WO1999027229A1 - Procede de traitement de formation geologique au moyen de particules deformables - Google Patents

Procede de traitement de formation geologique au moyen de particules deformables Download PDF

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Publication number
WO1999027229A1
WO1999027229A1 PCT/US1998/010735 US9810735W WO9927229A1 WO 1999027229 A1 WO1999027229 A1 WO 1999027229A1 US 9810735 W US9810735 W US 9810735W WO 9927229 A1 WO9927229 A1 WO 9927229A1
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WO
WIPO (PCT)
Prior art keywords
deformable
psi
beaded
mixture
proppant
Prior art date
Application number
PCT/US1998/010735
Other languages
English (en)
Inventor
Allan R. Rickards
Harold D. Brannon
Philip J. Rae
Gino A. Dilullo
Christopher J. Stephenson
Original Assignee
Bj Services Company
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from DK199701333A external-priority patent/DK133397A/da
Application filed by Bj Services Company filed Critical Bj Services Company
Priority to CA002308372A priority Critical patent/CA2308372C/fr
Priority to GB0015133A priority patent/GB2348907B/en
Priority to AU76001/98A priority patent/AU7600198A/en
Publication of WO1999027229A1 publication Critical patent/WO1999027229A1/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
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • C09K8/805—Coated proppants
    • 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
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP 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
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Definitions

  • This invention relates generally to subterranean formation treatments and, more specifically, to hydraulic fracturing treatments for subterranean formations.
  • this invention relates to deformable particles mixed with fracturing proppants to reduce fines generation, improve fracture conductivity, and/or minimize proppant flowback.
  • Hydraulic fracturing is a common stimulation technique used to enhance production of fluids from subterranean formations.
  • fracturing treatment fluid containing a solid proppant material is injected into the formation at a pressure sufficiently high enough to cause the formation or enlargement of fractures in the reservoir.
  • proppant material is deposited in a fracture, where it remains after the treatment is completed. After deposition, the proppant material serves to hold the fracture open, thereby enhancing the ability of fluids to migrate from the formation to the well bore through the fracture. Because fractured well productivity depends on the ability of a fracture to conduct fluids from a formation to a wellbore, fracture conductivity is an important parameter in determining the degree of success of a hydraulic fracturing treatment.
  • fines are produced when proppant materials are subjected to reservoir closure stresses within a formation fracture which cause proppant materials to be compressed together in such a way that small particles (“fines”) are generated from the proppant material and/or reservoir matrix.
  • production of fines may be exacerbated during production workover operations when a well is shut-in and then opened up. This phenomenon is known as “stress cycling” and is believed to result from increased differential pressure and closure stress that occurs during fluid production following a shut-in period. Production of fines is undesirable because of particulate production problems, and because of reduction in reservoir permeability due to plugging of pore throats in the reservoir matrix.
  • Production of particulate solids with subterranean formation fluids is also a common problem.
  • the source of these particulate solids may be unconsolidated material from the formation, proppant from a fracturing treatment and/or fines generated from crushed fracture proppant, as mentioned above.
  • Production of solid proppant material is commonly known as "proppant flowback.”
  • proppant flowback In addition to causing increased wear on downhole and surface production equipment, the presence of particulate materials in production fluids may also lead to significant expense and production downtime associated with removing these materials from wellbores and/or production equipment. Accumulation of these materials in a well bore may also restrict or even prevent fluid production. In addition, loss of proppant due to proppant flowback may also reduce conductivity of a fracture pack.
  • proppant flowback methods utilizing special types of proppants and or additives to proppants have been employed to help form a fracture pack in the reservoir which is resistant to proppant flowback.
  • One well known method of this type utilizes resin-coated proppant materials designed to help form a consolidated and permeable fracture pack when placed in the formation.
  • this method may be carried out are by mixing a proppant particulate material with an epoxy resin system designed to harden once the material is placed in the formation, or by the use of a pre-coated proppant material which is pumped into the formation with the fracturing fluid and then consolidated with a curing solution pumped after the proppant material is in place.
  • resin-coated proppant techniques may reduce proppant flowback, they may also suffer from various problems, including incompatibility of resins with cross-linker and breaker additives in the fracturing fluid, and long post-treatment shut-in times which may be economically undesirable. Resin-coated proppants may also be difficult to place uniformly within a fracture and may adversely affect fracture conductivity. In addition, resin-coated proppants are typically only
  • rod-like fibrous materials are mixed with proppant material for the purpose of causing particle bridging within a fracture proppant pack so as to inhibit particle movement and proppant flowback.
  • This technique is believed to control proppant flowback by forming a "mat" of fibers across openings in the pack which tends to hold the proppant in place and limit proppant flowback during fluid production.
  • this method has proven to have several drawbacks, including reduction in fracture conductivity at effective concentrations of fibrous materials, and an effective life of only about two years due to slight solubility of commonly used fiber materials in brine.
  • fiber proppant material used in the technique may be incompatible with some common well-treating acids, such as hydrofluoric acid.
  • thermoplastic material in the form of ribbons or flakes is mixed with proppant material in order to form a fracture proppant pack that is resistant to proppant flowback.
  • the thermoplastic material is designed to intertwine with proppant particles and become "very tacky" at reservoir temperatures such as those greater than about 220°F. In doing so, the materials are believed to adhere to proppant material to form agglomerates that bridge against each other and help hold proppant materials in place.
  • This method of controlling proppant flowback suffers similar drawbacks as the fiber proppant additive method described above, most notably reduced conductivity. Therefore, a method of reducing fines creation while at the same time improving fracture conductivity and reducing proppant flowback is desirable.
  • this invention is a method of treating a subterranean formation by injecting into the formation a fracturing fluid composition that includes a blend of a fracture proppant material and a deformable beaded material.
  • this invention is a method of treating a subterranean formation by injecting into the formation a blend of a fracture proppant material and a deformable particulate material.
  • Individual particles of the deformable particulate material may have a shape with a maximum length-based aspect ratio of equal to or less than about 5.
  • this invention is a method of treating a subterranean formation by injecting into the formation a blend of a fracture proppant material and a deformable particulate material having a shape that is at least one of beaded, cubic, bar-shaped, cylindrical, or a mixture thereof.
  • Beaded or cylindrical shaped particulate materials may have a length to diameter aspect ratio of equal to or less than about 5, and bar-shaped particulate material may have a length to width aspect ratio of equal to or less than about 5 and a length to thickness aspect ratio of equal to or less than about 5.
  • this invention is a method of treating a subterranean formation by injecting into the formation a fracturing fluid composition that includes a blend of fracture proppant material and deformable particulate material.
  • the fracturing fluid composition is deposited in the subte ⁇ anean formation so that the blend of fracture proppant material and deformable particulate material has an in situ conductivity greater than an in situ conductivity of either fracture proppant material or deformable particulate material alone.
  • this invention is a method of treating a subte ⁇ anean formation by injecting into the formation a fracturing fluid composition that includes a blend of fracture proppant material and deformable particulate material.
  • the fracturing fluid composition is deposited in the subterranean formation so that the blend of fracture proppant material and deformable particulate material has an in situ creation of fines that is less than an in situ creation of fines in said fracture proppant material alone.
  • this invention is a composition for fracturing a subterranean formation that includes a blend of a fracture proppant material and a deformable particulate material.
  • the deformable particulate material may have a particle size of from about 4 mesh to about 100 mesh, a specific gravity of from about 0.4 to about 3.5, and a shape with a maximum length-based aspect ratio of equal to or less than about 5.
  • this invention is a method of treating a subte ⁇ anean formation, including the step of injecting a fracturing fluid composition into the subterranean formation, wherein the fracturing fluid composition includes a blend of a fracture proppant material and a deformable beaded material.
  • this invention is a method of treating a subte ⁇ anean formation, including the step of injecting a blend including a fracture proppant material and a deformable particulate material into a subte ⁇ anean formation, wherein at least a portion of the individual particles of the deformable particulate have a shape with a maximum length-based aspect ratio of equal to or less than about 5.
  • the blend may include between about 1% to about 50% by weight deformable particulate material.
  • at least a portion of the individual particles of the deformable beaded material may include two or more components.
  • this invention is a method of treating a subterranean formation, including the step of injecting a deformable particulate material into a subterranean formation, wherein at least a portion of the individual particles of the deformable particulate material include an agglomerate of substantially non-deformable material and substantially deformable material, a core of substantially non-deformable material surrounded by one layer of substantially deformable material, or a mixture thereof.
  • this invention is a method of treating a subte ⁇ anean formation, including the steps of injecting a fracturing fluid composition into the subterranean formation, wherein the fracturing fluid composition includes a blend of fracture proppant material and substantially deformable particulate material; and depositing the fracturing fluid composition in the subte ⁇ anean formation, wherein an in situ conductivity of the blend of fracture proppant material and substantially deformable particulate material is greater than an in situ conductivity of either one of the fracture proppant material or substantially deformable particulate material alone; wherein at least a portion of the individual particles of the deformable particulate material include an agglomerate of substantially non-deformable material and substantially deformable material, a core of substantially non-deformable material surrounded by one layer of substantially deformable material, or a mixture thereof.
