Abstract: A brine-based viscosified pill including (1) a viscosified brine, (2) a surfactant-solvent blend containing about 5 wt. % to about 40 wt. % of at least one nonionic surfactant; about 5 wt. % to about 20 wt. % of at least one polyglycerol ester, about 20 wt. % to about 60 wt. % of at least one co-solvent; about 20 wt. % to about 25 wt. % water; and optionally about 1 wt. % to about 15 wt. % of at least one hydrophobic solvent, and (3) no solid weighting agent, may be introduced to a wellbore in an effective amount to clean the wellbore or displace fluid in the wellbore at a wide range of temperatures.

Abstract: A method of inhibiting carbon dioxide (CO2) hydrate formation in a CO2 pipeline is described. The method includes injecting a composition including monoethylene glycol carbon quantum dots (MEG CQDs) into the CO2 pipeline to deposit the MEG CQDs on an inside surface of the CO2 pipeline. The method further includes pressurizing the CO2 pipeline with a gas stream containing CO2 and water vapor at a pressure of 200-2,000 pounds per square inch (psi). The MEG CQDs are present on the inside surface of the CO2 pipeline in an amount effective to reduce the formation of CO2 hydrates in the CO2 pipeline during the pressurizing in comparison to the formation of the CO2 hydrates in the CO2 pipeline under the same conditions but in the absence of the MEG CQDs.

Abstract: The disclosure is directed to low molecular weight polyelectrolyte complex nanoparticles that can be used to deliver agents deep into hydrocarbon reservoirs. Methods of making and using said polyelectrolyte complex nanoparticles are also provided.

Abstract: The present invention relates to a hair cosmetic containing the following components (A) to (C): (A) a compound represented by the following general formula (1) or a salt thereof: wherein a broken line represents the presence or absence of a ? bond; R1 represents a hydroxy group or an acetoxy group; R2 represents a hydrogen atom or —COOR (R is a hydrogen atom, a methyl group, or an ethyl group); and R3 represents a hydrogen atom, an acetyl group, a methyl group, or an ethyl group; (B) a cationic polymer; and (C) an ampholytic polymer having a predetermined cationic structural unit and an anionic structural unit, a mass ratio of the component (C) to the component (A) [(C)/(A)] being 0.7 or more and 10 or less.

Abstract: Methods and system for using salting out inhibitors in subterranean formations are provided. In some embodiments, the methods comprise introducing a treatment fluid comprising an aqueous base fluid, a salting out inhibitor, a gelling agent, and one or more salts into at least a portion of a subterranean formation, wherein the salting out inhibitor is selected from the group consisting of: an oligomer comprising one or more quaternary ammonium cations, a polymer comprising one or more quaternary ammonium cations, a source of one or more phosphate anions, and any combination thereof.

Abstract: Provided herein are compositions comprising borate-acid buffers, as well as methods of using these compositions in oil and gas operations, including enhanced oil recovery (EOR) operations, fracturing operations, stimulation operations, etc.

Abstract: A well bore cementing system may comprise a spacer fluid and a cement slurry. The spacer fluid may be positioned within a well bore, and the spacer fluid may comprise a first surfactant package comprising one or more surfactants. The cement slurry may be positioned within the well bore, and the cement slurry may comprise a second surfactant package comprising one or more surfactants.

Abstract: Sandstone formations of oil and gas and geothermal wells may be successfully stimulated with a fluid containing GLDA or salt and HF or a HF-generating component and an organophosphonate component. The organophosphonate acts as a sequestering agent and reduces the amount of metal fluoride precipitates produced.

Abstract: The disclosure is directed to polyelectrolyte complex nanoparticles that can be used to deliver agents deep into hydrocarbon reservoirs. Methods of making and using said polyelectrolyte complex nanoparticles are also provided.

Abstract: Salt-free invert emulsions having an external phase comprising a hydrocarbon fluid, and an internal phase comprising a hygroscopic fluid selected from the group consisting of an amino alcohol, a glycol, an amine glycol, and any combination thereof. Methods including introducing the salt-free invert emulsion into a subterranean formation and performing a subterranean formation operation.

Abstract: A method for temporary isolation of a well interval is proposed, the method comprising: pumping a first slurry into the well, the slurry comprising a viscous carrier fluid, degradable particulates, and degradable fibers, until a first filter cake is formed; and pumping a second slurry into the well, the slurry comprising a viscous carrier fluid, non-degradable particulates, and degradable fibers, until a second filter cake is formed. The first and the second slurries are not mixed when pumped into the well. To ensure optimum interval isolation, the ratio of the volume of the first slurry to the volume of the second slurry should be in the range 1:5 to 2:1. A method for hydraulic refracturing within an interval with several hydraulic fractures and a non-damaging well killing method are also proposed. The technical result is manifested in no formation damage and degradation of the sealing layer formed.

