Abstract: Additives configured to temporarily reduce viscosity in oil-based fluids are provided. The additives may be a reaction product of at least one non-ionic additive and at least one acid anhydride of maleic, succinic and/or glutaric acid. The at least one non-ionic additive may be selected from linear or branched alcohols, alcohol ethoxylates, a combination thereof, and/or a derivative thereof.

Abstract: The present invention provides a method for separating oily drill fluid from an oily drill cuttings slurry comprising oily drill fluid and drill cuttings. The method comprises destructively modifying at least a portion of the drill cuttings that are contacted by at least one cuttings-reactive chemical thereby disrupting attraction forces between the portion of the drill cuttings and the oily drill fluid and making it easier for mechanical cuttings treatment equipment to separate oily drill fluid from the oily drill cuttings slurry.

Abstract: A novel method for the placement of spearhead acid and stimulation of a hydrocarbon-bearing formation, said method comprising the steps of: providing a wellbore in need of multiple stages of stimulation; inserting an isolation plug in the wellbore at a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore simultaneously exposing the wireline and tool to the acid; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for stimulation; removing the tool form the wellbore; and initiating the stimulation of the perforated area using a stimulation fluid.

Abstract: A fracturing fluid composition includes an aqueous fluid, a proppant particle, and a date tree fiber. A method of treating a hydrocarbon-bearing formation is also provided. The method includes injecting a fracturing fluid in the hydrocarbon-bearing formation, where the fracturing fluid includes an aqueous fluid, a proppant particle, and a date tree fiber.

Abstract: A treatment composition for remediating for remediating H2S and other contaminant(s) in contaminated gasses comprising: an aqueous hydroxide solution containing at least one hydroxide compound at a collective concentration of 35-55 weight percent of the aqueous hydroxide solution; at least one organic acid selected from the group consisting of fulvic acid and humic acid; and a chelating agent, wherein the aqueous hydroxide solution constitutes at least 80 wt % of the treatment composition, the at least one organic acid constitutes 0.1-5 wt % of the treatment composition, the chelating agent constitutes 0.1-5 wt % of the treatment composition, and a pH of the treatment composition is at least 12.0.

Abstract: A treatment process for remediating a contaminated liquid containing more than 5 ppm hydrogen sulfide, includes steps of: preparing a treatment solution containing an aqueous solution containing ?1 hydroxide compound, in which a collective concentration of the ?1 hydroxide compound in the aqueous solution is in a range of 35-55 weight percent and the aqueous solution constitutes at least 95% of the treatment solution; adding to the liquid an amount of an treatment solution sufficient to reduce a concentration of hydrogen sulfide in the contaminated liquid to ?5 ppm based on stoichiometry of reactions between the ?1 hydroxide compound and the hydrogen sulfide in the liquid; and dispersing the treatment solution in the liquid and allowing the treatment solution to react with the contaminated liquid for a period of time until a concentration of hydrogen sulfide in the liquid is reduced to ?5 ppm.

Abstract: An aqueous slurry composition for use in industries such as petroleum and pipeline industries, such as for use as a fracturing fluid. The aqueous slurry composition includes a particulate, an aqueous liquid and a chemical compound that renders the particulate surface hydrophobic. The slurry is produced by rendering the surface of the particulate hydrophobic during or prior to making the slurry.

Abstract: Biocidal compositions and their use in aqueous media, such as metalworking fluids, the compositions comprising a biocidal agent; and a non-biocidal primary amino alcohol compound of the formula (I); wherein R1, R2, R3, R4, and R5 are as defined herein.

