Abstract: Methods of subterranean cementing involving cement compositions comprising particulate foamed elastomers and associated methods are provided. In one embodiment, the cement composition comprises a hydraulic cement, a particulate foamed elastomer, and an aqueous fluid. In one embodiment, the particulate foamed elastomer may comprise polyurethane foam.

Abstract: Method of diverting fluids in a subterranean formation including the steps of providing a first fluid comprising an aqueous fluid and a hydrophobically modified water-soluble relative permeability modifier; introducing the first fluid into a well bore such that the first treatment fluid penetrates into a portion of the subterranean formation in a sufficient amount so as to substantially divert a second treatment fluid to another portion of the subterranean formation. Then, a second aqueous fluid is introduced into the well bore and substantially diverted from the portion of the subterranean formation penetrated with the first treatment fluid. In some cases, a well treatment operation, such as acid stimulation operation, a clay stabilization operation, or a scale inhibition operation, is performed using the second fluid.

Abstract: Methods of stabilizing water-sensitive clays in subterranean formations may include introducing a drill-in treatment fluid into at least a portion of a subterranean formation comprising water-sensitive minerals, where providing the drill-in treatment fluid comprises an aqueous-based fluid and a hydrophobically-modified cationic polymer; and allowing the hydrophobically-modified cationic polymer to at least partially coat the water-sensitive mineral.

Abstract: A method comprising: providing at least one encaged treatment chemical that comprises a treatment chemical and a polymer carrier; placing the encaged treatment chemical into a portion of a subterranean formation; and allowing the treatment chemical to diffuse out of the encaged treatment chemical and into a portion of the subterranean formation or an area adjacent thereto.

Abstract: Pre-coated particulate for use in a subterranean operation comprising a particulate; and a film coated onto a surface of the particulate. The film is formed by allowing an anionic polymer and a cationic surfactant to contact the surface of the particulate, and allowing the anionic polymer and the cationic surfactant to interact with each other. In some cases, the anionic polymer is selected from the group consisting of a polyacrylamide; an alkylpolyacrylamide; a copolymer of polyacrylamide, with ethylene, propylene, and styrene; a copolymer of alkylpolyacrylamide with ethylene, propylene, and styrene; a polymaleic anhydride; and any derivatives thereof.

Abstract: A particle mixture useful for estimating the locations of rock fractures in rock includes a mixture of particles of proppant with particles of an energetic material having a size, shape, and density that are about the same as for the particles of proppant. Particles of proppant and of an energetic material having the same desired sizes and shapes of the proppant may be obtained by collecting those particles that pass through a sieve of a chosen size but not through a sieve of the next smaller size. The location of rock fractures that contain proppant can be estimated by sending the particle mixture into fractured rock, allowing the energetic particles to release their energy, and afterward estimating the locations in the rock where the energy was released from the particles, thereby providing the locations of fractures in the rock that contain proppant.

Abstract: Aqueous well treatment fluid compositions are disclosed comprising an aqueous fluid containing polymer or copolymer for modifying fluid viscosity of the aqueous fluid and, in addition, an agent for effecting a controlled reduction in the aqueous fluid viscosity in a subterranean environment. The viscosity-reducing agent comprises a dilute concentration of peracetic acid. A method of using such compositions in oil- and gas-field treatment operations is also disclosed.

Abstract: A non-aqueous wellbore servicing fluid comprising a fluid loss additive wherein the fluid loss additive comprises the reaction product of (i) a functional polymer and (ii) an oligomerized fatty acid. A method of conducting an oil-field operation comprising placing a non-aqueous wellbore servicing fluid downhole wherein the non-aqueous wellbore servicing fluid comprises a fluid loss additive comprising the reaction product of (i) a functional polymer and (ii) an oligomerized fatty acid.

Abstract: Well operating elements are described, one embodiment comprising a first component that is substantially non-dissolvable when exposed to a selected wellbore environment and a second component that is soluble in the selected wellbore environment and whose rate and/or location of dissolution is at least partially controlled by structure of the first component. A second embodiment includes the component that is soluble in the selected wellbore environment, and one or more exposure holes or passages in the soluble component to control its solubility. The second embodiment may or may not include a substantially non-dissolvable component. Methods of using the well operating elements in oilfield operations are also described. This abstract allows a searcher or other reader to quickly ascertain the subject matter of the disclosure. It will not be used to interpret or limit the scope or meaning of the claims.