  • this invention is a method of treating a subterranean formation, including the steps of injecting a fracturing fluid composition into the subterranean formation, wherein the fracturing fluid composition includes a blend of fracture proppant material and deformable particulate material; and depositing the fracturing fluid composition in the subte ⁇ anean formation, wherein an in situ creation of fines in the blend of fracture proppant material and deformable particulate material is less than an in situ creation of fines in the fracture proppant material alone; wherein at least a portion of the individual particles of the deformable particulate material include an agglomerate of substantially non-deformable material and substantially deformable material, a core of substantially non-deformable material surrounded by one layer of substantially deformable material, or a mixture thereof.
  • this invention is a composition for fracturing a subterranean formation, the composition including a deformable particulate material, wherein at least a portion of the individual particles of the deformable particulate material include a core of substantially non-deformable material surrounded by one layer of substantially deformable material.
  • this invention is a composition for fracturing a subterranean formation, the composition including a blend of a fracture proppant material and a deformable particulate material, wherein the deformable particulate material has a maximum length-based aspect ratio of equal to or less than about 5.
  • deformable beaded material may have a Young's modulus of, for example, between about 500 psi and about 2,000,000 psi at in situ formation conditions, between about 5000 psi and about 200,000 psi at in situ formation conditions, or between about 7000 psi and about 150,000 psi at in situ formation conditions.
  • Deformable beaded material may be a copolymer, such as a terpolymer, which may be at least one of polystyrene/vinyl/divinyl benzene, acrylate-based terpolymer or a mixture thereof.
  • Deformable beaded material may also be polystyrene divinylbenzene that includes from about 4% to about 14% divinylbenzene by weight. At least a portion of the individual particles of the deformable beaded material may include two components such as, for example, a core of substantially non-deformable material surrounded by a layer of substantially deformable material.
  • the core may include a material selected from at least one of silica, ceramics, synthetic organic particles, glass microspheres, or a mixture thereof; and wherein the layer of substantially deformable material includes at least one of a cross-linked polymer, plastic, or a mixture thereof.
  • the core may includes a material selected from at least one of silica, ceramics, synthetic organic particles, glass microspheres, or a mixture thereof; the layer of substantially deformable material may include resin and make up greater than 8% by weight of the total weight of the deformable beaded particle.
  • a deformable particle may also be an agglomerate of substantially non-deformable material and substantially deformable material with the substantially deformable material making up between about 5% and about 50% by volume of the total volume of each of the individual particles of the deformable beaded material; and the substantially non-deformable material making up between about 50% and about 95% by volume of the total volume of each of the individual particles of the deformable beaded material.
  • FIG. 1 is a representation of a uni-planar structural "mat" of fibers believed to form in situ using rod-like fibrous proppant additives of the prior art.
  • FIG. 2 is a representation of uni-planar agglomerate structures believed to form in situ using thermoplastic ribbon or flake proppant additives of the prior art.
  • FIG. 3 is a representation of a substantially spherical deformable beaded particle according to one embodiment of the disclosed method.
  • FIG. 4 is a representation of one mechanism believed responsible for deformation of the substantially spherical particle of FIG. 3 due to contact with fracture proppant under conditions of formation stress.
  • FIG. 5 is a representation of a multi-planar hexagonal close-packed structure believed to form in situ using one embodiment of the disclosed method having a 7:1 ratio of fracture proppant material to polystyrene divinylbenzene plastic beads.
  • FIG. 6 is a simplified representation of one possible shape of a deformable beaded particle subjected to hexagonal contact with fracture proppant material.
  • FIG. 7 is a simplified representation of one possible shape of deformable beaded particle subjected to pentagonal contact with fracture proppant material.
  • FIG. 8 is a simplified representation of one possible shape of a deformable beaded particle subjected to tetragonal contact with fracture proppant material.
  • FIG. 9 is a simplified representation of one possible shape of a deformable beaded particle subjected to contact in two locations by fracture proppant material.
  • FIG. 10 illustrates stress versus strain, and shows variation in Young's modulus of elasticity for polystyrene divinylbenzene plastic beads.
  • FIG. 11 illustrates volume compaction versus closure stress for polystyrene divinylbenzene plastic beads.
  • FIG. 12 illustrates linear compaction versus closure stress for polystyrene divinylbenzene plastic beads.
  • FIG. 13 illustrates linear compaction versus closure stress for 20/40 mesh Ottawa sand at a pack density of 2 lb/ft .
  • FIG. 14 illustrates permeability versus closure stress for plastic beads, 20/40 mesh Ottawa sand, and 3:1 and 7:1 mixtures by volume of 20/40 plastic beads and 20/40 mesh Ottawa sand according to embodiments of the disclosed method.
  • FIG. 15 illustrates conductivity versus closure stress for 20/40 mesh Ottawa sand, 20/40 mesh plastic beads, and 3:1 and 7:1 mixtures by volume of 20/40 mesh Ottawa sand and 20/40 mesh plastic beads according to one embodiment of the disclosed method.
  • FIG. 16 illustrates fines generation versus closure stress for 20/40 mesh Ottawa sand and 3:1 and 7:1 mixtures of 20/40 mesh Ottawa sand and 20/40 mesh plastic beads according to embodiments of the disclosed method.
  • FIG. 17 illustrates three dimensional deformation of polystyrene divinylbenzene particles after being subjected to stress in a simulated fracture proppant pack.
  • FIG. 18 illustrates the flowback failure of an Ottawa sand proppant pack under a closure stress of greater than 1000 psi.
  • FIG. 19 illustrates the flowback failure of a proppant pack containing a 3:1 mixture of
  • FIG. 20 illustrates the flowback failure of a proppant pack containing a 4:1 mixture of Ottawa sand to polystyrene divinylbenzene plastic beads under a closure stress of greater than 1000 psi.
  • FIG. 21 illustrates the flowback failure of a proppant pack containing a 5.7:1 mixture of Ottawa sand to polystyrene divinylbenzene plastic beads under a closure stress of greater than 1000 psi.
  • FIG. 22 illustrates drag force versus fracture width of a proppant pack containing 20/40 mesh Ottawa sand.
  • FIG. 23 illustrates drag force versus fracture width for a proppant pack mixture containing 20/40 mesh Ottawa sand and 15% by weight of 20 mesh polystyrene divinyl benzene plastic beads.
  • FIG. 24 illustrates drag force versus fracture width for a proppant pack mixture containing 20/40 mesh Ottawa sand and 30 mesh silica/resin agglomerate beads.
  • FIG. 25 illustrates drag force versus flow rate for a proppant pack containing 20/40 mesh Ottawa sand and proppant pack mixtures containing 20/40 mesh Ottawa sand and 15% by weight of polystyrene divinyl benzene plastic beads of varying size.
  • FIG. 26 illustrates conductivity as a function of a closure stress for 20/40 mesh Ottawa sand and a mixture containing 20/40 Ottawa sand and 15% by weight 20 mesh polystyrene divinylbenzene plastic beads.
  • FIG. 27 is a representation of a layered deformable beaded particle including a substantially non-deformable core surrounded by a substantially deformable coating or layer according to one embodiment of the disclosed method.
  • FIG. 28 is a representation of a fracture proppant pack believed to form in situ using one embodiment of the disclosed method employing a mixture of layered deformable beaded particles and substantially non-deformable fracture proppant material.
  • FIG. 29 is a representation of a fracture proppant pack believed to form in situ using one embodiment of the disclosed method employing only layered deformable beaded particles.
  • FIG. 30 is a representation of an agglomerated deformable beaded particle including substantially non-deformable components su ⁇ ounded and intermixed with a coat of substantially deformable material according to one embodiment of the disclosed method.
  • deformable particulate material e.g., deformable particles
  • fracture proppant material e.g., deformable particles
  • deformable it is meant that individual particles of a particulate material yield upon point to point stress with particles of fracture proppant material and or deformable particulates present in a fracture pack.
  • blends of fracture proppants and deformable particles according to embodiments of the disclosed method are synergistic in that combinations of fracture proppant material and deformable particles may possess greater conductivity and or permeability than either material possesses alone. This synergistic effect is believed to result from a number of factors, including the in situ deformation of the deformable particles to form multi-planar structures or networks that, among other things, may cushion the fracture proppant material.
  • deformable particulates act as a "cushion" to prevent grain to grain contact and absorb stress between particles of silica, synthetic or other types of proppants. It is believed that this cushion effect prevents proppant particles from shattering or breaking due to stress (including stress induced by stress cycling) and that therefore less fines are produced.
  • porosity, permeability and/or conductivity may be maintained.
  • combinations of deformable particulate and proppant material according to embodiments of the disclosed method may also reduce proppant flowback due to plastic deformation of deformable particles into multi-planar structures.
  • deformable particles deform at formation temperatures and with proppant contact as fracture closure stress is applied.
  • Previous methods using fracturing treatment additive materials having fiber 2 or ribbon-like (or flake) 4 geometries are believed to address proppant flowback by creating uni-planar structures with proppant as shown in FIGS. 1 and 2.
  • uni-planar it is meant that the in situ structures created by these additives are believed to have geometries that extend vector stress in one plane of a proppant pack.
  • multi-planar structures or networks in situ that act to reduce or prevent proppant flowback by increasing particle cohesion and proppant pack stability.