Abstract: An invert emulsion treatment fluid comprises: (A) an external phase, wherein the external phase comprises a hydrocarbon liquid; (B) an internal phase, wherein the internal phase comprises a hygroscopic liquid; (C) a suspending agent, wherein the suspending agent is a polymer, and wherein the polymer comprises urea linkages; and (D) a particulate, wherein the particulate has a density less than 3.5 g/cm3, wherein a test fluid consisting essentially of the external phase, the internal phase, the suspending agent, and the particulate, and in the same proportions as the treatment fluid, and after static aging for 2 months at a temperature of 200° F. (93.3° C.), has a 10 minute gel strength of at least 30 lb/100 ft2 (1,436 Pa) at a temperature of 120° F. (48.9° C.). A method of using the invert emulsion treatment fluid comprises: introducing the treatment fluid into a portion of a subterranean formation.

Abstract: Aqueous and substantially anhydrous fluids having particularly low thermal conductivities and variable densities are disclosed. The fluids include: one or more organic and/or inorganic salts and at least one aprotic polar organic solvent, a mixture of aprotic and protic polar organic solvents, and/or a polar organic solvent having both protic and aprotic polar functional group linkages. The fluids optionally include one or more viscosifying agents and are free of cross-linking agents. Methods for formulating and using the fluids are also disclosed.

Abstract: Fluids viscosified with viscoelastic surfactants (VESs) may have their viscosities reduced (gels broken) by the direct or indirect action of an internal breaker composition that contains at least one mineral oil, at least one polyalphaolefin oil, at least one saturated fatty acid and/or at least one unsaturated fatty acid. The internal breaker may initially be dispersed oil droplets in an internal, discontinuous phase of the fluid. In one non-limiting embodiment, the internal breaker, e.g. mineral oil, is added to the fluid after it has been substantially gelled. An oil-soluble surfactant is present to enhance or accelerate the reduction of viscosity of the gelled aqueous fluid.

Abstract: A method of treating an earth formation that includes introducing at least one blocked isocyanate in a liquid phase into the earthen formation; introducing at least one active hydrogen compound into the earthen formation; and contacting the blocked isocyante and the active hydrogen compound form an elastomeric gel is disclosed.

Abstract: A composition that includes a product resulting from a condensation reaction of quebracho with at least one organophilic species that includes a reactive amine is disclosed.

Abstract: The present invention relates to nitrogen-containing hydroxyethyl substituted compounds to be used as corrosion inhibitors for metal surfaces, for example in aqueous systems and in particular in oil-field applications, e.g. in oil or gas wells, and which could be used under sweet-well conditions as well as under sour-well conditions. It may also be used in oil-field acidizing and fracture-acidizing well stimulation treatment. The compounds belong to the group of partly ethoxylated fatty alkylamines, partly ethoxylated alkyletheramines and partly or fully hydroxyethyl substituted alkylamidopropylamines.

Abstract: Methods of treating a wellbore in a subterranean formation including providing an oil-external treatment fluid, wherein the oil-external treatment fluid is a 3D-network comprising a chemical interaction between a hydrocarbon fluid, an aqueous fluid, and a surface modification agent; providing proppant particulates; suspending the proppant particulates in the oil-external treatment fluid; and introducing the oil-external treatment fluid comprising the proppant particulates into the wellbore in the subterranean formation.

Abstract: A high carrying capacity temperature-stable breakable gel of selectable viscosity with exceptional lubricity and high-temperature stability for varied use as a carrier of solids and particulate matter, as well as semi-solids and liquids in water and petroleum well drilling, completion and production such as gravel pack fluid, drilling fluid, fracturing fluid, pigging fluid, sweep for coiled tubing, and other uses. A preferred formulation comprises a formulated “Base Concentrate” which is added to water or drilling fluids to be viscosified and an “Activator” which is added in amounts to develop the desired gel consistency. When breaking of the gel is desired a “Breaker” composition containing multivalent ions collapses the gel into a free-flowing liquid.