Abstract: The present invention discloses a method and a process of producing ammonia from methane extracted from methane-hydrate at the site of methane-hydrate extraction. The method and the process comprise coupled chemical reactions. During the first reaction, carbon dioxide reacts methane-hydrate to produce carbon-dioxide-hydrate and methane: carbon dioxide+methane-hydrate?carbon-dioxide-hydrate+methane (CO2+CH4-hydrate?CO2-hydrate+CH4). The produced methane is reacted with water to produced carbon dioxide and hydrogen via the second reaction: methane+water?carbon dioxide+hydrogen (CH4+2H2O?CO2+4H2). One embodiment of the second reaction is a combination of the methane steam reforming reaction (CH4+H2O?CO+3H2) and the water-gas shift reaction (CO+H2O?CO2+H2), both are widely known in the art. The carbon dioxide produced in the second reaction is recycled and used for the first reaction.

Abstract: Disclosed herein is a degradable diverter material having a urea compound. In particular, the degradable diverter material may be a particulate with each individual particle being a nanocompo site of a urea compound and clay. The degradable diverter material may be introduced into a wellbore penetrating a subterranean formation. The degradable diverter material may then be allowed to divert at least a portion of fluid present downhole, the fluid being introduced from the surface or already present dowhole. The degradable diverter material can then be allowed to at least partially degrade.

Abstract: The invention relates to an injectable composition for rapid and sustained delivery of a biologically active agent and to uses of the injectable composition in the treatment or prevention of a condition in a subject. The injectable composition comprises a water-in-oil emulsion having an aqueous phase dispersed in an oil phase. The aqueous phase comprises a plurality of hydrogel particles and an aqueous liquid and a biologically active agent is contained in the hydrogel particles and in the aqueous liquid.

Abstract: Methods include introducing a multistage treatment fluid into one or more intervals of a wellbore, wherein the treatment fluid contains one or more stages of a polymer-forming composition and one or more stages of a spacer fluid and initiating polymerization of the one or more stages of polymer-forming composition. Methods may include designing a multistage treatment fluid containing one or more stages of a polymer-forming composition and one or more stages of a spacer fluid, wherein or more stages of the polymer-forming composition comprises a thermosetting polymer; and pumping the multistage treatment fluid into a wellbore, wherein the pumping rate is determined by constructing a model based upon (a) the minimum pumping rate determined from the critical reaction temperature and the downhole temperature, (b) the fracture closing time, (c) the temperature within one or more fractures, and (d) the maximum pumping rate.

Abstract: Compositions and methods for the controlled delivery of acid to a desired location. In some embodiments, methods for in situ acid stimulation of a subterranean formation that contains a hydrocarbon reservoir comprise contacting the formation with an aqueous fluid that comprises (a) an ammonium salt capable of being oxidized to produce acid and (b) an oxidizing agent capable of oxidizing the ammonium salt, where the ammonium salt and oxidizing agent react to produce an acid.

Abstract: Method for inhibiting the swelling and the dispersion of shales in the treatment of subterranean shale formations comprising the use of a cationic tamarind gum and fluids for the treatment of subterranean shale formations comprising a cationic tamarind gum.

Abstract: The present invention relates to a method for preparing a concentrated polysaccharide mass, in particular a method for preparing concentrated glucan or schizophyllan, in particular a method for redispersing glucan or schizophyllan for producing a ready-to-use mass.

Abstract: A composite temperature resistance gel plugging agent, a preparation method thereof and Fuse thereof in profile control and water plugging of ultra-deep oil reservoirs.

Abstract: A method for making proppant particles is provided. The method can include providing a slurry of ceramic raw material, the slurry containing a reactant including a polycarboxylic acid, and flowing the slurry through a nozzle in a gas while vibrating the slurry to form droplets. The method can also include receiving the droplets in a vessel containing a liquid having an upper surface in direct contact with the gas, the liquid containing a coagulation agent. The method can further include reacting the reactant with the coagulation agent to cause coagulation of the reactant in the droplets. The droplets can then be transferred from the liquid and dried to form green pellets. The method can include sintering the green pellets in a selected temperature range to form the proppant particles. In one or more exemplary embodiments, the reactant can be or include a PMA:PAA copolymer.