Abstract: Gellable treatment fluids may have their gel times modified by using a polymer mixture therein that contains two or more polymers having disparate average molecular weights. Methods for treating a subterranean formation using such gellable treatment fluids can comprise providing a gellable treatment fluid comprising a polymer mixture and a crosslinking agent, introducing the gellable treatment fluid into a subterranean formation, and allowing the gellable treatment fluid to form a gel in the subterranean formation. The polymer mixture comprises a base polymer and an addend polymer, where the base polymer and the addend polymer each comprise an acrylamide monomer unit or a derivative thereof and have different average molecular weights, such that a molecular weight distribution of the polymer mixture contains at least two local maxima.

Abstract: The present invention relates to proppants and the manufacture of proppants by contacting a substrate with an alkali-activated composition that cures to form a continuous polymer coating.

Abstract: A well treatment composition is formed from a fluid mixture of a viscoelastic surfactant and a liquid carrier fluid. The fluid mixture has rheological properties wherein the mixture exhibits shear-thickening behavior when the shear rate is increased from a first shear rate to a second higher shear rate. The fluid mixture may further include a shear activation additive that interacts with the viscoelastic surfactant to facilitate the shear-thickening behavior. The method is accomplished by introducing the fluid mixture into a wellbore formed in a subterranean formation. In certain applications, the fluid mixture may be recycled by bringing the fluid mixture to the surface and reintroducing the fluid into the same or a different wellbore.

Abstract: Consolidation fluids comprising: an aqueous base fluid comprising a hardening agent; an emulsified resin having an aqueous external phase and an organic internal phase; a silane coupling agent; and a surfactant. The consolidation fluid itself may be emulsified and further comprise an emulsifying agent. The consolidation fluid may also be foamed in some cases.

Abstract: The present disclosure is directed to a method of servicing a well. The method comprises providing a well servicing fluid. The well servicing fluid is formulated with the following components comprising, at least one friction reducer chosen from polychloroprenes, vinyl acetate polymers, polyalkylene oxides polyalphaolefins; and a nonaqueous carrier fluid. The well servicing fluid is introduced into the well.

Abstract: A method of treating a subterranean formation by forming a treatment fluid that contains at least a non-surface active substituted ammonium containing aminoacid derivative. The treatment fluid may then be introduced to the subterranean formation.

Abstract: Compositions, systems and methods for the controlled and/or delayed release of chemical additive components into an aqueous fluid used in hydraulic fracturing of oil and/or gas wells. The chemical additive components may include a viscosity-reducing composition, an oxidizer composition, a pH modulating composition, a lubricant composition, a cross-linking composition, an anti-corrosion composition, an biocide composition, a crosslink-enhancing composition, and/or a combination of two or more of these compositions. Further embodiments include additives and methods of delivering a particle comprising an additive component to a desired site in an aqueous medium prior to release of the additive component into the aqueous medium. The coating is permeable, but insoluble in an aqueous medium, whereupon the additive components are released into the medium.

Abstract: Of the many compositions and methods provided herein, an example method includes a method of treating a subterranean formation that comprises combining components comprising water and a density-matched suspension to prepare a treatment fluid, wherein the density-matched suspension comprises a suspending liquid and a solid particle suspended in the suspending liquid, and introducing the treatment fluid into a well bore. An example composition includes a suspension that comprises a suspending liquid comprising a hydrophobic liquid, wherein the hydrophobic liquid hydrolyzes when placed in contact with an aqueous fluid to form hydrophilic products, and a solid particle suspended in the suspending liquid, wherein the suspension is a density-matched suspension.

