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WO2005040553A1 - Fracturation de formations souterraines - Google Patents

Fracturation de formations souterraines Download PDF

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Publication number
WO2005040553A1
WO2005040553A1 PCT/GB2004/004049 GB2004004049W WO2005040553A1 WO 2005040553 A1 WO2005040553 A1 WO 2005040553A1 GB 2004004049 W GB2004004049 W GB 2004004049W WO 2005040553 A1 WO2005040553 A1 WO 2005040553A1
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WO
WIPO (PCT)
Prior art keywords
polymeric material
treatment fluid
fluid formulation
polymeric
formulation
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/GB2004/004049
Other languages
English (en)
Inventor
Michael John Crabtree
Philip Fletcher
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.)
Advanced Gel Technology Ltd
AGT Energy Ltd
Original Assignee
Advanced Gel Technology Ltd
AGT Energy Ltd
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
Application filed by Advanced Gel Technology Ltd, AGT Energy Ltd filed Critical Advanced Gel Technology Ltd
Priority to CA002550340A priority Critical patent/CA2550340A1/fr
Priority to GB0607898A priority patent/GB2423324B/en
Priority to US10/574,359 priority patent/US20070114028A1/en
Publication of WO2005040553A1 publication Critical patent/WO2005040553A1/fr
Anticipated expiration legal-status Critical
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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • 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
    • 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
    • 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures

