fluid
foamed
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PCT/US2012/043308
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English (en)
Inventor
Paul S. Carman
Original Assignee
Gupta, D.V. Satyanarayana
Baker Hughes Incorporated
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Priority claimed from US13/236,378 external-priority patent/US8691734B2/en
Application filed by Gupta, D.V. Satyanarayana, Baker Hughes Incorporated filed Critical Gupta, D.V. Satyanarayana
Priority to MX2014003324A priority Critical patent/MX368317B/es
Priority to RU2014115672/03A priority patent/RU2014115672A/ru
Priority to CN201280045707.3A priority patent/CN104024369A/zh
Priority to AU2012313410A priority patent/AU2012313410A1/en
Priority to CA2849248A priority patent/CA2849248C/fr
Priority to NZ621852A priority patent/NZ621852B2/en
Priority to BR112014006604A priority patent/BR112014006604A2/pt
Priority to EP12731854.1A priority patent/EP2758488A1/fr
Publication of WO2013043243A1 publication Critical patent/WO2013043243A1/fr

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    • 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
    • C09K8/602—Compositions for stimulating production by acting on the underground formation containing surfactants
    • 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
    • C09K8/602—Compositions for stimulating production by acting on the underground formation containing surfactants
    • C09K8/604—Polymeric surfactants
    • 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
    • C09K8/703—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
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/725—Compositions containing 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
    • C09K8/60—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
    • C09K8/882—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
    • 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
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/24—Bacteria or enzyme containing gel breakers
    • 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
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/26—Gel breakers other than bacteria or enzymes

