Abstract: Methods and compositions for use in the inhibition of the formation of gas hydrate agglomerates are provided. In some embodiments, a method is provided that includes: providing an emulsion drilling fluid including: a continuous phase including a non-oleaginous fluid; an internal phase including an oleaginous fluid; and a thermodynamic hydrate inhibitor; and drilling at least a portion of a wellbore penetrating a subterranean formation.

Abstract: An aqueous sol used in CO2 foam flooding, one of EOR flooding methods for recovering crude oil by injection into the oil reservoir of an onshore or offshore oil field, the aqueous sol increasing foam stability even over a substantial period of time, at high temperatures and pressures, and in salt water, thus improving crude oil recovery rate. The aqueous sol for increasing stability of froth or emulsion in a mixture containing carbon dioxide, water, and oil in CO2 foam flooding of EOR, the sol including silica particles having an average particle diameter of 1 to 100 nm as measured by dynamic light scattering and having surfaces at least partially coated with a silane compound having a hydrolyzable group, the silica particles serving as a dispersoid and dispersed in an aqueous solvent having a pH of 1.0 to 6.0 serving as a dispersion medium.

Abstract: Well stimulating fluids and methods may use a first and a second chelating agent, e.g., diethylene triamine pentaacetic acid (DTPA), glutamic diacetic acid (GLDA), and/or hydroxyethyl ethylene diamine triacetic acid (HEDTA), particularly in amounts of from 1 to 10 wt. %, to control iron precipitation during the stimulation process. Such fluids can stabilize iron ions without precipitation to manage the efficiency and performance of the stimulation fluid. Such stimulation fluids can be used with for highly concentrated HCl solutions, e.g., more than 20 up to 28 wt. % or more, that are useful in emulsified acid formulations in acid fracturing or acidizing of carbonate formations.

Abstract: Wellbore fluids may contain an aqueous base fluid comprising a monovalent brine, a modified starch, and a metal oxide. Methods of using wellbore fluids may include drilling a subterranean well while circulating a wellbore fluid into the subterranean well, wherein the wellbore fluid contains an aqueous base fluid comprising a monovalent brine, a modified starch, and a metal oxide.

Abstract: Disclosed herein are compositions, processes, and systems for deploying and creating a temporary fluid barrier at an interface between a high fluid conductivity zone and a lower fluid conductivity zone. The disclosed compositions include mixtures of solvents and biodegradable non-spherical particles, wherein the particles include a coating that may slow or inhibit degradation, for example by hydrolysis, of the particle. The disclosed particles are designed to possess sufficient flexibility to traverse the high conductivity zone.

Abstract: A method and hydraulic fracturing fluid that is a viscoelastic surfactant (VES) fracturing fluid having a surfactant and an inorganic oxidizer salt for hydraulic fracturing of a geological formation. The VES fracturing fluid is provided through a wellbore into the geological formation to hydraulically fracture the geological formation to form hydraulic fractures in the geological formation. The method includes oxidizing organic material in the hydraulic fractures with the VES fracturing fluid.

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

Abstract: A method of treating a well, comprising introducing a well treatment fluid into the well. The well treatment fluid includes an aqueous base fluid and a dewatering agent. The dewatering agent includes water, a demulsifying surfactant, and a polyamine polyether.

Abstract: The present invention relates to methods of cryopreservation and compositions for use in such methods where the methods utilise non-Newtonian fluid properties of the cryopreservation medium to modulate the viscosity of that medium to deliver an improved cryopreservation process.

Abstract: Various embodiments provide methods and systems for providing fluid lighteners for use in downhole wells. The fluid lighteners may include one or more viscosifiers, one or more aphron generators, and a location-specific non-emulsifying surfactant.