Definitions

  • This invention relates to the fracturing of subterranean formations and particularly, although not exclusively, relates to a method of fracturing a subterranean formation and materials therefor.
  • Hydrocarbons such as oil and natural gas
  • a subterranean geologic formation i.e. a "reservoir”
  • This provides a partial flowpath for the oil to reach the surface.
  • oil to be "produced” that is travel from the formation to the wellbore (and ultimately to the surface)
  • This flowpath is through the formation rock which has pores of sufficient size, connectivity, and number to provide a conduit for the oil to move through the formation.
  • One known method of stimulation involves injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbons can more readily move from the formation and into the wellbore.
  • Hydraulic fracturing involves breaking or fracturing a portion of the strata surrounding the wellbore, by injecting a fluid into the wellbore directed at the face of the geologic formation at pressures sufficient to initiate and extend a fracture in the formation. More particularly, a fluid is injected through a wellbore; the fluid exits the wellbore through holes (perforations in the well casing) and is directed against the face of the formation (sometimes wells are completely openhole where no casing and therefore no perforations exist, so the fluid is injected through the wellbore and directly to the formation face) at a pressure and flow rate sufficient to overcome the minimum in situ stress to initiate and/or extend a fracture or fractures into the formation. Often, a fracture zone, i.e. a zone having multiple fractures, or cracks in the formation is created, through which hydrocarbon can more easily flow to the wellbore.
  • Guar based fracture fluids use solid fluid loss reducing agents to prevent "leak off” (a process wherein fluid extends further into the fracture face than desired, thereby reducing the fluid pressure) .
  • solid fluid loss reducing agents to prevent "leak off” (a process wherein fluid extends further into the fracture face than desired, thereby reducing the fluid pressure) .
  • the introduction of solids to address the leak off problem can reduce the resultant permeability of the fracture zone and reduce production from the fracture once the well is brought back into production after the treatment .
  • a method of hydraulically fracturing a subterranean formation comprising the step of:
  • the treatment fluid formulation comprises a third polymeric material which comprises a second polymeric material cross-linked by a first polymeric material, wherein said first polymeric material comprises: (i) a first polymeric material having a repeat unit of formula
  • a and B are the same or different, are selected from optionally-substituted aromatic and heteroaromatic groups and at least one comprises a relatively polar atom or group and R 1 and R 2 independently comprise relatively non-polar atoms or groups; or (ii) a first polymeric material prepared or preparable by providing a compound of general formula
  • said first and second polymeric materials are reacted to form said third polymeric material prior to the treatment fluid formulation being injected via the wellbore into the subterranean formation.
  • the treatment fluid formulation prior to the treatment fluid formulation being injected, it has attained at least 50% of the maximum viscosity attainable for the formulation at the temperature at which it is to be injected into the formation. Preferably, it has attained at least 65%, more preferably 90%, especially about 100% of its maximum viscosity.
  • said first and second polymeric materials are substantially completely reacted to form said third polymeric material prior to injection into the formation.
  • Said treatment fluid formulation preferably has a viscosity at 25°C in the range 50-500 cp, more preferably in the range 200-500cp, at a shear rate of 100s "1 .
  • the relatively high initial viscosity of the formulation may advantageously facilitate suspension of proppants (and other) materials therein.
  • Said treatment fluid formulation preferably has a viscosity at 200°F in the range 20-100cp, more preferably of greater than 50 cp, measured at a shear rate of 100s "1 .
  • the relatively high viscosity at high temperature may help to maintain fracture pressure, the effectiveness of the fracture process and also to minimise fluid leak off.
  • Said treatment fluid formulation is preferably aqueous. It may include at least 90wt%, preferably at least 95wt% water. It preferably includes 90 to 99wt% water.
  • Said treatment fluid formulation preferably includes one or more proppants.
  • the formulation is compatible with any common proppant size required.
  • the proppant may have a size in the range 20-40 mesh.
  • Said proppant (s) may be selected from sand, bauxite, man-made intermediate or high strength materials and glass beads. The proppant is arranged to restrict close down of a fracture on removal of the hydraulic pressure which caused the fracture.
  • the total weight of proppant (s) in said treatment fluid formulation is suitably in the range 5wt% to 30wt%
  • the total weight of proppant (s) in said treatment fluid formulation is in the range 10 to 20 wt% .
  • Said treatment fluid formulation preferably includes breaker means for breaking the third polymeric material suitably to reduce its viscosity and facilitate clean up of the fracture.
  • said treatment fluid formulation is arranged to break the formulation to enable it to be removed, by pressure within the formation, via the wellbore.
  • Said breaker means is preferably arranged to cleave chains of said third polymeric material, preferably chains thereof derived from said second polymeric material.
  • said breaker means comprises an oxidising agent arranged to cleave said chains.
