Abstract: The present invention relates to particles that are useful for enhancing hindered settling in suspensions. One embodiment of the present invention provides a method of providing a subterranean treatment fluid including a base fluid and a weighting agent having a first average settling velocity; and a neutral-density particle; and mixing the subterranean treatment fluid with the neutral-density particle thereby reducing the weighting agent to a second average settling velocity.

Abstract: Compositions of lost circulation materials are provided that are useful for identifying the location of fluid loss in a wellbore. The compositions include additives which enhance a property of the composition such that they can be detected by an LWD or MWD tool capable of measuring the property when the composition is deployed in a region of loss, and can be distinguished by the LWD or MWD tool from the formation and mud fluid. Methods are also provided for using the composition to detect the location of fluid loss and for controlling the loss of fluid from the wellbore. The methods involve deploying the compositions in loss regions by adding the compositions to drilling mud, and measuring a property of the compositions using an LWD or MWD tool.

Abstract: Invert emulsion drilling fluids that have extended emulsion stability and reduced sag potential can be realized through incorporation of colloidal particles therein. The invert emulsion drilling fluids can be free of organophilic clays. The organophilic clay-free drilling fluids can comprise: an oleaginous fluid continuous phase; an aqueous fluid internal phase; a surfactant; a weighting agent; and a plurality of colloidal particles, the colloidal particles comprising fibrous colloidal particles and at least one other type of colloidal particle; wherein at least a portion of the plurality of colloidal particles interact with the surfactant to form an associative supporting structure that inhibits sag of the weighting agent.

Abstract: A method of wellbore strengthening may include providing a wellbore strengthening fluid comprising a drilling fluid, a particulate, and a fiber; introducing the wellbore strengthening fluid into a wellbore penetrating a subterranean formation; and forming a plug comprising the particulate and the fiber in a void near the wellbore, the plug being capable of maintaining integrity at about 1000 psi or greater overbalance pressure.

Abstract: The present invention relates to nanoparticle smart tags and the use of nanoparticle smart tags in the detection of analyte. In particular, the present invention relates to nanoparticle smart tags that may be used in subgeologic formations to detect analytes of interest in real-time. One embodiment of the present invention provides a suspension having a nanoparticle smart tag analyte complex formed by an interaction having a nanoparticle smart tag and an analyte; and a subterranean treatment fluid.

Abstract: An additive composition including a synergistic combination of a hectorite organoclay composition and an attapulgite organoclay composition. The hectorite organoclay composition includes (i) a first organic cation provided by an alkoxylated quaternary ammonium salt; and ii) a second organic cation wherein such second organic cation is not provided by an alkoxylated quaternary ammonium salt. The attapulgite organoclay composition includes (iii) a third organic cation provided by an alkoxylated quaternary ammonium salt; and (iv) a fourth organic cation wherein such third organic cation is not provided by an alkoxylated quaternary ammonium salt.

Abstract: A method for treating hydrocarbon-servicing fluid is provided for reducing contaminants, especially bacteria, volatile and semi-volatile organics, in hydrocarbon-servicing fluids by microwaving and irradiating the fluid with ultraviolet light, with or without use of catalyst. The treated fluid can be used in upstream and downstream hydrocarbon processing operations.

Abstract: A screen assembly for a shale shaker comprising a panel (500) and a support structure (600), the panel (500) having an area provided with a multiplicity of apertures and at least one layer of screening material arranged over the multiplicity of apertures, wherein said panel (500) is removable from said support structure (600).

Abstract: Proppant material for hydraulic fracturing is provided. The particles of the proppant are formed by drip casting. A slurry of finely divided ceramic particles is flowed through nozzles and formed into droplets under the influence of vibration. Uniform sized, smooth surface, spherical green particles are formed. The green particles are dried and sintered to form the proppant. The proppant is used in the process of hydraulic fracturing of wells.

Abstract: Working fluids, such as drilling fluids, may remove heat from other fluids, tools, equipments and environments and transfer it to other locations by using reversible phase change elements. The heat removal occurs through the absorption of heat by one or more phase transitions or a sequence of phase transitions in the elements of the working fluid. For instance, heat is absorbed when the phase change portions of the reversible phase change elements change phase including, but not necessarily limited to, a change from solid to smectic liquid crystal, from solid to nematic liquid crystal, from smectic liquid crystal to isotropic liquid, from nematic liquid crystal to isotropic liquid, from solid to isotropic liquid, and sequences and combinations thereof. Heat is released when the phase change reverses. These phase changes are first-order transitions and are associated with a latent heat or enthalpy.

