Abstract: A well tool device for transporting a heat generating mixture into a well pipe includes an upper connection section, a main housing section, and an anchoring device. The main housing section includes a compartment for the heat generating mixture. The anchoring device is connected between the upper connection section and the main housing section. The main housing section includes a compartment subsection and a distance subsection. The compartment is located within the compartment subsection. The distance subsection is located above the compartment subsection.

Abstract: A hydraulic fracturing fluid and methods for using the hydraulic fracturing fluid fracturing a formation are provided. An exemplary hydraulic fracturing fluid includes a polymer additive, a breaker, a non-ionic surfactant. The hydraulic fracturing fluid also includes an amphoteric surfactant, or a cationic surfactant, or both, and a base fluid.

Abstract: The present invention generally relates to improved catalysts that provide for reduced product contaminants, related methods and improved reaction products. It more specifically relates to improved direct fuel production and redox catalysts that provide for reduced levels of certain oxygenated contaminants, methods related to the use of those catalysts, and hydrocarbon fuel or fuel-related products that have improved characteristics. In one aspect, the present invention is directed to a method of converting one or more carbon-containing feedstocks into one or more hydrocarbon liquid fuels. The method includes the steps of: converting the one or more carbon-containing feedstocks into syngas; and, converting the syngas to one or more hydrocarbons (including liquid fuels) and a water fraction. The water fraction comprises less than 500 ppm of one or more carboxylic acids.

Abstract: Provided in the present invention are a pH-responsive nano-gel plugging material, and a preparation method therefor and the use thereof. The pH-responsive nano-gel plugging material comprises the following raw materials in parts by mass: 50-70 parts of water, 2-3 parts of an emulsifier, 25-35 parts of an acrylic terpolymer, 10-15 parts of a polyalcohol compound, and 10-20 parts of a vinyl pyridine compound. The pH-responsive nano-gel plugging material can be applied to the plugging of Ordovician carbonate rock fractures and micro-karst cave strata, and can automatically identify Ordovician carbonate rock fractures and micro-karst cave leaking layers and realize effective blocking thereof.

Abstract: Compositions containing a diverting material, and related methods and systems for diverting a fluid from a high permeability zone in an underground formation to a low permeability zone in the underground formation. The diverter material contains a polyurethane and a second polymer. The compositions, methods and systems may be used to achieve more homogeneous stimulation during a well stimulation treatment.

Abstract: A composition for fracturing a wellbore may include a reacting fluid. The reacting fluid includes an encapsulated breaker, sodium nitrite, and an ammonium-comprising compound. The sodium nitrite and the ammonium-comprising compound undergo an exothermic reaction producing heat operable to release the encapsulated breaker, releasing the breaker that then reduces viscosity in the polymer-comprising fluid. A method for fracturing a wellbore may include injecting into a fractured wellbore a fluid comprising an ammonium-comprising compound and a fluid comprising sodium nitrite. The fractured wellbore has been fractured with a fracturing fluid comprising an encapsulated breaker. Sodium nitrite and the ammonium-comprising compound undergo an exothermic chemical reaction that generates heat to release the encapsulated breaker.

Abstract: A method includes disposing a device into a borehole in proximity to a subterranean formation where a filter cake has been formed adjacent thereto, the device comprising a support structure and a shape-memory article disposed at the support structure, the shape-memory article comprising a shape-memory polymer, wherein the device is disposed when the shape-memory article is in a compacted shape; exposing the shape-memory article to a fluid system to cause the shape-memory article to expand and conform to a surface of the borehole; exposing the filter cake to the fluid system; and removing the filter cake with the fluid system. The fluid system comprises a chelating agent, an activator, a non-emulsifier, and water or a brine.

Abstract: Provided are wellbore treatment fluids and methods to introduce these treatment fluids in a subterranean formation. The treatment fluids include a diverter material and an aqueous carrier fluid. Further, the diverter material comprises a composite material of a polyvinyl alcohol and a plasticizer. The diverter material includes particles having a particle size distribution of about 2 to about 10 U.S. mesh and an aspect ratio of 20:1 or less. The treatment fluid is introduced into a permeable zone of a subterranean formation, wherein the permeable zone is part of a wellbore that is permeated or penetrated by fractures and fissures. The diverter material diverts at least partially the treatment fluid to a different portion of the subterranean formation.