  • said breaker means is arranged to cleave 1,2-diol linkages.
  • Said breaker means preferably comprises a periodate, especially sodium or potassium periodate.
  • at least 0.05wt%, preferably at least 0.1wt% of said breaker means is included.
  • 0.05 to 0.3wt% of said breaker means is included.
  • Said breaker means may enable the viscosity to be reduced by a factor of at least 50%, preferably at least 70%, especially at least 90%.
  • Said breaker means is preferably arranged to have a delayed action and suitably includes means for restricting contact between an active material (e.g. a material arranged to cleave chains of the third polymeric material) and said third polymeric material.
  • Said active material is preferably encapsulated.
  • Said breaker means preferably comprises crushable beads which incorporate said active material.
  • Said breaker means is preferably arranged to be crushed to release said active material when the pressure of the treatment fluid formulation is reduced so that the fractures in the formation close down.
  • said treatment fluid formulation includes proppant (s) and breaker means it is preferred that the bead size of the breaker means is 0.75 to 3 times that of the proppant (s) and preferably is greater than the proppant size.
  • the breaker means is preferably adapted to resist breakage when passing through pumps or blending equipment that may be used in the fracturing method and when being subjected to the fracture pressure used in the method.
  • a crushable breaker means may be formed from glass, porous ceramics, plastics, gels or mixtures thereof.
  • the active material being encapsulated by a crushable material
  • it may be encapsulated by a material which is arranged to release the active material via an alternative mechanism.
  • it may be arranged to rupture after prolonged fluid exposure or may slowly dissolve.
  • Said treatment fluid formulation may include 0.05 to 0.3wt% of crushable breaker.
  • the treatment fluid formulation may have very low solids content which should facilitate its use.
  • the treatment fluid formulation includes less than 1 wt%, preferably less than 0.5 wt%, especially less than 0.25 wt% of fluid loss reducing agents.
  • the treatment fluid formulation may be contacted with a subterranean formation so that it attains a temperature of at least 200°C.
  • Said method preferably comprises selecting a said first polymeric material; selecting a second polymeric material which includes a functional group which is able to react in the presence of said first polymeric material to form a third polymeric material; and causing the formation of said third polymeric material by a reaction involving said first and second polymeric materials.
  • the ratio of the wt% of said first polymeric material to the wt% of said second polymeric material selected for preparation of said third polymeric material is suitably less than 0.15, preferably less than 0.10, more preferably 0.8 or less. Said ratio may be at least 0.01, preferably at least 0.02, more preferably at least 0.025.
  • the ratio of the wt% of said first polymeric material to the wt% of said second polymeric material selected for preparation of said third polymeric material is in the range 0.025 to 0.067.
  • the sum of the wt% of the first and second polymeric materials selected for preparation of said third polymeric material may be at least 1 wt%, preferably at least 2 wt%, based on the total weight of the treatment fluid formulation.
  • the sum may be less than 8 wt%, preferably less than 6 wt%, more preferably less than 4 wt%.
  • the sum of the wt% of the first and second polymeric materials selected for preparation of said third polymeric material is preferably in the range 1 to 6wt%, more preferably in the range 2 to 4wt%.
  • first polymeric material and second polymeric material refer to the sum of the amounts of first polymeric materials (if more than one type is provided) and the sum of the amounts of second polymeric materials (if more than one type is provided) .
  • Water for use in the treatment fluid formulation may be derived from any convenient source. It may be potable water, surface water, sea water, aquifer water, deionised production water and filtered water derived from any of the aforementioned sources.
  • the water may be treated so that it is suitable for use in the method. For example, it may be treated by addition of oxygen scavengers, biocides, corrosion inhibitors, scale inhibitors, anti- foaming agents and flow improvers.
  • Sea water and/or water from other sources may be deoxygenated and/or desulphonated.
  • a catalyst is preferably provided for catalysing the reaction of the first and second polymeric materials.
  • Said catalyst is preferably a protic acid.
  • Said acid preferably has an acid dissociation constant value of greater than 10 "6 , more preferably greater than 10 "4 and, especially, greater than 10 "2 .
  • a precursor formulation which includes said first and second polymeric materials suitably includes less than 5 wt%, preferably less than 2wt%, more preferably less than 1 wt%, especially less than 0.5 wt% of catalyst.
  • said treatment fluid formulation has a pH in the range 6 to 8 and is preferably neutral.
  • the method may include a neutralisation step after addition of said catalyst.
  • a and/or B could be multi-cyclic aromatic or heteroaromatic groups.
  • a and B are independently selected from optionally-substituted five or more preferably six- membered aromatic and heteroaromatic groups.
  • Preferred heteroatoms of said heteroaromatic groups include nitrogen, oxygen and sulphur atoms of which oxygen and especially nitrogen, are preferred.
  • Preferred heteroaromatic groups include only one heteroatom.
  • a or said heteroatom is positioned furthest away from the position of attachment of the heteroaromatic group to the polymer backbone.
  • the heteroatom comprises a six-membered ring
