Abstract: Methods of acidizing a subterranean formation penetrated by a wellbore that include the steps of (a) injecting into the wellbore at a pressure below subterranean formation fracturing pressure a treatment fluid having a first viscosity and including an aqueous acid and a gelling agent selected from the group consisting of Formulas I-XI and combinations thereof; (b) forming at least one void in the subterranean formation with the treatment fluid; and (c) allowing the treatment fluid to attain a second viscosity that is greater than the first viscosity.

Abstract: Embodiments provide a method for controlled release of a cement additive for use in a wellbore. The method includes the steps of mixing an aramide capsule with a cement slurry to form an additive-containing slurry, and introducing the additive-containing slurry into the wellbore. The aramide capsule is formed by interfacial polymerization where an aramide polymer forms a semi-permeable membrane encapsulating the cement additive.

Abstract: A fracturing carrier fluid for fracturing a subterranean formation contains at least one linear or branched hydrofluorocarbon ether compound having a boiling point, at a pressure of 1 atmosphere, of between 0° C. and 90° C. A fracturing fluid contains the fracturing carrier fluid and proppants. A method for fracturing a subterranean formation uses the fracturing fluid.

Abstract: A composition, e.g., a fracturing carrier fluid, for fracturing a subterranean formation containing at least one linear or branched hydrofluorocarbon compound having a boiling point, at a pressure of 1 atmosphere, of between 0° C. and 65° C., and at least one proppant. A method for fracturing a subterranean formation with the composition is also provided.

Abstract: Incorporating water-based polymer breakers, such as oxidizers, enzymes and/or acids, into a mixture of an oil and oil-soluble surfactants creates an emulsion that can then perform as a dual-functional breaker for reducing the viscosity of hybrid fluids gelled with both a viscoelastic surfactant (VES) and a polymer. The outer phase of the dual-functional breaker emulsion is oil, e.g. a mineral oil, containing an oil-soluble surfactant that will, over time and with heat, break the VES portion of the gel. As it does so, the polymer breaker in the internal aqueous phase will be released to then break the polymer portion of the gel. The polymer breaker will not start to break the polymer gel before the oil-soluble surfactant starts to break the VES gel. The overall breaking using the emulsion is slower as compared to introducing the polymer breaker and the oil-soluble surfactant in a non-emulsified form.

Abstract: Methods for reducing fines migration in a porous subterranean reservoir. In certain aspects, the methods include introducing a composition including a water-soluble or dispersible branched polyhydroxyetheramine into the porous subterranean reservoir, maintaining a sufficient temperature in the porous subterranean reservoir for a period of time, adsorbing the composition onto a surface of the porous subterranean reservoir, and stabilizing at least a portion of the fines present in the porous subterranean reservoir. A treatment composition can be used and in certain aspects, the treatment composition can be a reaction product of bisphenol A, an ethanol amine, diethanol amine, and a monofunctionalized polyoxyalkyleneamine.

Abstract: A microemulsion delivery system containing a well treatment agent in a water-in-oil microemulsion may be used for well remediation as well as in other treatment operations including stimulation, acidizing, and drilling. In addition, the water-in-oil microemulsion delivery system may be used to clean surface equipment and downhole equipment.

Abstract: A well treatment fluid comprising a 2-oxo-aldehyde having 3 or more carbon atoms is disclosed herein. Methods to prepare and to utilize the fluid, and to inhibit biological degradation of a well treatment fluid, are also disclosed.

Abstract: Treatment fluids and methods for treating a subterranean formation include introducing a treatment fluid into a subterranean formation, the treatment fluid containing a nanocrystalline cellulose. The treatment fluid may be a fracturing fluid, well control fluid, well kill fluid, well cementing fluid, acid fracturing fluid, acid diverting fluid, a stimulation fluid, a sand control fluid, a completion fluid, a wellbore consolidation fluid, a remediation treatment fluid, a spacer fluid, a drilling fluid, a frac-packing fluid, water conformance fluid or a gravel packing fluid.

