Drilling fluids including core-shell polymer particles, and related methods

Abstract

A wellbore fluid includes a base fluid and a swellable fluid loss material comprising core-shell polymer particles. The core-shell polymer particles include a core comprising a nanoparticle, and a shell comprising a polymer coupled to the core, the polymer comprising at least one of a reaction product of acrylamide and 2‑acrylamido-2-methyl-propanesulfonic acid crosslinked with methylene bisacrylamide and tetra ethylene glycol diacrylate, a polyamine, a polyol, a polyvinyl ester, styrene-butadiene rubber, or polymethylmethacrylate. Related methods of operating a wellbore and wellbore fluids are disclosed.

Description

TITLEDRILLING FLUIDS INCLUDING CORE-SHELL POLYMER PARTICLES, AND RELATED METHODSCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This patent application claims priority benefit of United States ProvisionalPatent Application Serial No. 63 / 604501 filed November 30, 2023, which is entirely incorporated herein by reference.BACKGROUND OF THE DISCLOSURE

[0002] Wellbore drilling operations include drilling a bore in a formation to access reservoirs of hydrocarbons and other subsurface resources. During drilling of a wellbore, various fluids may be circulated into the wellbore through a drill pipe and drill bit, and may subsequently flow upward through the wellbore to the surface. For example, a drilling fluid (e.g., an aqueous-based fluid, such as drilling mud) may be pumped down the inside of the drill pipe, through the drill bit, and into the wellbore. The drilling fluid returns to the surface through the annulus. The drilling fluid may lubricate and cool the drill bit and simultaneously facilitate removal of formation cuttings.

[0003] In some instances, undesirable formation conditions may result in the loss of wellbore fluids to the formation. For example, wellbore fluids may leave the borehole through fissures and / or fractures in the formation or through a porous formation material (e.g., a porous rock matrix) surrounding the borehole. To reduce loss of the drilling fluids, the drilling fluid may include one or more fluid loss agents, such as xanthan gum and hydroxyethyl cellulose (HEC).

[0004] During drilling of a wellbore, rather than being circulated back to the wellhead, some of the drilling fluid may flow into the formation via permeable areas of the formation in a phenomenon known as lost circulation. For example, some formations include so-called “thief zones” including relatively large pores and a relatively high porosity suchthat the drilling fluid and / or circulating fluids are lost to the formation. For example, thief zones may include weak portions of the formation, fractured regions of the formation, and zones including cavities, voids, and / or large pores (e.g., vugular formations). Methods of reducing the fluid loss to the thief zones include introducing a pill or a drilling fluid comprising a blend of chemicals formulated to plug the thief zone and reduce the loss of the circulating fluids to the formation.

[0005] The pills may include one or more fluid loss materials formulated and configured to plug pores and openings of the formation within the thief zone. Conventional fluid loss materials include insoluble particles, such as nut shells (e.g., walnut shells, peanut shells), seed shells, mica, ground rubber, plant fibers, and cottonseed hulls. However, the solid particles may prematurely bridge with each other in areas of the tubing strings or downhole equipment or sharp angles. The premature bridging may obstruct desired flow of fluids through the wellbore, drill sting, annulus, and wellbore equipment. In addition, the insoluble particles may not reduce fluid loss to acceptable levels.

[0006] Other fluid loss materials for water-based treatment fluids include nonionic water-soluble polymers, such as starches, derivatized starches, gums, derivatized gums, and cellulosic materials. However, starches may not exhibit uniform properties and, therefore, may not exhibit uniform effectiveness in the formation. In addition, starches are subject to degradation responsive to exposure to temperatures greater than about 121°C (about 250°F). Other fluid loss materials include synthetic polymers, but known synthetic polymers are used with additional additives which may be undesirable.SUMMARY

[0007] In some embodiments, a wellbore fluid comprises a base fluid, and a swellable fluid loss material comprising core-shell polymer particles. Each of the core-shell particles comprise a core comprising a nanoparticle, and a shell comprising a polymer coupled to the core. The polymer comprises at least one of a reaction product of acrylamide and 2-acrylamido-2-methyl-propanesulfonic acid crosslinked with methylene bisacrylamide and tetra ethylene glycol diacrylate, a polyamine crosslinked with a polyglycidyl ether, a polyol crosslinked with epichlorohydrin or divinyl sulfone, a polyvinyl ester crosslinked with a triallyl ether, styrene-butadiene rubber, or polymethylmethacrylate.

