Abstract: Provided are methods for modifying the permeability of subterranean formations for the purposes of selectively reducing excessive production of water and aqueous fluids in oil and gas wells, wherein the methods utilize an emulsion containing a copolymer, which is typically prepared in an aqueous salt media.

Abstract: A formation treatment fluid may include a wettability alteration agent, a solvent, an injection gas, and an optional foaming agent. The wettability alteration agent may include a fluorinated surfactant, a silicon-based surfactant, charged nanoparticles partially modified with fluorine containing groups, or combinations thereof. Methods for altering a hydrocarbon-bearing reservoir surface wettability may include providing the formation treatment fluid, injecting the formation treatment fluid into the hydrocarbon-bearing reservoir, and recovering fluids produced from the hydrocarbon-bearing reservoir.

Abstract: The present disclosure relates to fracturing fluids that use friction reducers. The composition of the present disclosure is a slurry comprising a water-soluble polymer suspended in an oil-based vehicle with the aid of a suspension agent and a surfactant.

Abstract: Disclosed are compositions and methods for use in oil and gas operations.

Abstract: An acid treatment composition includes a nonionic surfactant, including nonyl phenol ethoxylate. The acid treatment composition also includes a retarding agent comprising magnesium, an acid, and water. The nonionic surfactant and retarding agent of the acid treatment composition are reactive with carbonate.

Abstract: A method of stimulating a hydrocarbon-bearing formation may include generating a foamed fracturing fluid having a half-life of 160 to 300 min at 77° F. The foamed fracturing fluid may comprise a fluorosurfactant, a nanoparticle, and a gas phase. The method may then include introducing the foamed fracturing fluid into a hydrocarbon-bearing formation under a pressure greater than the fracturing pressure of the hydrocarbon-bearing formation to generate fractures in the hydrocarbon-bearing formation. Another method of stimulating a hydrocarbon-bearing formation may include introducing a foaming composition into the hydrocarbon-bearing formation under a pressure greater than fracturing pressure of the hydrocarbon-bearing formation to generate fractures in the hydrocarbon-bearing formation. The foaming composition may include a fluorosurfactant, a nanoparticle, and a gas phase. The method then may include generating a foam from the foaming composition inside the hydrocarbon-bearing formation.

Abstract: A method for enhancing recovery of hydrocarbons from a hydrocarbon-bearing subterranean formation includes withdrawing hydrocarbons from a production well and injecting a treatment fluid that includes carbon nanodots dispersed in a brine solution from an injection well that is spaced apart from the production well. The carbon nanodots include carbon, oxygen, nitrogen, and hydrogen and are surface functionalized. A concentration of carbon nanodots in the treatment fluid is less than or equal to 500 parts per million by weight. Injection of the treatment fluid having the carbon nanodots is characterized by an injection duration, an injection pressure, an injection volume, or a combination thereof, that is sufficient to increase cumulative oil recovery of hydrocarbons from the first subterranean formation, the second subterranean formation, or both by at least 10% compared to injecting the brine solution without the carbon nanodots.

Abstract: Hybrid fracturing fluids for treating subterranean formations are provided. An exemplary hybrid fracturing fluid includes a mixture of an aqueous copolymer composition including a crosslinkable polymer (CLP), the CLP including crosslinking sites. The mixture also includes a crosslinker for the crosslinking sites, and a friction reducing polymer (FRP).

Abstract: Disclosed are compositions and methods for use in oil and gas operations.

Abstract: A composition for preparing an injection fluid in oil and gas recovery comprising an inverse emulsion of a water-soluble polymer A comprising cationic monomer units, and solid particles of a water-soluble polymer B comprising cationic monomer units, and wherein water-soluble polymer A comprises between 10 and 40 mol % of a cationic monomer units based on the total amount of monomer units; and wherein the cationicity in mol % of polymer A is superior or equal to the cationicity in mol % of polymer B. Method of treating a portion of subterranean formation comprising providing said composition, preparing an injection fluid with at least said composition, introducing the injection fluid into portion of the subterranean formation. The composition is particularly useful to prepare fracturing fluid in fracturing operations.

