Abstract: A composition made of fibers and a material able to exhibit reverse solubility has utility for treating subterranean wells. The composition may used to cure lost circulation. The composition may be added to drilling fluids, spacer fluids or cement slurries. As the fluid temperature increases in a well, the reverse solubility material may precipitate and migrate to the fibers, causing the fibers to stick to each other and form a network, thereby forming a barrier that reduces further egress of treatment fluid from the wellbore.

Abstract: Methods are disclosed for improved sand control, fines control, load recovery and well productivity, where the compositions comprise reaction products of an amine and a phosphate-containing compound.

Abstract: A cement composition comprises: cement; water; and an additive, wherein the additive is a pozzolan and a strength-retrogression inhibitor, and wherein a mixture consisting essentially of: the additive; water; and a source of calcium develops a compressive strength of at least 500 psi at a time of 24 hours, a temperature of 190° F., and a pressure of 3,000 psi. A method of cementing in a subterranean formation comprises: introducing the cement composition into the subterranean formation and allowing the cement composition to set. The compressive strength of the test cement composition consisting essentially of: the cement; the water; and the additive at a final time of 72 hours has a percent change greater than ?5% from the compressive strength of the test cement composition at an initial time of 24 hours when tested at a temperature of 300° F. and a pressure of 3,000 psi.

Abstract: A well treatment fluid comprising a Pickering particle emulsion comprising particles of a first liquid phase dispersed in a continuous second liquid phase, and comprising a plurality of colloidal particles adsorbed to a liquid-liquid interface between the first liquid phase and the second liquid phase. Methods, equipment and/or systems for treating a subterranean formation utilizing such treatment fluids are also disclosed.

Abstract: A method of treating a very high salinity high temperature hydrocarbon containing formation is described. The method includes (a) providing a hydrocarbon recovery composition to at least a portion of a hydrocarbon containing formation having a brine salinity of above about 13 wt % and a temperature of above about 7° C., wherein the composition comprises a C15-18 internal olefin sulfonate; and (b) allowing the composition to interact with hydrocarbons in the hydrocarbon containing formation.

Abstract: Methods and compositions that comprise sub-micron alumina for accelerating setting of a cement composition. An embodiment includes a method of cementing in a subterranean formation. The method may comprise introducing a cement composition into the subterranean formation, wherein the cement composition comprises hydraulic cement, sub-micron alumina, and water. The method further may comprise allowing the cement composition to set in the subterranean formation. Another embodiment includes a cement composition that may comprise hydraulic cement, sub-micron alumina, and water.

Abstract: A method includes providing a slurry comprising a carrier fluid and a solids mixture, and injecting said slurry in a wellbore wherein the solids mixture comprises at least two volume-averaged particle size distribution (PSD) modes, wherein a first PSD mode comprises solids having a volume-average median size at least three times larger than the volume-average median size of a second PSD mode such that a packed volume fraction (PVF) of the solids mixture exceeds 0.75.

Abstract: A method of cleaning a wellbore prior to the production of oil or gas is disclosed, wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake. The method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid includes an aqueous fluid, and imino diacetic acid or salt thereof. Optionally an acid buffering agent, and a weighting age are also included. The breaker fluid is formulated such that after a predetermined period of time and the filter cake present in the wellbore or on the wellbore face is substantially degraded. Other methods may also include drilling the wellbore with a water-based drilling mud that forms a water-based filter cake, wherein the method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid may include an aqueous fluid, and an iminodiacetic acid or a salt thereof.

Abstract: A method for forming a well and pipeline treating fluid is provided. The method comprises combining a cross-linkable gelling polymer, a scavenging compound capable of reducing a concentration of divalent and polyvalent metal ions and salts thereof available for reaction, a hydration solvent and optionally an acid. The resulting mixture has a pH ranging from about 3 to about 7 and a first viscosity. The mixture is maintained at conditions suitable for hydration of the cross-linkable gelling polymer until the mixture has a second viscosity that is greater than the first viscosity. The mixture is combined with an aqueous based fluid and at least one cross-linking agent. The pH of the mixture is raised to a sufficient level to allow a desired degree of cross-linking to occur. Other methods, a well and pipeline treating gel and a well and pipeline treating fluid are also provided.