Definitions

  • the invention relates to methods and compositions for treating high temperature subterranean formations. More particularly, it relates to methods and compositions for treating a subterranean formation penetrated by a wellbore into which a high temperature energized or foamed well treatment fluid is injected at temperatures of up to about 500 °F (260 °C).
  • well treatment fluids for hydraulic fracturing contain guar gum or guar gum derivatives or viscoelastic surfactants as thickeners to assist in proppant transport, friction reduction, fluid loss control, and controlling fracture geometry.
  • the hydraulic fracturing fluids generally transport proppant into the fracture to prevent the fracture from fully closing. Besides being able to place the proppant in the fracture, the fluid must be able to degrade by lowering its viscosity so that a low viscosity fluid results that can be easily cleaned out of the fracture just prior to hydrocarbon production.
  • a foaming agent such as nitrogen and carbon dioxide.
  • a mixture of such gases may be used.
  • a mixture of two of such gases is referred to as a binary composition.
  • the word "energized” refers to a fluid containing two phases whereby less than 53 volume percent of the internal phase is either a gas or a liquid (e.g. nitrogen or liquid C0 2 ).
  • the term “foamed” refers to a fluid wherein greater than 53 volume percent of the internal phase of the fluid is either a gas or a liquid. Energized or foamed fluids are particularly applicable to under-pressured gas reservoirs and wells which are rich in swellable and migrating clays.
  • guar-based polymers readily undergo auto-degradation by a number of methods, usually within periods of time shorter than what is necessary to complete the fracturing treatment. The degradation generally gets worse as the temperatures continue to increase. Increasing temperatures exasperates this behavior. Most degradation results in the cleavage of the polymer chains, which simultaneously reduces the fluid's viscosity. This can be due to oxidation from residual amounts of air entrained in the fluid, thermal induced cleavage of the acetal linkage along the polymer backbone, hydrolysis of the polymer, or a combination thereof.
  • a high temperature well treatment fluid that is capable of fracturing a subterranean formation in temperatures of up to about 500 °F (260 °C) is provided as an embodiment of the present invention.
  • the high temperature well treatment fluid includes water, a high molecular weight synthetic copolymer and a crosslinking agent.
  • the high temperature well treatment fluid may further contain a pH buffer.
  • the high molecular weight synthetic copolymer is derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate.
  • the copolymer comprises about 30 - about 80 wt. % acrylamide, about 20 - about 50 wt. % acrylamidomethylpropanesulfonic acid, and about 1 - about 5 wt. % vinyl phosphonate.
  • the pH buffer enables the high temperature well treatment fluid to maintain a pH in a range of about 4.5 to about 5.25.
  • a high temperature foamed or energized well treatment fluid is also capable of fracturing a subterranean formation in temperatures of up to about 500 °F (260 °C) is provided as an embodiment of the present invention.
  • the high temperature foamed or energized well treatment fluid includes water, a high molecular weight synthetic copolymer, a crosslinking agent and, optionally, a pH buffer and a foaming agent such as a foaming gas like nitrogen and carbon dioxide and, optionally, a non-gaseous foaming agent.
  • the pH of the high temperature well treatment fluid may be between from about 4.0 and about 6.0 and the pH buffer enables the high temperature well treatment fluid to maintain the pH range.
  • the foamed or energized fluid contains a high molecular weight synthetic copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate.
  • the copolymer comprises about 30 - about 80 wt. % acrylamide, about 20 - about 50 wt. % acrylamidomethylpropanesulfonic acid, and about 1 - about 5 wt. % vinyl phosphonate.
  • a method of fracturing subterranean formation having a temperature of up to about 500 °F (260 °C) is provided.
  • a high temperature well treatment fluid comprising water; a high molecular weight copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate; a crosslinking agent and a pH buffer is contacted with at least a portion of the subterranean formation at pressures sufficient to fracture the subterranean formation.
  • the pH buffer maintains a pH of the high temperature well treatment fluid in a range of about 4.5 to about 5.25.
  • Another method of fracturing a subterranean formation is provided as another embodiment of the present invention.
  • water is contacted with a high molecular weight copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate to form a water-soluble polymer.
  • the water-soluble polymer is contacted with a crosslinking agent and a foaming agent to produce a foamed or energized fluid.
  • At least a portion of the subterranean formation is contacted with the foamed or energized fluid at pressures sufficient to fracture the formation.
  • the foamed or energized fluid may further contain a pH buffer, preferably to maintain the pH of the foamed or energized fluid in a range of about 4.0 to about 6.0.
  • additives that are useful in high temperature well treatment fluids described herein can also be used in embodiments of the present invention.
  • Such additives can include additional monomers that can be copolymerized with the high molecular weight polymers of the high temperature well treatment fluids, stabilizers to help the high temperature well treatment fluids perform for extended periods of time, crosslinking agents to help increase the viscosity of the high temperature well treatment fluids, breakers to help break down the high temperature well treatment fluids, surfactants that help with hydration of the high temperature well treatment fluids, and the like.