Abstract: A composition for enhancing fluid viscosity including a mixture of at least one cationic or cationizable polymer and at least one anionic or anionizable (hydrolysable) polymer. The composition has a zeta potential at 25° C. in the range of 0.5 to 100 mV or ?0.5 to ?100 mV, typically 1 to 60 mV or ?1 to ?60 mV, or is a precursor convertible at a temperature of 100 to 250° C. to the composition having a zeta potential at 25° C. of 0.5 to 100 mV or ?0.5 to ?100 mV, typically 1 to 60 mV or ?1 to ?60 mV. Typically the compositions exhibit salt tolerance and interaction of both polymers at very high temperatures (>300° F.) such that the system exhibits an increase of viscosity at extreme temperatures. The compositions are useful for hydraulic fracturing, enhanced oil recovery, subterranean acidization, personal care as well as home and industrial cleaners.

Abstract: A method includes providing an oilfield treatment fluid including an aqueous HCl solution having greater than 15% HCl by weight, and a fixing agent (FA) in a molar ratio of FA:HCl of between 0.5 and 2.5 inclusive. The FA is urea and/or a urea derivative. The oilfield treatment fluid further includes a viscosifying agent that is not a plant-based polysaccharide gum. The method further includes providing the oilfield treatment fluid to a high pressure pump, and operating the high pressure pump to treat a formation fluidly coupled to a wellbore.

Abstract: A well treatment fluid comprising a Pickering particle emulsion comprising particles of a first liquid phase dispersed in a continuous second liquid phase, and comprising a plurality of colloidal particles adsorbed to a liquid-liquid interface between the first liquid phase and the second liquid phase. Methods, equipment and/or systems for treating a subterranean formation utilizing such treatment fluids are also disclosed.

Abstract: A thixotropic agent comprised of a gel which is comprised of a polymeric organic material cross-linked with certain boehmite aluminas having a crystallite size of less than about 100 ? as measured on the 120 plane.

Abstract: The present invention relates to solid-supported crosslinkers for treatment of a subterranean formation. In various embodiments, the present invention provides a method of treating a subterranean formation. The method can include obtaining or providing a composition that includes a solid-supported crosslinker. The solid-supported crosslinker includes a supporting solid, and a crosslinker supported on the supporting solid. The method can also include contacting a subterranean material downhole with the composition.

Abstract: A method for forming a well and pipeline treating fluid is provided. The method comprises combining a cross-linkable gelling polymer, a scavenging compound capable of reducing a concentration of divalent and polyvalent metal ions and salts thereof available for reaction, a hydration solvent and optionally an acid. The resulting mixture has a pH ranging from about 3 to about 7 and a first viscosity. The mixture is maintained at conditions suitable for hydration of the cross-linkable gelling polymer until the mixture has a second viscosity that is greater than the first viscosity. The mixture is combined with an aqueous based fluid and at least one cross-linking agent. The pH of the mixture is raised to a sufficient level to allow a desired degree of cross-linking to occur. Other methods, a well and pipeline treating gel and a well and pipeline treating fluid are also provided.

Abstract: A pill for wellbore operations, that includes a base fluid; and at least two polymers that interact to form a gelatinous structure characterized as isolating and controllably transmitting hydrostatic pressure between a first wellbore fluid above the pill in a wellbore and a second wellbore fluid below the pill in the wellbore is disclosed.

Abstract: A method includes adding an amount of chlorine dioxide from about 10 ppm to about 400 ppm to an aqueous base fluid to provide a treated fluid, adding a water-soluble polymer to the treated fluid, thereby forming a hydrated polymer, the amount of chlorine dioxide added confers a viscosity increase allowing a reduction in the amount of water-soluble polymer to obtain a target viscosity by about 25% to about 75% relative to a control fluid lacking chlorine dioxide.