Abstract: A waveform energy generation system, the system including at least one joint of production casing, and one or more energy generators residing along the joint of production casing. The energy generators are configured to be in substantial mechanical contact with a subsurface formation within a wellbore. The energy generators may include either explosive devices or a piezo-electric material. The system also includes a signal transmission system. The signal transmission system is used to send control signals from the surface down to the energy generators for activation at the formation's resonant frequency. Methods of enhancing the permeability of a rock matrix within a subsurface formation using the wellbore as an energy generator are also provided.

Abstract: The compositions for removing a mineral phase from a surface composition for removing a mineral phase of inorganic sulfate scale include a phosphonoalkyl aminopolycarboxylic acid chelating agent; a wettability modifier comprises a dibasic ester and a surfactant, wherein the surfactant comprises one or more of an anionic alkyl sulfonate or an anionic aryl sulfonate; a pH-adjusting agent; a scale converting agent; and water. The methods for removing a mineral phase from a surface include contacting the mineral phase with an aqueous dissolver fluid that is one of the present compositions; and removing the oil wet mineral phase from the surface with the aqueous dissolver fluid. The compositions and methods provide enhanced remediation of mineral phases from surfaces associated with wellbores.

Abstract: Provided herein are compositions and methods for the controlled delivery of acid to a subterranean formation.

Abstract: The present application relates to methods and systems for mitigating condensate banking. In some embodiments, the methods and systems involve altering the wettability of a rock formation in the vicinity of a wellbore for a gas condensate reservoir.

Abstract: Methods and compositions for treating a well. A method comprising: introducing a treatment fluid into a wellbore penetrating a subterranean formation wherein the treatment fluid comprises: a base fluid; and multi-functional diverter particulates, wherein the multi-functional diverter particulates comprise a polyvinyl alcohol and a well service additive; and diverting at least a portion of the treatment fluid and/or a subsequently introduced fluid away from the zone. A treatment fluid comprising: a base fluid; and a multi-functional diverter particulate, wherein the multi-functional diverter particulates comprise a polyvinyl alcohol and a well service additive.

Abstract: Provided is a composition comprising at least one polymer, the repeat unit of which comprises at least one amide functional group, at least one polyetheramine with a weight-average molecular weight (Mw) of greater than 100 g.mo1?1 and exhibiting at least two secondary and/or tertiary amine functional groups, and optionally, but preferably, at least one organic solvent. Also provided is method of using of the composition for delaying, indeed even preventing, the formation of gas hydrates, in particular in a process for extracting oil and/or gas and/or condensates, and also to the process for delaying, indeed even preventing, the formation and/or the agglomeration of gas hydrates, employing a composition as defined above.

Abstract: A method for fracturing a subterranean formation, the method comprising injecting a fracturing fluid into a wellbore through the subterranean formation, thereby creating a fracture network in the subterranean formation, the fracturing fluid comprising a proppant and a plurality of polymer fibers having a deflection temperature ranging from about 70° C. to about 150° C. dispersed in a carrier fluid.

Abstract: A method and reactive treatment fluid for treating a wellbore for filter cake removal, including providing the reactive treatment fluid having a viscoelastic surfactant (VES) into a wellbore in a subterranean formation and attacking the filter cake via the reactive treatment fluid.

Abstract: Compositions and methods for use in subterranean treatment fluids involving thermoassociative polymers are provided. In some embodiments, the methods include providing a treatment fluid that includes an aqueous base fluid, one or more thermoassociative polymers that include a water soluble polymeric backbone having one or more hydrophobic moieties attached to the polymer backbone, wherein the thermoassociative polymer exhibits thermoassociation at a first temperature Tassoc, and one or more tuning additives that changes the temperature at which at least one of the thermoassociative polymers exhibits thermoassociation from Tassoc to a second temperature Tassoc?; and introducing the treatment fluid into a portion of a subterranean formation.