Abstract: A method of servicing a wellbore in a subterranean formation comprising placing a wellbore servicing fluid comprising a coupling agent, a hardenable resin and a hardening agent into the wellbore wherein the coupling agent comprises a multihydroxy phenyl, a dihydroxy phenyl, a trihydroxy phenyl, ascorbic acid, a hydroxymethylnaphthol, an oxidation product thereof, a derivative thereof, or combinations thereof. A wellbore servicing fluid comprising a coupling agent, a hardenable resin, a hardening agent and a proppant wherein the coupling agent comprises a multihydroxy phenyl, a dihydroxy phenyl, a trihydroxy phenyl, ascorbic acid, a hydroxymethylphenol, a hydroxymethylnaphthol, an oxidation product thereof, a derivative thereof, or combinations thereof.

Abstract: Stabilizers that include hydrophobically modified amine-containing polymers may be utilized as compositions or in methods for controlling particulate migration in a subterranean formation. For example, a method may include providing a treatment fluid that comprises a base fluid and a hydrophobically modified amine-containing polymer (HMAP), the HMAP comprising a plurality of hydrophobic modifications on an amine-containing polymer; introducing the treatment fluid into a wellbore penetrating a subterranean formation, the subterranean formation comprising a plurality of particulates; and allowing the HMAP to coat at least some of the particulates.

Abstract: The invention discloses a method comprising providing a fluid comprising a viscosifying agent in an aqueous medium; contacting the fluid with a halogenisocyanuric acid or halogenisocyanurate component; whereby the viscosity of the fluid with the halogenisocyanuric acid or halogenisocyanurate component is reduced compared to the viscosity of the fluid alone; and introducing the fluid into a well. The halogenisocyanuric acid component can be mono chloroisocyanuric acid, dichloroisocyanuric acid or trichloroisocyanuric acid. The halogenisocyanurate component can be an alkali metal monochloroisocyanurate, alkali metal dichloroisocyanurate or alkali metal trichloroisocyanurate.

Abstract: The invention provides for the use of 1-alkyl-5-oxopyrrolidine-3-carboxylic esters, preparable by esterifying alcohols having from 1 to 100 hydroxyl groups with 1-alkyl-5-oxopyrrolidine-3-carboxylic acid, in amounts of from 0.01 to 2% by weight for preventing the formation of gas hydrates in aqueous phases which are in contact with a gaseous, liquid or solid organic phase.

Abstract: A method of converting an inactive biocide into an active biocide comprises: contacting the inactive biocide with an activating agent, wherein the activating agent is capable of chemically reacting with the inactive biocide; and causing or allowing a chemical reaction to take place between the inactive biocide and the activating agent, wherein the chemical reaction produces the active biocide. The methods can also include deactivating the active biocide via a chemical reaction between the active biocide and a deactivating agent.

Abstract: The invention relates to the use of compounds comprising three hydrophobic groups as additives to a stream of crude oil containing carboxylic acids, in particular naphthenic acids, and salt water, to prevent the formation of calcium carboxylates when the fluid is exposed to shear forces. Preferably, the compounds are added to a crude oil/water stream containing organic acids Ca2+ ions at a point between the well and the pressure reduction valve in the crude oil receiving station.

Abstract: A process for increasing mobility of heavy oil includes: disposing a solvating composition comprising a paraffinic solvent and a multifunctional solvent in a heavy oil environment including a heavy oil, the heavy oil comprising asphaltene; contacting the heavy oil with the solvating composition; and stabilizing asphaltene in the heavy oil with the solvating composition to increase mobility of the heavy oil and to form a stabilized heavy oil which includes the heavy oil and solvating composition. A method for making stabilized heavy oil includes separating resin from an oil; combining the resin and a paraffinic solvent to form a solvating composition; disposing the solvating composition in a heavy oil environment which includes heavy oil comprising asphaltene; and contacting the asphaltene with the solvating composition to make stabilized heavy oil, wherein the stabilized heavy oil comprises the solvating composition and heavy oil.