  • multi-planar it is meant that in situ structures created by the treatment additives of the disclosed method are believed to have geometries that extend vector stress in more than one plane of the proppant pack, i.e., in three dimensions. Therefore, structures formed in the practice of the disclosed method are believed to exist as in situ networks extending within, and forming part of, a fracture proppant matrix. Particular embodiments of the disclosed method may offer further advantages.
  • a substantially spherical deformable beaded material of the disclosed method is mixed with a relatively irregular or angular fracture proppant material such as sand
  • greater porosity and permeability may be achieved due to the creation of a pack geometry, such as hexagonal packing, that is superior to the pack geometry achieved by the fracture proppant material alone.
  • even greater fracture conductivity may be achieved using the disclosed method by blending a fracture proppant material with a deformable material having a density less than that of the fracture proppant material, resulting in a greater fracture width per unit mass.
  • FIG. 3 An example of a substantially spherical deformable beaded particle 10 according to one embodiment of the disclosed method is shown in FIG. 3.
  • FIG. 4 illustrates one possible mechanism believed responsible for deformation of a substantially spherical particle 10 of FIG. 3 as a result of contact with individual particles of fracture proppant material 20 under conditions of formation stress.
  • proppant particles 20 create "dimpled" impressions 30 in the sides 40 of deformable particle 10 in which proppant particles 20 may reside.
  • non-spherical beaded particles as well as non-beaded particle shapes may also be used successfully in the practice of the disclosed method.
  • non-spherical beaded particles include, but are not limited to, beaded particles having a shape that is elongated in one or more dimensions, such as particles that are oval shaped, egg-shaped, tear drop shaped, or mixtures thereof.
  • non-beaded particles include, but are not limited to, particles having a shape that is cubic, bar-shaped (as in a hexahedron with a length greater than its width, and a width greater than its thickness), cylindrical, multi-faceted, irregular, or mixtures thereof.
  • beaded or non-beaded deformable particles may have a surface that is substantially roughened or irregular in nature or a surface that is substantially smooth in nature.
  • mixtures or blends of deformable particles having differing, but suitable, shapes for use in the disclosed method may be employed.
  • particles having a length to diameter aspect ratio of equal to or less than about 5 are typically employed (as used herein, "length” is measured along the axis of a particle having the longest dimension). More typically, cylindrical or elongated beaded particles having a length to diameter aspect ratio of equal to or less than about 3 are employed. Most typically, cylindrical or elongated beaded particles having a length to diameter aspect ratio of equal to or less than about 2 are used.
  • both the length to width ratio and the length to thickness ratio of a given individual particle are typically equal to or less than about 5, more typically equal to or less than about 3, and most typically equal to or less than about 2.
  • maximum length based aspect ratio means the maximum aspect ratio that may be obtained by dividing the length of a particle by the minimum (or shortest) dimensional value that exists along any other axis (other than the length axis) taken through the center of mass of the particle.
  • particles of any shape may be employed in the disclosed method when such particles have a maximum length-based aspect ratio that is typically equal to or less than about 5, more typically equal to or less than about 3, and most typically equal to or less than about 2.
  • FIG. 5 An example of a multi-planar structure believed to form in situ from a mixture of deformable beaded particulate materials 10 and fracture proppant material 20 according to one embodiment of the disclosed method having a 7:1 blend of fracture proppant material to deformable particulate material is shown in FIG. 5.
  • a multi-planar pack may be formed by other ratios of deformable material to fracture proppant material.
  • proppant packs may be formed with proppant particles "locked" into deformed surfaces of the deformable particles, thus forming a stronger pack.
  • SUBSTITUTESrlEEr(RULE26) and fracture proppant material is required in order to obtain the benefits of the disclosed method.
  • Beaded particulate material is believed to deform into different shapes depending on the packing geometry surrounding each bead. Just a few of these shapes are illustrated in simplified geometrical form in FIGS. 6-9.
  • FIGS. 6-8 illustrate approximate cuboidal and pyramidal shapes of beaded particulate material 10 that are believed to result from hexagonal (bead contacted by proppant in six locations), pentagonal (bead contacted by proppant in five locations), and tetragonal (bead contacted in four locations) packing, respectively. As shown in FIG.
  • deformable particle embodiments of the disclosed method may allow a well to be put on production faster than resin coated sand methods which require shut-in time for resin curing, thus providing a more rapid return on investment.
  • embodiments of the disclosed method may be selected to be chemically compatible with fracture fluid additives.
  • deformable particles may be mixed with any substantially non-deformable proppant suitable to maintain a fracture in an oil, gas, geothermal, coalbed methane, water or other subte ⁇ anean well.
  • substantially non-deformable fracture proppant materials include, for example, silica (such as Ottawa, Brady or Colorado Sands), synthetic organic particles, glass
  • S ⁇ BSmiJTESHEET(RULE26) microspheres including ceramics (including aluminosilicates such as “CARBOLITE,” “NAPLITE” or “ECONOPROP"), resin-coated sand (such as “ACME BORDEN PR 6000” or “SANTROL TEMPERED HS”), sintered bauxite, and mixtures thereof.
  • ceramics including aluminosilicates such as “CARBOLITE,” “NAPLITE” or “ECONOPROP”
  • resin-coated sand such as “ACME BORDEN PR 6000” or “SANTROL TEMPERED HS”
  • sintered bauxite such as "ACME BORDEN PR 6000” or "SANTROL TEMPERED HS”
  • any natural or synthetic particulate material that is substantially deformable under reservoir conditions in the presence of fracture proppant material to prevent formation of fines, improve fracture conductivity, and/or reduce flowback of proppant or formation materials may be employed.
  • substantially deformable particulate materials include, but are not limited to, those deformable materials having a Young's modulus of between about 500 psi and about 2,000,000 psi at formation conditions, more typically between about 5,000 psi and about 500,000 psi, more typically between about 5,000 psi and 200,000 psi at formation conditions, and most typically between about 7,000 and 150,000 psi at formation conditions.
  • substantially deformable materials When used in the disclosed method, substantially deformable materials have a glass transition temperature that is greater than the reservoir temperature.
  • examples of such materials include, but are not limited to, polymers, cross-linked polymers and suitably deformable plastics.
  • deformable materials having varying or increased glass transition temperatures may be selected by those of skill in the art. For example, polystyrene beads with greater amounts of divinyl benzene crosslinker tend to have increased hardness and glass transition temperature.
  • materials that may be suitable in the practice of the disclosed method may include, but are not limited to cellulose acetate butyral, polystyrene acrylonitride, polytetrafluoroethylene, diglycol allyl carbonates, epoxy resins, polyester, furan, phenol formaldehyde, phenolic epoxy, urea aldehydes, silicones, acrylics, vinyl acetates, casein, and natural and synthetic rubbers.
  • crosslinked elastomeric or polymeric materials are typically employed.
  • Polymers that may be crosslinked for purpose of the disclosed method may include, but are not limited to, polystyrene, methylmethacrylate, nylon, polycarbonates, polyethylene, polypropylene, polyvinylchloride, polyacrylonitrile-butadiene-styrene, polyurethane, or any other suitable polymer, and mixtures thereof.
  • suitable crosslinkers may include
  • Particularly suitable materials may include deformable particles manufactured of resin and/or those commercially available materials that do not substantially interact chemically with components of well treatment fluids and which are stable in a subterranean formation environment.
  • deformable particles of crosslinked polymers may contain varying percentages of crosslinkers to produce proppant packs having varying stabilities and conductivities.
  • any amount of crosslinker suitable for forming a deformable particle may be employed. Percentages of crosslinker employed may be selected on many factors if so desired, such as the intended use of the deformable particle, the specific crosslinking agent, and other constituents which may optionally be present in the deformable particles.
  • polystyrene divinylbenzene plastic beads typically having between about 0.3% and about 55%, more typically between about 0.5% and about 20% by weight of divinylbenzene crosslinker are employed.
  • polystyrene divinylbenzene plastic beads having between about 0.5% and about 14% by weight of divinylbenzene crosslinker are employed.
  • divinylbenzene concentrations of polystyrene beads employed in this embodiment may be selected by those of skill in the art with benefit of this disclosure including, but not limited to, polystyrene divinyl benzene plastic beads containing less than or equal to about 14%, less than about 10%, less than about 5%, less than about 4%, less than about 3%, less than about 2%, less than about 1%, less than about 0.5%, or less than or equal to about 0.3% by weight of divinylbenzene crosslinker.
  • Still other exemplary bead compositions that that may be selected for use in this embodiment include, but are not limited to, polystyrene divinylbenzene plastic beads containing from about 0.1% to about 14%, from about 0.1% to about 10%, from about 0.2% to about 4%, from about 0.3% to about 4%, from about 0.5% to about 4%, from about 0.3% to about 2%, from about 0.3% to about 1%, and from about 0.3% to
  • Still other possible ranges include, but are not limited to, polystyrene divinylbenzene plastic beads containing respective amounts of about 0.3%, about 0.4%, about 0.5% to about 4%, about 4%, about 10%, or about 14% by weight divinylbenzene crosslinker by weight. It will be understood with benefit of this disclosure that the preceding concentration ranges for use at temperatures of up to about 200°F are exemplary only, and that polystyrene divinylbenzene beads containing greater than about 14% by weight polystyrene divinylbenzene may also be employed at formation temperatures within this range.