Abstract: Invert emulsion drilling fluids that have extended emulsion stability and reduced sag potential are described herein. The drilling fluids comprise an invert emulsion, a weighting agent, and a plurality of colloidal particles. The invert emulsion comprises an oleaginous fluid continuous phase, an aqueous fluid internal phase, and a surfactant. At least a portion of the plurality of colloidal particles interact with the surfactant to form an associative supporting structure that inhibits sag of the weighting agent. In some embodiments, the weighting agent comprises barite particles, particularly barite particles that are less than about 45 ?m in size. Methods for placing the invert emulsion drilling fluids in a subterranean formation via a wellbore are also disclosed.

Abstract: A method of treating a borehole is provided, wherein the method comprises introducing a drilling fluid into a borehole, wherein the drilling fluid comprises an ionic liquid. In particular, the ionic liquid may comprise a single ionic liquid, i.e., only one kind of anion and one kind of cation, or may comprise a mixture of different ionic liquids, e.g., may comprise several different anions and/or several different cations.

Abstract: Designed drilling fluids and methods of designing and using designed drilling fluids are disclosed. In one embodiment, a method of designing a drilling fluid comprises the step of determining a Design Space comprising specified ranges for one or more drilling fluid properties. The method further comprises determining a Final Fluid Formulations Set comprising drilling fluid compositions having drilling fluid properties compatible with the Design Space and satisfying one or more Performance Criterion. The method further comprises selecting a subset of drilling fluid compositions from the Final Fluid Formulations Set. The method further comprises preparing a drilling fluid based on the subset of drilling fluid compositions.

Abstract: Complementary surfactant systems and downhole fluids made using the systems are disclosed along with methods for making and using same, where the surfactant systems include from 0 wt. % to 100 wt. % of a first surfactant subsystem, from 100 wt. % to 0 wt. % of a second surfactant subsystem, and from 0 wt. % to 100 wt. % of a solvent subsystem based on the wt. % of the surfactant subsystems, where the system is tailored to foam the fluid including the analyzed crude and/or condensate.

Abstract: A reduced abrasion drilling fluid system and method of drilling a borehole by circulating the reduced abrasion drilling fluid through the borehole is disclosed. The reduced abrasion drilling fluid comprises a drilling fluid, a first additive and a weighting agent, wherein the weighting agent has a particle size of at least 90% by volume less than 50 ?m.

Abstract: The invention provides laccases, polynucleotides encoding these enzymes, the methods of making and using these polynucleotides and polypeptides.

Abstract: A method comprises providing a drilling fluid comprising: an aqueous fluid; and a microemulsion surfactant; and drilling a well bore in a subterranean formation comprising an oleaginous fluid using the drilling fluid, wherein the microemulsion surfactant forms a microemulsion with the oleaginous fluid within the well bore. In accordance with the method, the subterranean formation has a retained producibility greater than about 50%.

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: Fluids and associated methods useful in subterranean applications are provided. Compositions are provided that may be useful in subterranean applications for addressing, among other things, drill string sticking problems. More particularly, spotting fluid compositions are provided having a water insoluble external phase fluid; a water soluble internal phase fluid; and an ether carboxylic acid emulsifying agent. Additional optional components may be used, such as viscosifiers, weighting agents, and wetting agents.

Abstract: Fluids and associated methods useful in subterranean applications are provided. More particularly, methods of reducing drill string sticking are provided, which include: providing a spotting fluid composition comprising a water insoluble external phase fluid, a water soluble internal phase fluid, and an ether carboxylic acid emulsifying agent; introducing the spotting fluid to the vicinity of a desired portion of a drill string; and allowing the spotting fluid to interact with a portion of material surrounding the desired portion of the drill string spotting fluid. Compositions are provided that may be useful in subterranean applications for addressing, among other things, drill string sticking problems. Additional optional components may be used, such as viscosifiers, weighting agents, and wetting agents.