  • Other suitable compounds that are useful in high temperature well treatment fluids, such as proppant and other additives will be apparent to those of skill in the art and are to be considered within the scope of the present invention.
  • FIG. 1 is a graph of the apparent viscosity of the high temperature well treatment fluid with and without a breaker versus time at various temperatures in accordance with embodiments of the present invention
  • FIG. 2 is a graph of the apparent viscosity of the high temperature well treatment fluid with and without a breaker versus time at 350 °F (176.7 °C) in accordance with embodiments of the present invention
  • FIG. 3 is a graph of the apparent viscosity of the high temperature well treatment fluid with various amounts of copolymer and temperatures in accordance with embodiments of the present invention.
  • FIG. 4 is a graph of the apparent viscosity of the high temperature well treatment fluid with 63 volume percent nitrogen in accordance with embodiments of the present invention.
  • FIG. 5 is a graph of the apparent viscosity of a high temperature well treatment fluid energized with 30 volume percent carbon dioxide in accordance with embodiments of the present invention.
  • a high temperature well treatment fluid that is capable of fracturing a subterranean formation in temperatures of up to about 500 °F (260 °C) is provided as an embodiment of the present invention.
  • the high temperature well treatment fluid comprises water, a high molecular weight synthetic copolymer, a crosslinking agent, and optionally a pH buffer.
  • the high temperature well treatment fluid may be foamed or energized with a foaming agent, such as a foaming gas and, optionally, a non-gaseous foaming agent.
  • a foaming agent such as a foaming gas and, optionally, a non-gaseous foaming agent.
  • the resulting fluid contains two phases - a liquid phase and a gaseous phase.
  • the gaseous internal phase is less than about 53 volume percent, the fluid is referred to as an "energized fluid”.
  • the gaseous internal phase is greater than 53 volume percent, the fluid is referred to as a "foamed fluid”.
  • the high molecular weight synthetic copolymer is derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate.
  • the acrylamide can be derived from at least one amide of an ethylenically unsaturated carboxylic acid.
  • the high molecular weight synthetic copolymer has a K-value of greater than about 375. In an aspect, the K-value ranges between about 50 to about 750; or alternatively, between about 150 to about 350.
  • the K-value i.e. Fikentscher's K-value
  • Fikentscher's K-value is a measure of a polymer's average molecular weight.
  • the high temperature well treatment fluid comprises about 25 wt. % of the high molecular weight copolymer in an emulsion.
  • the high molecular weight copolymer in emulsion can be present in a range of about 10 gallons per 1,000 gallons high temperature well treatment fluid at temperatures of less than 350 °F (176.7 °C) to about 25 gallons per 1,000 gallons high temperature well treatment fluid at 500 °F (260° C).
  • the concentration of the high molecular weight synthetic copolymer depends upon the temperature of the subterranean formation and the duration in which the high molecular weight synthetic copolymer will be exposed to the elevated temperatures. In general, more high molecular weight synthetic copolymer is required at higher temperatures than at the lower temperatures.
  • the copolymer is derived from about 20 - about 90 wt. % acrylamide, about 9 - about 80 wt. % acrylamidomethylpropanesulfonic acid, and about 0.1 - about 20 wt. % vinyl phosphonate; alternatively, about 30 - about 80 wt. % acrylamide, about 25 - about 60 wt. % acrylamidomethylpropanesulfonic acid, and about 0.2 - about 10 wt. % vinyl phosphonate; alternatively, about 40 - about 70 wt. % acrylamide, about 30 - about 40 wt.
  • % acrylamidomethylpropanesulfonic acid and about 1 - about 3 wt. % vinyl phosphonate; or alternatively, about 50 wt. % acrylamide, about 30 wt. % acrylamidomethylpropanesulfonic acid, about 2 wt. % vinyl phosphonate, and a remainder of copolymers of acrylamide and acrylamidomethylpropanesulfonic acid.
  • the high temperature well treatment fluid may further be foamed or energized with a suitable gas or liquid or emulsified with a suitable liquid. Foamed and energized fluids reduce the density by reducing the amount of water without loss of treatment fluid volume and increase the viscosity of the well treatment fluid. Their use is especially desirable when treating a subterranean formation which is sensitive to water (such as under-pressured gas reservoirs like dry coal beds and wells which are which are rich in swellable and migrating clays)) where it is desired to minimize the amount of water in the fluid.
  • under-pressured gas reservoirs like dry coal beds and wells which are which are rich in swellable and migrating clays
  • the foaming agent is present in a quantity to provide, 53 volume percent to in excess of 96 volume percent internal gas for foamed fluids and from 5 to 53 volume percent of internal gas for energized fluids.
  • the amount of foaming agent in the treatment fluid is such to provide an energized fluid between from about 20% to 50% by volume of internal gas or a foamed fluid having from about 63 to about 94% by volume of internal gas.
  • non-gaseous foaming agent it may be desirable to add a non-gaseous foaming agent to the treatment fluid.
  • non-gaseous foaming agents are typically used in conjunction with a foaming gas.
  • Non-gaseous foaming agents often contribute to the stability of the resulting fluid and reduce the requisite amount of water in the fluid.
  • such agents typically increase the viscosity of the fluid. For instance, when the amount of internal gas in the treatment fluid exceeds 30% by volume, a non-gaseous foaming agent may further be added to the fluid in order to create a foamed fluid. The addition of a non-gaseous foaming agent typically increases the viscosity of the treatment fluid.