Abstract: A method for the encapsulation and triggered-release of water-soluble or water-dispersible materials. The method comprises a) providing an amount of electrolyte having a charge, b) providing an amount of counterion having a valence of at least 2, c) combining the polyelectrolyte and the counterion in a solution such that the polyelectrolyte self-assembles to form aggregates, d) adding a compound to be encapsulated, and e) adding nanoparticles to the solution such that nanoparticles arrange themselves around the aggregates. Release of the encapsulated species is triggered by disassembly or deformation of the microcapsules though disruption of the charge interactions. This method is specifically useful for the controlled viscosity reduction of the fracturing fluids commonly utilized in the oil field.

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: 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: Insensitive explosive compositions were prepared by reacting di-isocyanate and/or poly-isocyanate monomers with an explosive diamine monomer. Prior to a final cure, the compositions are extrudable. The di-isocyanate monomers tend to produce tough, rubbery materials while polyfunctional monomers (i.e. having more than two isocyanate groups) tend to form rigid products. The extrudable form of the composition may be used in a variety of applications including rock fracturing.

Abstract: A composition and method are disclosed. The composition includes a carrier fluid and a solids mixture combined to form a slurry, wherein the solids mixture comprises a plurality of volume-averaged particle size distribution (PSD) modes, wherein a first PSD mode comprises solids having a volume-average median size at least three times larger than the volume-average median size of a second PSD mode such that a packed volume fraction of the solids mixture exceeds 0.75, and wherein the solids mixture comprises a degradable material and includes a reactive solid. The method includes circulating the slurry through a wellbore to form a pack in a fracture and/or a screen-wellbore annulus; degrading the degradable material to increase porosity and permeability of the pack; and producing a reservoir fluid through the permeable pack.

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: A fluid may contain nanoparticles and a base fluid where the base fluid may be a non-aqueous fluid. The base fluid may be, but is not limited to a drilling fluid, a completion fluid, a production fluid, and/or a stimulation fluid. The fluid may have at least one property, such as but not limited to a dielectric constant ranging from about 5 to about 10,000, an electrical conductivity ranging from about 1×10?6 S/m to about 1 S/m, and combinations thereof. The non-aqueous fluid may be a brine-in-oil emulsion, or a water-in-oil emulsion, and combinations thereof. The addition of nanoparticles to the base fluid may modify the electrical properties of the fluid.

Abstract: An new class of oil-soluble, sulfur scavengers or converts are disclosed where the scavengers include substantially monomeric aldehyde-amine adducts from the reaction of at least one sterically hindered primary or secondary amine and a molar excess of at least one aldehyde. Methods are also disclosed for reducing, reducing below a given level or eliminating noxious sulfur species from fluids using the inventive scavengers and for making the inventive scavengers.

Abstract: There is a viscoelastic fluid. The fluid has one or more cationic surfactants selected from the group consisting of certain quaternary salts, certain amines, and combinations thereof; one or more anionic polymers/anionic surfactants; one or more of certain zwitterionic/amphoteric surfactants; and water. There is also a method of fracturing a subterranean formation. The viscoelastic fluid is pumped through a wellbore and into a subterranean formation at a pressure sufficient to fracture the formation. There is also a method for gravel packing a subterranean formation.

Abstract: A composition that includes a product resulting from a condensation reaction of quebracho with at least one organophilic species that includes a reactive amine is disclosed.

Abstract: Apparatus and methods to prevent the proliferation of undesired life forms in a subterranean formation, comprising forming a fluid comprising an inhibitor; and introducing the inhibitor to a surface in the formation. Apparatus and methods to prevent the proliferation of undesired life forms along a surface of tubular or equipment for use in the oil field services industry, comprising forming a coating comprising an inhibitor; and introducing the coating to a surface of the tubular or equipment. Apparatus and methods to prevent the proliferation of undesired life forms along a surface of tubular or equipment for use in the oil field services industry, comprising forming a material comprising an inhibitor; and embedding the material into a surface of the tubular or equipment.