[0008] In some embodiments, a wellbore fluid comprises a base fluid, and a fluid loss material comprising core-shell polymer particles comprising core nanoparticles and a polymer shell encapsulating the core nanoparticles. The polymer shell comprises at least one of a crosslinked polymer comprising a reaction product of one or more of a reaction product of acrylamide and 2-acrylamido-2-methyl-propanesulfonic acid and at least two crosslinkers, a crosslinked polyvinyl ester, a crosslinked polyamine, or a polyol crosslinked with epichlorohydrin or divinyl sulfone; styrene butadiene rubber; or polymethylmethacrylate.

[0009] In some embodiments, a method of operating a wellbore comprises pumping a drilling fluid into a wellbore extending through an earth formation. The drilling fluid comprises a base fluid, and a fluid loss material comprising a reaction product of acrylamide and 2-acrylamido-2-methyl-propanesulfonic acid crosslinked with at least two crosslinkers, a polyamine, a polyol crosslinked with at least one of epichlorohydrin or divinyl sulfone, a polyvinyl ester crosslinked with a triallyl ether, styrene-butadiene rubber, and polymethylmethacrylate.BRIEF DESCRIPTION OF THE DRAWINGS

[0010] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments, the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0011] FIG. l is a representation of a drilling system for drilling an earth formation to form a wellbore, according to at least one embodiment of the present disclosure;

[0012] FIG. 2 is a simplified cross-sectional view of a core-shell polymer nanoparticle of a fluid loss material, according to at least one embodiment of the present disclosure;

[0013] FIG. 3 is a simplified schematic illustrating a method of forming core-shell polymer nanoparticles, according to at least one embodiment of the present disclosure;

[0014] FIG. 4 is a simplified schematic illustrating the interaction of the fluid loss material within an earth formation, according to at least one embodiment of the present disclosure; and

[0015] FIG. 5 is a simplified flow diagram illustrating a method of drilling a wellbore, according to at least one embodiment of the disclosure.DETAILED DESCRIPTION

[0016] This disclosure generally relates to devices, systems, and methods for wellbore fluid additives for downhole applications, such as mitigation of fluid loss using one or more fluid loss materials. The fluid additive may be used in a wellbore fluid, such as a drilling fluid, drill-in fluids (also referred to as “reservoir drill -in fluids” (RDF)), workover fluids, spacer fluids (e.g., a fluid introduced into the wellbore after a drilling fluid and prior to a cement composition to flush residual drilling fluid from the annulus), stimulation fluids, or other wellbore fluids. The fluid additive may be referred to herein as a “fluid loss material,” a “lost-circulation material,” a “fluid loss additive,” or a “fluid loss control agent.”

[0017] The fluid loss material may be provided as a component of the wellbore fluid, such as of the drilling fluid. The wellbore fluid may include, for example, a base fluid, the fluid loss material, and one or more additives. The fluid loss material may comprise swellable core-shell particles, the core comprising nanoparticles and the shell comprising one or more polymers encapsulating the core. The core may include nanoparticles of a metal oxide, such as at least one of silicon dioxide (e.g., silica), zirconium oxide (e.g., zirconia), hafnium oxide (e.g., hafnia), aluminum oxide (e.g., alumina), titanium oxide, boron oxide (e.g., boron trioxide), zinc oxide, magnesium oxide, calcium oxide, or iron oxide.

[0018] The core may be encapsulated (e.g., surrounded) by the shell. In some embodiments, and depending on the composition of the shell and the composition of the polymer, the core may be modified with one or more functional groups (e.g., hydrophobic functional groups). In some embodiments, the shell is chemically bonded to the core. The shell may include one or more polymers formulated and configured to interact (e.g.,physically and / or chemically) with the core. The polymers may be crosslinked. In some embodiments, the polymers include one or more of a reaction product of acrylamide (AM) and 2-acrylamido-2-methyl-propanesulfonic acid (AMPS); a polyamine (e.g., polyethyleneimine, polyetheramine); apolyol (e.g., poly(vinyl alcohol)); a vinyl ester (e.g., one or more of vinyl acetate, vinyl propionate, and vinyl laurate); styrene-butadiene rubber (SBR); or polymethyl methacrylate (PMMA). The polymer may be crosslinked with one or more crosslinkers, such as one or more of methylene bisacrylamide (MBA), tetra ethylene glycol diacrylate, a polyglycidyl ether (e g., sorbitol glycidyl ether), epichlorohydrin, divinyl sulfone, or another crosslinker.