  • Non-gaseous foaming agents may be amphoteric, cationic or anionic and may include surfactants based on betaines, alpha olefin sulfonates, sulfate ethers, ethoxylated sulfate ethers and ethoxylates.
  • Suitable anionic non-gaseous foaming agents include alkyl ether sulfates, ethoxylated ether sulfates, phosphate esters, alkyl ether phosphates, ethoxylated alcohol phosphate esters, alkyl sulfates and alpha olefin sulfonates.
  • alpha-olefm sulfonates are salts of a monovalent cation such as an alkali metal ion like sodium, lithium or potassium, an ammonium ion or an alkyl-substituent or hydroxyalkyl substitute ammonium in which the alkyl substituents may contain from 1 to 3 carbon atoms in each substituent.
  • the alpha-olefm moiety typically has from 12 to 16 carbon atoms.
  • Preferred alkyl ether sulfates are also salts of the monovalent cations referenced above.
  • the alkyl ether sulfate may be an alkylpoly ether sulfate and contains from 8 to 16 carbon atoms in the alkyl ether moiety.
  • Preferred as anionic surfactants are sodium lauryl ether sulfate (2-3 moles ethylene oxide), Cs-Cio ammonium ether sulfate (2-3 moles ethylene oxide) and a C 14 -C 16 sodium alpha-olefm sulfonate and mixtures thereof.
  • ammonium ether sulfates are especially preferred.
  • Suitable cationic non-gaseous foaming agents include alkyl quaternary ammonium salts, alkyl benzyl quaternary ammonium salts and alkyl amido amine quaternary ammonium salts.
  • non-gaseous foaming agent are alkyl ether sulfates, alkoxylated ether sulfates, phosphate esters, alkyl ether phosphates, alkoxylated alcohol phosphate esters, alkyl sulfates and alpha olefin sulfonates.
  • the amount of foaming agent in the well treatment fluid is that amount sufficient to provide a foam quality between from about 30 to about 98, preferably 90 percent or higher.
  • the foam quality is a measurement of the lowest amount of liquid volume of well treatment fluid that is required to effectuate the desired result.
  • a 90 percent quality foam refers to the use of 100 ml of foamed well treatment fluid which, upon destabilization, rendered 10 ml of liquid well treatment fluid.
  • the pH buffer of the present invention helps maintain a low pH of the high temperature well treatment fluid in a range of about 4.0 to about 6.0.
  • the pH buffer may comprise acetic acid and sodium acetate or a combination of acetic acid, sodium acetate, or formic acid.
  • the amount of pH buffer that is needed is the amount that will effectively maintain a pH of the high temperature well treatment fluid in a range of about 4.5 to about 5.25; or alternatively, in a range of about 4.75 to about 5; or alternatively, about 5.
  • the pH buffer is a true pH buffer, as opposed to a pH adjuster, as will be understood by those of skill in the art.
  • the low pH of the systems and methods described herein aid in clean up of the fluid after well treatment processes.
  • the amount of pH buffer that is needed is the amount that will effectively maintain a pH of the high temperature well treatment fluid in a range of about 5.3 to about 5.75 when the foaming gas is nitrogen and from about 4.1 to about 4.5 when the foaming gas is carbon dioxide.
  • a pH buffer comprising acetic acid and sodium acetate having a pH of about 5 at 25% can be used.
  • other pH buffers can be used, such as acetic acid and formic acid buffers.
  • any pH buffer capable of maintaining a pH of the high temperature well treatment fluid within in a range of about 4.5 to about 5.25 and without interfering with the remaining components of the high temperature well treatment fluids can be used.
  • Other suitable pH buffers will be apparent to those of skill in the art and are to be considered within the scope of the present invention.
  • the pH buffer comprising acetic acid and sodium acetate having a pH of about 5 can be used in a concentration ranging from about 1 gallon per 1,000 gallons high temperature well treatment fluid to about 3 gallons per 1,000 gallons high temperature well treatment fluid, depending upon the temperature of the subterranean formation.
  • the high molecular weight synthetic copolymer can be further copolymerized with other monomers to provide various advantages related to the stability of the high temperature well treatment fluid. Similar to guar-based high temperature well treatment fluids, the viscosity of the high temperature well treatment fluid of the present invention can be significantly enhanced when first copolymerized with small amounts of monomers and crosslinked, at the wellsite, with transition metals, such as iron, titanium, zirconium, chromium, hafnium, aluminum, and combinations thereof.
  • transition metals such as iron, titanium, zirconium, chromium, hafnium, aluminum, and combinations thereof.
  • Suitable monomers that can be copolymerized with the high molecular weight synthetic polymer include monomers selected from the group consisting of an alkali metal of acrylamidomethylpropanesulfonic acid, an ammonium salt of acrylamidomethylpropanesulfonic acid, styrene sulfonate, vinyl sulfonate, N-vinylpyrolidone, N-vinylformamide, N-vinylacetamide, N,N-diallylacetamide, methacrylamide, acrylamide, ⁇ , ⁇ -dimethylacrylamide, methacrylamide, a divalent cation from calcium salt, a divalent cation from magnesium salt, and combinations thereof.
  • alkali metal or ammonium salts of acrylamidomethylpropanesulfonic acid (AMPS), styrene sulfonate or vinyl sulfonate can be copolymerized to add salt tolerance to the high molecular weight synthetic polymer.
  • Divalent cations from calcium salt and magnesium salt are also useful for adding salt tolerance to the high molecular weight synthetic polymer.