Abstract: A method of servicing a wellbore comprising preparing a wellbore servicing composition having a target water content, placing the wellbore servicing composition in the wellbore, recovering from the wellbore a recovered wellbore servicing fluid having a modified water content, wherein the modified water content is greater than the target water content, vacuum stripping water from the recovered wellbore servicing fluid to form a processed wellbore servicing fluid, wherein the processed wellbore servicing fluid has a water content less than the modified water content, and placing the processed wellbore servicing fluid in the same or a different wellbore.

Abstract: A method of solubilizing/removing cellulose or chemically-modified cellulosic polymers utilized in subterranean drilling operations such as fracturing. The method involves introducing a deep eutectic solvent (DES) into a subterranean region. Deep eutectic solvents useful as cellulose solvents include quaternary ammonium compounds, including choline chloride and chlorcholine chloride, reacted with a compound selected from amides, amines, carboxylic acids alcohols, and metal halides. The DES material can be pumped downhole after fracturing operations to remove cellulosic material used, for example, to thicken fracturing fluid which is left behind in the created fractures, on the face of the formation, along the wellbore, or elsewhere within the subterranean region. The DES can be used alone or in a sequential treatment protocol, whereby the DES is introduced into the subterranean region, followed by post-treatment introduction of water, caustic, acid or anhydride into the subterranean as a flush.

Abstract: Methods and related systems are configured to treat a drilling fluid to cause water droplets to coalesce. One or more phases are thereafter separated from the treated drilling fluid. The oil and/or solids separated from the treated drilling fluid may be added to a base fluid.

Abstract: A composition of matter and a method of sealing a permeable formation are provided incorporating the composition to reduce or eliminate lost circulation in permeable formations up to at least 6000 psi. The composition comprises one or more sealing components, a wetting component, a viscosifier component, an activator or flocculant component, and an extender. A dry mixture of the components may be added directly from the bag to the drilling mud up to the rate of 90 pounds per barrel. The mixture will seal the formation in an aqueous or organic environment. The mixture de-waters at a rapid rate without regard to the time and temperature required for curing agents or other additives. The mixture may be weighted and does not require additional agents such as defoamers, accelerators, retarders or spacers to de-water and set as a solid plug.

Abstract: A composition for reducing lost circulation in a well, while drilling the well with a drilling mud, which is composed of a base fluid, a mixture of particles, and a blend of fibers. The composition is used by stopping drilling with the mud, injecting a spacer, injecting the water-based composition, injecting a spacer, and resuming drilling with the oil-based mud.

Abstract: A process for minimizing breaking of an emulsion type drilling fluid system comprising one or more fibrous lost circulation material, the process comprising: determining the water retention value of one or more candidate fibrous lost circulation materials; and, formulating the emulsion type drilling fluid system to comprise fibrous lost circulation material consisting of one or more of the candidate fibrous lost circulation materials having a water retention value of about 1 or less.

Abstract: An invert emulsion wellbore fluid comprising an oleaginous continuous phase, an aqueous discontinuous phase, and an emulsifying fluid, wherein the emulsifying fluid comprises an aliphatic alcohol and a glycoside, is disclosed.

Abstract: Methods and compositions are provided that relate to well bore treatments that comprise swellable particles. An embodiment includes a method that comprises introducing a fluid comprising a dual oil/water-swellable particle into a subterranean formation. Another embodiment includes a method of cementing that comprises: introducing a cement composition comprising cement, water, and a dual oil/water-swellable particle into a space between a pipe string and a subterranean formation; and allowing the cement composition to set in the space. Another embodiment includes a well treatment composition comprising a dual oil/water-swellable particle.

Abstract: A method for removing drilling damage from a formation in a wellbore that has not been produced includes injecting a chemical-acting cleanup fluid and contacting it with a filtercake on a face of a formation of interest for a period of time sufficient to loosen some of the solids embedded in the filtercake. The method further includes circulating a solids removal fluid at a high rate through the wellbore across the face of the formation of interest, the solids removal fluid including a viscosifier, and positioning a second treatment fluid having a fluid loss control pill in the wellbore at the formation of interest. The method further includes degrading particles of the fluid loss control pill and degrading remaining bridging agent from the drilling fluid.

Abstract: Equipment and methods for preparing curved fibers in a batch or continuous process. Fiber strands comprising a thermoplastic material are placed on a cylindrical surface and heated such that they soften and become malleable. The fiber strands assume the curvature of the cylindrical surface and, upon cooling below their softening temperature, retain the curvature. The curved-fiber strands are then cut to a desired length.