Abstract: A polyelectrolyte composition is represented by the following formula (1). In the formula (1), R1 is hydrogen or CH3, R2 is any of C2H4, CH(CH3)CH2, and (CH2)3, m and n are each a copolymerization ratio of a structural unit in parentheses, and when m and n are set as follows: m+n=10, m and n satisfy the following formulae: 1?m?5 and 5?n?9, and p is 2 or more and 8 or less.

Abstract: Treatment fluids (e.g., fracturing fluids) comprising ionic water, and associated methods of use are provided. In one embodiment, the methods comprise providing a treatment fluid comprising an aqueous base fluid comprising one or more ionic species, a polymeric viscosifying agent carrying a first ionic charge, and an ionic surfactant carrying a second ionic charge that is the opposite of the first ionic charge; and introducing the treatment fluid into a well bore penetrating at least a portion of a subterranean formation.

Abstract: A method of treating a subterranean formation including combining an aqueous fluid, a biomaterial, an enzyme, and a deactivator to form a treatment fluid; and introducing the treatment fluid into the subterranean formation. A method is also disclosed for treating a subterranean formation by preparing a treatment fluid containing an aqueous fluid that contains bacterial and/or fungal cells that produce an enzyme that degrades the biomaterial, a biomaterial, and a deactivator; controlling degradation of the biomaterial by adding an effective amount of the deactivator to the aqueous fluid prior to the preparation of the treatment fluid; and introducing the treatment fluid into the subterranean formation. In the methods, the enzyme degrades the biomaterial and the deactivator is an oxygen-containing arene capable of inhibiting the enzyme from degrading the biomaterial.

Abstract: Polyelectrolyte nanoparticles are generated to stabilize foam for use in enhanced oil recovery. Stability is further enhanced by optimizing pH and a ratio of polycationic and polyanioinic materials, resulting in stronger and longer lasting foams in the presence of crude oil. Use of these nanoparticles results in negligible damage to formation permeability.

Abstract: Described is a method including emplacing a breaker fluid into a wellbore drilled with an oil-based drilling fluid that forms an oil-based filter cake. The breaker fluid includes a non-oleaginous base fluid and a surfactant blend comprising an alkyl polyglycoside, an ethoxylated alcohol, and a triethyleneglycol monobutyl ether. The method further includes allowing the breaker fluid to break the oil-based filter cake.

Abstract: A method for making proppant particles is provided. The method can include providing a slurry of ceramic raw material, the slurry containing a reactant including a polycarboxylic acid, and flowing the slurry through a nozzle in a gas while vibrating the slurry to form droplets. The method can also include receiving the droplets in a vessel containing a liquid having an upper surface in direct contact with the gas, the liquid containing a coagulation agent. The method can further include reacting the reactant with the coagulation agent to cause coagulation of the reactant in the droplets. The droplets can then be transferred from the liquid and dried to form green pellets. The method can include sintering the green pellets in a selected temperature range to form the proppant particles. In one or more exemplary embodiments, the reactant can be or include a PMA:PAA copolymer.

Abstract: A salt-tolerant, thermally-stable rheology modifier and, in particular, a rheology modifier for applications in oilfield well-bore fluids. In accordance with one aspect, the rheology modifier comprises a terpolymer of acrylamide, 2-acrylamido-2-methyl-propanesulfonic acid (AMPS) and a long-chain alkyl acrylate wherein the terpolymer is prepared by dispersion polymerization.

Abstract: Disclosed herein is a method of producing a polyaniline zirconia nanocomposite, and the uses of the thus produced polyaniline zirconia nanocomposite for the treatment of wastewater. The polyaniline zirconia nanocomposite is characterized in having a particle size of about 0.3 to 50 ?m in diameter, an isoelectric point at about pH 6.2, and is capable of reducing at least 99% of the pathological microorganism and at least 60% of the phosphate in the wastewater after coming into contact with wastewater for 24 hrs and 12 hrs, respectively.

Abstract: A downhole tool member for hydrocarbon resource recovery, comprising a shaped body of a polyglycolic acid resin blended with an inorganic or organic short fiber reinforcement material, and having thickness reduction rate characteristics when held in water at 120° C., inclusive of: an initial thickness reduction rate (as an average for a holding period for 4 hours) which is at most 0.8 times that of a shaped body of the polyglycolic acid resin alone, and has a terminal thickness reduction rate (after the thickness decreases to 50% or less of an initial thickness) which is larger than 1.5 times the initial thickness reduction rate.