  • the heteroatom is preferably provided at the 4-position relative to the position of the bond of the ring with the polymeric backbone.
  • a and B represent different groups.
  • one of A or B represents an optionally- substituted aromatic group and the other one represents an optionally-substituted heteroaromatic group.
  • A represents an optionally-substituted aromatic group and B represents an optionally-substituted heteroaromatic group especially one including a nitrogen heteroatom such as a pyridinyl group.
  • optionally-substituted groups described herein, for example groups A and B may be substituted by halogen atoms, and optionally substituted alkyl, acyl, acetal, hemiacetal, acetalalkyloxy, hemiacetalalkyloxy, nitro, cyano, alkoxy, hydroxy, amino, alkylamino, sulphinyl, alkylsulphinyl, sulphonyl, alkylsulphonyl, sulphonate, amido, alkylamido, alkylcarbonyl, alkoxycarbonyl, halocarbonyl and haloalkyl groups.
  • up to 3 more preferably up to 1 optional substituents may be provided on an optionally substituted group.
  • an alkyl group may have up to 10, preferably up to 6, more preferably up to 4 carbon atoms, with methyl and ethyl groups being especially preferred.
  • a and B each represent polar atoms or group
  • groups A and B and/or groups A and B do not include carbon and hydrogen atoms only.
  • At least one of A or B includes a functional group which can undergo a condensation reaction, for example on reaction with said second polymeric material.
  • A includes a said functional group which can undergo a condensation reaction.
  • one of groups A and B includes an optional substituent which includes a carbonyl or acetal group with a formyl group being especially preferred.
  • the other one of groups A and B may include an optional substituent which is an alkyl group, with an optionally substituted, preferably unsubstituted, C 1 - alkyl group, for example a methyl group, being especially preferred.
  • A represents a group, for example an aromatic group, especially a phenyl group, substituted (preferably at the 4-position relative to polymeric backbone when A represents an optionally-substituted phenyl group) by a formyl group or a group of general formula
  • x is an integer from 1 to 6 and each R is independently an alkyl or phenyl group or together form an alkalene group.
  • B represents an optionally-substituted heteroaromatic group, especially a nitrogen-containing heteraromatic group, substituted on the heteroatom with a hydrogen atom or an alkyl or aralkyl group. More preferably, B represents a group of general formula
  • R represents a hydrogen atom or an alkyl or aralkyl group
  • R 5 represents a hydrogen atom or an alkyl group
  • X " represents a strongly acidic ion.
  • R 1 and R 2 are independently selected from a hydrogen atom or an optionally-substituted, preferably unsubstituted, alkyl group.
  • R 1 and R 2 represent the same atom or group.
  • R 1 and R 2 represent a hydrogen atom.
  • Preferred first polymeric materials may be prepared from any of the compounds described on page 3 line 8 to line 39 ' of GB2030575B by the method described in W098/12239 and the contents of the aforementioned documents are incorporated herein by reference.
  • Said first polymeric material may be of formula
  • n is an integer.
  • Integer n is suitably 10 or less, preferably 8 or less, more preferably 6 or less, especially 5 or less.
  • Integer n is suitably at least 1, preferably at least 2, more preferably at least 3.
  • formation of said third polymeric material from said first and second polymeric materials involves a condensation reaction.
  • formation of said third polymeric material involves an acid catalysed reaction.
  • said first and second polymeric materials include functional groups which are arranged to react, for example to undergo a condensation reaction, thereby to form said third polymeric material.
  • said first and second polymeric materials include functional groups which are arranged to react for example to undergo an acid catalysted reaction thereby to form said third polymeric material .
  • said second polymeric material includes ' a functional group selected from an alcohol, carboxylic acid, carboxylic acid derivative, for example an ester, and an amine group.
  • Said second polymeric material preferably includes a backbone comprising, preferably consisting essentially of carbon atoms. The backbone is preferably saturated. Pendent from the backbone are one or more said functional groups described.
  • Said polymer may have a number average molecular weight (Mn) of at least 10,000, preferably at least 50,000, especially at least 75,000. Mn may be less than 500,000, preferably less than 400,000.
  • Said second polymeric material is preferably a polyvinyl polymer.
  • Preferred second polymeric compounds include optionally substituted, preferably unsubstituted, polyvinylalcohol, polyvinylacetate, polyalkylene glycols, for example polypropylene glycol, and collagen (and any component thereof) and of these polyvinylalcohol and/or polyvinylacetate based polymeric materials are preferred.
  • said second polymeric material includes at least one vinyl alcohol/vinyl acetate copolymer which suitably includes greater than 50%, preferably greater than 65%, more preferably greater than 80wt% of vinyl alcohol moieties .
  • Said third polymeric material suitably includes a moiety of formula
  • a 1 represents a residue of group A described above after the reaction involving said first and second polymeric materials
  • Y represents a residue of said second polymeric material after said reaction involving said first and second polymeric materials
  • X represents a linking atom or group extending between the residues of said first an second polymeric materials.
  • a 1 represents an optionally-substituted phenyl group
  • X represents a group
