Abstract: A method of processing a return oil-based drilling fluid includes centrifuging a primarily fluids phase at a first speed and separating the primarily fluids phase into a first effluent and a first residual, centrifuging the first effluent at a second speed and separating the first effluent into a second effluent and a second residual, and centrifuging the second effluent at a third speed and separating the second effluent into a third effluent and a third residual. A surfactant, a polymer, combinations of surfactant(s) and polymer(s) and/or a wash water may be added to one or more of the return oil-based drilling fluid, the primarily fluids phase, the primarily solids phase, the first effluent, the second effluent, and the third effluent.

Abstract: A proppant for use in fracturing a subterranean formation is characterized by specific mean particle size, particle size standard deviation, and aspect ratio. The proppant is prepared from a thermoplastic composition that includes specific amounts of a polyamide and a poly(phenylene ether). The proppant is useful for propping a fracture in a subterranean formation.

Abstract: An invert emulsion drilling fluid comprises: an external phase, wherein the external phase of the drilling fluid comprises a hydrocarbon liquid; an internal phase, wherein the internal phase of the drilling fluid comprises a hygroscopic liquid; and a suspending agent, wherein the suspending agent is a polymer comprising urea linkages or urea and urethane linkages. The hygroscopic liquid comprises a salt and a suitable solvent or comprises an alcohol. The drilling fluid can exclude an organophilic clay or organophilic lignite. A method of using the invert emulsion drilling fluid comprises: introducing the drilling fluid into at least a portion of a subterranean formation.

Abstract: Methods of treating flowback water from a subterranean formation penetrated by a well bore are provided, comprising: (a) providing remediated flowback water having a ferrous iron (Fe+2) ion concentration of less than about 100 milligrams of ferrous iron ion per liter of flowback water, a barium ion (Ba+2) concentration of less than about 500 milligrams of barium ion per liter of flowback water, and a calcium ion (Ca+) concentration of at least about 1,000 milligrams of calcium ion per liter of remediated flowback water; and (b) treating the flowback water with: (i) at least one friction reducing agent; and (ii) at least one scale formation inhibiting agent and/or at least one iron precipitation control agent to provide treated flowback water which can be reused as fracturing fluid in a well drilling operation.

Abstract: In one aspect, embodiments disclosed herein relate to a wellbore strengthening composition including at least one polymer capable of polymerizing through a free radical polymerization reaction from the group of epoxy acrylates, modified epoxy acrylates, epoxy precursors, modified epoxy vinyl esters, unsaturated polyesters, urethane(meth)acrylates, polyester acrylates, epoxy vinyl ester resins having the wherein R and R1-R5 may be CH3— or H and R6-R21 may be H or Br, and polymer combinations thereof; and at least one initiator, wherein the resin is present in the amount from about 10 to about 90 weight percent.

Abstract: Nanomaterial compositions are useful for applications in drilling and completion fluids as enhancers of electrical and thermal conductivity, emulsion stabilizers, wellbore strength improvers, drag reduction agents, wettability changers, corrosion coating compositions and the like. These nanomaterials may be dispersed in the liquid phase in low volumetric fraction, particularly as compared to corresponding agents of larger size. Nanofluids (fluids containing nano-sized particles) may be used to drill at least part of the wellbore. Nanofluids for drilling and completion applications may be designed including nanoparticles such as carbon nanotubes. These fluids containing nanomaterials, such as carbon nanotubes, meet the required rheological and filtration properties for application in challenging HPHT drilling and completions operations.

Abstract: A plurality of solid particles including a thermoplastic composition having a softening temperature in a range from 50° C. to 180° C. and a blocked isocyanate resin; optionally at least some of the particles in the plurality of solid particles comprise both the thermoplastic composition and the blocked isocyanate resin. A composition comprising the plurality of particles dispersed in a fluid is also disclosed. A method of modifying a wellbore within a geological formation is also disclosed. The method includes introducing the fluid composition into the wellbore. A method of making a plurality of particles, for example, to use in the fluid composition, is also disclosed.