Abstract: Methods of temporarily blocking zones of a subterranean formation for diversion, isolation, and fluid-loss control are provided. The method of diverting a fluid includes introducing a treatment fluid comprising a formate brine, xanthan gum, and a cross-linking agent into the formation; allowing the treatment fluid to set into a gel in perforations in a first zone of the formation to block the perforations in the first zone; introducing a stimulation fluid into the formation; and diverting the stimulation fluid away from the perforations in the first zone to perforations in a second zone of the formation.

Abstract: A barite filter cake removing composition, and single- and multi-stage methods of removing a barite filter cake from a wellbore. The composition comprises at least one polymer removal agent, at least one chelating agent, and at least one converting agent. The single-stage method includes contacting the barite filter cake with the composition to dissolve the barite filter cake from the wellbore. The multi-stage method includes contacting the barite filter cake from the wellbore with at least one polymer removal agent to remove a polymer coat present on the barite filter cake, contacting the barite filter cake with at least one converting agent to convert barium sulfate in the barite filter cake to a barium salt of carbonate, formate, cyanide, nitrate, and/or chloride, and removing the barium salt of carbonate, formate, cyanide, nitrate, and/or chloride with at least one chelating agent.

Abstract: A method comprises obtaining or providing a treatment fluid comprising a gellable agent; an aqueous carrier fluid; at least one polymer comprising one or more ortho-dioxy arylene units; a crosslinking agent; and placing the treatment fluid in a subterranean formation. In some embodiments, the aqueous carrier fluid comprises produced and/or flowback water. In some embodiments, the aqueous carrier fluid comprises high total dissolved solids, including multivalent salts or both monovalent and multivalent salts.

Abstract: A barite filter cake removing composition, and single- and multi-stage methods of removing a barite filter cake from a wellbore. The composition comprises at least one polymer removal agent, at least one chelating agent, and at least one converting agent. The single-stage method includes contacting the barite filter cake with the composition to dissolve the barite filter cake from the wellbore. The multi-stage method includes contacting the barite filter cake from the wellbore with at least one polymer removal agent to remove a polymer coat present on the barite filter cake, contacting the barite filter cake with at least one converting agent to convert barium sulfate in the barite filter cake to a barium salt of carbonate, formate, cyanide, nitrate, and/or chloride, and removing the barium salt of carbonate, formate, cyanide, nitrate, and/or chloride with at least one chelating agent.

Abstract: A well treatment method includes forming a well treatment fluid by combining ingredients including a polymer, a crosslinker, an acidifying substance, and a base fluid. Crosslinking increases viscosity of the fluid during a development time. A pH decrease is controlled during the development time using the acidifying substance. The method also includes delaying the development time of the viscosity increase by controlling the pH decrease. A well treatment method includes forming a well treatment fluid by combining ingredients including a hydratable polymer, a crosslinker, an acidifying substance, and a base fluid. The method includes delaying development time of a viscosity increase by controlling a pH decrease without adding further acidifying substance after combining the polymer, crosslinker, acidifying substance, and base fluid. A well treatment fluid formulated with ingredients include a base fluid, a polymer, a crosslinker, and an acidifying substance.

Abstract: Incorporating at least oil-soluble organic peroxide into a mixture of an aqueous phase and at least one surfactant creates a breaker fluid that is a microemulsion or a nanoemulsion that can then perform as an internal breaker for reducing the viscosity of aqueous fluids gelled with a polymer, such as a crosslinked polysaccharide. One phase of the breaker fluid is water or water-based, e.g. brine, containing at least one oil-soluble organic peroxide as a non-aqueous internal phase that will, over time and optionally with heat, break the polymer-gelled portion of the gel. The overall breaking using the breaker fluid is slower as compared to introducing the organic peroxide breaker in a non-microemulsified or non-nanoemulsified form.

Abstract: The present invention relates to a process for preparing control agents for applications in the petroleum field, where a polymer bearing —OH, amine and/or amide functions, which is in the form of a divided solid, is reacted with at least one crosslinking agent bearing at least two —R groups capable of reacting with the —OH, amine or amide groups, under conditions where said polymer remains in solid form and where said crosslinking agent is at least partly in vapour form, The invention also relates to the control agents obtained in solid form according to this process, and also to the mixtures of these solid agents with other additives, which can be used in particular for the preparation of cement grout for oil extraction.