Abstract: Disclosed are spacer fluids comprising cement kiln dust (“CKD”) and methods of use in subterranean formations.

Abstract: Fluids comprising elongated nanoparticles and methods of using the fluids in treating a subterranean formation penetrated by a wellbore are disclosed.

Abstract: A composition and method required for providing a fracturing fluid pumped down a well bore and into a subterranean formation under conditions of pressure that will fracture the subterranean formation is described. More specifically, the composition increases the recovery of hydrocarbons from a geological formation penetrated by a well bore, wherein the composition includes a fracturing fluid that is liquid carbon dioxide (LCO2) with proppant to aid transport of the proppant in suspension, and thereby create a fracture using a fracturing fluid which is the thickened composition containing fumed silica. When the composition is without a proppant, the viscosity of the composition is increased in order to improve the fracturing operation through aspects such as increased fracture width and reduced fluid leak-off.

Abstract: A method for manufacturing a plurality of glass microspheres comprises: melting a batch into a first glass melt in a melter system, processing the first glass melt into a second glass, pulverizing the second glass into a plurality of glass fragments, thermally processing the plurality of glass fragments into a plurality of glass microspheres, providing at least one of a plurality of redox reactions and a plurality of events in at least one of the first glass melt and a melt of the second glass, and the plurality of redox reactions and the plurality of events are induced by a plurality of redox active group (RAG) components.

Abstract: Compositions, systems and methods for the prevention or reduction of clumping or sticking of particulate hydraulic fracturing chemical additives. In preferred examples the particulate hydraulic fracturing chemical additives may be coated with, for example, a coating comprising a polymeric component and with or without silica. Inorganic flow agents (IFA) may be applied to the exterior surface of the particulate hydraulic fracturing chemical additives to prevent hardening or clumping of the additives upon storage. Preferably the coating is permeable, but insoluble in an aqueous medium, whereupon the additive components are released into the medium.

Abstract: A method for drilling through a producing zone in a subterranean formation or for completing a wellbore in a subterranean formation, using a drill-in and completion fluid comprising a blend of a phosphate brine and water.

Abstract: Methods and compositions are disclosed that comprise cement kiln dust having a mean particle size that has been altered. An embodiment discloses a method of preparing cement kiln dust comprising: providing cement kiln dust having an original particle size; and altering the mean particle size of the cement kiln dust from the original size by grinding, separating, or a combination thereof. Another embodiment discloses a well treatment fluid comprising: cement kiln dust having a mean particle size that has been altered from its original size by grinding, separating, or a combination thereof; and water.

Abstract: A cement composition comprises: cement; water; and an additive, wherein the additive is a pozzolan and a strength-retrogression inhibitor, and wherein a mixture consisting essentially of: the additive; water; and a source of calcium develops a compressive strength of at least 500 psi at a time of 24 hours, a temperature of 190° F., and a pressure of 3,000 psi. A method of cementing in a subterranean formation comprises: introducing the cement composition into the subterranean formation and allowing the cement composition to set. The compressive strength of the test cement composition consisting essentially of: the cement; the water; and the additive at a final time of 72 hours has a percent change greater than ?5% from the compressive strength of the test cement composition at an initial time of 24 hours when tested at a temperature of 300° F. and a pressure of 3,000 psi.

Abstract: A method of treating a subterranean formation penetrated by a wellbore involves introducing an acid treatment fluid through the wellbore into the formation. The treatment fluid is formed from a zwitterionic viscoelastic surfactant, an acid in an amount to provide the treatment fluid with an initial pH of ?0 and a rheology enhancer. The treatment fluid has a high viscosity at the initial pH and a lower viscosity when the pH of the treatment fluid is raised to an intermediate pH of from greater than 0 to about 5.