  • monomers such as N-vinylamides, N-vinylpyrolidone, N-vinylformamide, N-vinylacetamide, and N-diallylacetamide can also be copolymerized with the high molecular weight synthetic polymer to assist in proppant transport by adsorbing onto the proppant surface.
  • the copolymers of the high molecular weight synthetic copolymer can be made by any polymerization method necessary to produce high molecular weight copolymers.
  • a particularly effective method of producing the copolymers is by invert polymer emulsion because it can be easily metered into a flowing stream of water during fracturing processes and it can be made to rapidly hydrate, which may reduce the amount of equipment needed at the wellsite.
  • the high temperature well treatment fluid of the present invention can also include a stabilizer to help the high temperature well treatment fluids perform for extended periods of time.
  • the stabilizer is sodium thiosulfate, phenothiazine, or combinations thereof.
  • phenothiazine as a stabilizer is described in co-pending U.S. Patent Application Serial No. 12/020,755, filed on January 28, 2008.
  • Another suitable stabilizer is a gel stabilizer that is commercially available as GS-1L that contains sodium thiosulfate from Baker Hughes Incorporated.
  • any stabilizer compound capable of maintaining viscosity of the high temperature well treatment fluid long enough to perform the fracturing process can be used.
  • the amount of stabilizer that can be used includes an effective amount that is capable of maintaining viscosity, i.e. preventing thermal degradation, of the high temperature well treatment fluid long enough to perform the fracturing process.
  • the high temperature well treatment fluid of the present invention can also include a crosslinking agent.
  • a suitable crosslinking agent can be any compound that increases the viscosity of the high temperature well treatment fluid by chemical crosslinking, physical crosslinking, or any other mechanisms.
  • the gellation of the high molecular weight synthetic copolymer can be achieved by crosslinking the high molecular weight synthetic copolymer with metal ions including boron, zirconium, and titanium containing compounds, or mixtures thereof.
  • metal ions including boron, zirconium, and titanium containing compounds, or mixtures thereof.
  • One class of suitable crosslinking agents is zirconium-based crosslinking agents.
  • Suitable crosslinking agents can include zirconium oxychloride, zirconium acetate, zirconium lactate, zirconium malate, zirconium glycolate, zirconium lactate triethanolamine, zirconium citrate, titanium lactate, titanium malate, titanium citrate, titanium, aluminum, iron, antimony, a zirconate -based compound, zirconium triethanolamine, an organozirconate, or combinations thereof.
  • XLW-14 is a particularly suitable zirconate-based crosslinking agent that is commercially available from Baker Hughes Incorporated and described in U.S. Patent No. 4,534,870, which is incorporated by reference in its entirety.
  • the amount of the crosslinking agent needed in the high temperature well treatment fluid depends upon the well conditions and the type of treatment to be effected, but is generally in the range of from about 10 ppm to about 1000 ppm of metal ion of the crosslinking agent in the high molecular weight synthetic polymer fluid.
  • the amount of crosslinking agent that can be used includes an effective amount that is capable of increasing the viscosity of the high temperature well treatment fluid to enable it to perform adequately in fracturing processes.
  • the aqueous polymer solution is crosslinked immediately upon addition of the crosslinking agent to form a highly viscous gel.
  • the reaction of the crosslinking agent can be retarded so that viscous gel formation does not occur until the desired time.
  • zirconium When zirconium is used as a crosslinking agent, zirconium has a built-in delay and is used from 1 gallon per 1 ,000 gallons to 2 gallons per 1,000 gallons depending on the temperature and high molecular weight synthetic polymer concentration in the high temperature well treatment fluid. If extra stability time is required, an additional stabilizer, such as sodium thiosulfate (e.g., GS-1L from BJ Services), can be used in a range of about 1 gallon per 1,000 gallons high temperature well treatment fluid to about 3 gallons per 1,000 gallons high temperature well treatment fluid.
  • the high temperature well treatment fluid of the present invention can also include a surfactant to aid in well treatment processes.
  • the high temperature well treatment fluids of the present invention can take up to about 20 to 30 minutes to adequately hydrate. With the addition of the surfactant, the hydration time is substantially reduced. With the surfactant, the hydration can take less than 5 minutes. 90 - 95 % of the high temperature well treatment fluid of the present invention can be hydrated in about 1 to 2 minutes with a suitable surfactant. The type and concentration of the surfactant can control the hydration time of the high temperature well treatment fluid. Any suitable surfactant can be used, as will be apparent to those of skill in the art.
  • a nonionic surfactant such as an ethoxylated alcohol
  • a nonionic surfactant such as an ethoxylated alcohol
  • a suitable surfactant that can be used in the present invention is a proprietary blend of two different surfactants commercially available from Rhodia.
  • the Rhodia blend contains 50 wt. % Rhodasurf BC 720, which is an alkoxypoly(ethyleneoxy)ethanol surfactant, and an ethoxylated long chain alcohol having between 10 and 18 carbon molecules.
  • the surfactant comprises alkoxypoly(ethyleneoxy)ethanol, an ethoxylated alcohol having from 10 to 18 carbon molecules, and combinations thereof. Effective types and amounts of suitable surfactants will be apparent to those of skill in the art and are to be considered within the scope of the present invention.