  • polystyrene divinylbenzene plastic beads having greater than about 14% by weight divinyl benzene crosslinker are employed.
  • divinylbenzene concentration of polystyrene beads employed in this embodiment may be selected by those of skill in the art with benefit of this disclosure including, but not limited to, polystyrene divinyl benzene plastic beads containing between greater than about 14% and about 55%, and between greater than about 14% and about 20% by weight of divinylbenzene crosslinker.
  • polystyrene divinylbenzene beads having amounts of divinylbenzene crosslinker less than about 0.2% or less than about 0.1% by weight may also be employed at any given formation temperature if so desired.
  • polystyrene divinylbenzene beads disclosed herein may be employed at temperatures of greater than about 300°F, if so desired.
  • polystyrene divinylbenzene plastic beads having the above-described concentration ranges of divinylbenzene crosslinker may be used under a wide variety of formation conditions. For example, it may be preferable to use beads containing less divinylbenzene crosslinker at lower
  • polystyrene divinylbenzene plastic beads having from about 0.3% to about 0.5% by weight divinylbenzene crosslinker may optionally be employed in the treatment of formations having closure stresses of less than or equal to about 6000 psi.
  • polystyrene divinylbenzene plastic beads having greater than or equal to about 4% by weight divinylbenzene crosslinker may be employed in treatment of formations having closure stresses of greater than about 6000 psi.
  • deformable bead embodiments may also be employed in the practice of the disclosed method.
  • the polymer type and/or composition of a deformable particle may be varied in order to further tailor the characteristics of deformable particles to anticipated formation conditions and/or to optimize cost versus benefits of the disclosed method, if so desired.
  • deformable particles may be formulated to comprise co-polymers for use at higher formation temperatures, such as temperatures greater than about 300°F.
  • terpolymer compositions such those comprising polystyrene/vinyl/divinyl benzene, acrylate-based terpolymer, other terpolymers, etc. may be employed.
  • Table I includes a partial listing of melting point, glass transition temperature and Young's modulus of elasticity values for some of the polymer materials listed above.
  • polystyrene divinylbenzene particles are typically employed at formation temperatures from about 150°F to about 300°F, and at formation stress values of from about 500 psi to about 12,000 psi.
  • materials such as rubbers or non-crosslinked polymers, including non-crosslinked species of those polymers described above, may be suitable.
  • materials such as polyvinylchloride or soft metals, including lead, copper, and aluminum, may be employed.
  • values of Young's modulus may vary with in situ formation conditions,
  • FIG. 10 illustrates the relationship between values of Young's modulus and stress for polystyrene divinylbenzene beads.
  • FIG. 5 illustrates just one embodiment of a multi-planar structure believed to be formed in situ between beaded deformable particles and fracture proppant material in the practice of the disclosed method.
  • deformable particles of any size and shape suitable for forming multi-planar structures or networks in situ with fracture proppants may be employed, such as those particles having shapes as mentioned previously.
  • This also includes any deformable particles suitable for forming multi-planar structures or networks that offer improved fracture conductivity and/or reduced fines creation over conventional proppant packs.
  • Fracture proppant sizes may be any size suitable for use in a fracturing treatment of a subterranean formation. It is believed that the optimal size of deformable particulate material relative to fracture proppant material may depend, among other things, on in situ closure stress. In this regard, deformable particles having a size substantially equivalent or larger than a selected fracture proppant size are typically employed. For example, a deformable particulate material having a larger size than the fracture proppant material may be desirable at a closure stress of about 1000 psi or less, while a deformable particulate material equal in size to the fracture proppant material may be desirable at a closure stress of about 5000 psi or greater.
  • a deformable particle is selected to be at least as big as the smallest size of fracture proppant being used, and may be equivalent to the largest fracture proppant grain sizes. In either case, all things being equal, it is believed that larger fracture proppant and deformable particulate material is generally advantageous, but not necessary. Although deformable particulate material smaller than the fractured proppant may be employed, in some cases it may tend to become wedged or lodged in the fracture pack interstitial spaces.
  • Deformable particles used in the disclosed method typically have a beaded shape and a size of from about 4 mesh to about 100 mesh, more typically from about 8 mesh to about 60 mesh, even more typically from about 12 mesh to about 50 mesh, even more typically from about 16 mesh to about 40 mesh, and most typically about 20/40 mesh.
  • deformable particles may range in size from about 1 or 2 mm to about 0.1 mm; more typically their size will be from about 0.2 mm to about 0.8 mm, more typically from about 0.4 mm to about 0.6 mm, and most typically about 0.6 mm.
  • sizes greater than about 2 mm and less than about 0.1 mm are possible as well.
  • Deformable particles having any density suitable for fracturing a subte ⁇ anean formation may be employed in the practice of the disclosed method.
  • the specific gravity of a deformable particulate material is from about 0.3 to about 3.5, more typically from 0.4 to about 3.5, more typically from about 0.5 to about 3.5, more typically from about 0.6 to about 3.5, and even more typically from about 0.8 to about 3.5. More typically a deformable particulate material having a specific gravity of from about 1.0 to about 1.8 is employed, and most typically a deformable particle having a specific gravity of
  • SUBSTITUTE SHEET about 1.0 to about 1.1 is employed.
  • a particular divinylbenzene crosslinked polystyrene particle may have a bulk density of from about 0.4 to about 0.65, and most typically of about 0.6.
  • a particular divinylbenzene crosslinked polystyrene particle may have a specific gravity of about 1.055.
  • other specific gravities are possible.
  • deformable particles having a density less than that of a selected fracture proppant material are employed, reduced treating pressures and concentration levels of potentially formation-damaging gelled or viscous fluids may be employed. This may allow higher treating rates and/or result in higher formation productivity.
  • Deformable particles may be mixed and pumped with fracture proppant material throughout or during any portion of a hydraulic fracturing treatment in the practice of the disclosed method.
  • deformable particulate material when deformable particulate material is mixed with only a portion of a fracture proppant material pumped into a formation, it is typically mixed with proppant during the latter stages of the treatment in order to dispose the deformable particulate material in the fracture pack at or near the point where the well bore penetrates a subte ⁇ anean formation.
  • mixtures of deformable particles and fracture proppant material may be pumped in any number of multiple stages throughout a fracture treatment job.
  • any suitable concentration of deformable particles may be mixed with fracture proppant material, with greater concentrations of deformable particles typically resulting in a greater reduction in fines generation for a given formation and proppant material.
  • ratio of substantially non- deformable fracture proppant material to deformable particulate material in a deformable particle/fracture proppant material mixture is from about 20:1 (or about 5% by volume deformable particulate) to about 0.5:1 (or about 67% by volume deformable particulate) by volume of total volume of deformable particle/fracture proppant mixture.
  • a ratio of fracture proppant to deformable particulate material may be from about 1 :1 to about 15:1 by volume of total volume of deformable particle/fracture proppant mixture. More typically, a ratio of fracture proppant to deformable particulate material is about 3:1 to about 7:1. Most typically, a ratio of about 3:1 is employed. In another embodiment of the
  • concentrations of deformable particulate material in a deformable particle/fracture proppant mixture may be from about 1% to about 50% by weight of total weight of fracture proppant mixture, more typically from about 10% to about 25% by weight of total weight of fracture proppant mixture, more typically from about 15% to about 25% by weight of total weight of fracture proppant mixture and most typically about 15% by weight of total weight of fracture mixture.
  • deformable particulate material may be mixed with a fracture proppant or mixture of fracture proppants in any manner suitable for delivering such a mixture to a subte ⁇ anean formation.
  • deformable particles may be mixed with a fracture proppant prior to mixing with ca ⁇ ier fluid, or deformable particles may be mixed with carrier fluid before or after a ca ⁇ ier fluid is mixed with a proppant.
  • Deformable particulate materials may also be mixed in a solution which is later added to proppant or ca ⁇ ier fluid as it is pumped.
  • mixtures or blends of deformable particles and fracture proppant may be injected into a subte ⁇ anean formation in conjunction with other treatments at pressures sufficiently high enough to cause the formation or enlargement of fractures, or to otherwise expose the blend of deformable particles and fracture proppant material to formation closure stress.
  • Such other treatments may be near wellbore in nature (affecting near wellbore regions) and may be directed toward improving wellbore productivity and/or controlling the production of fracture proppant or formation sand.
  • Particular examples include gravel packing and "frac-packs.”
  • any ca ⁇ ier fluid suitable for transporting a mixture of fracture proppant material and deformable particles into a formation fracture in a subterranean well may be employed including, but not limited to, carrier fluids comprising salt water, fresh water, liquid hydrocarbons, and/or nitrogen or other gases.
  • carrier fluids comprising salt water, fresh water, liquid hydrocarbons, and/or nitrogen or other gases.
  • Suitable carrier fluids include or may be used in combination with fluids have gelling agents, cross-linking agents, gel breakers, curable resins, hardening agents, solvents, surfactants, foaming agents, demulsifiers, buffers, clay stabilizers, acids, or mixtures thereof.
  • Polystyrene divinylbenzene plastic beads for use with the disclosed methods may be prepared by methods that would be apparent to those of skill in the art or purchased from "DOW CHEMICAL.”