Abstract: Drilling fluids comprising graphenes and nanoplatelet additives and methods for production thereof are disclosed. Graphene includes graphite oxide, graphene oxide, chemically-converted graphene, and functionalized chemically-converted graphene. Derivatized graphenes and methods for production thereof are disclosed. The derivatized graphenes are prepared from a chemically-converted graphene through derivatization with a plurality of functional groups. Derivatization can be accomplished, for example, by reaction of a chemically-converted graphene with a diazonium species. Methods for preparation of graphite oxide are also disclosed.

Abstract: Among the methods provided is a method of drilling a subterranean well with an invert emulsion fluid comprising: providing an invert emulsion fluid formed by combining components that comprise: an oil-based continuous phase; an aqueous discontinuous phase; and a polar hydrophobic additive that comprises a polar hydrophobe, wherein the polar hydrophobic additive may substantially increases the yield point, the low-shear yield point, or both of the invert emulsion fluid relative to a fluid without a polar hydrophobic additive while limiting the change in the plastic viscosity to no more than about 35% of the change in the property with the largest increase; and placing the invert emulsion fluid in a subterranean formation.

Abstract: A method of treating a formation that includes exposing a region of the formation occupied by a hydrolysable gel to a hydrolyzing agent; and allowing sufficient time for the hydrolyzing agent to hydrolyze the gel. Various methods may also include the use of a swelling agent to allow for expansion of the gel.

Abstract: The present disclosure relates to drilling fluids for use in bitumen recovery from oil sands. In particular, the disclosure relates to a drilling fluid composition containing hydrophobically associating polymers which encapsulate the bitumen, and a method and use of the composition.

Abstract: A method of drilling is disclosed and includes pumping a wellbore fluid into a wellbore through an earth formation, wherein the wellbore fluid comprises a base fluid and a surface active agent capable of altering wettability of fines located in the earth formation, and allowing filtration of at least a portion of the wellbore fluid into the earth formation.

Abstract: A fluid pressure transmission pill (FPTP) having an ultra-high viscosity for use in association with hydrocarbon drilling and exploration operations, particularly, managed pressure drilling (MPD) operations, is described. The ultra-high viscosity pill is a weighted pill composition that includes a hydrocarbon fluid, a thixotropic viscosifying agent, one or more activators, an emulsifier/wetting agent, a fluid loss control additive, and a weighting material. In accordance with selected aspects of the described fluid pressure transmission pill, the ratio of the amount of the thixotropic viscosifying agent to the activator is a ratio of about 7:1, and the weighting material is a barium-containing solid-phase material. Also described are methods of use of such FPTP products in subterranean operations, such as well killing operations during managed pressure drilling.

Abstract: An oil-in-water emulsion that includes a brine continuous phase; and an oleaginous discontinuous phase stabilized by an emulsifier blend, the emulsifier blend comprising: an emulsifier having an HLB greater than 11; and an amphoteric chemotrope is disclosed.

Abstract: A composition for reducing lost circulation in a well, while drilling the well with a drilling mud, which is composed of a base fluid, a mixture of particles, and a blend of fibers. The composition is used by stopping drilling with the mud, injecting a spacer, injecting the water-based composition, injecting a spacer, and resuming drilling with the oil-based mud.

Abstract: A spotting fluid is provided and the spotting fluid consists essentially of: syrup, syrup solids and a liquid medium, said syrup and syrup solids are derived from a group consisting essentially of agave syrup, barley syrup, sugar syrup, beets syrup, birch syrup, rice syrup, cane syrup, chocolate syrup, coconut syrup, corn syrup, date syrup, fruit syrup, golden syrup, high fructose corn syrup, inverted sugar syrup, karo syrup, citrus fruit syrup, maple syrup, molasses, Muscavado syrup, palm syrup, rice syrup, sorghum syrup, Turbinado syrup, vanilla syrup and mixtures and blends thereof, and the liquid medium is selected from a group consisting of water, purified water, ionized water, salt water and mixtures thereof.