  • the high temperature well treatment fluid also includes a breaker that is capable of degrading the high temperature well treatment fluid in a controlled manner to assist operators in clean up and removal of the high temperature well treatment fluid when the well treatment process is complete.
  • the breakers can assist in clean-up efforts after fracturing treatments. Viscometer tests have shown that most breakers that contain oxidizing agents are useful in the degradation of the fluid. Suitable oxidizing agents can include sodium bromate, ammonium persulfate, sodium persulfate, sodium perborate, sodium percarbonate, calcium peroxide, magnesium peroxide and sodium periodate. Controlled degradation can be recognized because it results in a simultaneous and controlled reduction in fluid viscosity.
  • the breaker comprises sodium bromate, either as is or encapsulated. Sodium bromate has been shown to easily degrade the high temperature well treatment fluid in a controlled manner.
  • the breaker comprises sodium bromate, ammonium persulate, sodium persulfate, sodium perborate, sodium percarbonate, calcium peroxide, magnesium peroxide, sodium periodate, an alkaline earth metal percarbonate, an alkaline earth metal perborate, an alkaline earth metal peroxide, an alkaline earth metal perphosphate, a zinc peroxide, a zinc perphosphate, a zinc perborate, a zinc percarbonate, a boron compound, a perborate, a peroxide, a perphosphate, or combinations thereof, the breaker comprising sodium bromate, ammonium persulate, sodium persulfate, sodium perborate, sodium percarbonate, calcium peroxide, magnesium peroxide, sodium periodate, or combinations thereof.
  • Other types and amounts of suitable breakers that
  • the concentration of the sodium bromate can be from about 0.5 ppt high temperature well treatment fluid to 20 ppt high temperature well treatment fluid.
  • concentration will depend on if the sodium bromate is run as a solid, a solution, or encapsulated, such as High Perm BRTM Gel Breaker from Baker Hughes Incorporated.
  • pH buffers, stabilizers, crosslinking agents, breakers, monomers, and other additives described herein can be used in the method embodiments as well as the compositional embodiments of the present invention.
  • Other suitable compounds for high temperature well treatment fluids, such as proppant and other additives, will be apparent to those of skill in the art and are to be considered within the scope of the present invention.
  • a high temperature well treatment fluid is contacted with at least a portion of the subterranean formation at pressures sufficient to fracture the subterranean formation.
  • the high temperature well treatment fluid includes water; a high molecular weight polymer comprising acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate; a crosslinking agent; and a pH buffer that maintains a pH of the high temperature well treatment fluid in a range of about 4.5 to about 5.25.
  • Another method of fracturing a subterranean formation is provided as another embodiment of the present invention.
  • water is contacted with a high molecular weight copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate to form a water-soluble polymer that is then contacted with a crosslinking agent and a pH buffer to produce a gelling fluid.
  • the gelling fluid is then contacted with at least a portion of the subterranean formation at pressures sufficient to fracture the formation.
  • the pH buffer maintains a pH of the gelling fiuid in a range of about 4.5 to about of about 5.25.
  • Another method of fracturing a subterranean formation is provided as another embodiment of the present invention.
  • water is contacted with a high molecular weight copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate to form a water-soluble polymer.
  • the water-soluble polymer is contacted with a crosslinking agent and a foaming agent to produce a foamed or energized fiuid.
  • At least a portion of the subterranean formation is contacted with the foamed or energized fiuid at pressures sufficient to fracture the formation.
  • the foamed or energized fiuid may further contain a pH buffer, preferably to maintain the pH of the foamed or energized fiuid in a range of about 4.0 to about 6.0.
  • compositions and methods described herein perform well when compared with traditional guar-based well treatment fluids.
  • Well treatment fluids require sufficient viscosity that lasts long enough for the well treatment fluid to complete the well treatment process, such as fracturing.
  • the compositions and methods describe herein are stabilized for much longer than most prior art well treatment fluids at elevated temperatures.
  • the high temperature well treatment fiuid of the present invention can be pumped at a temperature of up to about 500 °F (260 °C) for a period of up to about 2 hours.
  • the high temperature well treatment fiuid can be pumped at a temperature of up to about 425 °F (218.3 °C) for a period of up to about 4 hours.
  • the high temperature well treatment fiuid can be pumped at a temperature of up to about 400 °F (204.4 °C) for a period of up to about 6 hours.
  • the methods and compositions of the present invention do not require any new or additional equipment.
  • Traditional well treatment fiuid equipment can be used without any modification.
  • the methods and compositions of the present invention can be used in subterranean formations having higher temperatures than many prior art well treatment fluids are capable of functioning properly.
  • Samples of the high temperature well treatment fluid of the present invention were prepared by mixing 40 pounds of copolymer derived from acrylamide and acrylamidomethylpropanesulfonic acid in one thousand gallons (ppt) tap water and allowed to hydrate for 30 minutes.
  • a suitable copolymer that was used in this example is commercially available as Allessan® AG 5028P from Allessa Chemie. The order of addition of the additives is as it appears in FIG. 1. As shown in FIG.