Abstract: This invention describes and claims the stimulation of several Wolfcamp and Bone Springs targeted wells in the northern Delaware Basin using fracturing treatments and a new method employing relatively small pre-pad pill volumes of Brine Resistant Silicon Dioxide Nanoparticle Dispersions ahead of each stage of treatment have been successfully performed. The invention includes a method of extending an oil and gas system ESRV comprising the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion (“BRINE RESISTANT SDND”) to conventional oil well treatment fluids. The invention also includes a method of increasing initial production rates of an oil well by over 20.0% as compared to wells either not treated with the BRINE RESISTANT SDND technology or treated by conventional nano-emulsion surfactants. The Method focuses on the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion to conventional oil well treatment fluids.

Abstract: The present invention relates to a cold-crystallizing material having high latent heat, and a method of using the present material for heat storing. The material of the invention comprises of a phase change material and an additive which is preferably a hydrophilic polymer matrix. Preferably, sugar alcohols, such as erythritol or D-mannitol, are used as the phase change material. The polymer of the invention is preferably cross-linked and ionic, i.e. a polyelectrolyte. PCM stores a high amount of heat energy while melting and releases the stored thermal energy by cold-crystallization. Compared to previously studied cold-crystallizing materials, the latent heat of the cold-crystallizing material of the invention is considerably higher, and cold-crystallization is more repeatable in successive melting-crystallization cycles. The material can be used for heat storing. Heat energy can be released from the material by a heat pulse on demand. The method is particularly suitable for long-term heat storing.

Abstract: A lubricant including a fluid medium and at least one intercalation compound of a metal chalcogenide having molecular formula MX2, where M is a metallic element such as tungsten (W), and X is a chalcogen element such as sulfur (S), wherein the intercalation compound has a fullerene-like hollow structure or tubular-like structure.

Abstract: This invention describes and claims the stimulation of several Wolfcamp and Bone Springs targeted wells in the northern Delaware Basin using fracturing treatments and a new method employing relatively small pre-pad pill volumes of Brine Resistant Silicon Dioxide Nanoparticle Dispersions ahead of each stage of treatment have been successfully performed. The invention includes a method of extending an oil and gas system ESRV comprising the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion (“BRINE RESISTANT SDND”) to conventional oil well treatment fluids. The invention also includes a method of increasing initial production rates of an oil well by over 20.0% as compared to wells either not treated with the BRINE RESISTANT SDND technology or treated by conventional nano-emulsion surfactants. The Method focuses on the steps of adding a Brine Resistant Silicon Dioxide Nanoparticle Dispersion to conventional oil well treatment fluids.

Abstract: A method of demulsifying crude oil, said method comprising the step of reacting an amount of crude oil with a polyester demulsifier, therein the demulsifier is used in quantities from 0.0001% to 5% (1-50,000 ppm), preferably 0.0005% to 2% (5-20,000 ppm), more preferably 0.0008% to 1% (8-10,000 ppm) and most preferably 0.001 to 0.1 wt. % polymer (10-1,000 ppm) related to the oil fraction of the utilized emulsion.

Abstract: Treatment fluids containing salts, surfactants, mutual solvents and fibers may be used to remove wellbore filter cakes that have been deposited by drilling fluids. The drilling fluids may be water-base, oil-base, synthetic-base or emulsions. The fibers may be selected from polylactic acid, celluloses, polyesters, polyvinyl alcohols and polyethylene terephthalates. A combination of straight and crimped fibers is present in the treatment fluid.

Abstract: Provided herein are liquid polymer (LP) compositions comprising a synthetic (co)polymer (e.g., an acrylamide (co)polymer), as well as methods for preparing inverted polymer solutions by inverting these LP compositions in an aqueous fluid. The resulting inverted polymer solutions can have a concentration of a synthetic (co)polymer (e.g., an acrylamide (co)polymer) of from 50 to 15,000 ppm, and a filter ratio of 1.5 or less at 15 psi using a 1.2 ?m filter. Also provided are methods of using these inverted polymer solutions in oil and gas operations, including enhanced oil recovery.