  • cross-linked polystyrene beads having a specific gravity of from about 1.0 to about 1.8 are employed.
  • 20-40 mesh polystyrene divinylbenzene copolymer plastic beads having a specific gravity of about 1.0 are mixed with 20/40 mesh Ottawa sand at a ratio of about 3:1 by weight.
  • These beads are commercially available as a lubrication fluid from "SUN DRILLING PRODUCTS” under the brand name "LUBRAGLIDE,” or as ion exchange beads manufactured by "DOW CHEMICAL.” These beads offer crush resistance, are resistant to solvents, and are substantially round and smooth, having length to width and length to height ratios of about 1 :1.
  • the polystyrene divinylbenzene plastic beads of this embodiment have a reduced bulk density (i.e., about 0.64 gm cm ), the beads may be suspended in frac fluids with a significant reduction in gelling agents. With a reduction in density, these plastic beads require less packing density (i.e., lb/ft 2 ) to achieve the same fracture width. Test results indicated that these plastic beads are deformable under conditions of stress and relative to sand proppant. Test results also showed that these beads are compatible with oil field solvents and acids.
  • Favorable formation treating characteristics offered by polystyrene divinylbenzene beads include, among other things, strength, crush resistance, chemical resistance, elasticity, high glass transition temperature. These beads are also "non-creeping" (i.e., resistant to slow change in shape due to constant force).
  • HCP hexagonal-close-pack
  • multi-component or multiple component deformable particles may be utilized.
  • multi-component or multiple component means a particle comprised of at least two materials having different deformation characteristics (such as differing values of elastic modulus).
  • at least one component of such a multi-component particle has the characteristic of being substantially deformable, and at least one other component of the particle has the characteristic of being substantially non-deformable relative to the deformable component.
  • the two or more materials may be configured in virtually any manner desired to form multi-component particles, for example, to achieve varying overall deformation characteristics of such particles.
  • Possible particle configurations include, but are not limited to, layered particles (such as concentrically layered particles), agglomerated particles, stratified particles, etc.
  • Such multi-component deformable particles may be employed with substantially non-deformable fracture proppant material in any of the amounts described elsewhere herein for deformable particles.
  • Such multi-component deformable particles may be employed alone so as to make up all, or substantially all, of a fracture pack with little or no substantially non-deformable fracture proppant material present in the pack.
  • layered multi-component deformable particles may be provided that comprise a substantially hard or non-deformable core surrounded by one or more layers of substantially deformable material.
  • layered multi-component deformable particles may be particularly desirable for use with higher anticipated formation temperatures and or higher anticipated formation closure stresses due to the ability to provide sufficient elasticity or deformability of the surface of the particle without being susceptible to excessive or total
  • a layered multi-component deformable particle 200 may be provided using a proppant particle or other substantially hard or substantially non-deformable material core 202 coated by a substantially deformable material 204.
  • a layered deformable particle may be formulated to be capable of withstanding total deformation, particularly at high formation temperatures and formation stresses (i.e., formation temperatures exceeding about 300°F and formation stresses exceeding about 6000 psi).
  • a substantially hard core of such a layered deformable particle may be selected to provide sufficient strength or hardness to prevent total deformation of the particle at temperatures and/or formation closure stresses where substantially deformable materials (such as crosslinked polymers) generally become plastic.
  • total or near-total deformation of a deformable particle in a proppant pack is undesirable because it may damage fracture proppant pack permeability when the amount of deformation reaches levels sufficient to plug proppant pack pore spaces.
  • a layered deformable particle having a substantially non-deformable inner core surrounded by a single layer of substantially deformable material is depicted in FIG. 27, it will be understood with benefit of this disclosure, that one or more layers of deformable material/s may be utilized to provide a substantially deformable coating over a substantially non-deformable or hard inner core. Similarly, it will also be understood that a substantially non-deformable inner core may comprise more than one layer or thickness of substantially non- deformable material. Furthermore layers of such non-deformable and deformable materials may be alternated if so desired.
  • a deformable coating is typically provided in a thickness or volume sufficient to allow adjacent and relatively hard fracture proppant particles in a fracture proppant pack to penetrate all or a portion of the deformable coating so as to provide one or more benefits of deformable particles as described elsewhere herein, but without substantially reducing porosity of a fracture pack due to excessive deformation.
  • a substantially non-deformable inner core acts to limit undesirable distortion of the deformable particle so as to prevent excessive damage to the conductivity of a fracture proppant pack.
  • FIG. 28 illustrates just one possible embodiment of a multi-planar structure believed to be formed in situ between layered deformable particles 200 and fracture proppant particles 206 in the practice of the disclosed method.
  • layered deformable particles of any size and shape suitable for forming multi-planar structures or networks in situ with fracture proppants may be employed, including deformable particles having shapes as mentioned previously.
  • layered deformable particles 200 may be utilized alone in well stimulation treatments to create proppant packs comprising only deformable particles 200 as depicted in FIG. 29.
  • a layered deformable particle may have one or more layers or coatings of deformable material which may include any of the deformable materials mentioned elsewhere herein.
  • layered deformable particles include one or more coatings of crosslinked polymers.
  • Suitable crosslinked polymers include, but are not limited to, polystyrene, methylmethacrylate, nylon, polycarbonate, polyethylene, polypropylene, polyvinylchloride, polyacrylonitrile-butadiene-styrene, polyurethane, mixtures thereof, etc.
  • any other deformable material suitable for coating a substantially hard proppant core and having suitable deformable characteristics as defined elsewhere herein may be employed.
  • a core of a layered deformable particle may comprise any material or materials suitably hard enough to form a substantially nondeformable core about which one or more layers of deformable material may be disposed.
  • a core is typically a fracture proppant such as sand or any of the other substantially non- deformable fracture proppants mentioned elsewhere herein.
  • a suitable core material may be silica (such as Ottawa sand, Brady sand, Colorado sand, etc.), synthetic organic particles, glass microspheres, sintered bauxite (including aluminosilicates), ceramics (such as CARBOLITE from Carbo Ceramics, Inc., NAPLITE from Norton Alcoa, ECONOPROP, from
  • a core material may have a Young's modulus that is suitably hard and non-deformable relative to the Young's modulus of layers of deformable material disposed thereabout.
  • a core material may have a Young's modulus greater than about 500,000 psi, alternatively a Young's modulus between about 500,000 psi and about 15,000,000 psi or alternatively a Young's modulus of between about 2,000,000 psi and about 15,000,000 psi.
  • a deformable layer or coating around a substantially non-deformable particle core may be any thickness suitable for allowing deformation of the layer upon contact with fracture proppant materials under closure stress.
  • typically thickness of such layer/s are limited such that deformation under anticipated formation closure stress does not result in damage to conductivity due to excessive deformation and impingement into fracture proppant pack pore spaces.
  • a layer/s of deformable material typically is thick enough to provide a coating sufficient for reducing proppant flowback and/or fines generation by allowing adjacent relatively hard fracture proppant material to embed in the layers of deformable material without substantially reducing porosity or conductivity of the proppant pack.
  • one or more layers of deformable material comprise at least about 10% by volume or alternatively at least about 20% by volume of the total volume of the layered deformable particle.
  • one or more layers of deformable particulate material may comprise respectively from about 10% to about 90%, from about 20% to about 90%, from about 20% to about 70%, from about 40% to about 70%, or about 70% by volume of total volume of a layered deformable particle.
  • one or more layers of deformable material may comprise less than about 10% by volume of the total volume of a layered deformable particle, and greater than about 90% by volume of the total volume, of a layered deformable particle.
  • one or more layers of deformable material may comprise greater than 8%, or alternatively greater than about 10%, by weight of the total weight of a layered deformable particle.
  • the thickness of the outside layer or coating of a two component deformable particle may be substantially equivalent to the diameter or thickness of the particle core.
  • a substantially hard core having a 40 mesh size may be coated with sufficient deformable material to produce a 20 mesh two-layer or two-component deformable particle.
  • the thickness of one or more outside layers or coatings of deformable material is typically equal to or greater than the non-deformable core diameter for each particle.
  • the thickness of the one or more outside layers or coatings of deformable material is typically equal to or less than about 10% of the diameter of the non-deformable core of each particle.
  • any deformable material described elsewhere herein may be employed for one or more layers of a layered deformable particle, in one embodiment materials having a modulus of between about 500 psi and about 2,000,000 psi, or alternatively between about 5,000 psi and about 200,000 psi, may be employed. Typically such deformable materials are selected to be chemically resistant and substantially non-swelling in the presence of solvents as described elsewhere herein.
  • a layered deformable particle comprises a silica core material su ⁇ ounded by a single layer or coating of polystyrene divinylbenzene co-polymer (having from about 0.5% to about 20% by weight divinyl benzene cross-linker).
  • the core material has a modulus of about 2,000,000 psi to about 5,000,000 psi and the single layer coating has a modulus of about 70,000 psi.
  • the disclosed layered deformable particles may be of any overall size suitable for use in a fracture proppant pack, either alone or in a mixture with fracture proppant material, as well as in sizes as described elsewhere herein.
  • a layered deformable particle for inclusion in a mixture with fracture proppant is selected to have a size at least as large as the smallest fracture proppant particles being used.