Abstract: A thermoviscoelastic system (TVE) fluid useful in a well treatment method can include a hydrophobically-modified polymer and a viscoelastic surfactant (VES) in an aqueous medium, wherein the polymer has a lower critical solution temperature (LCST). The polymer can have water solubility for preparation below the LCST, and the TVE has a low viscosity for pumping down a well bore in communication with a subterranean formation. When the TVE is heated above the LCST, interaction between the hydrophobic groups of the polymer and the VES form a cross-linked network to increase the viscosity to transport proppant into a fracture. The thickened TVE can have a low leak-off rate, optionally including colloidal particles or other fluid loss control agent, and can be broken by contact with hydrocarbons as during flowback from the reservoir.

Abstract: A method and composition for treating a subterranean formation penetrated by a wellbore including preparing an aqueous composition containing a source of boron, whereby boron is present in the slurry in an amount of about 1.7% or greater, by weight, based upon a total weight of the composition, combining the composition with a mixture comprising a viscosifier and aqueous medium to form a treatment fluid, wherein the composition is added to the mixture in an amount of about 0.5% or less, by volume, based upon a total volume of the treatment fluid, and contacting the formation with the treatment fluid to treat the formation. The source of boron may be boric acid.

Abstract: A well servicing fluid is formulated with ingredients comprising a viscosifying polymer that is a crosslinked copolymer of an ethylenically unsaturated dicarboxylic anhydride and an alkyl vinyl ether, or the di-acid thereof; a pH adjuster capable of maintaining a pH of 5.5 or greater; and a solvent. Methods include treating a well formation with the wellbore servicing fluid and methods also include making the wellbore servicing fluid.

Abstract: Subterranean formations, such as tight gas formations, may be subjected to hydraulic fracturing by introducing into the formation a fracturing fluid of an aqueous fluid, a hydratable polymer, a crosslinking agent and proppant. The fluid enters the reservoir through an entrance site. The apparent viscosity of the fluid decreases distally from the entrance site such that at in situ conditions: (a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent viscosity of the fracturing fluid at the entrance site; (b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of the apparent viscosity of the fracturing fluid at the entrance site; and/or (c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the entrance site.

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: Methods of treating a subterranean formation with a treatment fluid comprising a swellable organic polymer coated onto proppant particulates. The swellable organic polymer is water-swellable, having a swelled configuration when contacted with water and an unswelled configuration in the absence of water contact. The treatment fluid may be introduced into the subterranean formation, where the swellable organic polymer adopts the swelled configuration and is placed in a fracture. During hydrocarbon production, the swellable organic polymer adopts the unswelled configuration.

Abstract: A persulfate compound activated by a strong base is used for low-temperature breaking of fluids viscosified with a multi-chain polysaccharide. The breaker system can be used in an oilfield or pipeline application where a multi-chain polysaccharide may be used in a fluid. It is particularly useful at low temperatures of less than 100° F. Optionally, the water can be a brine.

Abstract: Methods and fluids are provided that include, but are not limited to, a drilling fluid comprising an aqueous base fluid and a fluid loss control additive that comprises at least one polymeric micro gel and a method comprising: providing an aqueous based treatment fluid comprising a fluid loss control additive that comprises at least one polymeric micro gel; placing the aqueous based treatment fluid in a subterranean formation via a well bore penetrating the subterranean formation; allowing the fluid loss control additive to become incorporated into a filter cake located on a surface within the subterranean formation; allowing the filter cake to be degraded; and producing hydrocarbons from the formation. Additional methods are also provided.

Abstract: The current application discloses fluids and methods for treating a subterranean formation penetrated by a wellbore. In one aspect, there is provided a fluid comprising chitosan and titanate, where the fluid has an increased viscosity compared with a solution containing chitosan without titanate. In another aspect, there is provided a method of using such fluid to treat a subterranean formation penetrated by a wellbore. The method may comprise mixing chitosan and titanate in a carrying medium, forming a gel comprising chitosan and titanate, introducing the gel into a subterranean formation, and treating the subterranean formation with the gel.

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: An aqueous fluid, possibly a wellbore fracturing fluid, comprises an aqueous solution or dispersion of a first polymer, which may be polysaccharide, as a thickener and a cross linking agent to enhance the viscosity of the fluid by crosslinking the first polymer, wherein the crosslinking agent is a second polymer comprising at least one polymer chain with phenyl boronate groups distributed along the polymer chain and the phenyl boronic acid groups have nitrogen attached to the phenyl group at a position which is meta relative to the boronate group.

Abstract: The disclosed compositions and methods provide a system that is effective for hydraulic fracturing, which can be used to extract natural gas and oil from subterranean formations, such as deep shale and coal bed type rack formations. In a first aspect, the invention features a composition for hydraulic fracturing, which includes a low pH product, a surfactant, and a thickening agent, all in an aqueous composition. The composition includes i) from about 0.01 wt % to about 20.0 wt % of a low pH product that includes an ammonium salt (e.g., ammonium bicarbonate, ammonium carbonate, or ammonium hydroxide) and hydrogen chloride (and optionally a carborane).