Abstract: Methods and compositions of fracturing formations are provided. The fracturing fluid includes an enzyme breaker that decreases the viscosity of the fracturing fluid over time. The enzyme breaker can be used in environments having a pH value ranging from about 7 to about 12.

Abstract: A method of treating a well including the steps of: (A) treating a first aqueous fluid comprising seawater with electrocoagulation to obtain a second aqueous fluid, wherein the second aqueous fluid has a reduced concentration of magnesium ions relative to the original concentration of magnesium ions in the first aqueous fluid; (B) forming a treatment fluid comprising: (i) an aqueous phase, wherein the aqueous phase comprises the second aqueous fluid, and (ii) a viscosity-increasing agent in the aqueous phase; and (C) introducing the treatment fluid into a well. The aqueous phase can have a pH of at least about 9 or the treatment fluid can be introduced into a well at a design temperature of at least about 93° C. (200° F.).

Abstract: A treatment fluid comprises: water; a carboxylate; and a corrosion inhibitor, wherein the corrosion inhibitor is environmentally-friendly, biodegradable, and is a polymer, wherein the polymer comprises a carbohydrate backbone and a quaternary amine functional group; wherein a test fluid consisting essentially of the water, the carboxylate, and the corrosion inhibitor, and in the same proportions as in the treatment fluid, is capable of providing a corrosion weight loss to a metal plate of less than 0.05 pounds per square feet (lb/ft2) under testing conditions of 200° F. (93.3° C.), a pressure of 500 psi (3.4 MPa), and a time of 24 hours whereas a substantially identical test fluid without the corrosion inhibitor provides a corrosion weight loss of greater than 0.05 lb/ft2 under the testing conditions. A method of treating a portion of a well comprises: forming the treatment fluid; and introducing the treatment fluid into the well.

Abstract: By including a chemical additive in the well treatment fluid system design the cost and environmental impact of hydraulic fracturing may be substantially reduced. By adding a weak base to the well treatment fluid, water having a high, heterogeneous concentration of dissolved solids, such as water produced by oil and gas wells, may be utilized as the base fluid for hydraulic fracturing or other stimulation processes without adversely affecting the various components of the well treatment fluid. The well treatment fluid typically includes a base fluid, in this case produced water, a gelling agent, a weak base, and other additives useful for treating a well such as friction reducers, buffering agents, clay control agents, biocides, scale inhibitors, chelating agents, gel-breakers, oxygen scavengers, antifoamers, crosslinkers, wax inhibitors, corrosion inhibitors, de-emulsifiers, foaming agents, or tracers.

Abstract: A ceramic propping agent, in the form of a spherical pellet, and containing common mineral particulate. The desired propping agent is defined as a particulate ceramic made from raw materials which may be comprised of about: 10%-90% parts by weight of a naturally occurring mineral particulate, 30%-70% parts by weight aluminosilicate network modifier, 0.25-20% parts by weight strength enhancer, and at least one part, typically less than 10% by weight, binder. For use in oil and/or natural gas wells as a hydraulic fracturing proppant.

Abstract: A method of treating a subterranean formation. The method may include providing a fluid-loss control pill that comprises an aqueous base fluid, a gelling agent, and an internal breaker that is selected from the group consisting of inorganic delayed acids or inorganic salts. The method can include introducing the fluid-loss control pill into a subterranean formation, allowing the internal breaker to reduce the viscosity of the pill after a delay period, and allowing the fluid-loss control pill to break.

Abstract: The present invention relates to hollow hydrogel capsules. In various embodiments, the present invention provides a method of treating a subterranean formation with a hollow hydrogel capsule including a hydrogel shell including a hydrolyzed and crosslinked polymerized composition. The hollow hydrogel capsule also includes a hollow interior including at least one component of a downhole composition for subterranean petroleum or water well drilling, stimulation, clean-up, production, completion, abandonment, or a combination thereof. In various embodiments, the present invention provides compositions comprising the hollow hydrogel capsules and methods of making the hollow hydrogel capsules.