Abstract: A method for replacing glycol-based mutual solvents in an oil field application comprising: obtaining an alternative solvent and solvent blends and replacing all or a portion a glycol-based mutual solvent, which forms a component of an oil field formulation, with the alternative solvent or solvent blends, wherein the oil field formulation can be utilized in an oil field application.

Abstract: Methods of reducing the viscosity of a viscosified treatment fluid; providing a clean-up composition comprising a carboxylic acid; a chlorite-based breaker system comprising an alkali metal compound and an activator wherein the activator comprises a metal and an amine. Placing a viscosified treatment fluid in a subterranean formation via a well bore penetrating the subterranean formation; first contacting the viscosified treatment fluid with the chlorite-based breaker; and then contacting the viscosified treatment fluid with the clean-up composition; and, allowing the viscosity of the viscosified treatment fluid to reduce.

Abstract: Of the many methods provided herein, one method of reducing the viscosity of a viscosified treatment fluid includes: providing a clean-up composition comprising a carboxylic acid; providing a chlorite-based breaker system; providing a viscosified treatment fluid; placing the viscosified treatment fluid in a subterranean formation via a well bore penetrating the subterranean formation; contacting the viscosified treatment fluid with the clean-up composition; contacting the viscosified treatment fluid with the chlorite-based breaker; and allowing the viscosity of the viscosified treatment fluid to reduce. Also provided herein are methods that include a method of reducing polymeric residue from a subterranean formation that includes: placing a clean-up composition and a chlorite-based breaker system in a subterranean formation in contact with an amount of polymeric residue; and allowing the amount of polymeric residue present in the formation to be reduced.

Abstract: A method for affecting the viscosity of an aqueous fluid gelled with a VES 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, a glyceride oil comprising a fatty acid, and a plurality of metallic particles to produce a mixture comprising dispersed metallic particles. The method also includes dissolving at least a portion of the metallic particles in the aqueous fluid to provide a compound comprising a metallic base and forming in situ a soap reaction product of the fatty acid with the compound, wherein the soap reaction product is present in an amount effective to increase, decrease, or increase and then decrease a viscosity of the gelled aqueous fluid.

Abstract: Guard bed compositions for protecting metal surfaces in a wellbore from corrosion may comprise a variety of constituent components. Exemplary guard bed compositions may include: one or more surfactants selected from the group comprising amine surfactants; one or more co-surfactants selected from the group comprising C3 to C15 alcohols; and one or more non-surfactant amines. Other exemplary guard bed compositions may comprise: a hydrocarbon fluid and an overbased detergent. Still other exemplary guard bed compositions may comprise: a hydrocarbon fluid; one or more surfactants; one or more co-surfactants; and one or more non-surfactant amines. The one or more surfactants may be selected from the group comprising alkyl alkoxylated surfactants. Still further, exemplary guard bed compositions may comprise: a hydrocarbon fluid and one or more associating surface active polymers selected from the group comprising amphiphilic polymers.

Abstract: Guard bed compositions for protecting metal surfaces in a wellbore from corrosion may comprise a variety of constituent components. Exemplary guard bed compositions may include: one or more surfactants selected from the group comprising amine surfactants; one or more co-surfactants selected from the group comprising C3 to C15 alcohols; and one or more non-surfactant amines. Other exemplary guard bed compositions may comprise: a hydrocarbon fluid and an overbased detergent. Still other exemplary guard bed compositions may comprise: a hydrocarbon fluid; one or more surfactants; one or more co-surfactants; and one or more non-surfactant amines. The one or more surfactants may be selected from the group comprising alkyl alkoxylated surfactants. Still further, exemplary guard bed compositions may comprise: a hydrocarbon fluid and one or more associating surface active polymers selected from the group comprising amphiphilic polymers.