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: Embodiments of the invention provide a drilling, drill-in, and completion water-based mud composition containing micro or nanoparticles for use in hydrocarbon drilling. The water-based drilling mud composition includes water present in an amount sufficient to maintain flowability of the water-based drilling mud composition, and drilling mud, which includes particles. The particles are selected from microparticles, nanoparticles, and combinations thereof. The water-based drilling mud composition also includes an effective amount of a multi-functional mud additive, which includes psyllium seed husk powder. The water-based drilling mud composition is operable to keep the particles stabilized and dispersed throughout the drilling mud composition in the absence of a surfactant.

Abstract: The present invention relates to a foam containing water, between 5 and 30 wt % on total weight of the foam of a chelating agent selected from the group of glutamic aid N,N-diacetic acid or a salt thereof (GLDA), aspartic acid N,N-diacetic acid or a salt thereof (ASDA), methylglycine N,N-diacetic acid or a salt thereof (MGDA), N-hydroxyethyl ethylenediamine-N,N?,N?-triacetic acid or a salt thereof (HEDTA), a foaming agent, and at least 25 vol % on total volume of the foam of a gas, and having a pH of between 2 and 5, to a viscosified composition containing water, between 5 and 30 wt % on total volume of the composition of a chelating agent selected from the group of glutamic aid N,N-diacetic acid or a salt thereof (GLDA), aspartic acid N,N-diacetic acid or a salt thereof (ASDA), methylglycine N,N-diacetic acid or a salt thereof (MGDA), N-hydroxyethyl ethylenediamine-N,N?,N?-triacetic acid or a salt thereof (HEDTA), and at least 0.

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: Improved hydraulic fracturing compositions are disclosed which help reduce potential negative environmental impact by hydraulic fracturing. The disclosed compositions have flammability and toxicity and are relatively safe for the environment. The compositions may also contain biodegradable components.

Abstract: Charged nanoparticles may be added to an aqueous downhole fluid having polymers therein where the charged nanoparticles may crosslink at least a portion of the polymers. The polymers may be or include, but are not limited to polyacrylamide, xanthan, guar, polyacrylic acid, poly 2-acrylamido-2-methyl-1-propane sulfonic acid (AMPS), polyethylene oxide, polypropylene oxide, or combinations thereof. The polymers may be homopolymers, copolymers, terpolymers, or combinations thereof. The charged nanoparticles may be or include, but are not limited to clay nanoparticles, modified nanoparticles, or combinations thereof. The aqueous downhole fluid may be or include, but is not limited to fracturing fluids, injection fluids, and combinations thereof for performing a fracturing operation, an injection operation, another enhanced oil recovery operation, and the like.

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 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 provides a wellbore fluid, such as a drilling, completion or workover fluid, said wellbore fluid comprising a glucomannan additive. Further provided is a method of forming a gel plug from the wellbore fluid, a method of modifying the properties of a wellbore fluid, a method of drilling a subterranean hole with such a fluid and the use of glucomannan in wellbore fluids.

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 of preparing and using a drag-reducing composition in a well treatment operation includes the step of preparing the drag-reducing composition by mixing a polymer emulsion that includes a first surfactant and a first solvent, with a second surfactant and a second solvent. The method continues with the step of combining the drag-reducing composition with an aqueous treatment fluid. The method further includes the step of injecting the drag-reducing composition and aqueous treatment fluid into a subterranean formation, a pipeline or a gathering line.

Abstract: Various embodiments disclosed relate to acidizing compositions including an ampholyte polymer. Various embodiments provide a method of treating a subterranean formation. The method can include placing in a subterranean formation an ampholyte polymer including an ethylene repeating unit including a —C(O)NH2 group, an ethylene repeating unit including an —S(O)2OR1 group, and an ethylene repeating unit including an —N+R23X? group. At each occurrence, R1 can be independently selected from the group consisting of —H and a counterion. At each occurrence, R2 can be independently substituted or unsubstituted (C1-C20)hydrocarbyl. At each occurrence, X? can be independently a counterion.