Abstract: A well fracturing fluid is shown which includes an aqueous base fluid, a hydratable polymer, such as a guar gum, and a suitable crosslinking agent for crosslinking the hydratable polymer to form a polymer gel. The hydratable polymer has a higher molecular weight which is achieved by improvements in the processing of the guar split. The higher molecular weight polymer provides improved performance in well fracturing operations.

Abstract: Methods and compositions are disclosed that comprise cement kiln dust having a mean particle size that has been altered. An embodiment discloses a method of preparing cement kiln dust comprising: providing cement kiln dust having an original particle size; and altering the mean particle size of the cement kiln dust from the original size by grinding, separating, or a combination thereof. Another embodiment discloses a well treatment fluid comprising: cement kiln dust having a mean particle size that has been altered from its original size by grinding, separating, or a combination thereof; and water.

Abstract: Controlling microbial growth and activity during Microbial Enhanced Oil Recovery processes is disclosed. Specific control of microbial growth and activity in this process results in prevention of nutrient loss in transit and allows better targeting of microbial activity to the desired subsurface location(s).

Abstract: A composition, treatment fluid and method using hydrolyzable fines. A treatment fluid, which may optionally include a high solids content fluid (HSCF) and/or an Apollonianistic solids mixture, includes a fluid loss control agent comprising a dispersion of hydrolyzable fines, optionally with one or more of a surfactant, plasticizer, dispersant, degradable particles, reactive particles and/or submicron particles selected from silicates, ?-alumina, MgO, ?-Fe2O3, TiO2, and combinations thereof.

Abstract: The present invention includes compositions and methods of supplying a corrosion inhibitor including placing a corrosion inhibitor attached to a nanostructure carrier, placing the nanostructure carrier containing the corrosion inhibitor at a location and the nanostructure carrier is capable of releasing the corrosion inhibitor.

Abstract: Relatively high viscosity materials and methods for introducing them as discrete bodies or masses into relatively low viscosity fluids, such as brine, give fracturing fluids that help control the diversion and distribution of fluids as they are pumped downhole against a subterranean formation, particularly shale, to fracture it. A wide range of relatively viscous materials may be used, including polymers, crosslinked polymers and/or surfactant gels, for instance gels created with viscoelastic surfactants (VESs). Once the fracturing fluids containing these bodies or masses are within the hydraulic fracture, the processes of paths of least resistance, flow deviation, viscous material flow displacement, total fluid diversion, in situ fluid viscosity generation and distribution of delayed release treatment additives may be deployed.

Abstract: A variety of methods and compositions are disclosed, including, in one embodiment, a method of cementing in a subterranean formation, comprising: providing a set-delayed cement composition comprising water, pumice, hydrated lime, and a set retarder; activating the set-delayed cement composition; introducing the set-delayed cement composition into a subterranean formation; and allowing the set-delayed cement composition to set in the subterranean formation.

Abstract: Defoamer compositions are disclosed and methods for making and using same, where the defoamer has universal applicability at low concentrations. The defoamer compositions include between 40 vol. % and about 80 vol. % distilled water (other waters may be used instead), 10 vol. % and about 30 vol. % of silicon anti-foam agent and between about 10 vol. % and about 30 vol. % of active silicon anti-foam agent. The defoamer compositions are used in amount of less than or equal to 200 ppm in all foamed downhole fluid systems.

Abstract: A self-adaptive cement formulation includes cement, water and asphaltite-mineral particles. The set cement demonstrates self-healing properties when exposed to methane, and is particularly suited for well-cementing applications. After placement and curing, the self-healing properties help maintain zonal isolation should bonding be disrupted between the set cement and the formation or a casing string, should cracks or defects appear in the set-cement matrix, or both.