  • FIG. 1 shows stability of the high temperature well treatment fluid of the present invention without the use of breakers.
  • the pH was controlled using two different pH buffers. As indicated in FIG. 1, some of the samples were added as a dry powder to the fracturing fluid, while others were prepared in an emulsion. A pH of 4.5 with acetic acid (BF-10L by Baker Hughes Incorporated) was used in the samples up to 400 °F (204.4 °C).
  • a pH of 4.76 with a true buffer of pH 4.5 (BF-18L by Baker Hughes Incorporated) was used in the samples that were greater than 400 °F (204.4 °C).
  • 2.5 to 3.0 gpt of a zirconate-based crosslinking agent (XLW-14 by Baker Hughes Incorporated) was used in the samples.
  • Two samples were made and measured at 400 °F (204.4 °C), one of the samples was prepared with 0.06 wt. % sodium thiosulfate gel stabilizer and the other sample was prepared without the stabilizer.
  • the sample at 400 °F (204.4 °C) with the stabilizer performed much better than the sample without the stabilizer, i.e., it maintained its viscosity for a longer period of time than the sample without the stabilizer.
  • Three samples of the high temperature well treatment fluid of the present invention were prepared by mixing 40 pounds of copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate in one thousand gallons tap water (Allessan® AG 5028P from Allessa Chemie) and allowed to hydrate for 30 minutes. The order of addition of the additives is as it appears in FIG. 2. As shown in FIG. 2, the apparent viscosity was measured and plotted for the high temperature well treatment fluid at 350 °F (176.7 °C) using a RiB 5 bob and cup combination against time in minutes.
  • the pH was controlled using 1 gpt of acetic acid to pH 4.5 (e.g., BF-10L by Baker Hughes Incorporated). 2.5 gallons per 1,000 gallons high temperature well treatment fluid (gpt) of a zirconate -based crosslinking agent (e.g., XLW-14 by Baker Hughes Incorporated) was used in the samples. The first sample was made without the use of a breaker. The second and third samples were prepared with one and three ppt respectively of an encapsulated sodium bromate labeled as High Perm Br in FIG. 2 (High Perm BRTM Gel Breaker from Baker Hughes Incorporated). As can be seen in FIG.
  • the viscosity tapers off at a consistent rate with each of the samples that contain the sodium bromate breaker, which indicates that the high temperature well treatment fluid can be degraded in a controlled manner.
  • the viscosity of the second sample with 1 ppt breaker decreased slower than the viscosity of the third sample having 3 ppt breaker.
  • Example 3 Three samples of the high temperature well treatment fluid of the present invention were prepared by mixing varying amounts of copolymer derived from acrylamide, acrylamidomethylpropanesulfonic acid, and vinyl phosphonate with tap water (Allessan® AG 5028P with a built in stabilizer from Allessa Chemie) and allowed to hydrate for 30 minutes.
  • the components, order of addition, and conditions in this example are as follows:
  • the gel stabilizer GS-1L, buffer BF-65L, and crosslinking agent XLW-65 are all commercially available from Baker Hughes Incorporated.
  • the apparent viscosity was measured and plotted for the high temperature well treatment fluid at temperatures ranging from 350 °F (176.7 °C) to 450 °F (232.2 °C) using a RiB 5 bob and cup combination against time in minutes.
  • the pH was controlled using a true 5.0 pH buffer (e.g., BF-65L by Baker Hughes Incorporated).
  • the viscosity tapers off at a consistent rate with each of the samples, which indicates that the high temperature well treatment fluid can be stable for an extended period of time and still be degraded in a controlled manner.
  • Samples of a high temperature well treatment fluid were prepared by mixing 15 gallons of GW-65L, a copolymer of Baker Hughes Incorporated derived from acrylamide and acrylamidomethylpropanesulfonic acid, in one thousand gallons (ppt) tap water which further contained about 140 ppm phenothiazine.
  • the fluid was allowed to hydrate for 30 minutes with the addition of about 1 gpt of PSA-65L, a product of Baker Hughes Incorporated.
  • the pH was controlled using BF-65L buffer and XLW-65 was used as the crosslinker.
  • the order of addition of the additives is as it appears in FIG. 4.
  • the rheology of the fluid was then evaluated using a flow-loop rheometer which was equipped with a constant volume circulating pump and an independent air driven pump.
  • the flow-loop was further fitted with a 10,000 psi site glass for observation.
  • the foamed fluid was passed through the closed loop rheometer for 20 minutes. As shown in FIG. 4, the foam is stable over an extended period of time.
  • Samples of a high temperature well treatment fluid were prepared by mixing 15 gallons of GW-65L, a copolymer of Baker Hughes Incorporated derived from acrylamide and acrylamidomethylpropanesulfonic acid, in one thousand gallons (ppt) tap water which further contained about 140 ppm phenothiazine.
  • the fluid was allowed to hydrate for 30 minutes with the addition of about 1 gpt of PSA-65L, a product of Baker Hughes Incorporated.
  • the pH was controlled using BF-65L buffer and XLW-65 was used as the crosslinker and Claytreat-3C clay stabilizer, a product of Baker Hughes Incorporated.
  • FAW-4 foamer a product of Baker Hughes Incorporated, and carbon dioxide were introduced to the fluid to provide 30 volume percent carbon dioxide.
  • the order of addition of the additives is as it appears in FIG. 5.
  • the foamed fluid was then passed through a closed loop rheometer for approximately 40 minutes.
  • fluid exhibited greater viscosity than the fluid of Example 4 and the fluid was stable over an extended period of time.
  • various types of additives can be used in the high temperature well treatment fluid of the present invention.
  • various types of equipment can be used for the well treatment processes described herein.