Abstract: Mapping propped fractures in a well can be performed using a mixture including a proppant and an encapsulated salt. The proppant can be positioned in a fracture in the well for propping open the fracture to form a propped fracture. The encapsulated salt can be positioned in the propped fracture proximate to the proppant and include a salt and a non-permeable coating. The salt can be dissolved in response to fracture closure, encapsulant degradation, or encapsulant dissolution to form an electrically conductive solution usable for mapping the propped fracture. The non-permeable coating can prevent a fluid from contacting the salt during pumping and placement operations.

Abstract: A hydrocarbon well remediation/stimulation treatment based on an Y-Grade natural gas liquid injection fluid mixture, including prescribed amounts of gas, nanoparticles with wettability alteration properties, foaming agents (including nanoparticles with foam stabilization properties), and solvent additives. The fluid mixture may be tuned to address multiple factors contributing to production decline, such as liquid blockage, wettability properties, fines/debris/scale build-up and organic deposits, reservoir heterogeneity/permeability, and/or reservoir fluid and hydrocarbon compositions, resulting in hydrocarbon production enhancement. The treatment is typically applied with a Huff-n-Puff process, however may also be applied with a flooding process.

Abstract: A nanosilica containing fluid system for shale stabilization in a shale formation. The nanosilica containing fluid system comprising a functionalized nanosilica composition operable to react with shale at the surface of the shale formation to form a barrier on the shale formation. The functionalized nanosilica composition comprising a nanosilica particle, the nanosilica particle having a mean diameter, and a functionalization compound, the functionalization compound appended to the surface of the nanosilica particle. And an aqueous-based fluid, the aqueous-based fluid operable to carry the functionalized nanosilica composition into the shale formation. The functionalization compound is an amino silane. The aqueous-based fluid is selected from the group consisting of water, deionized water, sea water, brine, and combinations thereof.

Abstract: A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

Abstract: A date tree fiber mix lost circulation material (LCM) is provided. The date tree fiber mix LCM may include includes date tree trunk fibers produced from date tree trunks and date tree leaf and leaf stem fibers produced from date tree leaves and leaf stems. The LCM include a mix of 30% by weight date tree trunk fibers and 70% date tree leaf and leaf stem fibers, 40% by weight date tree trunk fibers and 60% date tree leaf and leaf stem fibers, 50% by weight date tree trunk fibers and 50% date tree leaf and leaf stem fibers. Methods of lost circulation control using and manufacture of a date tree fiber mix LCM are also provided.

Abstract: A date tree fiber mix lost circulation material (LCM) is provided. The date tree fiber mix LCM may include includes date tree trunk fibers produced from date tree trunks and date tree leaf and leaf stem fibers produced from date tree leaves and leaf stems. The LCM include a mix of 30% by weight date tree trunk fibers and 70% date tree leaf and leaf stem fibers, 40% by weight date tree trunk fibers and 60% date tree leaf and leaf stem fibers, 50% by weight date tree trunk fibers and 50% date tree leaf and leaf stem fibers. Methods of lost circulation control using and manufacture of a date tree fiber mix LCM are also provided.

Abstract: A mixture of at least two shapes of a dissolvable diverter material. The shapes range from a flake having a high surface area to mass ratio to beads having a low surface area to mass ratio. The density of the various shapes may be manipulated by including voids or low-density materials within the shape. The density manipulation allows matching the transport properties of the at least two shapes to the transport fluid so that both shapes may arrive at the desired location at the desired time.

Abstract: Systems and methods for treating proppant to mitigate erosion of equipment used in certain subterranean fracturing operations are provided. In some embodiments, the methods comprise: conveying a plurality of coated proppant particulates into a blender, wherein the coated proppant particulates comprise at least a partial coating of DFR and/or a hydratable polymer; blending the plurality of coated proppant particulates with an aqueous base fluid in the blender to form a treatment fluid; and introducing the treatment fluid from the blender into at least a portion of a subterranean formation.