Abstract: Emulsions for use in a well including: (a) a water-insoluble resinous material; (b) water; and (c) an emulsifier, wherein the emulsifier comprises a non-ionic, a cationic, or a zwitterionic emulsifier; wherein the continuous phase of the emulsion comprises the water; wherein a dispersed phase of the emulsion comprises the resinous material; wherein the dispersed phase is in the form of droplets having a size distribution range such that at least 50% of the droplets have a size of 0.5 micrometers-500 micrometers; wherein the resinous material of the droplets is in a concentration of at least 5% by weight of the water; and wherein the composition of the droplets has a viscosity of less than 2,000 Poise measured at 20° F. Methods include the steps of: (a) forming an emulsion described above; and (b) introducing the emulsion into a portion of a subterranean formation.

Abstract: The present invention provides modified proppants, and methods for their manufacture. In embodiments, the modified proppant comprises a proppant particle and a hydrogel coating, wherein the hydrogel coating is applied to a surface of the proppant particle and localizes on the surface to produce the modified proppant. In embodiments, formulations are disclosed comprising the modified particles, and methods are disclosed for using the formulations.

Abstract: In subterranean operations, additives used in treatment fluids such as drilling and cementing fluids include weighting agents; a method includes the steps of providing a treatment fluid for use in a subterranean formation comprising a weighting agent, the weighting agent comprising a micronized metal oxide particle and a polymer linked to the metal oxide particle, the method including introducing the treatment fluid into the subterranean formation.

Abstract: The invention discloses a hydrophobic proppant and a preparation method thereof. The aggregate particles of the hydrophobic proppant are coated with a coating resin which comprises a hydrophobic resin and nano-particles which are uniformly distributed in the coating resin and constitute 5-60% of the coating resin by weight. The contact angle labeled as ? between water and the hydrophobic proppant in which nano-particles are added is in the range of 120°???180°. The proppant of the present invention is prepared by adding the nano-particles in the existing resin in which low-surface-energy substances with hydrophobic groups are added, and a rough surface with a micro-nano structure is constructed on the outer surface of the prepared resin film, so that the contact angle ? at the solid-liquid contact surface on the outer surface of the coating resin of the proppant is more than 120°.

Abstract: The present invention relates to particles that are useful for enhancing hindered settling in suspensions. One embodiment of the present invention provides a method of providing a subterranean treatment fluid including a base fluid and a weighting agent having a first average settling velocity; and a neutral-density particle; and mixing the subterranean treatment fluid with the neutral-density particle thereby reducing the weighting agent to a second average settling velocity.

Abstract: High solids content slurry, systems and methods. The slurry comprises a carrier fluid and a solids mixture of first, second, third and fourth particle size distribution (PSD) modes wherein the first PSD mode is at least three times larger than the second PSD mode, which is larger than the third PSD mode, which is larger than the fourth PSD mode, and wherein at least one of the second and third PSD modes is less than 3 times larger than the respective third or fourth PSD mode. The method comprises forming the slurry, positioning a screen in a wellbore and circulating the slurry through the wellbore such that the solids mixture is deposited between the screen and the wellbore. The system comprises a pump to circulate the slurry, a workstring to position the screen and means for converting the slurry to a gravel pack.

Abstract: Solid proppants are coated in a process that includes the steps of: (a) coating free-flowing proppant solids with a first component of either a polyol or an isocyanate in mixer; (b) adding a second component of either an isocyanate or a polyol that is different from the first component at a controlled rate or volume sufficient to form a polyurethane coating on the proppant solids; and (c) adding water at a rate and volume sufficient to retain the free-flowing characteristics of the proppant solids.

Abstract: Methods and compositions are provided that relate to cementing operations. Methods and compositions that include a latex strength enhancer for enhancing the compressive strength of slag compositions.

Abstract: An embodiment of the present invention comprises a method of cementing comprising: placing a settable composition into a well bore, the settable composition comprising unexpanded perlite, cement kiln dust, and water; and allowing the settable composition to set. Another embodiment of the present invention comprises a method of cementing comprising: placing a settable composition into a well bore, the settable composition comprising ground unexpanded perlite, Portland cement interground with pumicite, and water; and allowing the settable composition to set. Yet another embodiment of the present invention comprises a settable composition comprising: ground unexpanded perlite; cement kiln dust; and water.

Abstract: A system for curing lost circulation is made of fibers and a material able to stick fibers in a network when activated. Such activation can be temperature or pH change or both. The fibers can be metallic amorphous fibers, metallic non-amorphous fibers, glass fibers, carbon fibers, polymeric fibers and combinations thereof. The material can be a fiber coating or an additional material, for example polyvinyl alcohol, polyurethane and heat activated epoxy resin.