Abstract: Embodiments of the present invention provide compositions and methods for lining a wellbore. In certain aspects, the compositions and methods comprise providing a fluid composition that is solidifiable or gellable on exposure to actinic radiation of a predetermined wavelength at the wall of open-hole wellbore and providing actinic radiation at the predetermined wavelength to solidify or gel the composition. The predetermined wavelength lies in a range from 100 nm to 1500 nm.

Abstract: Disclosed herein is a polymer useful in a method of forming a wellbore fluid additive. This polymer comprises a polyethylene backbone comprising pendant aminoalkylsulfonic acid amides which comprise a carbonyl directly attached to a backbone carbon, and an amide formed via the amine group from the aminoalkylsulfonic acid. Methods of preparing these polymers by addition of the aminoalkylsulfonic acid to a polymeric anhydride are disclosed. Methods related to oil extraction using the wellbore fluid with the additive are also disclosed.

Abstract: Minimizing circulating pressure loss and/or reducing friction in drilling fluid operations to minimize equivalent circulating density (ECD) and maximize flow for borehole cleaning, tool optimization and efficient drilling may be achieved by the addition of friction improvers or drag reducers while circulating drilling fluids. Suitable drag reducers may include, but not necessarily be limited to, poly(alpha-olefins); polyisobutylene; condensation polymers of dicarboxylic acids or anhydrides, or polyols and monocarboxylic acids, addition polymers of unsaturated esters; copolymers of alpha-olefins with unsaturated esters; polystyrene acylated with long chain fatty acids; polyalkylene oxides; copolymers of alkyl acrylates with N-containing olefins; and combinations thereof.

Abstract: A method includes providing a measured dose amount of manufactured metallic nanoparticle material and adding the measured dose amount of the manufactured metallic nanoparticle material to a sub-surface earth activity material to a sub-surface earth activity material for treatment corresponding to the sub-surface earth activity. A composition of silver in the form of silver nanoparticles in suspension having an interior of non-metallic material and a surface of silver dioxide, a maximum diameter less than about 100 nanometers, a minimum diameter of greater than about 2 nanometers, and biocidal properties.

Abstract: A variety of methods and compositions are disclosed, including, in one embodiment, a method of treating a subterranean formation comprising: providing coated particles, wherein the coated particles comprise solid particles coated with an expandable coating; and introducing the coated particles into a permeable zone of the subterranean formation such that the coated particles form a barrier to fluid flow in the permeable zone. In another embodiment, a method of drilling a well bore may be provided, the method comprising: including coated particles in a drilling fluid, the coated particles comprising solid particles coated with an expandable coating; using a drill bit to enlarge the well bore; and circulating the drilling fluid past the drill bit.

Abstract: A sealant composition comprising an inverse emulsion polymer and methods of servicing a wellbore using the same are disclosed. In one embodiment, a method of servicing a wellbore that penetrates a subterranean formation is disclosed. The method comprises placing a sealant composition comprising an inverse emulsion polymer into the wellbore to reduce a loss of fluid to the subterranean formation during placement of the fluid in the wellbore.

Abstract: Methods and fluids are provided that include, but are not limited to, a drilling fluid comprising an aqueous base fluid and a fluid loss control additive that comprises at least one polymeric micro gel and a method comprising: providing an aqueous based treatment fluid comprising a fluid loss control additive that comprises at least one polymeric micro gel; placing the aqueous based treatment fluid in a subterranean formation via a well bore penetrating the subterranean formation; allowing the fluid loss control additive to become incorporated into a filter cake located on a surface within the subterranean formation; allowing the filter cake to be degraded; and producing hydrocarbons from the formation. Additional methods are also provided.

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: Methods and fluids are provided that include, but are not limited to, a drilling fluid comprising an aqueous base fluid and a fluid loss control additive that comprises at least one polymeric micro gel and a method comprising: providing an aqueous based treatment fluid comprising a fluid loss control additive that comprises at least one polymeric micro gel; placing the aqueous based treatment fluid in a subterranean formation via a well bore penetrating the subterranean formation; allowing the fluid loss control additive to become incorporated into a filter cake located on a surface within the subterranean formation; allowing the filter cake to be degraded; and producing hydrocarbons from the formation. Additional methods are also provided.