Abstract: A composition of a treatment fluid and method for treating a zone of well. In an embodiment, the composition includes at least: (i) an aqueous phase; (ii) at least 5 ppm iron ion in the aqueous phase; (iii) a source of at least 5 ppm iodide ion to be dissolved in the aqueous phase; (iv) a water-soluble viscosity-increasing agent dissolved in the aqueous phase; and (v) a source of an oxidative breaker to be dissolved in the aqueous phase. In an embodiment, a method of treating a zone of a subterranean formation of a well includes at least the steps of: (a) forming a treatment fluid according to the composition; and (b) introducing the treatment fluid into the zone.

Abstract: Additives are used in treatment fluids in subterranean operations to prevent fluid loss within a subterranean formation. A method includes providing a treatment fluid that includes a viscosifying polymer and a solid-liquid phase transition temperature modifier and placing the treatment fluid in a subterranean formation penetrated by a wellbore, wherein the solid-liquid phase temperature modifier is added in an amount to modulate the gelling temperature of the viscosifying polymer to a target temperature.

Abstract: An emulsion including: (a) an external oil phase, wherein the oil phase has a viscosity of less than 200 cP; (b) an internal water phase adjacent the external phase, wherein the internal water phase has a pH in the range of 5 to 9; (c) an emulsifier having a hydrophilic-lipophilic balance in the range of 3 to 7 on the Davies scale; and (d) a Bronsted-Lowry base having a pKb(1) less than 12, wherein the base is encapsulated with an encapsulated breaker composition comprising: an encapsulant that comprises an ether cellulose. A method of treating a well includes the steps of: forming a treatment fluid including the emulsion; and introducing the treatment fluid into the well. In a preferred embodiment, the emulsion has a viscosity greater than 200 cP.

Abstract: Methylhydroxyethyl cellulose may be used as an additive in cement slurries in the treatment of wells to prevent or reduce the occurrence of gas channeling. In addition to acting as a gas control additive, methylhydroxyethyl cellulose controls fluid loss, minimizes free fluid and stabilizes foam during cementing of the well.

Abstract: Treatment fluids comprising an aqueous fluid and a low-leakoff particulate, wherein the low-leakoff particulate comprises a low molecular weight modified polysaccharide that has been crosslinked with a crosslinking agent wherein the low molecular weight modified polysaccharide contains one or more of the following monosaccharide units: galactose, mannose, glucoside glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate.

Abstract: The present invention is a cryogenic subterranean fracturing fluid, comprising a liquefied industrial gas and a viscosity increasing additive. The liquefied industrial gas may be liquefied carbon dioxide, liquefied nitrogen, or a blend of the two. The liquefied industrial gas mixture should be substantially free of water. In this context, substantially free of water means less than 10% water by volume, or preferably less than 5% water by volume. In addition to the viscosity increasing additive, a proppant may be added to the fracturing fluid. In addition to the viscosity increasing additive and/or proppant additional additives may be added to the liquefied industrial gas as required.

Abstract: A method includes introducing a treatment fluid into a wellbore penetrating a subterranean formation, the treatment fluid including a polymer gel having a water-soluble polymer, a proppant, and a polymer gel-preserving amount of chlorine dioxide, the placing step includes applying the treatment fluid at a sufficient pressure and at a sufficient rate to fracture the subterranean formation.

Abstract: The present invention relates to formulations (F) based on crude glycerol (CG), cellulose ether and urea, to a process for producing mineral oil from mineral oil deposits having inhomogeneous permeability and to a process for producing formulations (F) comprising crude glycerol (CG). The rheological properties of the inventive formulations (F) are modifiable within wide ranges, and can be adjusted to the geotechnical parameters, the environmental conditions and the nature of the mineral oil in different mineral oil deposits.

Abstract: An encapsulated reactant(s) having at least one encapsulant and at least one reactant. An outermost encapsulant is substantially nonreacting, impermeable and nondissolving with water. The reactant(s) contribute to at least one reaction with contaminants in environmental media rendering the environmental media less harmful. Processes for using the encapsulated reactant in environmental media is also hereby claimed.