Abstract: A gas hydrate hydrogel inhibitor comprising at least one polymer hydrogel particle having from 50 to 100% hydrogel content, the at least one polymer hydrogel particle including an inhibitor selected from the group consisting of: at least one thermodynamic hydrate inhibitor, at least one kinetic hydrate inhibitor, or a combination thereof.

Abstract: A mixture of at least two shapes of a dissolvable diverter material. The shapes range from a flake having a high surface area to mass ratio to beads having a low surface area to mass ratio. The density of the various shapes may be manipulated by including voids or low-density materials within the shape. The density manipulation allows matching the transport properties of the at least two shapes to the transport fluid so that both shapes may arrive at the desired location at the desired time.

Abstract: A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

Abstract: A method and composition of treating an oil or gas well having a wellbore, well casing, production equipment or recovery equipment. The method involves introducing into the wellbore, well casing, production equipment or recovery equipment a high flash point solvent blend. The blend includes at least one C1-C4 ester of a C16-C20 fatty acid component, at least one terpene hydrocarbon component (e.g., a pure gum turpentine, an oil of turpentine, or mixture thereof), and optionally at least one emulsifier component. The weight percent ratio of the at least one C1-C4 ester of a C16-C20 fatty acid component to the at least one terpene hydrocarbon component is from about 60:40 weight percent to about 95:5 weight percent, based on the total weight of the blend. The blend has a flash point greater than about 140° F. The blend may be biodegradable, and has no ozone depleting compounds, no hazardous air pollutants, and no carcinogens.

Abstract: A composite having a solid particulate and a surface modifying treatment agent on the solid particulate wherein the surface modifying treatment agent has a hydrophobic tail and an anchor for adhering the hydrophobic tail onto the solid particulate. The anchor is an organophosphorus acid derivative. The composite may be used as a proppant in a hydraulic fracturing operation as well as a sand control particulate in a gravel packing operation. The presence of the surface modifying treatment agent on the surface of the solid particulate reduces the generation of fines and dust as well as the migration of sand during a hydraulic fracturing operation or a sand control operation. The presence of the surface modifying treatment agent on the surface of the solid particulate further enhances the crush resistance of the solid particulate.

Abstract: Injection fluids formed of reverse emulsions and related methods of forming and using reverse emulsions for cavity control in solution mining. The reverse emulsion can reduce the volume of oil required to create an oil pad at the roof of a solution mining cavern in order to prevent vertical leaching and cavern collapse. The reverse emulsion can be formed from an emulsifier, a brine solution and oil. The emulsifier concentration can range from about 1% to about 5% by weight of the reverse emulsion. The emulsifier and the oil can be combined to form an oil/emulsifier mixture, wherein the oil/emulsifier mixture is combined with the brine solution to form the reverse emulsion. The oil/emulsifier mixture can be from about 1% to about 5% by weight of the reverse emulsion.

Abstract: Breakers for gelling agents are disclosed, for example pyromellitamide gelling agents. The breakers include sulfonic acids in one example.

Abstract: Various illustrative embodiments of a process for enhanced flocculation and clarification of produced water from oil and gas wells using nanoparticles are provided herein. Certain nanoparticles can increase the settling rate of solids in produced water when used alone or combined with certain conventional flocculents.

Abstract: A method for measuring liquid-rock and liquid-liquid interfaces including performing at least one measurement technique proximate a subterranean rock sample and an interfacial liquid hydrocarbon fraction, where a liquid hydrocarbon fraction and the subterranean rock sample are combined to exhibit a first interface between the liquid hydrocarbon fraction and the subterranean rock sample, producing the interfacial liquid hydrocarbon fraction. The method includes performing at least one measurement technique proximate the interfacial liquid hydrocarbon fraction and a brine solution, where the liquid hydrocarbon fraction and the brine solution are combined to exhibit a second interface between the liquid hydrocarbon fraction and the brine solution, and where the measurement techniques result in measurements of the interfacial liquid hydrocarbon fraction at macro, micro to nano, nano to sub-nano, and sub-nano scales, and result in measurements of the second interface at macro and micro to nano scales.