  • group X may be bonded to the polymer backbone of said second polymeric material .
  • a treatment fluid formulation e.g. a fracturing fluid
  • a treatment fluid formulation comprising:
  • the method may include contacting the first and second polymeric materials with an acid for catalysing the reaction thereof.
  • the method may include incorporating into the treatment fluid formulation one or more proppants.
  • the method may include incorporating into the treatment fluid formulation a breaker means.
  • Said breaker means is preferably arranged to cleave 1,2-diol linkages.
  • Said breaker means preferably comprises a periodate.
  • said one or more proppants and/or said breaker means is/are incorporated after formation of said third polymeric material.
  • the method comprising contacting said first and second polymeric materials at a weight ratio of first to second in the range 0.025 to 0.067; and contacting the third polymeric material which forms with 5 to 20wt% proppants.
  • a treatment fluid formulation comprising : water; a third polymeric material as described according to the first and second aspects; and one or more proppants .
  • Said treatement fluid formulation preferably comprises 1 to 5wt% of said third polymeric material, 65 to 90wt% water and 5 to 30 wt% of proppants.
  • Said treatment fluid formulation preferably includes a breaking means.
  • the treatment fluid formulation preferably has a viscosity ' at 25°C of at least 200 cp, measured at a shear rate of 100s "1 .
  • a method of breaking a third polymeric material as described herein comprises providing a formulation comprising said third polymeric material and a breaker means (e.g. encapsulated periodate) and causing said breaker means to change its state (e.g. rupture) in order to release an active breaker material arranged to break the third polymeric material .
  • a breaker means e.g. encapsulated periodate
  • an encapsulated breaker means for a third polymeric material as described herein per se is provided.
  • a method of recovering oil from a subterranean formation comprising: hydraulically fracturing a subterranean formation as described according to said first aspect; allowing an area fractured to close down whilst being propped by a proppant; wherein as a result of said close down, a breaker means releases an active material which is arranged to lower the viscosity of the treatment fluid formulation of the first aspect; and allowing oil to flow to the surface after the viscosity of the treatment fluid formulation has been lowered.
  • fracturing of a subterranean formation may be achieved using a hydrogel.
  • the gel is formed from a gel precursor formulation which comprises an aqueous formulation of poly (1, -di ( - (N-methylpyridinyl) ) -2, 3- di (4- (1-formylphenyl) butylidene), poly (vinyl alcohol) and a suitable proppant, in the presence of an acid catalyst.
  • the gel may be prepared at the surface with a viscosity of greater than 200 cp measured at 100s "1 and then injected into the subterranean formation under high pressure to fracture the formation.
  • Example 1 Preparation of poly (1, 4-di (4- (N- methylpyridinyl) ) -2, 3-di (4- (1-formylphenyl) butylidene This was prepared as described in Example 1 of PCT/GB97/02529, the contents of which are incorporated herein by reference.
  • an aqueous solution of greater than 1 wt% of 4- ( 4-formylphenylethenyl) -1- methylpyridinium methosulphonate (SbQ) is prepared by mixing the SbQ with water at ambient temperature. Under such conditions, the SbQ molecules form aggregates. The solution was then exposed to ultraviolet light.
  • a blend may be prepared comprising 0.125 wt% of the butylidene polymer of Example 1 and 2 wt% of 88% hydrolysed poly (vinylalcohol) of molecular weight 300,000 in water.
  • the poly (vinylalcohol) is added slowly with constant stirring to an aqueous solution of the butylidene polymer so as to disperse the poly (vinylalcohol) .
  • Final dissolution may be achieved by maintaining the solution at a temperature of 60°C for a period of 6 hours.
  • Example 2 To the aqueous solution of the polymer blend described in Example 2 was added 0.01 wt% of 0.25M hydrocholoric acid. This causes the butylidene and the poly (vinylalcohol) polymers to react according to the scheme below.
  • the concentration of acid affects the speed of the reaction and therefore the development of the visco- elastic properties.
  • the formulation described is injected into a wellbore under high pressure. Once the natural reservoir pressures are exceeded, the fluid initiates a fracture in the formation which generally continues to grow during pumping and the formulation enters the fracture. On removal of the pressure, the fracture tends to close down but is restricted from doing so by the proppant which prevents complete closure of the fracture and thereby helps to maintain open a channel which extends from the fracture zone to the wellbore.
  • the fracture will crush the breaker (since its particle sizes will be about the same as or greater than those of the proppants) and, consequently, sodium metaperiodate is released which contacts the gel and causes it to break down due to cleavage of 1,2-diol linkages of the moiety in the gel derived from polyvinylalcohol. Consequently, the viscosity of the gel is substantially reduced whereupon, when the wellbore is opened to the surface oil or gas in the fracture zone can push the broken gel to the surface.
  • a summary of the properties of a gel formed as described herein includes: (a) It is stable in typical sea water obtained from the North Sea. (b) It is not affected detrimentally by temperatures of 150°C and above. (c) It is stable at temperatures below 0°C and may be prepared and/or applied in cold climates as well as hot. (d) It is not affected detrimentally by pressure of 7000 psi and above. (e) Good fluid loss properties can be achieved at relatively low solids content.