Abstract: Additives used in treatment fluids include particulate weighting agents comprising removable coatings which can be used in methods such as drilling and cementing operations; a method includes providing a treatment fluid for use in a subterranean formation, the treatment fluid including a coated particulate weighting agent including a core weighting agent having a first specific gravity and a removable polymer coating having a second specific gravity, the first specific gravity and the second specific gravity are not the same, introducing the treatment fluid into the subterranean formation, and allowing a portion of the removable polymer coating to be removed to alter the specific gravity of the coated particulate weighting agent down hole.

Abstract: A treatment fluid comprises: water; a carboxylate; and a corrosion inhibitor, wherein the corrosion inhibitor is a polymer, wherein the polymer comprises silicone, an ether monomer residue, and an amine functional group; wherein a test fluid consisting essentially of the water, the carboxylate, and the corrosion inhibitor, and in the same proportions as in the treatment fluid, is capable of providing a corrosion weight loss to a metal plate of less than 0.05 pounds per square feet (lb/ft2) under testing conditions of 200° F. (93.3° C.), a pressure of 500 psi (3.4 MPa), and a time of 24 hours whereas a substantially identical test fluid without the corrosion inhibitor provides a corrosion weight loss of greater than 0.05 lb/ft2 under the testing conditions. A method of treating a portion of a well comprises: forming the treatment fluid; and introducing the treatment fluid into the well.

Abstract: A method of servicing a wellbore in a subterranean formation comprising placing a wellbore servicing fluid comprising a lost-circulation composite material into a wellbore, wherein the lost-circulation composite material comprises a swellable component and a reinforcing component. A wellbore servicing fluid comprising a reinforcing component disposed within a swellable component wherein the swellable component comprises a crosslinked polymer.

Abstract: The invention provides concentrates for reducing the fluid loss on an oil base well drilling or servicing fluid, the concentrates comprising an oleagineous liquid and (1) a polymer which is solublized in the oleagineous liquid, or (2) a polymer which is solublized in the oleaginous liquid together with an organophilic polyphenolic material which is solublized and/or dispersed in the oleagineous liquid. The method of preparing the concentrate and the method of reducing the fluid loss of an oil base well drilling or servicing fluid utilizing the concentrates is also disclosed. The preferred oil soluble polymer is a styrene-butadiene rubber crumb. The preferred oleagineous liquid is an aromatic-free hydrogenated oil essentially containing only saturated hydrocarbons. The preferred polyphenolic material is a source of humic acid, such as mined lignite.

Abstract: A hydration acceleration surfactant may be utilized in conjunction with high molecular weight polymers in forming high viscosity, aqueous based treatment fluids. Forming such fluids may involve mixing an aqueous base fluid, a hydration acceleration surfactant, a crosslinker polymer, and a base polymer, thereby yielding a treatment fluid, wherein the base polymer is provided in the form of a first polymeric emulsion before mixing and/or the crosslinker polymer is provided in the form of a second polymeric emulsion before mixing. Further, such fluids may be useful in subterranean operations to perform for at least one function within the wellbore and/or the subterranean formation including bridge a fracture, provide fluid loss control, seal a rock surface, enable fluid diversion, plug a void, reduce formation permeability, control water production, and any combination thereof.

Abstract: The invention is related in general to 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: Compositions used in subterranean operations include absorbent polymers useful in controlling fluids within a subterranean formation; a method includes the steps of providing a treatment fluid having an absorbent polymer, the absorbent polymer including an aminoalcohol or polyamine-modified water-soluble polymer which includes a carboxylic acid derivative group, the method further includes placing the treatment fluid in at least a portion of a subterranean formation.

Abstract: A method using a single additive to modify or enhance one or more properties of a drilling fluid for drilling a wellbore in a subterranean formation, prevent lost circulation during the drilling, and/or increase bonding strength during cementing of the wellbore. The additive comprises an oil absorbent material comprising homopolymers or copolymers comprising styrene butadiene, acrylate, phthalate, and carbonate salts.