Abstract: The disclosure is directed to a process for treating a subterranean earth formation by introducing a monovalent salt of monochloroacetic acid into said subterranean earth formation in the presence of a chelating agent which comprises at least one carboxylate group having a monovalent counterion and furthermore comprises a carbon chain carrying at least five hydroxyl groups. Preferably the cation of the monovalent salt of monochloroacetic acid is sodium.

Abstract: A solids-control fluid for controlling flow of solids in a subterranean formation is disclosed herein. The solids-control fluid can include a diluent and a curable resin. The diluent can include a mutual solvent and an ethylene glycol. The curable resin can be dispersed within the diluent for controlling flow of solids in the subterranean formation.

Abstract: A coiled tubing wellbore fluid may include a base fluid; and a crosslinked and branched polymeric fluid loss control agent formed from at least an acrylamide monomer and a sulfonated anionic monomer; wherein the coiled tubing wellbore fluid has a low shear rate viscosity, measured at 120° F. at 3 rpm, of at least 20,000 centipoise.

Abstract: A downhole treatment system, apparatus, and methods are disclosed. In some embodiments a treatment apparatus includes a first conduit configured to transport a first fluid from a first fluid source through a first enclosed channel to a first outlet. A second conduit is configured to transport a second fluid from a second fluid source through a second enclosed channel to a second outlet. The treatment apparatus further comprises a mixing applicator that includes the first outlet positioned to provide a discharge path for the first fluid that at least partially intersects a flow path of the second fluid within a confluence region within or external to the second conduit.

Abstract: A method for generating microfractures in low carbonate mineral content shale reservoirs in which sulfate acid or persulfate compound (such as ammonium persulfate ((NH4)2S2O8)) injected into conventional fracturing fluid can react with shale carbonate components resulting in the precipitation reaction of gypsum crystal (CaSO4·2H2O) to occur.

Abstract: Methods of capturing carbon dioxide in a wellbore can include installing a sealing element in the wellbore. The sealing element swells in the presence of carbon dioxide and can be used for capturing the carbon. The sealing element can include a carbon-swelling material, such as a carbon-swelling polymers, metal-based materials, or combinations of elastomeric polymers and metal-based materials. The sealing element can also include combinations of different carbon-swelling materials, fillers or other compounds, and materials that are not carbon swellable. The sealing element can create a seal, form an anchor, or create a seal and form an anchor in the wellbore after swelling.

Abstract: Disclosed is a temperature stabilized aqueous wettability composition and method of use for the recovery of petroleum from subterranean formulations. Said aqueous wettability composition comprises a polyethylene oxide nonionic surfactant, a disulfonated anionic surfactant, and one or more alcohol.

Abstract: A method is provided including: introducing a first diverter material comprising polyvinyl alcohol and a plasticizer into or adjacent to a permeable zone of a subterranean formation; introducing a second diverter material into or adjacent to the permeable zone of the subterranean formation, wherein at least a portion of the first diverter material comprises particles larger than particles of the second diverter material; and allowing the first diverter material and the second diverter material to at least partially divert at least a portion of a treatment fluid to a different portion of the subterranean formation.

Abstract: A method of making a proppant-gel matrix comprising: a) hydrating a gelling agent to form a hydrated gelling agent; b) adding a basic compound to the hydrated gelling agent to form a basic hydrated gelling agent having a pH in the range of 11.5 to 14.0; c) mixing the basic hydrated gelling agent and a proppant to form a basic hydrated gelling system; and d) adding a crosslinking agent to the basic hydrated gelling system to form the proppant-gel matrix, is disclosed. The proppant-gel matrix can then be used as a fracturing fluid in a hydraulic fracturing process.

Abstract: A method for generating hydrofluoric acid (HF) in-situ in a subterranean formation (e.g. sandstone formation) by simultaneously injecting an acid generating component having ammonium fluoride and an oxidizing agent and a heat generating component having ammonium and nitrite salts into a wellbore of the formation. The method optionally involves a pre-flush of an acid (e.g. HCl) containing solution prior to the injecting. HF is generated via an endothermic reaction of the ammonium fluoride and the oxidizing agent with the assistance of the heat provided by an exothermic reaction of the ammonium and nitrite salts. The method is effective in enhancing permeability of the formation by at least 30%.