  • a layered deformable particle for use in a mixture with fracture proppant is selected to have a size equal to the largest fracture proppant particles.
  • a layered deformable particle has a size typically from about 4 mesh to about 100 mesh, more typically from about 12 mesh to about 50 mesh, and most typically about 20/40 mesh.
  • layered deformable particulate materials may be employed alone as a fracture proppant material (i.e., without another type of fracture proppant material), or may be employed with mixtures of fracture proppant material as previously described for single component deformable particles.
  • layered deformable particles may be mixed with a fracture proppant material in any of the weight percentages or ratios relative to fracture proppant material as described elsewhere herein.
  • layered particles may include a substantially hard core with two or more layers of deformable materials su ⁇ ounding the core. Any combination of two or more deformable materials mentioned elsewhere herein may be employed in multi- component deformable particles having a core su ⁇ ounded by two or more layers. In this
  • deformable particles having two or more layers of deformable materials may be useful for providing the desired degree of deformability in combination with other desirable properties.
  • a first layer of relatively soft deformable material may be su ⁇ ounded or covered by a second or outside layer of relatively hard, but chemical resistant deformable material. In this way sufficient particle deformability and chemical resistance at high temperatures may be provided simultaneously.
  • a relatively softer and more chemical resistant second or outer layer of deformable material may surround a first layer of relatively harder, less chemical resistant deformable material.
  • a two-layer multi-component deformable particle may include a substantially hard 40 mesh Ottawa sand core surrounded by a first layer of substantially deformable acrylate or acrylic polymer and a second layer of substantially deformable polystyrene.
  • a particle configuration provides deformability and strength over a larger range of temperatures and stresses.
  • agglomerated multi-component deformable particles may be employed.
  • Such agglomerates may comprise one or more relatively hard or substantially non-deformable materials mixed or agglomerated with one or more relatively elastic or substantially deformable materials.
  • One example of such a particle 300 is illustrated in cross-section in FIG. 30.
  • An agglomerated multi-component deformable particle 300 may comprise one or more substantially non-deformable material components 302, such as one or more materials selected from the substantially non-deformable materials described elsewhere herein as suitable for a core material of a layered deformable particle.
  • Such substantially non-deformable material components 302 may be coated with or otherwise intermixed with substantially deformable material 304 so that the deformable material 304 functions to at least partially coat and/or fill pore spaces existing between individual non- deformable material components 302 as shown in FIG. 30.
  • An outer layer of deformable material 304 may be present as shown in FIG. 30, although this is not necessary.
  • the deformable component/s 304 of such an agglomerated multi-component deformable particle 300 may comprise any suitable substantially deformable materials, such as one or more materials selected from the substantially deformable materials described elsewhere herein as suitable for use in single component and/or layered deformable particles.
  • substantially non- deformable material may be any substantially non-deformable granular material less than about 100 microns in size, and substantially deformable material may be any substantially deformable material suitable for encapsulating the substantially non-deformable material in a matrix.
  • substantially non-deformable material employed in this embodiment include, but are not limited to, at least one of silica, cristobalite, graphite, gypsum, talc, or a mixture thereof
  • substantially deformable material employed in the same embodiment include, but are not limited to, resins such at least one of furan, furfuryl, phenol formaldehyde, phenolic epoxy, or a mixture thereof. It will be understood with benefit of this disclosure by those of skill in the art that whenever resins are utilized as substantially deformable material in the practice of any of the embodiments of the disclosed method that they may be chemically modified, such as by inclusion of suitable plasticizers, to render the resin/s suitably deformable for individual applications.
  • plasticizer may be incorporated in all or a portion of the deformable material content of each particle.
  • a plasticizer may be incorporated into only an outer layer of an agglomerate particle, or alternatively throughout all of the deformable material of the agglomerate particle.
  • an agglomerated deformable particle comprises from about 5% to about 50%, alternatively from about 5% to about 25%, and in a further alternative from about 10% to about 20% by weight of substantially deformable material/s, with the balance of the particle being composed of substantially non-deformable material/s.
  • substantially deformable material may make up between about 5% and about 50% by volume of the total volume of an agglomerated particle, and substantially non-deformable material may make up between about 50% and about 95% by volume of the total volume of the agglomerated particle.
  • an agglomerated multi-component particle may comprise an agglomerated mixture of silica and resin.
  • a resin component may comprise any resin suitable for encapsulating the silica, including, but not limited to, epoxy resins, furan, phenol formaldehyde, phenolic epoxy, etc. Most typically, such a particle comprises about 10.5% by weight of phenolic resin mixed with particles of silica having a size of from about 6 to about 100 microns.
  • multi-component deformable particles may be employed in any of the shapes and sizes described elsewhere herein as being suitable for other forms or embodiments of deformable particles. Moreover, such particles may be employed alone as a fracture proppant, or in mixtures in amounts and with types of fracture proppant materials as described elsewhere herein for other types of deformable particles. It will also be understood with benefit of this disclosure by those of skill in the art that selection of multi-component deformable particle characteristics may be made based on anticipated formation conditions such as formation temperature and/or formation closure stress.
  • Such characteristics include, but are not limited to, core and layer materials of a layered deformable particle, layer and core thicknesses of a layered deformable particle, types and relative percentages of deformable and non-deformable materials employed in an agglomerated multi- component particle, etc.
  • Polystyrene divinylbenzene copolymer plastic beads with a 20/40 mesh size were tested alone (without other proppant materials) using modified API standards. These beads contained about 4% divinylbenzene by weight. These plastic beads used in this example were found to pass the standard API RP 56 test for roundness, sphericity, and acid solubility (i.e., 0.5%). Testing was also performed to determine if any swelling in solvents occurred. The beads were placed in xylene at room temperature and photographed over 65 hours. No swelling occu ⁇ ed
  • the polystyrene divinylbenzene plastic beads of this embodiment had a sphericity of 0.9 and roundness of 0.9 which is suitable for proppant use since it meets the required minimum value of 0.6 for each property.
  • a sieve analysis of the material contained an acceptable 93.8% 20/40 distribution with 6.1% retained on the 50 mesh screen and 0.1 % fines.
  • the acid solubility at 150°F was an acceptable 0.5% using a 12-3 HCI-HF acid.
  • the plastic bead material was slowly (i.e., 2 minutes) stressed in a 1-inch diameter cell by computer control of the measured load while accurately monitoring the change in sample volume by using a sensitive linear variable differential transducer (LVDT) calibrated to
  • volume per cent change in plastic beads is plotted as a function of closure stress.
  • 25% of the bulk bead volume has been lost due to pore volume changes.
  • 6000 psi closure stress essentially all of the pore volume is lost (i.e., 42%) due to compaction, and the beads are essentially a conglomerate solid.
  • This large compaction of plastic beads is shown in FIG. 12 where the change in fracture width is plotted versus stress.
  • SUBST ⁇ UTESHEET (RULE 26) performed using a "DAKE” hydraulic press having a “ROSEMOUNT” differential transducer (#305 IC) and controlled by a “CAMILE” controller. Also employed in the testing was a "CONSTAMETRIC 3200" constant rate pump. In addition to testing 20/40 plastic beads alone, a 7:1 mixture of 1.75 lbs/ft 2 of 20/40 mesh Ottawa sand to 0.25 lbs/ft 2 of 20/40 mesh plastic beads, and a 3 : 1 mixture of 1.50 lbs/ft 2 of 20/40 mesh Ottawa sand to 0.50 lbs/ft 2 of 20/40 mesh plastic beads were also tested. Averaged test results are given in Tables III and IV, as well as FIGS. 14 and 15. For comparison purposes, conductivity and permeability data for 20/40 Ottawa sand published by "STIMLAB" is also presented.
  • test results indicate that combinations of plastic beads and Ottawa sand according to this embodiment of the disclosed method may have a positive synergistic effect on permeability and conductivity.
  • the about 36 darcy permeability of the 3:1 combination is approximately 300% greater than the about 9 darcies permeability of Ottawa sand alone.
  • this test demonstrated the ability of the beads to reduce the production of fines by Ottawa at higher closures stresses by preventing grain to grain contact between grains of proppant.
  • mixtures of deformable particulate material and fracture proppant according to the disclosed method may be used to successfully reduce fines generation and/or proppant flowback independent of, or without, any associated permeability or conductivity improvement over fracture proppant alone.
  • deformation tests demonstrated that a deformable particulate, in this embodiment a polystyrene divinylbenzene bead of 20/40 U.S. Mesh size and containing about 4% divinylbenzene by weight, deforms to consume approximately 33% of the existing pore space at 1000 psi closure stress.
  • a deformable particulate in this embodiment a polystyrene divinylbenzene bead of 20/40 U.S. Mesh size and containing about 4% divinylbenzene by weight, deforms to consume approximately 33% of the existing pore space at 1000 psi closure stress.
  • 2000 psi closure approximately 55% deformation had occu ⁇ ed and at 8000 psi the pore space was essentially nil.
  • the conductivity values are 5778 md-ft for the 3:1 mixture, 4340 md-ft for the 20/40 mesh Ottawa sand, and 3260 md-ft for the plastic beads.
  • the 3:1 mixture gave 1310 md-ft while 20/40 mesh Ottawa sand alone has a conductivity of 1178 md-ft.