Abstract: Various salt crystal and agglomeration settling inhibiting agents may aid the ability to keep salt crystals of a desired particle size undissolved and dissolved in an aqueous drilling fluid, including, whey, wine-making residues, “steepwater solubles” or an organic liquid formed from the residue of wet processing of grains, sugar cane, sugar beets, and similar plants for the food and beverage industries for consumption by human or animals, and combinations thereof. A fluid so treated has more uniform properties and a reduced tendency for the salt therein to settle out as compared to an otherwise identical fluid absent an effective proportion or amount of the salt crystal agglomeration and settling inhibiting agent, even for saturated salt fluids. The salt crystal agglomeration and settling inhibiting agents are also believed to be useful in inhibiting or preventing the formation of gas hydrates under gas hydrate forming conditions of low temperature and high pressure.

Abstract: Methods for drilling and treating for lost returns continuously while drilling are provided. High fluid loss drilling fluid is used, along with particulate material that forms an immobile mass in hydraulic fractures to prevent their growth. The particulate material may be selected based on the predicted size of a hydraulic fracture, based on particle size to minimize fines, based on specific gravity to attain high solids content for a selected fluid density, and/or based on permeability of the particles to a high spurt loss.

Abstract: The invention relates to a tool for use in wellbore drilling, suitable for use with a drill string for drilling a wellbore having an inner wall, the tool comprising means for generating particles of solid material from the formed inner wall of a drilled wellbore, and means for directing the generated particles to the inner wall of the wellbore and a method of forming a layer of solid particles on the inner wall of a wellbore drilled by such a drill string.

Abstract: This invention relates to improved lubrication in drilling and completion fluids used in subterrain drilling for oil and gas. The addition of zinc dialkyl dithiophosphate (ZDDP) acts as a lubricant, an enhancer to other lubricants and rate of penetration enhancer.

Abstract: An engineered composition for reducing lost circulation in a well includes a mixture of coarse, medium and optional fine particles, and a blend of long fibers and short fibers. The long fibers are rigid and the short fibers are flexible. The long fibers form a tridimensional mat or net in the lost-circulation pathway that traps the mixture of particles and short flexible fibers to form a mudcake. The mixture of particles and blend of fibers may be added to water-based and oil-based drilling fluids. The composition, size, and concentration of each component of the mixture of particles and blend of fibers may be fine-tuned for each application.

Abstract: In one embodiment, the present invention provides a silicone-tackifier matrix composition that comprises at least one silicone polymer component, at least one tackifying agent, and at least one curing agent and/or at least one cross linking agent.

Abstract: Disclosed is a composition comprising a chemical formulation useful for creating geosynthetic composites in-situ, which includes a reactive ester having at least one carbon-carbon double bond, preferably a vinyl ester of a C9 to C11 versatic acid or vinyl ester of a long chain fatty acid, or a combination thereof, at least one unsaturated thermoplastic elastomer soluble in the reactive ester; at least one di- or tri-functional acrylate or methacrylate monomer. The formulation may further include a non-aqueous drilling fluid.

Abstract: A method of formulating a wellbore fluid that includes precipitating a weighting agent from a solution; and adding the precipitated weighting agent to a base fluid to form a wellbore fluid is disclosed. Fluids and methods of formulating wellbore fluids that contain dispersant coated precipitated weighting agents are also disclosed.

Abstract: The present invention includes compositions and methods for improving wellbores stability of a hydrocarbon bearing shale formation using nanoparticles to decrease swelling and plug pore throats.

Abstract: A composition of matter and a method of sealing a permeable formation are provided incorporating the composition to reduce or eliminate lost circulation in permeable formations up to at least 5100 psi. The composition comprises one or more sealing components, a wetting component, a viscosifier component, an activator or flocculant component, and an extender. A dry mixture of the components may be added directly from the bag to the drilling mud up to the rate of 90 pounds per barrel. The mixture will seal the formation in an aqueous or organic environment. The mixture de-waters at a rapid rate without regard to the time and temperature required for curing agents or other additives. The mixture may be weighted and does not require additional agents such as defoamers, accelerators, retarders or spacers to de-water and set as a solid plug.

Abstract: A wellbore fluid that includes a base fluid; a weighting agent having a d90 greater than 30 microns; and a micronized weighting agent having a d90 less than 25 microns, the micronized weighting agent comprising less than 30 percent by volume of the total weighting agents is disclosed herein.