[0019] The fluid loss material may be dispersed in, for example, a continuous phase of the wellbore fluid (e.g., the drilling fluid). In some embodiments, the fluid loss material comprises an emulsion, wherein droplets of the fluid loss material are dispersed in a continuous phase of the wellbore fluid.

[0020] The fluid loss material may be formulated and configured to plug pores (e.g., pore throats), voids, vugs, cavities, fissures, cracks, fractures, and other openings of an earth formation through which the wellbore extends, facilitating a reduction or prevention of loss of wellbore fluids (e.g., drilling fluids) to the earth formation. Since the fluid loss material includes core nanoparticles, the fluid loss materials may not be extruded through the pore throats of pores of the earth formation. By way of comparison, fluid loss materials that do not include a solid core, such as soft gel particles, may be extruded through pores under wellbore and earth formation pressures. Accordingly, the fluid loss materials described herein may facilitate plugging of the pores, without substantially being extruded through the pore throats of the earth formation. In addition, the polymer shell of the fluid loss material may be swellable and configured to absorb water.

[0021] FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of drill string 105.

[0022] The drill string 105 may include several joints of drill pipe 108 connected end-to-end through tool joints 109. The drill string 105 transmits drilling fluid through acentral bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected-size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0023] The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and / or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory.

[0024] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.

[0025] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed-cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement,other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface, or may be allowed to fall downhole.

[0026] During drilling operations, a drilling fluid may be used to facilitate lubrication and cooling of the bit 110 and removal of earth formation 101 cuttings. In some embodiments, such as during drilling of sections of the earth formation 101 comprising pores (e.g., pore throats), voids, vugs, cavities, fissures, cracks, fractures, and other openings, the drilling fluid may include one or more fluid loss materials formulated and configured to reduce and / or prevent loss of wellbore fluids (e.g., the drilling fluid) to the earth formation 101, such as through the pores. For example, the fluid loss materials may be formulated and configured to substantially plug pores (e.g., pore throats) of the earth formation 101 in intermediate sections of the wellbore 102.

[0027] The drilling fluid may include a base fluid, the fluid loss material, and one or more additional additives (e.g., one or more of bridging agents, viscosifiers, thinners (e.g., dispersion aids), weighting materials, filtration control agents, shale stabilizers, pH buffers, emulsifiers, corrosion inhibitors, emulsion activators, gelling agents, shale inhibitors, defoamers, surfactants, foaming agents, scale inhibitors, solvents, rheological additives, or other additives).

[0028] In some embodiments, the drilling fluid comprises an aqueous-based drilling fluid or an oil-based drilling fluid, and may be referred to as a “drilling mud.” In some embodiments, such as where the drilling fluid comprises an aqueous-based drilling fluid, the base fluid include water, sea water, brine, or a salt-containing aqueous solution. By way of non-limiting example, the base fluid may include a brine including water and one or more salts (e.g., one or more organic salts and / or one or more inorganic salts).

[0029] In other embodiments, the drilling fluid comprises an oil-based drilling fluid. In some such embodiments, the base fluid comprises an oleaginous or oil-based fluid and may include a natural or synthetic oil. The oleaginous or oil-based fluid may include one or more salts. In some embodiments the oleaginous fluid is selected from the group consisting of at least one of diesel oil, mineral oil, a synthetic oil, (e.g., hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branched olefins) polydiorganosiloxanes, siloxanes, organosiloxanes, or esters of fatty acids (e.g., straight chained, branched and cyclical alkyl ethers of fatty acids).

[0030] The one or more salts (of the aqueous-based drilling fluid or the oil-based drilling fluid) may provide a desired density to the drilling fluid and may also reduce the effect of the drilling fluid on hydratable clays and shales the earth formation 101. The salts may include salts of one or more of sodium, calcium, aluminum, magnesium, zinc, potassium, strontium, or lithium, and salts of one or more of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, or fluorides. In some embodiments, the salt comprises a divalent halide, such as an alkaline earth halide (e.g., calcium chloride (CaCh), calcium bromide (CaB )), or a zinc halide. The salt may include cesium formate (HCOOR), sodium bromide (NaBr), potassium bromide (KBr), and cesium bromide (CsBr). The particular composition of the salt may be selected based on compatibility with the earth formation 101 and / or to match the brine phase of a completion fluid.