Abstract: Methods of treating a subterranean formation include forming a treatment fluid including a hydrophilic fiber coated with a water soluble polymer and a crosslinking agent.

Abstract: An encapsulated reactant(s) having at least one encapsulant and at least one reactant, and methods of making and using the encapsulated reactant(s), are is presently provided. 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.

Abstract: A well cleanup process involves removing an impermeable filter cake from a formation face with thermochemical and chelating agents to allow formation fluids to flow from a reservoir to a wellbore. The method may be used with oil and water-based drilling fluids with varied weighting agents, e.g., bentonite, calcium carbonate, or barite. Such thermochemical agents may involve two salts, e.g., NO2? and NH4+, which, when mixed together, can generate pressure and heat, in addition to hot H2O and/or N2. For example, the thermochemical agents may comprise Na+, K+, Li+, Cs+, Mg2+, Ca2+, and/or Ba2+ with NO2? and NH4+ with F?, Cl?, Br?, I?, CO32?, NO3?, ClO4?, and/or ?OH.

Abstract: The present disclosure provides methods, compositions, and systems directed to filter cake removal embodying a delayed breaker fluid for oil-based drill-in fluids. A wellbore treatment method comprising: introducing a delayed breaker fluid into a wellbore, wherein the delayed breaker fluid comprises an aqueous base fluid, an acid precursor, and a carbodiimide; and contacting a filter cake in the wellbore with the delayed breaker fluid such that the filter cake is at least partially degraded by acid released from the acid precursor.

Abstract: An acidizing and formation stabilizing treatment fluid for stabilizing a fracture in a subterranean formation. An acid generating agent generates an acid in situ to acidize the formation thereby enhancing the fractures within and to cure an acid-catalyzed, curable resin to stabilize the formation.

Abstract: Treatment fluid compositions that include a carrier fluid, a crosslinkable polymer, one or more degradable fibers grafted with a crosslinking moiety capable of crosslinking the crosslinkable polymer, and optionally a proppant or gravel. Methods and systems for treating a subterranean wellbore or formation using the grafted degradable fiber treatment fluids are further provided. The presently disclosed treatment fluids may be suitable for use as hydraulic fracturing treatment fluids, gravel packing treatment fluids, or fluid diversion treatment fluids.

Abstract: Methods, systems, and compositions for increasing hydrocarbon production from a wellbore where the wellbore or a nearby hydrocarbon reservoir is suffering from water blockage, one method including identifying water blockage in a rock sample of a formation via increased capillary pressure in the rock sample; formulating an exothermic reaction component to remove water blockage from a reservoir rock in situ via heat and pressure release, the reservoir rock type the same as the rock sample; injecting the exothermic reaction component into the wellbore; and allowing the exothermic reaction component to react to remove water blockage in situ to decrease capillary pressure of the reservoir rock without substantially changing porosity of the reservoir rock.

Abstract: Methods and compositions for stimulating oil or gas production from a well with a single treatment fluid for use in a combined acidizing and hydraulic fracturing treatment are provided. An embodiment is a method comprising: coating a plurality of proppant particulates with oil to form oil-coated proppant particulates; adding the oil-coated proppant particulates to a solution comprising water, an acid source, and an emulsifier, wherein the ratio of the oil coating the proppant particulates to the water in the solution is less than 20:80 by volume; and mixing the solution and the oil-coated proppant particulates to form a treatment fluid comprising a water-in-oil emulsion and the oil-coated proppant particulates.

Abstract: A non-explosive downhole tool for creating openings in tubulars and or earthen formations includes a carrier holding a non-explosive material, such as thermate, a head connected with the carrier and having a port to eject a product of the ignited material from the head and a communication path extending from the material to the port and a moveable member in a closed position blocking the communication path and in an open position opening the communication path.