Abstract: A drilling fluid is provided that comprises a non-ionic or cationic polymer having general formula I or II. The drilling fluid may be used in drilling or other oilfield operations to prevent or limit the accretion of hydrocarbons to metal components when these are in contact with highly viscous hydrocarbons such as those present in formations containing heavy crude oil or tar sand.

Abstract: Methods and compositions useful to prevent scale formation and/or diageneous reactivity on mineral surfaces residing or to be placed in subterranean formations, are provided. In one embodiment, the methods comprise: providing an anionic polymer and a cationic surfactant; contacting a mineral surface with the anionic polymer and the cationic surfactant; and allowing the anionic polymer and the cationic surfactant to interact with each other, whereby a film is formed on at least a portion of the mineral surface.

Abstract: Methods of stabilizing water-sensitive clays in subterranean formations may include introducing a drill-in treatment fluid into at least a portion of a subterranean formation comprising water-sensitive minerals, where providing the drill-in treatment fluid comprises an aqueous-based fluid and a hydrophobically-modified cationic polymer; and allowing the hydrophobically-modified cationic polymer to at least partially coat the water-sensitive mineral.

Abstract: Ester based drilling fluids with enhanced stability at high temperatures for drilling, running casing in, and/or cementing a borehole in a subterranean formation. The drilling fluids comprise a monomeric or polymeric carbodiimide hydrolysis inhibitor.

Abstract: Pre-coated particulate for use in a subterranean operation comprising a particulate; and a film coated onto a surface of the particulate. The film is formed by allowing an anionic polymer and a cationic surfactant to contact the surface of the particulate, and allowing the anionic polymer and the cationic surfactant to interact with each other. In some cases, the anionic polymer is selected from the group consisting of a polyacrylamide; an alkylpolyacrylamide; a copolymer of polyacrylamide, with ethylene, propylene, and styrene; a copolymer of alkylpolyacrylamide with ethylene, propylene, and styrene; a polymaleic anhydride; and any derivatives thereof.

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 mud cake. 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: The present invention relates to bridging agents for use in subterranean formations, to well drill-in and servicing fluids comprising such bridging agents, and to methods of using such bridging agents and well drill-in and servicing fluids in subterranean drilling operations. An example of a well drill-in and servicing fluid of the present invention comprises a viscosified fluid, a fluid loss control additive, and a bridging agent comprising a degradable material.

Abstract: A wellbore servicing composition comprising a filter cake positioned within a wellbore, the filter cake comprising an invert emulsion fluid, the invert emulsion fluid comprising an oleaginous fluid, a non-oleaginous fluid, and an acid-sensitive surfactant, and an emulsion reversing fluid positioned within the wellbore in contact with the filter cake, the emulsion reversing fluid comprising an acid precursor, wherein the acid precursor is not an acid.

Abstract: A dispersion liquid for supporting oil drilling, including: an aqueous medium and a particulate solid polyglycolic acid resin dispersed in the aqueous medium; wherein the particulate polyglycolic acid resin has a weight-average molecular weight of at least 70,000 and at most 500,000, and exhibits weight retentivities in water at 80° C. of at least 85% after 12 hours, at most 80% after 72 hours, and at most 45% after 168 hours. The particulate solid polyglycolic acid resin included in the above-mentioned dispersion liquid for supporting oil drilling, functions as a fluidity control material exhibiting ideal degradation characteristics in the drilling operation for expansion of oil production capacity, demanded for suppressing the liquid permeability in the early stage and recovery of the liquid permeability after completion of the operation of the formation around the oil well.

Abstract: The present invention relates to bridging agents for use in subterranean formations, to well drill-in and servicing fluids comprising such bridging agents, and to methods of using such bridging agents and well drill-in and servicing fluids in subterranean drilling operations. An example of a well drill-in and servicing fluid of the present invention comprises a viscosified fluid, a fluid loss control additive, and a bridging agent comprising a degradable material.