  • a similar effect may be observed for the 7:1 mixture.
  • Example 6 Packing Geometries Refe ⁇ ing to FIG. 17, photographs of polystyrene divinylbenzene beads obtained from a stereo microscope are shown. These beads were mixed with an Ottawa sand fracture proppant at a ratio of 3:1 to form a simulated proppant pack, and then subjected to a stress of 10,000 psi. Stress was then relieved and the deformed polystyrene divinylbenzene beads photographed. As shown in FIG.
  • Proppant flowback failure was determined for Ottawa sand and mixtures of Ottawa sand to polystyrene divinylbenzene beads ranging from about 3:1 to about 6:1. For comparison purposes, proppant flowback failure was also determined for Ottawa sand alone.
  • SUBS ⁇ TUTESHEET(RULE26) polystyrene divinylbenzene beads employed for these tests contained about 0.5% divinylbenzene crosslinker by weight, had a Young's confined modulus of about 50,000 psi, and had a size of about 20 mesh.
  • the proppant samples were loaded into a standard conductivity cell at 2 lbs/ft 2 .
  • the width of the pack was measured throughout the test using an LVDT.
  • the differential pressure between the input and output flow of water through the pack was measured employing a Rosemount PD transducer and the rate of the flow was measured by a Micromotion D6 mass flow meter.
  • Closure stress (approximately 1000 psi) was applied to the pack.
  • the end of the conductivity cell was then removed to expose the proppant pack and replaced with a lexan tube filled with water. This allowed sand to flow into the tube at failure.
  • compositions of Ottawa sand/polystyrene divinylbenzene bead mixtures failed at flow rates of greater than approximately 110 ml/min while the Ottawa sand composition failed at flow rates of from about 60 to 80 ml/min.
  • the present invention allows for a significant improvement (approximately 150%) in the stability of the pack while still improving the conductivity at a closure stress of about 1000 psi.
  • Resistance to flowback or measure of the force sufficient to move a proppant particle was determined for 20/40 mesh Ottawa sand and mixtures containing 20/40 mesh Ottawa sand and 15% by weight polystyrene divinyl benzene beads using the testing procedure of Example 7. For comparison purposes, resistance to flowback was also determined for 20/40 mesh Ottawa sand alone.
  • the polystyrene divinyl benzene beads employed for these tests contained about 0.5% divinyl benzene crosslinker by weight, had a Young's confined modulus of about 50,000 psi, and had a size of about 20 mesh.
  • proppants comprising a mixture of 20/40 Ottawa sand and polystyrene divinyl benzene beads exhibited maximum drag force ("Fd") or resistance to flow of from about 0.85 dynes for a mixture containing 40/60 mesh polystyrene divinyl benzene deformable beads to about 1.65 dynes for a mixture containing 20 mesh polystyrene divinyl benzene deformable beads.
  • Fd maximum drag force
  • Higher maximum drag force values at higher flow rates are an indication of higher resistance to proppant movement for mixtures of deformable beads and sand as compared to sand alone.
  • 20/40 mesh Ottawa sand proppant alone exhibited a maximum drag force of about 0.65 dynes at a flow rate of about 70 ml per minute.
  • mixtures of 40/60 mesh, 30/50 mesh, and 20 mesh polystyrene divinyl benzene beads with 20/40 Ottawa sand exhibited maximum drag force values of about 0.85 dynes at about 80 ml per minute, 1.45 dynes at about 110 ml per minute, and about 1.65 dynes at about 120 ml per minute.
  • FIGS. 22 and 23 represent resistance to flowback test data obtained at varying fracture widths for 20/40 mesh Ottawa sand and a mixture of 20/40 Ottawa sand with 15% by weight of 20 mesh polystyrene divinylbenzene beads containing 0.5% by weight divinylbenzene crosslinker, respectively.
  • This data was generated under stepped flowrate conditions up to failure.
  • the proppant mixture of Ottawa sand and polystyrene divinylbenzene beads exhibited a significantly higher Fd of about 1.3 to about 1.6 dynes as compared to Fd of the 20/40 Ottawa sand alone (about 0.60).
  • the Ottawa sand/polystyrene divinylbenzene also maintained this greater flowback resistance up to a fracture width of about 0.235 inches as compared to a fracture width of about 0.205 inches for the Ottawa sand alone.
  • FIG. 24 represents resistance to flowback test data for a mixture of 20/40 Ottawa sand with 25% by weight of 30 mesh agglomerate beads containing approximately 90% 6 micron silica and 10% phenolic resin. This data was generated under stepped flowback conditions up to failure. As may be seen the combination of agglomerate beads and Ottawa sand generated even more resistance to proppant flowback than the Ottawa sand polystyrene divinyl benzene mixture of FIG. 23.
  • the phenolic resin may include a plasticizer to make the deformable layer more elastic.
  • Example 4 The tests of this example were performed at a temperature of 150°F using the procedure of Example 4, with the exception that measurements were made under conditions of cyclic rather than static stress. Stress was increased from 2000 psi to 4000 psi and held at 4000 psi for one hour. The stress was then decreased to 2000 psi and held for one hour before repeating the cycle several times.
  • conductivity of the 20/40 mesh Ottawa sand was about 900 millidarcy-feet ("md-ft") compared to a conductivity of about 2600 md-ft for the mixture of 20/40 Ottawa sand and polystyrene divinyl benzene beads.
  • md-ft millidarcy-feet
  • the conductivity of the 20/40 mesh Ottawa sand dropped from about 900 md-ft to about 750 md-ft.

Abstract

Selon l'invention, on traite une formation souterraine en y injectant un mélange constitué d'un matériau de soutènement de fracture (20) et d'un matériau particulaire déformable (10). Le matériau particulaire déformable (10) peut se combiner avec le matériau de soutènement de fracture (20) pour augmenter la conductibilité de la fracture, réduire la production de fines et/ou réduire le reflux de matériau de soutènement. Le matériau de soutènement de fracture peut être un matériau tel que du sable, et le matériau particulaire déformable peut être constitué de perles de polystyrène divinylbenzène.
PCT/US1998/010735 1997-11-21 1998-05-27 Procede de traitement de formation geologique au moyen de particules deformables WO1999027229A1 (fr)

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CA002308372A CA2308372C (fr) 1997-11-21 1998-05-27 Procede de traitement de formation geologique au moyen de particules deformables
GB0015133A GB2348907B (en) 1997-11-21 1998-05-27 A composition for fracturing a subterranean formation
AU76001/98A AU7600198A (en) 1997-11-21 1998-05-27 Formation treatment method using deformable particles

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DK1333/97 1997-11-21
DK199701333A DK133397A (da) 1996-11-27 1997-11-21 Fremgangsmåde ved behandling af formationer under anvendelse af deformerbare partikler
NL1007616 1997-11-25
NL1007616A NL1007616C2 (nl) 1996-11-27 1997-11-25 Behandelingsmethode voor formaties met gebruikmaking van vervormbare deeltjes.