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  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • General Life Sciences & Earth Sciences (AREA)
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  • Materials Engineering (AREA)
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  • Mining & Mineral Resources (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Physics & Mathematics (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Addition Polymer Or Copolymer, Post-Treatments, Or Chemical Modifications (AREA)
  • Compositions Of Macromolecular Compounds (AREA)
  • Fire-Extinguishing Compositions (AREA)
  • Heterocyclic Carbon Compounds Containing A Hetero Ring Having Nitrogen And Oxygen As The Only Ring Hetero Atoms (AREA)

Abstract

La fracturation d'une formation souterraine peut être réalisée à l'aide d'un hydrogel. Ce gel est formé à partir d'une formulation de précurseur gel qui contient une formulation aqueuse de poly (1,4-di(4-(N-méthylpyridinyl)) -2, 3-di(4-(l-formylphényl) butylidène), alcool (poly) vinylique et un agent de soutènement adéquat, en présence d'un catalyseur acide. Ce gel peut être préparé à la surface avec une viscosité de plus de (200) cp mesurée à (100)s-1 et puis injecté dans la formation souterraine à haute pression pour fracturer la formation.
PCT/GB2004/004049 2003-10-02 2004-09-23 Fracturation de formations souterraines Ceased WO2005040553A1 (fr)

Priority Applications (3)

Application Number Priority Date Filing Date Title
CA002550340A CA2550340A1 (fr) 2003-10-02 2004-09-23 Fracturation de formations souterraines
GB0607898A GB2423324B (en) 2003-10-02 2004-09-23 Fracturing of subterranean formations
US10/574,359 US20070114028A1 (en) 2003-10-02 2004-09-23 Fracturing of subterranean formations

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GBGB0323065.3A GB0323065D0 (en) 2003-10-02 2003-10-02 Fracturing of subterranean formations
GB0323065.3 2003-10-02

Publications (1)

Publication Number Publication Date
WO2005040553A1 true WO2005040553A1 (fr) 2005-05-06

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PCT/GB2004/004049 Ceased WO2005040553A1 (fr) 2003-10-02 2004-09-23 Fracturation de formations souterraines

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US (1) US20070114028A1 (fr)
CA (1) CA2550340A1 (fr)
GB (2) GB0323065D0 (fr)
RU (2) RU2006114167A (fr)
WO (1) WO2005040553A1 (fr)

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CN106907137A (zh) * 2015-12-23 2017-06-30 中国石油化工股份有限公司 一种页岩油藏体积压裂裂缝有效导流的方法

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GB2425777B (en) * 2003-10-02 2008-12-17 Proflux Systems Llp Viscous fluids
US8841914B2 (en) 2008-04-11 2014-09-23 Baker Hughes Incorporated Electrolocation apparatus and methods for providing information about one or more subterranean feature
US8797037B2 (en) 2008-04-11 2014-08-05 Baker Hughes Incorporated Apparatus and methods for providing information about one or more subterranean feature
CA2786020A1 (fr) * 2010-02-20 2011-08-25 Baker Hughes Incorporated Appareil et procedes de fourniture d'informations concernant une ou plusieurs variables souterraines
US9587169B2 (en) * 2012-01-12 2017-03-07 Courtney Gene Rogers Low-toxicity, low-flammability, environmentally-safe, friction reducer fluid for hydraulic fracturing
WO2015099131A1 (fr) * 2013-12-26 2015-07-02 日本合成化学工業株式会社 Agent d'ajustement d'un fluide de forage et fluide de forage l'utilisant

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RU2006114166A (ru) 2007-11-27
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GB2423324B (en) 2007-04-18
GB0323065D0 (en) 2003-11-05
CA2550340A1 (fr) 2005-05-06
GB0607898D0 (en) 2006-05-31
GB2423324A (en) 2006-08-23

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