Abstract: A method of servicing a wellbore in contact with a subterranean formation, comprising placing a wellbore servicing fluid comprising a drilling fluid and lost circulation material into a lost circulation zone within the wellbore, wherein the lost circulation material comprises a polyelectrolyte multilayer material and a first counterion. A wellbore servicing fluid comprising a drilling fluid and a lost circulation material comprising a polyelectrolyte multilayer material and a counterion comprising a halide, wherein the LCM has a first state that is hydrophilic. A tunable lost circulation material comprising a base material, a polyelectrolyte multilayer on said base material, wherein the polyelectrolyte multilayer comprises a first electrolyte layer, a second electrolyte layer, and a charged surface, and a counterion, wherein wettability of the lost circulation material is a function of the counterion.

Abstract: In subterranean operations, additives used in treatment fluids such as drilling and cementing fluids include weighting agents; a method includes the steps of providing a treatment fluid for use in a subterranean formation comprising a weighting agent, the weighting agent comprising a micronized metal oxide particle and a polymer linked to the metal oxide particle, the method including introducing the treatment fluid into the subterranean formation.

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: A method for fracture stimulation of a subterranean formation includes providing a thermoset polymer nanocomposite particle precursor composition comprising a polymer precursor mixture, dispersed within a liquid medium, containing at least one of an initiator; at least one of a monomer, an oligomer or combinations thereof, said monomer and oligomer having three or more reactive functionalities capable of creating crosslinks between polymer chains; at least one of an impact modifier; and nanofiller particles substantially dispersed within the liquid medium; subjecting the nanocomposite particle precursor composition to suspension polymerizing conditions; subjecting the resulting nanocomposite particles to heat treatment; forming a slurry comprising a fluid and a proppant that includes the heat-treated nanocomposite particles; injecting the slurry into a wellbore; and emplacing the proppant within a fracture network in the formation.

Abstract: A system for curing lost circulation is made of fibers and a material able to stick fibers in a network when activated. Such activation can be temperature or pH change or both. The fibers can be metallic amorphous fibers, metallic non-amorphous fibers, glass fibers, carbon fibers, polymeric fibers and combinations thereof. The material can be a fiber coating or an additional material, for example polyvinyl alcohol, polyurethane and heat activated epoxy resin.

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: The present application is directed to an aqueous composition made up of an alkali metal silicate; a hardener containing at least one dibasic ester, at least one nonionic surfactant, at least one terpene or terpene derivative and optionally at least one polyalkylene glycol; and a retarder. The composition is useful for reducing the permeability in a subterranean formation, so as to reduce or prevent water flow and circulation loss of well fluids such as drilling fluids or cement.

Abstract: A method for fracture stimulation of a subterranean formation includes providing a thermoset polymer nanocomposite particle precursor composition comprising a polymer precursor mixture, dispersed within a liquid medium, containing at least one of an initiator; at least one of a monomer, an oligomer or combinations thereof, said monomer and oligomer having three or more reactive functionalities capable of creating crosslinks between polymer chains; at least one of an impact modifier; and nanofiller particles substantially dispersed within the liquid medium; subjecting the nanocomposite particle precursor composition to suspension polymerizing conditions; subjecting the resulting nanocomposite particles to heat treatment; forming a slurry comprising a fluid and a proppant that includes the heat-treated nanocomposite particles; injecting the slurry into a wellbore; and emplacing the proppant within a fracture network in the formation.

Abstract: Use of two different methods, either each by itself or in combination, to enhance the stiffness, strength, maximum possible use temperature, and environmental resistance of such particles is disclosed. One method is the application of post-polymerization process steps (and especially heat treatment) to advance the curing reaction and to thus obtain a more densely crosslinked polymer network. The other method is the incorporation of nanofillers, resulting in a heterogeneous “nanocomposite” morphology. Nanofiller incorporation and post-polymerization heat treatment can also be combined to obtain the benefits of both methods simultaneously. The present invention relates to the development of thermoset nanocomposite particles.