Abstract: Breaking compositions are disclosed for controlled breaking of borate cross-linked fracturing fluids, and to method for making and using same, where the composition includes an oxidative component and an ester component.

Abstract: Drilling, drill-in and completion fluids containing nanoparticles for use in hydrocarbon drilling and recovery processes and methods related thereto are provided. The fluids also include a dual acting shield agent that shields the nanoparticles and also acts as a viscosifier. The fluids can be used in various types of hydrocarbon drilling and recovery processes, such as drilling, drill in, completion, and the like.

Abstract: Nanoemulsions have been discovered to be useful to the oil field. More particularly water-in-oil (W/O), oil-in-water (O/W) and other classes of nanoemulsions have found beneficial application in drilling, completion, well remediation and other oil and gas industry related operations. Additionally, nanoemulsions may reduce friction pressure losses, as well as reduce subsidence of solid weight material during oil and gas operations. New preparation methods for nanoemulsions have also been discovered.

Abstract: An improvement over known hydraulic fracturing fluids. Boundary layer kinetic mixing material is added to components of fracturing fluid wherein kinetic mixing material is a plurality of particles wherein at least 25% of particles are several types, i.e., having surface characteristics of thin walls, three dimensional wedge-like sharp blades, points, jagged bladelike surfaces, thin blade surfaces, three-dimensional blade shapes that may have shapes similar to a “Y”, “V” or “X” shape or other geometric shape, slightly curved thin walls having a shape similar to an egg shell shape, crushed hollow spheres, sharp bladelike features, 90° corners that are well defined, conglomerated protruding arms in various shapes, such as cylinders, rectangles, Y-shaped particles, X-shaped particles, octagons, pentagon, triangles, and diamonds.

Abstract: A self-adaptive cement formulation includes cement, water, block copolymer and asphaltite-mineral particles. The set cement demonstrates self-healing properties when exposed to methane, and is particularly suited for well-cementing applications. After placement and curing, the self-healing properties help maintain zonal isolation should bonding be disrupted between the set cement and the formation or a casing string, should cracks or defects appear in the set-cement matrix, or both.

Abstract: Disclosed embodiments relate to well treatment fluids and methods that utilize nano-particles. Exemplary nano-particles are selected from the group consisting of particulate nano-silica, nano-alumina, nano-zinc oxide, nano-boron, nano-iron oxide, and combinations thereof. Embodiments also relate to methods of cementing that include the use of nano-particles. An exemplary method of cementing comprises introducing a cement composition into a subterranean formation, wherein the cement composition comprises cement, water and a particulate nano-silica. Embodiments also relate to use of nano-particles in drilling fluids, completion fluids, simulation fluids, and well clean-up fluids.

Abstract: Composition comprising a plurality of particulates wherein at least some particulates are at least partially covered with a coating that impedes the intrusion of water into the particulates; and, a silica scale control additive, wherein the silica scale control additive is capable of suppressing silica scale build-up proximate the plurality of particulates. Some compositions further include a treatment fluid wherein and the silica scale control additive are present in the treatment fluid.

Abstract: A process for forming a strong, low-density proppant, which process includes heating pumice particulates, or shaped agglomerates thereof, so as to form heat-treated pumice particulates, or heat-treated, shaped pumice agglomerates, having an apparent density of 2.4 or less and a crush resistance of no more than 10% fines at 4000 psi. Proppants, and well treatment fluids comprising proppants, meeting these characteristics and processes for treating subterranean formations using fluids which include such proppants are also described.

Abstract: Mineral particles may provide for wellbore fluids with tailorable properties and capabilities. In some instances, a dry wellbore additive may comprise a plurality of first mineral particles having a specific gravity of about 2.6 to about 20; a plurality of second mineral particles having a specific gravity of about 5.5 to about 20; a plurality of lubricant particles having a specific gravity of about 2.6 to about 20; wherein the first mineral particles, the second mineral particles, and the lubricant particles are different; and wherein the first mineral particles, the second mineral particles, and the lubricant particles have a multiparticle specific gravity of about 3 to about 20.