Abstract: Various embodiments disclosed relate to a composition including a crosslinkable ampholyte polymer or a crosslinked product of the same, methods of making and using the composition, and systems including the composition. In various embodiments, the present invention provides a method of treating a subterranean formation. The method can include obtaining or providing a composition including a crosslinkable ampholyte polymer. The crosslinkable ampholyte polymer can include an ethylene repeating unit including a —C(O)NH2 group, an ethylene repeating unit including a —S(O)2OR1 group, and an ethylene repeating unit comprising an —N+R23X? group. At each occurrence, R1 can be independently selected from the group consisting of —H and a counterion. At each occurrence, R2 can be independently substituted or unsubstituted (C1-C20)hydrocarbyl. At each occurrence, X? can be independently a counterion. The composition can also include at least one crosslinker.

Abstract: Reduction of the water permeability within a subterranean formation, particularly within a proppant pack or a gravel pack, can be achieved through the use of a relative permeability modifier (RPM) coated on a particulate material. Methods for reducing the water permeability include providing RPM-coated particulates that contain a RPM coating on the particulates, and placing a treatment fluid containing a base fluid and the RPM-coated particulates in at least a portion of a subterranean formation. The treatment fluid can also contain a companion polymer that serves to further reduce the water permeability compared to that achievable when using the RPM alone.

Abstract: Methods of treating a subterranean formation including providing a treatment fluid comprising an aqueous base fluid and a friction reducing agent, wherein the friction reducing agent is a biosynthetic polysaccharide produced by a host cell line with DNA encoding the biosynthetic polysaccharide; and introducing the treatment fluid into the subterranean formation.

Abstract: Of the many compositions and methods provided herein, one method includes contacting tar resident in a well bore with a tar stabilizer comprising an acrylonitrile-butadiene copolymer; and allowing the tar stabilizer to interact with the tar to at least partially reduce the tendency of the tar to adhere to a surface.

Abstract: Hydrophilic polymer particles have been obtained using polyacrylamide, xanthane, maleic anhydride polymers, allylamine, ethyleneimine, and oxazoline as core polymers. Then, hydrophobic polymers shells have been produced on the core-side using styrene, styrene copolymers, polyvinyl state, polysolfune, polymethyl methacrylate, and polycyclohxyl methacrylate by in-situ polymerization of monomer as method one and inverse emulsion process as method two. These particles can release hydrophilic polymers at oil-water interface at the reservoir temperature where the water flooding should have the maximum viscosity. So, active materials cause to decrease the mobility ratio of water to oil in the reservoirs and on the other hand, plug the swept porosities and prevent to act the water fingering process.

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: 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: The present invention relates to the preparation of foaming formulations for high temperature, salinity and concentration of divalent ions, such as Calcium and Magnesium, that apply the synergistic effect of sodium alpha olefin sulfonates and alkyl amido propyl betaines; said inventions may use, as solvent, water, sea water, connate water, alcohols or mixtures all thereof. Said formulations control the piping of gas in reservoirs of the naturally fractured carbonate type.

Abstract: Crosslinked gelling agents employed during subterranean operations use electronically-modified boronic acids to enable higher operating temperatures while allowing reduced gelling agent loadings; the boronic acids having Formula I: X1 and X2 are independently selected from O, CH2, CH2O, OCH2, bond, and null, Y1 and Y2 are independently N or C, Ar is a 5- or 6-membered ring aryl or heteroaryl group with a link L to monomer unit M1, m is 1 or 2, n is 0, 1, 2, or 3, and each Z is independently an electron withdrawing group selected from nitro, ester, carboxylic acids, carboxylates, halogen, cyano, amide, acyl, alkylsulfonyl, arylsulfonyl, heteroarylsulfonyl, CF3, a quaternary ammonium salt, polyhaloalkyl, and carbamate, with the proviso that when n is 0, the link L between M1 and Ar includes an electron withdrawing group attached to Ar, and introducing the treatment fluids into subterranean formations.

Abstract: Disclosed are treating fluid compositions for use in subterranean workover and hydrocarbon recovery operations, as well as methods of treating subterranean formations penetrated by a wellbore utilizing the treating fluid. The treating fluid compositions contain a first, aqueous liquid, and a crosslinkable organic polymer that is at least partly soluble in the liquid. The treating fluid further contains a borate crosslinking agent solution containing a primary, un-refined borate and a secondary, refined borate, the borate solution being present as a crosslinking agent upon addition to the first fluid admixture so as to crosslink the organic polymer and increase the viscosity and/or accelerate the crosslink time of the treating fluid.