Abstract: A method of introducing a drag reducing polymer into a pipeline such that the friction loss associated with the turbulent flow though the pipeline is reduced by suppressing the growth of turbulent eddies. The drag reducing polymer is introduced into a liquid hydrocarbon having an asphaltene content of at least 3 weight percent and an API gravity of less than about 26° to thereby produce a treated liquid hydrocarbon. The treated liquid hydrocarbon does not have a viscosity less than the viscosity of the liquid hydrocarbon prior to treatment with the drag reducing polymer. Additionally, the drag reducing polymer is added to the liquid hydrocarbon in the range from about 0.1 to about 500 ppmw.

Abstract: A method of preparing a drag reducing polymer wherein the drag reducing polymer is able to be injected into a pipeline, such that the friction loss associated with the turbulent flow through the pipeline is reduced by suppressing the growth of turbulent eddies. The drag reducing polymer is injected into a pipeline of liquid hydrocarbon hydrocarbon having an asphaltene content of at least 3 weight percent and an API gravity of less than about 26° to thereby produce a treated liquid hydrocarbon wherein the viscosity of the treated liquid hydrocarbon is not less than the viscosity of the liquid hydrocarbon prior to treatment with the drag reducing polymer. The drag reducing polymer has a solubility parameter within 4 MPa1/2 of the solubility parameter of the liquid hydrocarbon. The drag reducing polymer is also added to the liquid hydrocarbon in the range from about 0.1 to about 500 ppmw.

Abstract: A system for reducing pressure drop associated with the turbulent flow of asphaltenic crude oil through a conduit. The crude oil has a high asphaltene content and/or a low API gravity. Such reduction in pressure drop is achieved by treating the asphaltenic crude oil with a high molecular weight drag reducing polymer that can have a solubility parameter within about 20 percent of the solubility parameter of the heavy crude oil. The drag reducing polymer can also comprise the residues of monomers having at least one heteroatom.

Abstract: A method for breaking the viscosity of an aqueous fluid gelled with a viscoelastic surfactant (VES) includes: providing an aqueous fluid; adding to the aqueous fluid, in any order, components comprising: a VES comprising a non-ionic surfactant, cationic surfactant, amphoteric surfactant or zwitterionic surfactant, or a combination thereof, in an amount sufficient to form a gelled aqueous fluid comprising a plurality of elongated micelles, an unsaturated fatty acid comprising a monoenoic acid or a polyenoic acid; or a combination thereof; and a plurality of metallic particles to produce a mixture comprising dispersed metallic particles in the gelled aqueous fluid. The method also includes dissolving the metallic particles in the gelled aqueous fluid to provide a source of metal ions and heating the gelled aqueous fluid to a temperature sufficient to cause the unsaturated fatty acid to auto-oxidize to products present in an amount effective to reduce the viscosity.

Abstract: A method of introducing a drag reducing polymer into a pipeline such that the friction loss associated with the turbulent flow though the pipeline is reduced by suppressing the growth of turbulent eddies. The drag reducing polymer is introduced into a liquid hydrocarbon having an asphaltene content of at least 3 weight percent and/or an API gravity of less than about 26° to thereby produce a treated liquid hydrocarbon. The treated liquid hydrocarbon does not have a viscosity less than the viscosity of the liquid hydrocarbon prior to treatment with the drag reducing polymer. Additionally, the drag reducing polymer is added to the liquid hydrocarbon in the range from about 0.1 to about 500 ppmw.

Abstract: The present invention provides a filtration control agent and a drilling fluid containing the same. The filtration control agent comprises the product obtained from the reaction of water, lignite, aldehyde and sulfonate polymer at 180-220° C. and the units containing sulfonate groups in the molecular chains of sulfonate polymer are at least 30 wt %. The filtration control agent provided by the present invention features a good filtration loss reduction effect and a low viscosity effect and can improve the rheological behavior of the drilling fluid, thereby meeting the requirements of the drilling of deep wells, ultra-deep wells and ultra high pressure formations.

Abstract: An amphiphilic nanoparticle comprises a nanoparticle having a hydrophilic region comprising a hydrophilic functional group bonded to a first portion of a surface of the nanoparticle, and a hydrophobic region of a surface of the nanoparticle. A downhole fluid comprises the amphiphilic nanoparticle, and a method of controlling an oil spill using the downhole fluid are also disclosed.