[0031] In some embodiments, the weight percent of the salt may be greater than the weight percent of the water in the base fluid. In other embodiments, the weight percent of the salt is less than the weight percent of the water in the base fluid. The water may constitute from about 5.0 volume percent to about 30.0 volume percent of the drilling fluid, such as from about 5.0 volume percent to about 10.0 volume percent, from about 10.0 volume percent to about 20.0 volume percent, or from about 20.0 volume percent to about 30.0 volume percent of the drilling fluid. The salt may constitute from about 30.0 volume percent to about 60.0 volume percent of the drilling fluid, such as from about 30.0 volume percent to about 40.0 volume percent, from about 40.0 to about 50.0 volume percent, or from about 50.0 volume percent to about 60.0 volume percent of the drilling fluid. However, the disclosure is not so limited, and the weight percent of the salt and the water in the drilling fluid may be different than those described.

[0032] As described above, the drilling fluid may include at least one fluid loss material formulated and configured to reduce an amount of wellbore fluid (e.g., the drilling fluid) lost in the earth formation 101, such as in intermediate regions of the earth formation 101 (e.g., regions of the earth formation 101 that are not hydrocarbon producing regions). For example, the fluid loss material may facilitate formation of a filtercake on porous surfaces of the earth formation 101. In some embodiments, the fluid loss material may facilitateplugging of pores (e.g., pore throats) of the earth formation 101 and substantially reduce (e.g., prevent) infdtration of pores of the earth formation 101 by the wellbore fluid.

[0033] The fluid loss material may comprise a core-shell polymer material. FIG. 2 is a simplified cross-sectional view of a core-shell polymer particle 200 of the fluid loss material, according to at least one embodiment of the disclosure. The core shell polymer particle 200 may include a core 202 and a shell 204 surrounding the core 202. The core 202 may include a solid nanoparticle and the shell 204 may include a polymer (e.g., crosslinked polymer). The core-shell polymer particle 200 may comprise a swellable material. For example, the shell 204 may be formulated and configured to swell (e.g., increase in volume) responsive to exposure to water or another fluid (e.g., another liquid).

[0034] The core 202 may include a nanoparticle of a metal oxide, such as silicon dioxide (e.g., silica; SiCh), aluminum oxide (e.g., alumina; AI2O3), aluminosilicate (a compound including oxides of both silicon and aluminum), zirconium oxide (e.g., zirconia; ZrCh), hafnium oxide (e.g., hafnia; HfCh), titanium oxide (e.g., titania; TiCh), boron oxide (e.g., boron trioxide (B2O3)), iron oxide (e.g., Fe2C>3), zinc oxide (ZnO), magnesium oxide (MgO), calcium oxide (CaO), and combinations thereof. In some embodiments, the core 202 comprises silicon dioxide.

[0035] In some embodiments, the core-shell polymer material is provided to the drilling fluid as a silicate solution configured and formulated to form the core-shell polymer particle 200 in-situ. For example, a core-shell polymer particle 200 precursor may be provided to the drilling fluid. The precursor may include a silicate solution (or a corresponding solution, depending on the composition of the core 202) (e.g., sodium silicate, such as one or more of sodium metasilicate, sodium orthosilicate, or sodium pyrosilicate). Responsive to a change in the pH or exposure to an elevated temperature, the core 202 may be formed in-situ to form the core-shell polymer particle 200 in-situ in the drilling fluid.

[0036] In some embodiments, the core 202 is substantially spherical. In other embodiments, a shape of the core 202 may be other than spherical. For example, the core 202 may be plate-shaped, rod-shaped, cuboid-shaped, pyramidal-shaped, or another shape.