Abstract: Methods comprising providing a relative permeability modifier that comprises a hydrophilic polymer backbone with a hydrophobic modification and incorporating at least one cationic compound onto the hydrophilic polymer backbone. The hydrophilic polymer is one or more of: a polyacrylamide; a polyvinylamine; a poly(vinylamine/vinyl alcohol); an alkyl acrylate polymer; cellulose; chitosan; a polyamide; a polyetheramine; a polyhydroxyetheramine; a polylysine; a polysulfone; a gum; or a starch. The hydrophobic modification is achieved either by reacting the hydrophilic polymer with a hydrophobic compound or by a polymerization reaction product of a hydrophilic monomer and a hydrophobically modified hydrophilic monomer. The hydrophobic compound has an alkyl chain length from 4 to 22 carbons and is one or more of: an alkyl acrylate; an alkyl methacrylate; an alkyl acrylamide; an alkyl methacrylamide; or an alkyl dimethylammoniumethyl methacrylate halide.

Abstract: A ceramic propping agent, in the form of a spherical pellet, and containing common mineral particulate. The desired propping agent is defined as a particulate ceramic made from raw materials which may be comprised of about: 10%-90% parts by weight of a naturally occurring mineral particulate, 30%-70% parts by weight aluminosilicate network modifier, 0.25-20% parts by weight strength enhancer, and at least one part, typically less than 10% by weight, binder. For use in oil and/or natural gas wells as a hydraulic fracturing proppant.

Abstract: The present invention relates to a method for oil recovery from a reservoir which comprises the following phases: a) injecting a volume of a micro (nano)-structured fluid with released control of barrier substances into at least a portion of an underground reservoir containing oil, said micro (nano)-structured fluid comprising an aqueous dispersion of microcapsules composed of a core comprising a modifying substance of the absolute permeability of the rock formation which houses said reservoir, a protective shell insoluble in water which coats said core; b) clogging the porous intergranular spaces of said rock formation with said modifying substance with a reduction or inhibition of the absolute permeability of said rock formation, c) recovering said oil from the remaining portion of said reservoir by the further injection of a displacing fluid, preferably water.

Abstract: An aqueous composition for removing scale deposits, especially on subsea equipment and a method of using the same is described. The aqueous composition comprises (a) a potassium phosphate compound; and (b) acetic acid. The composition is capable of dissolving away into seawater and poses little or no risk to the environment.

Abstract: A composition comprising a carboxylated, sulfonated polysaccharide and a wellbore servicing fluid. A wellbore servicing composition comprising a hydraulic cement and a carboxylated, sulfonated polysaccharide. A wellbore servicing composition comprising a polysaccharide having carboxylate and sulfonate groups.

Abstract: According to an embodiment, a method of providing a biopolymer comprises: cryodesiccating a broth, wherein the broth comprises: (A) a biopolymer, wherein the biopolymer is an exopolysaccharide; and (B) a liquid growth medium. According to certain embodiments, the biopolymer is produced by the fermentation of at least one carbohydrate via a microbe. According to an embodiment, the microbe is a bacterium. According to another embodiment, the microbe is a fungus.

Abstract: A method of servicing a wellbore comprising introducing to the wellbore a wellbore servicing fluid comprising an additive composition comprising a polysaccharide having carboxylate and sulfonate groups. A method of servicing a wellbore comprising preparing at the well site an additive composition comprising a polysaccharide having carboxylate and sulfonate groups, introducing the additive composition into a wellbore servicing fluid, and placing the wellbore servicing fluid into a subterranean formation. A method of preparing a wellbore servicing fluid comprising contacting a polysaccharide composition with an oxidizing agent to form an oxidized polysaccharide, and contacting the oxidized polysaccharide with a sulfonating agent to form a carboxylated sulfonated polysaccharide, and contacting the carboxylated sulfonated polysaccharide with a wellbore servicing fluid.