Abstract: Methods and compositions that comprise sub-micron alumina for accelerating setting of a cement composition. An embodiment includes a method of cementing in a subterranean formation. The method may comprise introducing a cement composition into the subterranean formation, wherein the cement composition comprises hydraulic cement, sub-micron alumina, and water. The method further may comprise allowing the cement composition to set in the subterranean formation. Another embodiment includes a cement composition that may comprise hydraulic cement, sub-micron alumina, and water.

Abstract: A nanocomposite comprises a matrix; and a nanoparticle comprising an ionic polymer disposed on the surface of the nanoparticle, the nanoparticle being dispersed in and/or disposed on the matrix. A method of making a nanocomposite, comprises combining a nanoparticle and an ionic liquid; polymerizing the ionic liquid to form an ionic polymer; disposing the ionic polymer on the nanoparticle; and combining the nanoparticle with the ionic polymer and a matrix to form the nanocomposite.

Abstract: A method for deploying a shape memory polymer includes disposing a shape memory polymer having a deformed shape in an environment at a first temperature, the shape memory polymer having a first glass transition temperature which is greater than the first temperature. The method also includes decreasing the glass transition temperature of shape memory polymer from the first glass transition temperature to a second glass transition temperature which is less than or equal to the first temperature; and expanding the shape memory polymer to deploy the shape memory polymer in a deployed shape.

Abstract: The present invention relates to methods and compositions for treating a water- and hydrocarbon-producing subterranean formation with a relative permeability modifier, and more specifically, to improved treatment fluids, methods for preparing treatment fluids, and methods for use thereof in a subterranean formation. Methods of the present invention comprise providing a treatment fluid comprising a relative permeability modifier, at least one surfactant, and an aqueous phase base fluid; and placing the treatment fluid in a subterranean formation. The relative permeability modifier comprises a hydrophobically modified hydrophilic polymer. The at least one surfactant is operable to maintain the relative permeability modifier in a dissolved state in the treatment fluid above a pH of about 8.

Abstract: Use of two different methods, either each by itself or in combination, to enhance the stiffness, strength, maximum possible use temperature, and environmental resistance of thermoset polymer particles is disclosed. One method is the application of post-polymerization process steps (and especially heat treatment) to advance the curing reaction and to thus obtain a more densely crosslinked polymer network. The other method is the incorporation of nanofillers, resulting in a heterogeneous “nanocomposite” morphology. Nanofiller incorporation and post-polymerization heat treatment can also be combined to obtain the benefits of both methods simultaneously. The present invention relates to the development of thermoset nanocomposite particles.

Abstract: A method for fracture stimulation of a subterranean formation includes providing a thermoset polymer nanocomposite particle precursor composition comprising a polymer precursor mixture, dispersed within a liquid medium, containing at least one of an initiator; at least one of a monomer, an oligomer or combinations thereof, said monomer and oligomer having three or more reactive functionalities capable of creating crosslinks between polymer chains; at least one of an impact modifier; and nanofiller particles substantially dispersed within the liquid medium; subjecting the nanocomposite particle precursor composition to suspension polymerizing conditions; subjecting the resulting nanocomposite particles to heat treatment; forming a slurry comprising a fluid and a proppant that includes the heat-treated nanocomposite particles; injecting the slurry into a wellbore; and emplacing the proppant within a fracture network in the formation.

Abstract: Method for substantially sealing at least a portion of a wall of a wellbore. Method includes selecting a fracture sealing width defined by the portion of the wellbore wall and the formation, and formulating a fracture sealing composition based on the fracture sealing width. Sealing fluid includes drilling fluid, cementing slurry, completion fluid, and a concentration of particulates forming the fracture sealing composition. The method also includes determining a spurt loss volume of the sealing fluid based at least on the fracture sealing width, determining a fracture volume capacity based at least on the fracture sealing width, and comparing the spurt loss volume of the sealing fluid to the fracture volume capacity. If the sealing fluid has a spurt loss volume less than or equal to the fracture volume capacity, the sealing fluid is pumped into the wellbore, wherein the sealing fluid forms a sealing relationship with the fracture.