Abstract: The blocked isocyanate is a blocked isocyanate containing a latent isocyanate group, which is an isocyanate group blocked with a blocking agent, wherein the blocked isocyanate includes a first latent isocyanate group that is an isocyanate group blocked with a first blocking agent and a second latent isocyanate group that is an isocyanate group blocked with a second blocking agent; and the first blocking agent is represented by general formula (1) below, and has a higher catalysis activity that activates the isocyanate group than that of the second blocking agent. (where R1 to R3 represent a hydrocarbon group having 1 to 12 carbon atoms or a hydrogen atom, and at least one of R1 to R3 represents a hydrogen atom, and R1 and R3 may be bonded to each other to form a heterocycle.

Abstract: Methods of generating oligosaccharides are provided.

Abstract: Treatment fluids including a base fluid; and fly ash microspheres, wherein the fly ash microspheres are of a material selected from the group consisting of Class C fly ash, Class F fly ash, and any combination thereof, wherein the fly ash microspheres have a diameter in the range of from about 0.1??? to about 150???, and wherein the fly ash microspheres are present in the treatment fluid in an amount in the range of from about 0.001 ppg to about 1 ppg of the treatment fluid.

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: Provided is a method and composition for the in-situ generation of synthetic sweet spots in tight-gas formations. The composition can include gas generating compounds, which upon activation, exothermically react to generate heat and gas. The method of using the composition includes injecting the composition into a tight-gas formation such that upon activation, the heat and gas are generated, resulting in the formation of fractures and microfractures within the formation.

Abstract: A variety of methods and compositions are disclosed, including, in one embodiment, a method of inhibiting corrosion of a metal surface in a wellbore, comprising: providing a treatment fluid comprising a corrosion inhibitor, wherein the corrosion inhibitor comprises berberine; and introducing the treatment fluid into a wellbore.

Abstract: A method of treating a subterranean formation penetrated by a wellbore, comprising introducing a chemical packer composition into the wellbore, wherein the chemical packer composition comprises water, a suspending agent, a gelling agent, and a sealant composition and wherein the chemical packer composition has a pH greater than 9, and allowing the chemical packer composition to form a plug, wherein a portion of the wellbore below the plug is isolated from fluid communication with a portion of the wellbore above the plug.

Abstract: A method of controlling deposit buildup comprises generating a gas by reacting an active material in a gas generating element with a fluid that contacts the gas generating element; and controlling deposit buildup with the generated gas.

Abstract: Certain foamed gel treatment fluids and methods of using the treatment fluids in wellbores penetrating subterranean formations are provided. In one embodiment, the treatment fluids comprise: an aqueous base fluid, a gas, a plurality of particulates, and a plurality of swellable particles each comprising a material having a first monomer, a second monomer, and a third monomer comprising a foamable surfactant. In one embodiment, the methods comprise: preparing a treatment fluid comprising an aqueous base fluid and a swellable particle that comprises a material having a first monomer, a second monomer, and a third monomer comprising a foamable surfactant; blending the treatment fluid with a gas to form a foamed gel; and introducing the foamed gel into a wellbore penetrating at least a portion of a subterranean formation.

Abstract: Alkyl ester spotting fluid compositions and processes for freeing differentially stuck pipe are provided. An alkyl ester spotting fluid composition includes an invert emulsion having an alkyl ester as the external phase and water as the internal phase. In some embodiments, the alkyl ester spotting fluid composition may include the alkyl ester invert emulsion and an emulsifier. The alkyl ester spotting fluid composition may be introduced downhole in the vicinity of a portion of a differentially stuck pipe such that the spotting fluid composition contacts the mudcake and frees the differentially stuck pipe.

Abstract: Alkyl ester spotting fluid compositions and processes for freeing differentially stuck pipe are provided. An alkyl ester spotting fluid composition includes an invert emulsion having an alkyl ester as the external phase and water as the internal phase. In some embodiments, the alkyl ester spotting fluid composition may include the alkyl ester invert emulsion and an emulsifier. The alkyl ester spotting fluid composition may be introduced downhole in the vicinity of a portion of a differentially stuck pipe such that the spotting fluid composition contacts the mudcake and frees the differentially stuck pipe.

Abstract: A weighted acid composition comprising an acid, a brine, and an amino acid and associated methods.