Abstract: A sparingly soluble sulfonate-metal salt particle includes the metal ion salt of an alkyl aryl sulfonate, the metal ion salt of a petroleum sulfonate and a hydrophobically modified hydrophilic polymer, and has an average particle size diameter in a range of from about 50 nm to about 450 nm and is sparingly soluble in water at room temperature. A method of producing a sparingly soluble sulfonate-metal salt particle includes the steps of introducing an aqueous solution containing a metal ion salt into a reactor, introducing an aqueous solution containing a sulfonate surfactant and a polymer into the reactor, and operating the reactor such that the sparingly soluble sulfonate-metal salt particle forms from the interaction of the metal ion from the salt, the sulfonate surfactant and the polymer.

Abstract: A method of servicing a wellbore comprising placing a wellbore servicing fluid comprising a modified friction reducer into the wellbore. A modified friction reducer comprising a degradable polymer having functional degradable moieties, a polymer having a molecular weight of from about 5M to about 30M, a polymer having a PDI of from about 1.0 to about 2.5, a weakly crosslinked polymer, or combinations thereof.

Abstract: A thickened composition comprising a polymer, a divalent ions source, water and cement is disclosed. Such composition enables fluid loss reduction and higher gel strength. This may be useful for treating a well for example as a fluid spacer or a scavenger; this may also be used a hydraulic fracturing fluid.

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: 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: Provided is a method and composition for the in-situ generation of synthetic sweet spots in tight-gas formations. The composition can include nitrogen generating compounds, which upon activation, react to generate heat and nitrogen gas.

Abstract: Provided is a method and composition for the in-situ generation of synthetic sweet spots in tight-gas formations. The composition can include nitrogen generating compounds, which upon activation, react to generate heat and nitrogen gas. The method of using the composition includes injecting the composition into a tight-gas formation such that upon activation, heat and nitrogen gas are generated. Upon the generation of nitrogen gas and heat within the formation, microfractures are produced within the formation and the hydrostatic pressure within the reservoir is reduced to less than the reservoir fluid pressure, such that the rate of production of hydrocarbons from the formation is increased.

Abstract: A composition for treating a portion of a wellbore or a portion of a subterranean formation is provided, the composition comprising: (a) water; (b) a source of hydrogen peroxide, and (c) an activator for the source of hydrogen peroxide; wherein the pH of the composition is adjusted to be within an appropriate range for the type of activator. A method for treating a portion of a wellbore or a portion of a subterranean formation, the method comprising the steps of: forming or providing a composition comprising: (a) water; (b) a source of hydrogen peroxide, and (c) an activator for the source of hydrogen peroxide; wherein the pH of the composition is adjusted within an appropriate range for the type of activator; and introducing the composition through a wellbore to treat a portion of a wellbore or a portion of a subterranean formation. The activator can be a water-soluble alkanoyl-donor compound or a chelated transition metal. Preferably, the composition further comprises an iron chelating agent.

Abstract: Methods that comprise selecting proppant for use in a fracturing fluid based on one or more factors, wherein the one or more factors comprise an interaction between the proppant and the fracturing fluid. Methods that comprise designing a treatment fluid that comprises a gelled base fluid and a particulate based on one or more factors, wherein the one or more factors comprise an interaction between the particulate and the gelled base fluid.

Abstract: A treatment fluid for treating a subterranean formation penetrated by a wellbore is formed from an aqueous medium, a diutan heteropolysaccharide having a tetrasaccharide repeating unit in the polymer backbone and a peroxide breaker. A method of treating a subterranean formation penetrated by a wellbore may be carried out by introducing the treatment fluid into the formation through the wellbore. Breaking aids or catalysts may also be used with the treatment fluid.

Abstract: A method of treating a subterranean formation with a xanthan-viscosified cesium formate brine wherein the pH and/or another characteristic selected from density, xanthan loading, sodium formate loading, potassium formate loading and combinations thereof are modified to delay solid hydrogel formation and maintain pumpability. Also disclosed is a method of delaying onset of solid hydrogel formation, in a gel comprising cesium formate brine viscosified with xanthan polymer, comprises introducing acid into the brine in an amount effective for a pH from 7 to 11, wherein the acid introduction is before, during or after xanthan viscosification and prior to hydrogel formation, wherein the hydrogel formation in the acidified gel occurs at a later time relative to the same gel at a natural pH.