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Abstract

L'invention concerne des fluides de traitement de puits et des procédés de traitement de formations souterraines à température élevée allant jusqu'à environ 500 °F (260 °C). Les fluides et procédés de traitement de puits utilisent un copolymère synthétique à masse moléculaire élevée et un tampon de pH qui maintient un pH dans une plage d'environ 4,5 à environ 5,25 pour les fluides. Le copolymère synthétique à masse moléculaire élevée est dérivé d'acrylamide, d'acide acrylamidométhylpropanesulfonique, et de phosphonates vinyliques. Les fluides de traitement de puits peuvent être stimulés ou moussés.
PCT/US2012/043308 2011-09-19 2012-06-20 Compositions et procédés de traitement de formations souterraines à température élevée WO2013043243A1 (fr)

Priority Applications (8)

Application Number Priority Date Filing Date Title
MX2014003324A MX368317B (es) 2011-09-19 2012-06-20 Composiciones y métodos para tratamiento de formaciones subterráneas a altas temperaturas.
RU2014115672/03A RU2014115672A (ru) 2011-09-19 2012-06-20 Составы и способы высокотемпературной обработки подземных формаций
CN201280045707.3A CN104024369A (zh) 2011-09-19 2012-06-20 处理高温地下地层的组合物和方法
AU2012313410A AU2012313410A1 (en) 2011-09-19 2012-06-20 Compositions and methods of treating high temperature subterranean formations
CA2849248A CA2849248C (fr) 2011-09-19 2012-06-20 Procede de fracturation comportant un phenothiazine stabilisant
NZ621852A NZ621852B2 (en) 2011-09-19 2012-06-20 Compositions and methods of treating high temperature subterranean formations
BR112014006604A BR112014006604A2 (pt) 2011-09-19 2012-06-20 composições e métodos de tratar formações subterrâneas de temperatura alta
EP12731854.1A EP2758488A1 (fr) 2011-09-19 2012-06-20 Compositions et procédés de traitement de formations souterraines à température élevée

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US13/236,378 US8691734B2 (en) 2008-01-28 2011-09-19 Method of fracturing with phenothiazine stabilizer
US13/236,378 2011-09-19

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CN103265937A (zh) * 2013-05-07 2013-08-28 四川省博仁达石油科技有限公司 适用于类泡沫压裂液的破胶剂
CN106566490A (zh) * 2016-10-25 2017-04-19 中国石油大学(华东) 一种具有磷酸酯铝结构的油基钻井液用提切剂及其制备方法
EP3512918A4 (fr) * 2016-09-14 2020-04-29 Rhodia Operations Mélanges de polymères pour la stimulation de puits de pétrole et de gaz

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US9963630B2 (en) * 2015-11-18 2018-05-08 Cnpc Usa Corporation Method for a fracturing fluid system at high temperatures
CN107686724B (zh) * 2017-09-01 2020-08-11 中国石油天然气股份有限公司 一种超低含水二氧化碳压裂液及其制备方法
CN108071378B (zh) * 2017-12-28 2020-07-28 东方宝麟科技发展(北京)有限公司 一种适用于致密油气藏的co2泡沫压裂方法
CN108424759B (zh) * 2018-04-17 2020-11-06 四川申和新材料科技有限公司 一种抗110℃高温的二氧化碳泡沫压裂液及其制备方法

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EP2166060A1 (fr) * 2008-09-22 2010-03-24 Allessa Chemie GmbH Compositions de polymère aqueux stabilisé et leur utilisation

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US4624795A (en) * 1985-03-28 1986-11-25 Bj-Titan Services Company Aqueous acid gels and use thereof
EP0658612A1 (fr) * 1993-12-14 1995-06-21 Texas United Chemical Company, Llc. Fluides contenant des polysaccharides, à stabilité thermique améliorée
US20050039919A1 (en) * 2003-08-19 2005-02-24 Harris Phillip C. Methods of fracturing high temperature subterranean zones and foamed fracturing fluids therefor
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WO2009097286A1 (fr) * 2008-01-28 2009-08-06 Bj Services Company Compositions et procédés de traitement de formations souterraines à température élevée
EP2166060A1 (fr) * 2008-09-22 2010-03-24 Allessa Chemie GmbH Compositions de polymère aqueux stabilisé et leur utilisation

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Publication number Priority date Publication date Assignee Title
CN103265937A (zh) * 2013-05-07 2013-08-28 四川省博仁达石油科技有限公司 适用于类泡沫压裂液的破胶剂
CN103265937B (zh) * 2013-05-07 2015-10-28 四川省博仁达石油科技有限公司 适用于类泡沫压裂液的破胶剂
EP3512918A4 (fr) * 2016-09-14 2020-04-29 Rhodia Operations Mélanges de polymères pour la stimulation de puits de pétrole et de gaz
US10982519B2 (en) 2016-09-14 2021-04-20 Rhodia Operations Polymer blends for stimulation of oil and gas wells
CN106566490A (zh) * 2016-10-25 2017-04-19 中国石油大学(华东) 一种具有磷酸酯铝结构的油基钻井液用提切剂及其制备方法
CN106566490B (zh) * 2016-10-25 2018-02-09 中国石油大学(华东) 一种具有磷酸酯铝结构的油基钻井液用提切剂及其制备方法

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MX2014003324A (es) 2014-05-21
AU2012313410A1 (en) 2014-03-20
RU2014115672A (ru) 2015-10-27
CO6910177A2 (es) 2014-03-31
BR112014006604A2 (pt) 2017-03-28
EP2758488A1 (fr) 2014-07-30
CA2849248C (fr) 2018-07-10
AR087893A1 (es) 2014-04-23
CA2849248A1 (fr) 2013-03-28
NZ621852A (en) 2016-07-29
CN104024369A (zh) 2014-09-03

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