Abstract: A fracturing fluid including a mixture of an aqueous terpolymer composition including a terpolymer, an additive, and crosslinker. The terpolymer includes 2-acrylamido-2-methylpropanesulfonic acid, acrylamide, and acrylic acid monomer units, or a salt thereof. The additive includes a sugar alcohol or a derivative thereof, and the crosslinker includes a metal. The weight ratio of the metal to the terpolymer is in a range of 0.01 to 0.16, and a concentration of the additive is in a range of 0.001 wt. % to 10 wt. % of the fracturing fluid. Treating a subterranean formation includes introducing the fracturing fluid into a subterranean formation, and crosslinking the fracturing fluid in the subterranean formation to yield a crosslinked fracturing fluid. The crosslinked fracturing fluid mitigates damage caused by substantial amounts of total dissolved solids or significant water hardness.

Abstract: The present application provides a gas-generating aqueous fluid containing a gas-generating compound like an azo compound, and an organic amine like a primary, secondary or tertiary amine, a hydrazine, a hydrazide, or a semicarbazide. The aqueous fluid may also a viscosifier, and a foaming surfactant. The present application also provides a method of using the gas-generating composition to modulate density of a wellbore fluid for use in downhole applications. The method optionally includes adding an oxidizer to the wellbore fluid.

Abstract: Compositions including modified release material for treatment of subterranean formations are provided. Also provided is a method of treating a subterranean formation including placing in the subterranean formation a composition including a modified release material. The modified release material can include an additive and a solid substituted or unsubstituted fatty acid having a melting point of about 30° C. to about 250° C., wherein the additive is partially or wholly enveloped by the fatty acid.

Abstract: A weighted acid composition comprising an acid, a brine, and an amino acid and associated methods.

Abstract: An encapsulated agent includes a central part and an outer part that covers a surface of the central part. The central part contains a viscosity-reducing material that reduces viscosity of a fluid to be used in a hydrofracturing technique. The outer part contains a plurality of particulate substances and a holding material that holds the plurality of particulate substances and enables gradual release of the central part in the fluid. The outer part involves distribution of the plurality of particulate substances that allows a content to have one or more local maxima in a direction away from the central part.

Abstract: Methods and compositions for gravel packing a wellbore penetrating a subterranean formation are described. The methods include providing a gravel packing fluid and contacting the subterranean formation with the gravel packing fluid so as to place a gravel pack in or near a portion of the subterranean formation. The gravel packing fluid includes a particulate agent and hydroxypropyl starch phosphate.

Abstract: A method of time delayed reduction in the molecular weight of polymers in a viscosified fluid and a method of time delayed breaking of viscosified fluids through treatment of the viscosified fluid with a viscosity breaking composition. The viscosity breaking composition is formed from a peroxygen compound, a peroxygen inhibiting agent and a peroxygen catalyzing agent, where the relative concentration of the components determines the duration of the a time interval require for breaking the viscosified fluid.

Abstract: A non-explosive downhole tool for creating openings in tubulars and or earthen formations includes a carrier holding a non-explosive material, such as thermate, a head connected with the carrier and having a port to eject a product of the ignited material from the head and a communication path extending from the material to the port and a moveable member in a closed position blocking the communication path and in an open position opening the communication path.

Abstract: Crosslinked polymers that may be useful, for example, as viscosifiers or fluid-loss control additives for well treatment and servicing fluids are provided. In one embodiment, the methods comprise: providing a treatment fluid comprising a base fluid and a crosslinked polymer composition comprising at least one polymer that comprise at least one N-vinyl lactam monomeric unit, and at least one crosslinker selected from the group consisting of: an acrylamide-based crosslinker, an acrylate-based crosslinker, an ester-based crosslinker, an amide-based crosslinker, any derivative thereof, and any combination thereof; and introducing the treatment fluid into at least a portion of a wellbore penetrating at least a portion of a subterranean formation.

Abstract: A composition for dissolving drilling mud including barite particles and a polymer includes an enzyme capable of reacting with the polymer; a chelating agent capable of dissolving the barite particles; and a catalyst capable of promoting a reaction between the chelating agent and the barite particles.

Abstract: A system and method for delivering heat to a fluid in a fluid production pipeline. Particles are injected into a line adjacent the fluid production pipeline. The particles include a microencapsulated liquid exothermic phase change material configured to undergo a phase change by solidification and release heat at a selected temperature. The released heat is transferred to the fluid production pipeline.