NO975440 1997-11-26
NO975440A NO975440L (no) 1996-11-27 1997-11-26 Formingsbehandlingsmetode som anvender deformerbare partikler
GB9725153.2 1997-11-27
GB9725153A GB2319796B (en) 1996-11-27 1997-11-27 Formation treatment method using deformable particles

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US6330916B1 (en) 1996-11-27 2001-12-18 Bj Services Company Formation treatment method using deformable particles
US6364018B1 (en) 1996-11-27 2002-04-02 Bj Services Company Lightweight methods and compositions for well treating
US6406789B1 (en) 1998-07-22 2002-06-18 Borden Chemical, Inc. Composite proppant, composite filtration media and methods for making and using same
US6439309B1 (en) 2000-12-13 2002-08-27 Bj Services Company Compositions and methods for controlling particulate movement in wellbores and subterranean formations
US6582819B2 (en) 1998-07-22 2003-06-24 Borden Chemical, Inc. Low density composite proppant, filtration media, gravel packing media, and sports field media, and methods for making and using same
US6632527B1 (en) 1998-07-22 2003-10-14 Borden Chemical, Inc. Composite proppant, composite filtration media and methods for making and using same
US6749025B1 (en) 1996-11-27 2004-06-15 Bj Services Company Lightweight methods and compositions for sand control
US6877560B2 (en) 2002-07-19 2005-04-12 Halliburton Energy Services Methods of preventing the flow-back of particulates deposited in subterranean formations
US7153575B2 (en) 2002-06-03 2006-12-26 Borden Chemical, Inc. Particulate material having multiple curable coatings and methods for making and using same
EP1904601A2 (fr) * 2005-06-13 2008-04-02 Sun Drilling Products Corp. Particules thermodurcies a reticulation amelioree, leur traitement de production, et leur utilisation dans des applications de forage de petrole et de gaz naturel
US7678743B2 (en) 2006-09-20 2010-03-16 Halliburton Energy Services, Inc. Drill-in fluids and associated methods
US7678742B2 (en) 2006-09-20 2010-03-16 Halliburton Energy Services, Inc. Drill-in fluids and associated methods
US7687438B2 (en) 2006-09-20 2010-03-30 Halliburton Energy Services, Inc. Drill-in fluids and associated methods
US7803742B2 (en) 2004-12-30 2010-09-28 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US7833943B2 (en) 2008-09-26 2010-11-16 Halliburton Energy Services Inc. Microemulsifiers and methods of making and using same
US7906464B2 (en) 2008-05-13 2011-03-15 Halliburton Energy Services, Inc. Compositions and methods for the removal of oil-based filtercakes
US8006755B2 (en) 2008-08-15 2011-08-30 Sun Drilling Products Corporation Proppants coated by piezoelectric or magnetostrictive materials, or by mixtures or combinations thereof, to enable their tracking in a downhole environment
US8006754B2 (en) 2008-04-05 2011-08-30 Sun Drilling Products Corporation Proppants containing dispersed piezoelectric or magnetostrictive fillers or mixtures thereof, to enable proppant tracking and monitoring in a downhole environment
US8030251B2 (en) 2005-01-28 2011-10-04 Halliburton Energy Services, Inc. Methods and compositions relating to the hydrolysis of water-hydrolysable materials
US8030249B2 (en) 2005-01-28 2011-10-04 Halliburton Energy Services, Inc. Methods and compositions relating to the hydrolysis of water-hydrolysable materials
US8058213B2 (en) 2007-05-11 2011-11-15 Georgia-Pacific Chemicals Llc Increasing buoyancy of well treating materials
US8258083B2 (en) 2004-12-30 2012-09-04 Sun Drilling Products Corporation Method for the fracture stimulation of a subterranean formation having a wellbore by using impact-modified thermoset polymer nanocomposite particles as proppants
CN103194204A (zh) * 2013-04-10 2013-07-10 北京奥陶科技有限公司 一种用于煤层气与页岩气水力压裂的支撑剂及其制备方法
US8689872B2 (en) 2005-07-11 2014-04-08 Halliburton Energy Services, Inc. Methods and compositions for controlling formation fines and reducing proppant flow-back
WO2015057373A1 (fr) * 2013-10-17 2015-04-23 Schlumberger Canada Limited Traitement de puits au moyen de particules changeant de forme
US9102868B2 (en) 2010-07-29 2015-08-11 3M Innovative Properties Company Elastomer-modified crosslinked epoxy vinyl ester particles and methods for making and using the same
CN108315006A (zh) * 2017-01-17 2018-07-24 北京大学 仿生学智能立体支撑剂及其应用
CN111042794A (zh) * 2019-12-31 2020-04-21 延安双丰集团有限公司 一种常压混砂二氧化碳压裂施工工艺
US11613691B1 (en) * 2018-12-31 2023-03-28 Oceanit Laboratories, Inc. Well proppants

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GB2399118B (en) * 2000-03-06 2004-10-20 Bj Services Co Formation treatment method using deformable particles
US7044220B2 (en) * 2003-06-27 2006-05-16 Halliburton Energy Services, Inc. Compositions and methods for improving proppant pack permeability and fracture conductivity in a subterranean well

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US6330916B1 (en) 1996-11-27 2001-12-18 Bj Services Company Formation treatment method using deformable particles
US6364018B1 (en) 1996-11-27 2002-04-02 Bj Services Company Lightweight methods and compositions for well treating
US6749025B1 (en) 1996-11-27 2004-06-15 Bj Services Company Lightweight methods and compositions for sand control
US6406789B1 (en) 1998-07-22 2002-06-18 Borden Chemical, Inc. Composite proppant, composite filtration media and methods for making and using same
US6582819B2 (en) 1998-07-22 2003-06-24 Borden Chemical, Inc. Low density composite proppant, filtration media, gravel packing media, and sports field media, and methods for making and using same
US6632527B1 (en) 1998-07-22 2003-10-14 Borden Chemical, Inc. Composite proppant, composite filtration media and methods for making and using same
NL1017508C2 (nl) * 2000-03-06 2003-05-08 Bj Services Co Formatiebehandelingswerkwijze die vervormbare deeltjes gebruikt.
US6439309B1 (en) 2000-12-13 2002-08-27 Bj Services Company Compositions and methods for controlling particulate movement in wellbores and subterranean formations
US7153575B2 (en) 2002-06-03 2006-12-26 Borden Chemical, Inc. Particulate material having multiple curable coatings and methods for making and using same
US6877560B2 (en) 2002-07-19 2005-04-12 Halliburton Energy Services Methods of preventing the flow-back of particulates deposited in subterranean formations
US7803741B2 (en) 2004-12-30 2010-09-28 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US9505974B2 (en) 2004-12-30 2016-11-29 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US9630881B2 (en) 2004-12-30 2017-04-25 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US8258083B2 (en) 2004-12-30 2012-09-04 Sun Drilling Products Corporation Method for the fracture stimulation of a subterranean formation having a wellbore by using impact-modified thermoset polymer nanocomposite particles as proppants
US9777209B2 (en) 2004-12-30 2017-10-03 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US7803742B2 (en) 2004-12-30 2010-09-28 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US7803740B2 (en) 2004-12-30 2010-09-28 Sun Drilling Products Corporation Thermoset nanocomposite particles, processing for their production, and their use in oil and natural gas drilling applications
US8030251B2 (en) 2005-01-28 2011-10-04 Halliburton Energy Services, Inc. Methods and compositions relating to the hydrolysis of water-hydrolysable materials
US8030249B2 (en) 2005-01-28 2011-10-04 Halliburton Energy Services, Inc. Methods and compositions relating to the hydrolysis of water-hydrolysable materials
EP1904601A4 (fr) * 2005-06-13 2009-11-11 Sun Drilling Products Corp Particules thermodurcies a reticulation amelioree, leur traitement de production, et leur utilisation dans des applications de forage de petrole et de gaz naturel
EP1904601A2 (fr) * 2005-06-13 2008-04-02 Sun Drilling Products Corp. Particules thermodurcies a reticulation amelioree, leur traitement de production, et leur utilisation dans des applications de forage de petrole et de gaz naturel
EP2436749A1 (fr) * 2005-06-13 2012-04-04 Sun Drilling Products Corporation Particules thermodurcies avec réticulation améliorée, leur traitement de production, et leur utilisation dans des applications de forage de pétrole et de gaz naturel
US8689872B2 (en) 2005-07-11 2014-04-08 Halliburton Energy Services, Inc. Methods and compositions for controlling formation fines and reducing proppant flow-back
US7687438B2 (en) 2006-09-20 2010-03-30 Halliburton Energy Services, Inc. Drill-in fluids and associated methods
US7678742B2 (en) 2006-09-20 2010-03-16 Halliburton Energy Services, Inc. Drill-in fluids and associated methods
US7678743B2 (en) 2006-09-20 2010-03-16 Halliburton Energy Services, Inc. Drill-in fluids and associated methods
US8058213B2 (en) 2007-05-11 2011-11-15 Georgia-Pacific Chemicals Llc Increasing buoyancy of well treating materials
US9140111B2 (en) 2008-04-05 2015-09-22 Sun Drilling Products Corporation Proppants containing dispersed piezoelectric or magnetostrictive fillers or mixtures thereof, to enable proppant tracking and monitoring in a downhole environment
US9732269B2 (en) 2008-04-05 2017-08-15 Sun Drilling Products Corporation Proppants containing dispersed piezoelectric or magnetostrictive fillers or mixtures thereof, to enable proppant tracking and monitoring in a downhole environment
US8006754B2 (en) 2008-04-05 2011-08-30 Sun Drilling Products Corporation Proppants containing dispersed piezoelectric or magnetostrictive fillers or mixtures thereof, to enable proppant tracking and monitoring in a downhole environment
US7906464B2 (en) 2008-05-13 2011-03-15 Halliburton Energy Services, Inc. Compositions and methods for the removal of oil-based filtercakes
US8006755B2 (en) 2008-08-15 2011-08-30 Sun Drilling Products Corporation Proppants coated by piezoelectric or magnetostrictive materials, or by mixtures or combinations thereof, to enable their tracking in a downhole environment
US7960314B2 (en) 2008-09-26 2011-06-14 Halliburton Energy Services Inc. Microemulsifiers and methods of making and using same
US7833943B2 (en) 2008-09-26 2010-11-16 Halliburton Energy Services Inc. Microemulsifiers and methods of making and using same
US9102868B2 (en) 2010-07-29 2015-08-11 3M Innovative Properties Company Elastomer-modified crosslinked epoxy vinyl ester particles and methods for making and using the same
CN103194204B (zh) * 2013-04-10 2016-03-23 北京奥陶科技有限公司 一种用于煤层气与页岩气水力压裂的支撑剂及其制备方法
CN103194204A (zh) * 2013-04-10 2013-07-10 北京奥陶科技有限公司 一种用于煤层气与页岩气水力压裂的支撑剂及其制备方法
WO2015057373A1 (fr) * 2013-10-17 2015-04-23 Schlumberger Canada Limited Traitement de puits au moyen de particules changeant de forme
CN108315006A (zh) * 2017-01-17 2018-07-24 北京大学 仿生学智能立体支撑剂及其应用
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AU7600198A (en) 1999-06-15
GB2348907A (en) 2000-10-18
CA2308372C (fr) 2006-10-31
GB0015133D0 (en) 2000-08-09
GB2348907B (en) 2002-09-11
CA2308372A1 (fr) 1999-06-03

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