[0037] A dimension Di (e.g., a diameter) of the core 202 may be within a range of from about 5 nm to about 25 nm, such as from about 5 nm to about 10 nm, from about 10 nm toabout 15 nm, from about 15 nm to about 20 nm, or from about 20 nm to about 25 nm. However, the disclosure is not so limited, and the dimension Di may be different than those described. The fluid loss material may include core shell polymer particles 200 including cores 202 exhibiting a substantially unimodal size distribution, or may include cores 202 exhibiting a polymodal (e.g., a bimodal) size distribution. In some embodiments, more than 50 percent, such as more than 60 percent, more than 70 percent, or more than 80 percent of the cores 202 have a dimension Di less than the dimension Di described above.

[0038] As illustrated in FIG. 2, the shell 204 may substantially surround and encapsulate the core 202. For example, in some embodiments, the shell 204 completely surrounds and contacts substantially all exterior (e.g., exposed) surfaces of the core 202. A dimension D2 (e.g., a space between an inner surface and an outer surface of the shell 204) may be within a range of from about 5 nm to about 5 pm, such as from about 5 nm to about 10 nm, from about 10 nm to about 25 nm, from about 25 nm to about 50 nm, from about 50 nm to about 100 nm, from about 100 nm to about 300 nm, from about 300 nm to about 500 nm, from about 500 nm to about 1.0 pm, from about 1.0 pm to about 2.0 pm, from about 2.0 pm to about 3.0 pm, or from about 3.0 pm to about 5.0 pm. However, the disclosure is not so limited, and the dimension D2 may be different than that described. For clarity and ease of understanding the description, the relative size of the shell 204 and the core 202 may not be illustrated to scale in FIG. 1.

[0039] The shell 204 may comprise a polymer material. In some embodiments, the shell 204 comprises a crosslinked polymer material. The shell 204 may be formulated and configured to interact (e.g., physically and / or chemically) with the core 202. The polymer may be formed from one or more monomers including acrylamide (AM), 2-acrylamido-2- methyl-propanesulfonic acid (AMPS), a polyamine (e.g., polyethyleneimine, polyetheramine), a polyol (e.g., poly(vinyl alcohol)), a vinyl ester, styrene, butadiene, methyl methacrylate, methacrylamide, N-methylolacrylamide, (meth)acrylic acid alkyl esters, N,N-dimethylacrylamide, N-isopropylacrylamide, acrylic acid and salts thereof, dimethylaminopropyl methacrylamide (DMAPMA), methacylamido propyltrimethylammonium chloride (MAPTAC), N,N-dimethyl-N,N-diallyl ammonium chloride (DADMAC), [3-(acryloylamino)propyl]trimethyl ammonium chloride (APTAC), 2-acryloyloxyethyltrimethyl ammonium chloride (AETAC),2-methacryloyloxyethyltrimethyl ammonium chloride (METAC), acryloyloxyethyldimethylbenzyl ammonium chloride (AEDBAC), methacryloyloxyethyldimethylbenzyl ammonium chloride (MEDBAC), glycidyl group- containing monomers, phosphoric acid group-containing monomers, or alkyl vinyl ether monomers.

[0040] In some embodiments, the polymers include one or more of a reaction product of acrylamide and 2-acrylamido-2-methyl-propanesulfonic acid; a polyamine (e.g., polyethyleneimine, polyetheramine); a polyol (e.g., poly (vinyl alcohol)); a polyvinyl ester (e.g., one or more of poly(vinyl acetate), polyfvinyl propionate), or poly(vinyl laurate)); styrene-butadiene rubber (SBR); or polymethyl methacrylate (PMMA).

[0041] The polymer may be crosslinked with one or more crosslinkers, such as one or more of methylene bisacrylamide (MBA), tetra ethylene glycol diacrylate, a polyglycidyl ether (e.g., sorbitol polyglycidyl ether), epichlorohydrin, divinyl sulfone, a triallyl ether (e.g., pentaerythritol triallyl ether), propanediol divinyl ether, triallyl phosphate, triallyl isocyanurate, pentaerythritol triacrylate, 1,1,1 -trimethylolpropane triacrylate, 1,1,1- trimethylolpropane trimethacrylate, dipentaerythritol pentaacrylate, pentaerythritol tetraacrylate, triallyl cyanurate, butanediol divinyl ether, tetraallyl pentaerythritol, tetraallyl ortho silicate, tetraallyl 1,2,3,4-cyclopentanetetracarboxylate, tetraallyl silane, tetraallyl pyromellitate, pentaerythritol tetraallyl ether, and N,N,N',N'-tetraallyl-2,6- pyridinedicarboxamide, l,2,3,5,5-pentaallyl-l,3-cyclopentadiene, or poly(allyl glycidyl ether)-b-poly(ethylene oxide)-b-poly(allyl glycidyl ether). The crosslinkers may include one or more of acrylate diesters of diols such as glycols, acrylate diesters, triesters, or higher functionality esters of polyols including sugar alcohols (e.g., glycerol, erythritol, sorbitol) and sugars. In some embodiments, the crosslinkers comprise one or more of methylene bisacrylamide, tetra ethylene glycol diacrylate, sorbitol polyglycidyl ether, epichlorohydrin, divinyl sulfone, or a triallyl ether.