Abstract: Fluid systems may contain elements to provide changes in bulk fluid density in response to various environmental conditions. One environmental driver to the variable density is pressure; other environmental drivers include, but are not limited to, temperature or changes in chemistry. The variable density of the fluid is beneficial for controlling sub-surface pressures within desirable pore pressure and fracture gradient envelopes. The variability of fluid density permits construction and operation of a wellbore with much longer hole sections than when using conventional single gradient fluids.

Abstract: Use of two different methods, either each by itself or in combination, to enhance the stiffness, strength, maximum possible use temperature, and environmental resistance of such particles is disclosed. One method is the application of post-polymerization process steps (and especially heat treatment) to advance the curing reaction and to thus obtain a more densely crosslinked polymer network. The other method is the incorporation of nanofillers, resulting in a heterogeneous “nanocomposite” morphology. Nanofiller incorporation and post-polymerization heat treatment can also be combined to obtain the benefits of both methods simultaneously. The present invention relates to the development of thermoset nanocomposite particles.

Abstract: A method of introducing a drag reducing polymer into a pipeline such that the friction loss associated with the turbulent flow though the pipeline is reduced by suppressing the growth of turbulent eddies. The drag reducing polymer is introduced into a liquid hydrocarbon having an asphaltene content of at least 3 weight percent and an API gravity of less than about 26° to thereby produce a treated liquid hydrocarbon. The treated liquid hydrocarbon does not have a viscosity less than the viscosity of the liquid hydrocarbon prior to treatment with the drag reducing polymer. Additionally, the drag reducing polymer is added to the liquid hydrocarbon in the range from about 0.1 to about 500 ppmw.

Abstract: A system for reducing pressure drop associated with the turbulent flow of asphaltenic crude oil through a conduit. The crude oil has a high asphaltene content and/or a low API gravity. Such reduction in pressure drop is achieved by treating the asphaltenic crude oil with a high molecular weight drag reducing polymer that can have a solubility parameter within about 20 percent of the solubility parameter of the heavy crude oil. The drag reducing polymer can also comprise the residues of monomers having at least one heteroatom.

Abstract: A method of preparing a drag reducing polymer wherein the drag reducing polymer is able to be injected into a pipeline, such that the friction loss associated with the turbulent flow through the pipeline is reduced by suppressing the growth of turbulent eddies. The drag reducing polymer is injected into a pipeline of liquid hydrocarbon hydrocarbon having an asphaltene content of at least 3 weight percent and an API gravity of less than about 26° to thereby produce a treated liquid hydrocarbon wherein the viscosity of the treated liquid hydrocarbon is not less than the viscosity of the liquid hydrocarbon prior to treatment with the drag reducing polymer. The drag reducing polymer has a solubility parameter within 4 MPa1/2 of the solubility parameter of the liquid hydrocarbon. The drag reducing polymer is also added to the liquid hydrocarbon in the range from about 0.1 to about 500 ppmw.

Abstract: A method for breaking the viscosity of an aqueous fluid gelled with a viscoelastic surfactant (VES) includes: providing an aqueous fluid; adding to the aqueous fluid, in any order, components comprising: a VES comprising a non-ionic surfactant, cationic surfactant, amphoteric surfactant or zwitterionic surfactant, or a combination thereof, in an amount sufficient to form a gelled aqueous fluid comprising a plurality of elongated micelles, an unsaturated fatty acid comprising a monoenoic acid or a polyenoic acid; or a combination thereof; and a plurality of metallic particles to produce a mixture comprising dispersed metallic particles in the gelled aqueous fluid. The method also includes dissolving the metallic particles in the gelled aqueous fluid to provide a source of metal ions and heating the gelled aqueous fluid to a temperature sufficient to cause the unsaturated fatty acid to auto-oxidize to products present in an amount effective to reduce the viscosity.