Abstract: A method includes introducing a treatment fluid including a first polymer gel into a subterranean formation to generate a production fluid having an aqueous portion and a hydrocarbon portion, treating the aqueous portion of the production fluid with chlorine dioxide to separate additional hydrocarbons from the aqueous portion, and adjusting the viscosity of the treated aqueous portion prior to introducing the treated aqueous portion back into the subterranean formation.

Abstract: The invention relates to oil and gas industry, i.e. techniques for making proppants designed to be used as propping agents in oil and gas recovery by the method of formation hydraulic fracturing. A method for the production of a lightweight magnesium silicate proppant, the method comprises heat processing of a magnesium-containing component—a source of magnesium oxide, its co-grinding with a silica-containing component, pelletizing of the batch prepared, sintering and sieving of the pellets prepared, wherein the batch comprises (in terms of calcined substance), in % by weight: SiO2-6 4-72, MgO-11-18, natural impurities—remainder, wherein the heat processing is carried out at temperature not more than 1080 degrees C. A lightweight magnesium silicate proppant is characterized in that the proppant is produced by said method. At least one of the group: serpentine, brucite, caustic magnesite, talc may be used said magnesium-containing component.

Abstract: Thermoset ceramic compositions and a method of preparation of such compositions. The compositions are advanced organic/inorganic hybrid composite polymer ceramic alloys. The material combine strength, hardness and high temperature performance of technical ceramics with the strength, ductility, thermal shock resistance, density, and easy processing of the polymer. Consisting of a branched backbone of silicon, alumina, and carbon, the material undergoes sintering at 7 to 300 centigrade for 2 to 94 hours from water at a pH between 0 to 14, humidity of 0 to 100%, with or without vaporous solvents.

Abstract: The present invention relates to fluids useful for subterranean operations, and more particularly, to fluorosurfactants useful for the reduction of water blocks, gas blocks, and/or gas condensates and their associated treatment fluids and methods. Provided is a method of treating a subterranean formation. The Method may comprise contacting the subterranean formation with a fluorosurfactant. The fluorosurfactant may comprise an amine group, wherein the amine group comprises at least one substituent selected from the group consisting of a fluoroalkyl group, a fluoroalkenyl group, and combinations thereof, wherein the at least one substituent comprises about 3 carbons to about 22 carbons. Also provided are polymeric surfactants and treatment fluids that comprise fluorosurfactants.

Abstract: A ceramic propping agent, in the form of a spherical pellet, and containing common mineral particulate. The desired propping agent is defined as a particulate ceramic made from raw materials which may be comprised of about: 10%-90% parts by weight of a naturally occurring mineral particulate, 30%-70% parts by weight aluminosilicate network modifier, 0.25-20% parts by weight strength enhancer, and at least one part, typically less than 10% by weight, binder. For use in oil and/or natural gas wells as a hydraulic fracturing proppant.

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: Proppants for use in fractured or gravel packed/frac packed oil and gas wells are provided with a contaminant removal component to remove one or more of the contaminants found in subterranean water/hydrocarbon from a production well. The water/hydrocarbon cleaning proppant solids may be used as discrete particles in a proppant formulation, as a coating on proppant solids in pores of a porous proppant solid or as part of the proppant's internal structure. The contaminant removal component removes contaminants, especially dissolved contaminants, in the subterranean water or hydrocarbon before the water/hydrocarbon leaves the well. For those contaminant removal components that can be regenerated, such as ion exchange resins, a measured quantity of an acidic regeneration solution can be injected into the fractured stratum for regeneration and recovered when the well resumes production.