[0042] The crosslinkers may constitute from about 0.1 weight percent to about 5.0 weight percent of the polymer, such as from about 0.1 weight percent to about 0.2 weight percent, from about 0.2 weight percent to about 0.3 weight percent, from about 0.3 weight percent to about 0.5 weight percent, from about 0.5 weight percent to about 1.0 weight percent, from about 1.0 weight percent to about 3.0 weight percent, or from about 3.0weight percent to about 5.0 weight percent of the polymer. However, the disclosure is not so limited, and the weight percent of the crosslinkers in the polymer may be different than those described.

[0043] By way of non-limiting example, in some embodiments, the shell 204 may include a polymer comprising a reaction product of acrylamide and 2-acrylamido-2- methyl-propanesulfonic acid; a polyamine, such as polyethyleneimine or polyetheramine; or a polyol, such as poly(vinyl alcohol). In some such embodiments, the polymer may be crosslinked, such as with one or more of methylene bisacrylamide, tetra ethylene glycol diacrylate, sorbitol polyglycidyl ether, epichlorohydrin, or divinyl sulfone.

[0044] In some embodiments, the polymer is crosslinked with at least two crosslinkers. In some embodiments, the polymer comprises a reaction product of acrylamide and 2-acrylamido-2-methyl-propanesulfonic acid, and is crosslinked with at least two crosslinkers. For example, the at least two crosslinkers may include at least two of methylene bisacrylamide, tetra ethylene glycol diacrylate, a polyglycidyl ether (e.g., sorbitol polyglycidyl ether), epichlorohydrin, and divinyl sulfone. In some embodiments, the at least two crosslinkers include methylene bisacrylamide and at least one additional crosslinker. In some embodiments, the at least two crosslinkers include tetra ethylene glycol diacrylate and at least one additional crosslinker. In some embodiments, the at least two crosslinkers comprise methylene bisacrylamide and tetra ethylene glycol diacrylate.

[0045] In some embodiments, the shell 204 comprises a polymer of a polyamine crosslinked with sorbitol polyglycidyl ether. The polyamine may include, for example, polyethyleneimine, a polyetheramine, or both. In other embodiments, the shell 204 comprises a polymer of polyol, such as poly(vinyl alcohol), crosslinked with at least one of epichlorohydrin or divinyl sulfone.

[0046] In some embodiments, the core-shell polymer particles 200 are formed by instill polymerization using an inverse emulsion wherein the oil phase is the continuous phase and the aqueous phase is the discontinuous phase dispersed in the continuous oil phase. In some embodiments, the core 202 nanoparticles are suspended in the discontinuous phase with the hydrophilic (e.g., water soluble) monomers. In addition, in some embodiments, the discontinuous phase may include one or more of the crosslinkers (e.g., at least two of the crosslinkers) described above. The inverse emulsion may include one or moresurfactants formulated and configured to stabilize the discontinuous aqueous phase. Polymerization may be initiated (e.g., with one or more initiators) to polymerize the monomers in the presence of the core 202 nanoparticles to form the core-shell polymer particle 200 wherein the shell 204 is formed in-situ around the core 202 nanoparticles. The polymerization initiator may include, for example, azobisisobutyronitrile (AIBN), a redox initiator system (e.g., including an oxidizer and a reducing agent), or another initiator. In some embodiments, the initiator includes an initiator system including tert-butyl hydroperoxide and sodium metabisulfite.

[0047] The size of the core-shell polymer particle 200 may be based on the size of the droplets of the discontinuous phase in which the core-shell polymer particles 200 are formed. In some embodiments, the resulting emulsion including the core-shell polymer particles 200 are provided to the wellbore fluid (e.g., the drilling fluid). In other embodiments, the core-shell polymer particles 200 are separated (e.g., dried) from the emulsion and provided to the drilling fluid as a solid.