Abstract: Fluids including a parylene-coated chemical entity and methods of treating a subterranean formation with such fluids are disclosed. The methods may include introducing a treatment fluid into a subterranean formation, the treatment fluid containing a parylene-coated particle having a chemical entity encapsulated therein.

Abstract: Formulation for a natural product as a replacement for the use of traditional acidic chemical stimulation methods for the emulsification, removal and release of paraffin and asphaltenes from low producing or pumped off wells and reservoirs with the use of traditional methodologies. Also a method of use of formulation for stimulating an oil well consisting of introducing into the wellbore a biodegradable, non-reactive fluid system containing a water-miscible fatty acid solvent, a solution of fatty acids, an amino alcohol, and at least one non-ionic surfactant. The fluid system may be further in the form of a nanoemulsion that is formed by combining a colloidal solution with one or more emulsifiers, an alcohol, and water. The fluid system may be used in well remediation and stimulation as well as additional, alternative applications such as the cleaning of surface and/or downhole equipment.

Abstract: A method for breaking the viscosity of an aqueous fluid gelled with a water soluble polymer or a VES is disclosed. The method includes providing an aqueous fluid. The method also includes adding to the aqueous fluid, in any order: a water soluble polymer in an amount sufficient to form a gelled aqueous fluid having a viscosity, a water soluble oxidizing agent configured to generate free radicals and a plurality of metallic particles to produce a mixture comprising dispersed metallic particles dispersed within the gelled aqueous fluid, the metallic particles configured to dissolve in the gelled aqueous fluid and provide a reducing agent to accelerate the generation of free radicals. The method further 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 accelerate the generation of free radicals and reduce the viscosity.

Abstract: Methods of inhibiting corrosion of a metal surface in a well or pipeline are provided. The methods include the steps of: (a) forming a fluid of: (i) an aqueous acid solution; and (ii) inulin; and (b) introducing the fluid into the well or pipeline. The methods have wide application in various kinds of operations involved in the production or transportation of oil and gas, such as acid stimulation or remedial treatment in a pipeline.

Abstract: A spacer fluid comprising: (a) water; and (b) an alkyl polyglycoside derivative, wherein the alkyl polyglycoside derivative is selected from the group consisting of sorbitan fatty acids; functionalized sulfonates, functionalized betaines, an inorganic salt of any of the foregoing, and any combination of any of the foregoing. Preferably, the spacer fluid additionally comprises a solid particulate, such as a weighting agent. A method of displacing an oil-based drilling mud from a portion of a well comprising the steps of: (A) forming the spacer fluid; and (B) introducing the spacer fluid into the well.

Abstract: A hydraulic fracturing composition includes: a superabsorbent polymer in an expanded state; a plurality of proppant particles disposed in the superabsorbent polymer; a well treatment agent, and a fluid to expand the superabsorbent polymer into the expanded state. A process for treating a well with well treatment agent includes disposing a hydraulic fracturing composition comprising the well treatment agent in a well. The well treatment agent can be a scale inhibitor, tracer, pH buffering agent, or a combination thereof.

Abstract: A method of forming a fracturing fluid including mixing produced water or boron-containing oilfield water having an in-situ boron concentration greater than about 20 mg/L at the time of mixing with a hydratable boron crosslinkable polymer to form a fracturing fluid.

Abstract: Propping compositions comprising: a hardenable, liquid external phase comprising an element selected from the group consisting of: a cement, a cement foam, a polymer, a resin, an aluminum, a flowable carrier fluid, and any combination thereof; and an internal phase that is either gas or liquid and that is immiscible with the external phase; wherein the internal phase exits the propping composition as the hardenable external phase hardens, leaving behind an hardened, interconnected porous network. Some propping compositions may require contact with a treatment for removal from the hardenable external phase and the treatment for removal may comprise at least one material selected from the group consisting of: an acid, a base, a chelant, an oxidizer, a solvent, and any combination thereof.

Abstract: A spacer fluid comprising: (a) water; and (b) an alkyl polyglycoside derivative, wherein the alkyl polyglycoside derivative is selected from the group consisting of sorbitan fatty acids; functionalized sulfonates, functionalized betaines, an inorganic salt of any of the foregoing, and any combination of any of the foregoing. Preferably, the spacer fluid additionally comprises a solid particulate, such as a weighting agent. A method of displacing an oil-based drilling mud from a portion of a well comprising the steps of: (A) forming the spacer fluid; and (B) introducing the spacer fluid into the well.