Abstract: A treatment fluid comprises: a metal oxide, wherein the metal oxide is capable of forming a chelate complex or coordination complex with a ligand, wherein the chelate complex or coordination complex has a setting time of less than 90 minutes at a temperature of 71° F. and a pressure of 1 atmosphere. A method of treating a portion of a subterranean formation comprises: introducing the treatment fluid into the subterranean formation; allowing or causing a chelate complex or coordination complex to form between the metal oxide and a ligand; and allowing or causing the chelate complex or coordination complex to set.

Abstract: An embodiment includes a method of servicing a well bore. The method may comprise introducing a lost circulation composition into a lost circulation zone, the lost circulation composition comprising hydraulic cement, nano-particles, amorphous silica, clay, and water. The method further may comprise allowing the lost circulation composition to set in the lost circulation zone. Another embodiment includes a lost circulation composition. The lost circulation may comprise hydraulic cement, nano-particles, amorphous silica, clay, and water.

Abstract: A composition comprises: a treatment fluid comprising a lost-circulation material, wherein the lost-circulation material comprises a ceramic, and wherein the lost-circulation material has a median particle size in the range from about 0.001 millimeters to about 25.4 millimeters. According to another embodiment, a composition comprises: the treatment fluid comprising a lost-circulation material, wherein the lost-circulation material comprises a ceramic, and wherein the median particle size and the concentration of the lost-circulation material is selected such that the treatment fluid has a sealing pressure of at least 50 psi (0.3 MPa). A method of eliminating or reducing lost circulation from a well comprises: introducing the treatment fluid into at least a portion of the well.

Abstract: An ultra-lightweight, high strength ceramic proppant made from mixture of naturally occurring clays, preferably porcelain clay, kaolin and/or flint-clay, earthenware clay or other naturally occurring clays having an alumina content between about 5.5% and about 35%. The proppant has an apparent specific gravity from about 2.10 to about 2.55 g/cc, and a bulk density of from about 1.30 to about 1.50 g/cc. This ultra-lightweight proppant is useful in hydraulic fracturing of oil and gas wells, and has greater conductivity than sand at pressures up to 8,000 psi as measured by Stim-Lab after 50 hours and 275° F. on Ohio Sandstone, in the presence of deoxygenated aqueous 2% solution of KCI.

Abstract: The present invention relates to lightweight high strength microsphere containing ceramic particles having controlled microsphere placement and/or size and microsphere morphology, which produces an improved balance of specific gravity and crush strength such that they can be used in applications such as proppants to prop open subterranean formation fractions. Proppant formulations are further disclosed which use one or more microsphere containing ceramic particles of the present invention. Methods to prop open subterranean formation fractions are further disclosed. In addition, other uses for the microsphere containing ceramic particles of the present invention are further disclosed, as well as methods of making the microsphere containing ceramic particles.

Abstract: The present invention relates to methods and compositions that can be used to delay crystallization of a treatment solution so that thief zones or fractures are plugged in subterranean formations at a substantial distance from a wellbore. A supersaturated sodium aluminate solution, or other solutions, is introduced into the reservoir. The solution is relatively stable in the supersaturated state. Crystallization, or de-stabilizing the solution, can be controlled, which in turn plugs the thief zone or fracture at a designed point of time. By controlling the time that crystallization starts, that is, the induction period, thief zones that are located at a substantial distant from the wellbore can be plugged.

Abstract: A cement composition for use in an oil or gas well, the cement composition comprises: a calcium aluminate cement; water; an organic acid; and a polymeric mixture comprising: (A) water; (B) citric acid; (C) a first polymer, wherein the first polymer: (i) comprises a cellulose backbone and carboxymethyl functional groups; and (ii) has a molecular weight of less than 100,000; and (D) a second polymer, wherein the second polymer: (i) comprises a lignosulfonate; and (ii) has a molecular weight of less than 100,000, wherein a test composition consisting essentially of: the cement; the water; the organic acid; and the polymeric mixture, and in the same proportions as in the cement composition has a thickening time of at least 5 hours at a temperature of 300° F. (148.9° C.) and a pressure of 10,000 psi (68.9 MPa).