Abstract: Guard bed compositions for protecting metal surfaces in a wellbore from corrosion may comprise a variety of constituent components. Exemplary guard bed compositions may include: one or more surfactants selected from the group comprising amine surfactants; one or more co-surfactants selected from the group comprising C3 to C15 alcohols; and one or more non-surfactant amines. Other exemplary guard bed compositions may comprise: a hydrocarbon fluid and an overbased detergent. Still other exemplary guard bed compositions may comprise: a hydrocarbon fluid; one or more surfactants; one or more co-surfactants; and one or more non-surfactant amines. The one or more surfactants may be selected from the group comprising alkyl alkoxylated surfactants. Still further, exemplary guard bed compositions may comprise: a hydrocarbon fluid and one or more associating surface active polymers selected from the group comprising amphiphilic polymers.

Abstract: The invention relates to methods of controlling the stability of emulsions to coalescence and phase separation. Use of chaotropic counterions to promote coalescence and/or phase separation of emulsions stabilized by ionic surfactants is described.

Abstract: A method of secondary oil recovery is disclosed wherein from 0.1 to 100 000 ppm of a medium soluble aminoalkylene phosphonic acid amine salt are used wherein both the aminoalkylene phosphonic acid moiety and the amine moiety are selected from a specifically defined class of compounds. The substantially medium soluble aminoalkylene amine phosphonates exhibit a significantly improved compatibility with the recovery medium and thus can propagate fairly freely into the medium and consequently cover a largely extended rock surface before being subject to precipitation in the form of a medium insoluble scale inhibitor. The amine compound is represented by combinations of structurally different compounds.

Abstract: One or more compositions and methods for inhibiting the formation of hydrate agglomerates in a fluid that contain a specified generic formula are disclosed. The fluid can be contained in an oil or gas pipeline or refinery.

Abstract: One or more compositions and methods for inhibiting the formation of hydrate agglomerates in an aqueous medium that contain a specified generic formula are disclosed. The aqueous medium can be contained in an oil or gas pipeline or refinery.

Abstract: Phosphate brines are disclosed having reduced corrosive ratings. The phosphate brines include an additive system that reduces the corrosiveness of the phosphate brines compared to the phosphate brines in the absence of the additive system.

Abstract: A base fluid may contain graphene nanoparticles where the base fluid may include an oil-based fluid, a water-based fluid, and combinations thereof. The oil-based fluid may be a brine-in-oil emulsion, or a water-in-oil emulsion, and the water-based fluid may be an oil-in-water emulsion, or an oil-in-brine emulsion; and combinations thereof. The addition of graphene nanoparticles to the base fluid may improve one or more properties of the fluid, which may include the flow assurance properties of the fluid, the fluid loss control properties of the fluid, the rheological properties of the fluid, the stability of the fluid, the lubricity of the fluid, the electrical properties of the fluid, the viscosity of the fluid, the thermal properties of the fluid, and combinations thereof. The fluid may be a drilling fluid, a completion fluid, a production fluid, and/or a servicing fluid.

Abstract: The present invention relates to a process for binding non-consolidated oxidic inorganic materials with curable formulations which comprise etherified amino resins, and to cured compositions obtainable by the process. A preferred embodiment of the invention comprises a process for stabilizing underground formations composed of oxidic inorganic materials, wherein the curable composition is injected into the underground formation and cured at the temperatures which exist in the formation.

Abstract: Methods are provided that include a method comprising: providing an emulsified treatment fluid comprising an oleaginous phase, an aqueous phase, a consolidating agent, and an emulsifying agent that comprises at least one convertible surfactant described by a one of the disclosed formulae, and placing the subterranean treatment fluid in a subterranean formation.

Abstract: Aqueous and substantially anhydrous fluids having particularly low thermal conductivities and variable densities are disclosed. The fluids include: one or more organic and/or inorganic salts and at least one aprotic polar organic solvent, a mixture of aprotic and erotic polar organic solvents, and/or a polar organic solvent having both prone and aprotic polar functional group linkages. The fluids optionally include one or more viscosifying agents and are free of cross-linking agents. Methods for formulating and using the fluids are also disclosed.