[0048] In some embodiments, the shell 204 may substantially surround and encapsulate the core 202 and may not be chemically bonded to the core 202. For example, the interaction between the shell 204 and the core 202 may be physical. In other embodiments, the shell 204 may be chemically bonded (e.g., covalently bonded) to the core 202. For example, depending on the composition of the shell 204, such as when the shell 204 comprises a hydrophobic material, the shell 204 may be chemically bonded to the core 202. FIG. 3 is a simplified schematic illustrating a method 300 of forming core-shell polymer particles 306, according to at least one embodiment of the disclosure.

[0049] With reference to FIG. 3, a nanoparticle 302 may include exposed functional groups, such as exposed hydroxyl (-OH) groups. Although FIG. 3 illustrates only one hydroxyl group on the nanoparticle 302, it will be understood that the nanoparticle 302 may include multiple hydroxyl groups. The nanoparticle 302 may include one or more of the core 202 nanoparticles described above with reference to FIG. 2. For example, the nanoparticle 302 may include silica, alumina, aluminosilicate, zirconia, hafnia, titania, boron oxide, iron oxide, zinc oxide, magnesium oxide, and calcium oxide. In some embodiments, the nanoparticle 302 comprises silica.

[0050] The nanoparticles 302 may be hydrophobically modified to form hydrophobically modified nanoparticles 304 to facilitate dispersion of the hydrophobically modified nanoparticles 304 in one or more hydrophobic monomers. The nanoparticles 302 may be reacted with one or more functional groups exhibiting hydrophobic properties to form the hydrophobically modified nanoparticles 304. For example, with reference to FIG. 3, the nanoparticles 302 may be reacted with 3-(methyacryloyloxy) propyltrimethoxysilane (MPTS) (also referred to as 3 -(trimethoxy silyl) propyl methacrylate) to form the hydrophobically modified nanoparticles 304.

[0051] While FIG. 3 illustrates that the nanoparticles 302 are reacted with 3-(methyacryloyloxy) propyltrimethoxy silane to form the hydrophobically modified nanoparticles 304, the disclosure is not so limited. In some embodiments, the nanoparticles 302 are reacted with one or more other compounds in a hydrolysis reaction to form the hydrophobically modified nanoparticles 304. By way of non-limiting example, the nanoparticles 302 may be reacted with a compound having the formula [R'(3-X)(OR'')x]SiR'', wherein x is 1, 2, or 3; R' is methyl or ethyl; R" is methyl or ethyl; and R"' is an alkyl group (unsubstituted or substituted) or another functional group. In some embodiments, R'" comprises an alkyl chain with one or more amine groups. In some embodiments, R"' comprises a polymerizable group, such as acrylate or acrylamide. In some embodiments, R"' comprises one or more ester groups.

[0052] After forming the hydrophobically modified nanoparticles 304, the hydrophobically modified nanoparticles 304 may be dispersed within one or more monomers (e.g., hydrophobic monomers) to form the core-shell polymer particles 306. The core-shell polymer may include a core 308 including the nanoparticle 302 surrounded by the polymer 310 chemically bonded to the core 308 and / or to the hydrophobic groups chemically bonded to the core 308. In some embodiments, the polymer 310 is chemically bonded to the hydrophobic groups and the hydrophobic groups bridge between the polymer 310 and the core 308. For example, in some embodiments, a portion of the monomers may react with the carbon-carbon double bonds of the hydrophobic groups, and another portion of the monomers polymerize with one another to form a polymer, which interacts with the hydrophobically modified nanoparticles 304.

[0053] The monomers (from which the polymer 310 is formed) may include one or more of vinyl esters (e.g., vinyl acetate, vinyl propionate, vinyl laurate, vinyl valerate, vinyl caprate, vinyl stearate, vinyl benzoate, vinyl pivalate), styrene, butadiene, methyl (meth)acrylate, (meth)acrylic acid alkyl ester monomers (e.g., butyl (meth)acrylate, and 2- ethylhexyl (meth)acrylate), unsaturated amide monomers (e.g., (meth)acrylamide and N- methylolacrylamide), unsaturated carboxylic acid monomers (e.g., (meth)acrylic acid, crotonic acid, maleic acid, itaconic acid, fumaric acid), alkyl (e.g., methyl, ethyl, propyl, etc.) ester monomers of unsaturated carboxylic acids, unsaturated carboxylic acid anhydrides, glycidyl group-containing monomers (e.g., allyl glycidyl ether, glycidyl (meth)acrylate), or alkyl vinyl ether monomers. In some embodiments, the monomers include one or more of vinyl acetate, vinyl propionate, or vinyl laurate. In other embodiments, the monomers include styrene and butadiene. In some embodiments, the monomers include methylmethacrylate.