Abstract: A date tree fiber mix lost circulation material (LCM) is provided. The date tree fiber mix LCM may include includes date tree trunk fibers produced from date tree trunks and date tree leaf and leaf stem fibers produced from date tree leaves and leaf stems. The LCM include a mix of 30% by weight date tree trunk fibers and 70% date tree leaf and leaf stem fibers, 40% by weight date tree trunk fibers and 60% date tree leaf and leaf stem fibers, 50% by weight date tree trunk fibers and 50% date tree leaf and leaf stem fibers. Methods of lost circulation control using and manufacture of a date tree fiber mix LCM are also provided.

Abstract: A date tree fiber mix lost circulation material (LCM) is provided. The date tree fiber mix LCM may include includes date tree trunk fibers produced from date tree trunks and date tree leaf and leaf stem fibers produced from date tree leaves and leaf stems. The LCM include a mix of 30% by weight date tree trunk fibers and 70% date tree leaf and leaf stem fibers, 40% by weight date tree trunk fibers and 60% date tree leaf and leaf stem fibers, 50% by weight date tree trunk fibers and 50% date tree leaf and leaf stem fibers. Methods of lost circulation control using and manufacture of a date tree fiber mix LCM are also provided.

Abstract: Methods and compositions for the prevention of the formation, breakdown, and/or removal of gelled layers in an oil and/or gas well are provided. In some embodiments, the compositions and methods comprise a concentrate, as described in more detail herein, where the concentrate comprises two or more surfactants. In certain embodiments, the compositions and methods comprise an emulsion or a microemulsion. The emulsion or microemulsion may include a surfactant, optionally a solvent, and optionally a freezing point depression agent or other components.

Abstract: Disclosed herein are crosslinker compositions for aqueous hydroxyl functional polymers. The compositions include at least one borate species, about 0.05 wt % to 10 wt % of a synthetic layered silicate, and a water source. The compositions are characterized by shelf stability, wherein the sparingly soluble borate does not undergo sedimentation. The crosslinker compositions are usefully added to aqueous polymer solutions of hydroxyl functional polymers to form injectable compositions for hydraulic fracturing.

Abstract: A method of manufacturing particulate material. The method can include manufacturing particulate material during an operation at a well, injecting the particulate material into the well during the manufacturing, and changing a dimension of the particulate material during the injecting. Another method of manufacturing particulate material can include manufacturing particulate material during an operation at a well, injecting the particulate material and a proppant into the well during the manufacturing, and then the particulate material degrading in the well. Another method of manufacturing particulate material can include manufacturing particulate material during an operation at a well, fixing a shape of the particulate material by cooling the particulate material, and then injecting the particulate material into the well.

Abstract: Method of increasing the permeability in subterranean formations comprising rock that is soluble by acid, in particular carbonatic formations, using a formulation comprising at least an acid and a retarding surfactant which is an amphoteric surfactant. Preferably, the acid comprises methanesulfonic acid.

Abstract: Compositions and methods are provided for delayed breaking of viscoelastic surfactant gels inside subterranean formations. Breaking is accomplished without mechanical intervention or use of a second fluid. The delayed breaking agent is selected from alkyl ether phosphates and salts thereof, alkylaryl ether phosphates and salts thereof, alkyl sulfates and salts thereof, alkylaryl sulfates and salts thereof, alkyl ether sulfates and salts thereof, alkylaryl ether sulfates and salts thereof, and mixtures of any of the foregoing. The viscoelastic surfactant can be a zwitterionic surfactant, and can be selected from the group consisting of sultaines, betaines, and amidoamine oxides.