Abstract: A method for breaking the viscosity of an aqueous fluid gelled with a viscoelastic surfactant (VES) is disclosed. The method includes providing an aqueous fluid and adding to the aqueous fluid, in any order: at least one VES comprising a non-ionic surfactant, cationic surfactant, amphoteric surfactant or zwitterionic surfactant, or a combination thereof, in an amount sufficient to form a gelled aqueous fluid comprising a plurality of elongated micelles and having a viscosity, and a plurality of metallic particles to produce a mixture comprising dispersed metallic particles dispersed within the gelled aqueous fluid. The method also includes dissolving the metallic particles in the gelled aqueous fluid to provide a source of at least one transition metal ion in an amount effective to reduce the viscosity.

Abstract: The invention pertains to improved proppant particles comprising an aromatic polycondensation polymer having a glass transition temperature (Tg) of at least 120° C. when measured according to ASTM 3418 [polymer (P)] and a method of treating a subterranean formation using said proppant particles.

Abstract: The present invention relates to compositions and methods for enhancing fracture conductivity. One embodiment of the present invention provides a method of providing a fracturing fluid and a flowable propping composition having a hardenable external phase and an internal phase where the internal phase is immiscible with the external phase; introducing the fracturing fluid into a subterranean formation; introducing the flowable propping composition into a fracture in the subterranean formation; allowing the hardenable external phase to form a hardened external phase in the fracture in the subterranean formation; and allowing the presence of the internal phase to be reduced from the hardened external phase thereby leaving a void volume in the hardened external phase.

Abstract: A method of treating a subterranean formation comprises providing a treatment fluid comprising: an aqueous fluid; a gelling agent, and a multifunctional boronic crosslinker comprising two or more boronic functional groups; and introducing the viscosified fluid into a subterranean formation.

Abstract: A method of introducing a drag reducing polymer into a pipeline such that the friction loss associated with the turbulent flow though the pipeline is reduced by suppressing the growth of turbulent eddies. The drag reducing polymer is introduced into a liquid hydrocarbon having an asphaltene content of at least 3 weight percent and/or an API gravity of less than about 26° to thereby produce a treated liquid hydrocarbon. The treated liquid hydrocarbon does not have a viscosity less than the viscosity of the liquid hydrocarbon prior to treatment with the drag reducing polymer. Additionally, the drag reducing polymer is added to the liquid hydrocarbon in the range from about 0.1 to about 500 ppmw.

Abstract: Methods comprising introducing a hydrophobically and cationically modified relative permeability modifier into a portion of a subterranean formation. The hydrophobically and cationically modified relative permeability modifier comprises a hydrophilic polymer backbone with a hydrophobic modification and a cationic modification. The cationic modification may comprise at least one cationic compound comprising an alkyl chain length of from 1 to 3 carbons.

Abstract: Polyboronic compounds and methods of making them are provided. The polyboronic compounds are useful as crosslinking agents. The polyboronic compounds are produced by contacting a polymeric amine with a trialkylborate in the presence of a solvent so that the resulting molecule has more than one B—N bond.

Abstract: Fluorinated polymers having first divalent units represented by formula, and a plurality of groups of formula —CH2—CH2—O—. Compositions containing the fluorinated polymer and solvent, and methods of treating hydrocarbon-bearing formations using these compositions are disclosed. A method of making a composition containing the fluorinated polymer is also disclosed.

Abstract: According to one aspect of the inventions, emulsion compositions are provided. Emulsions according to this aspect include: (a) a water-insoluble resinous material; (b) water; and (c) an emulsifier, wherein the emulsifier comprises a non-ionic, a cationic, or a zwitterionic emulsifier; wherein the continuous phase of the emulsion comprises the water; wherein a dispersed phase of the emulsion comprises the resinous material; wherein the dispersed phase is in the form of droplets having a size distribution range such that at least 50% of the droplets have a size of 0.5 micrometers-500 micrometers; wherein the resinous material of the droplets is in a concentration of at least 5% by weight of the water; and wherein the composition of the droplets has a viscosity of less than 2,000 Poise measured at 20° F. According to another aspect of the inventions, methods are provided for treating a portion of a subterranean formation.

Abstract: A pressurized polymer bead such as may be useful as a proppant in hydraulic fracturing is described, including a shell that is substantially impermeable, wherein the shell includes a polyimide polymer. The pressurized polymer bead includes a core region that is at a pressure that is greater than 5 MPa.