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: Treatment fluids and methods for treating a subterranean formation are disclosed that include introducing a treatment fluid into a subterranean formation, the treatment fluid containing a nanocrystalline cellulose.

Abstract: The present invention relates to processes employing industrial streams, including glycerol-containing by-products of triglyceride processing as well as waste glycol streams recovered from several sources, to produce oil well drilling, completion and hydrofracturing fluids.

Abstract: Treating fluid compositions for use in hydrocarbon recovery operations from subterranean formations are described, as well as methods for their preparation and use. In particular, treating fluid compositions are described which comprise a liquid, a crosslinkable organic polymer material that is at least partially soluble in the liquid, a crosslinking agent that is capable of increasing the viscosity of the treating fluid by crosslinking the organic polymer material in the liquid, and a crosslinking modifier additive which can delay or accelerate the crosslinking of the treating fluid composition. Such compositions may be used in a variety of hydrocarbon recovery operations including fracturing operations, drilling operations, gravel packing operations, water control operations, and the like.

Abstract: A method of servicing a wellbore comprising introducing to the wellbore a wellbore servicing fluid comprising an additive composition comprising a polysaccharide having carboxylate and sulfonate groups. A method of servicing a wellbore comprising preparing at the well site an additive composition comprising a polysaccharide having carboxylate and sulfonate groups, introducing the additive composition into a wellbore servicing fluid, and placing the wellbore servicing fluid into a subterranean formation. A method of preparing a wellbore servicing fluid comprising contacting a polysaccharide composition with an oxidizing agent to form an oxidized polysaccharide, and contacting the oxidized polysaccharide with a sulfonating agent to form a carboxylated sulfonated polysaccharide, and contacting the carboxylated sulfonated polysaccharide with a wellbore servicing fluid.

Abstract: A method is provided for use in various well services, the method including the steps of: (a) forming or providing a well fluid comprising cellulose nanowhiskers; and (b) introducing the well fluid into a well. The method can be used, for example, for increasing the strength of a cement, for increasing the viscosity of a water-based well fluid, such as for a kill pill, a fracturing fluid, a gravel packing fluid.

Abstract: The invention describes improved environmentally friendly, non-toxic, CBM friendly, green fracturing compositions, methods of preparing fracturing compositions and methods of use. Importantly, the subject invention overcomes problems in the use of water-based mists as an effective fracturing composition particularly having regard to the ability of a mist to transport an effective volume of proppant into a formation. As a result, the subject technologies provide an effective economic solution to using high ratio gas fracturing compositions that can be produced in a continuous (i.e. non-batch) process without the attendant capital and operating costs of current pure gas fracturing equipment.

Abstract: The present invention relates to environmentally friendly compositions and methods for removing or suppressing metal ions in waters, flowback waters, and produced waters to make such waters suitable for subsequent use in oil-field applications and for delinking metal cross-linked gelling agents. One embodiment of the present invention provides a method of providing a competitive binder and allowing the competitive binder to interact with interfering metal ions in a flowback fluid to suppress or remove interfering metal ions.

Abstract: A fracking fluid hydration unit is provided that has a plurality of hydration tank sections wherein shear is added to the hydrated fluid flow via a recirculation hydrated fluid jetting system.

Abstract: A cellulose ether having (i) one or more substituents selected from the group consisting of methyl, hydroxyethyl and hydroxypropyl, (ii) one or more hydrophobic substituents, and (iii) one or more cationic, tertiary amino, or anionic substituents, and having a retained dynamic viscosity, % ?80/25, of at least 30 percent, wherein % ?80/25=[dynamic solution viscosity at 80° C./dynamic solution viscosity at 25° C.]×100, the dynamic solution viscosity at 25° C. and 80° being measured as 1% aqueous solution, is useful for modifying the viscosity of a composition selected from the group consisting of wellbore servicing fluids, cementitious formulations, ceramics, metal working fluids and cutting fluids.