[0054] The polymers may be crosslinked with one or more crosslinkers, such as one or more of propanediol divinyl ether, triallyl ethers, triallyl phosphate, triallyl isocyanurate, pentaerythritol triacrylate, 1,1,1 -trimethylolpropane triacrylate, 1,1,1 -trimethylolpropane trimethacrylate, dipentaerythritol pentaacrylate, pentaerythritol tetraacrylate, triallyl cyanurate, butanediol divinyl ether, tetraallyl pentaerythritol, tetraallyl ortho silicate, tetraallyl 1,2,3,4-cyclopentanetetracarboxylate, tetraallylsilane, tetraallyl pyromellitate, pentaerythritol tetraallyl ether, and N,N,N',N'-tetraallyl-2,6-pyridinedicarboxamide, or l,2,3,5,5-pentaallyl-l,3-cyclopentadiene. In some embodiments, the polymers are crosslinked with a triallyl ether.

[0055] In some embodiments, the polymers comprise a polyvinyl ester, such as poly(vinyl acetate), poly(vinyl propionate), and poly(vinyl laurate), and the polymer is crosslinked with a triallyl ether. The triallyl ether may include, for example, triallyl- isocyanurate, pentaerythritol triallyl ether, or both. In other embodiments, the polymer comprises SBR and may or may not be crosslinked. In further embodiments, the polymer comprises polymethylmethacrylate and may or may not be crosslinked.

[0056] The core 202 may constitute from about 0.1 weight percent to about 20.0 weight percent of the core-shell polymer particle 200, such as from about 0.1 weight percent to about 0.2 weight percent, from about 0.2 weight percent to about 0.5 weight percent, fromabout 0.5 weight percent to about 1.0 weight percent, from about 1.0 weight percent to about 3.0 weight percent, from about 3.0 weight percent to about 5.0 weight percent, from about 5.0 weight percent to about 10.0 weight percent, from about 10.0 weight percent to about 15.0 weight percent, or from about 15.0 weight percent to about 20.0 weight percent of the core-shell polymer particle 200. The shell 204 may constitute from about 80.0 weight percent to about 99.9 weight percent of the core-shell polymer particle 200, such as from about 80.0 weight percent to about 85.0 weight percent, from about 85.0 weight percent to about 90.0 weight percent, from about 90.0 weight percent to about 95.0 weight percent, from about 95.0 weight percent to about 97.0 weight percent, from about 97.0 weight percent to about 99.0 weight percent, from about 99.0 weight percent to about 99.5 weight percent, from about 99.5 weight percent to about 99.8 weight percent, or from about 99.8 weight percent to about 99.9 weight percent of the core-shell polymer particle 200. Similarly, the core 308 may constitute from about 0.1 weight percent to about 20.0 weight percent of the core-shell polymer particles 306; and the polymer 310 may constitute from about 80.0 weight percent to about 99.9 weight percent of the core-shell polymer particles 306.

[0057] The core-shell polymer particles 200, 306 may constitute from about 0.1 weight percent to about 5.0 weight percent of the drilling fluid, such as from about 0.1 weight percent to about 0.2 weight percent, from about 0.2 weight percent to about 0.3 weight percent, from about 0.3 weight percent to about 0.5 weight percent, from about 0.5 weight percent to about 1.0 weight percent, from about 1.0 weight percent to about 2.0 weight percent, from about 2.0 weight percent to about 3.0 weight percent, or from about 3.0 weight percent to about 5.0 weight percent of the drilling fluid. In addition, the core-shell polymer particles 200, 306 may constitute from about 1.0 volume percent to about 5.0 volume percent of the drilling fluid, such as from about 1.0 volume percent to about 2.0 volume percent, from about 2.0 volume percent to about 3.0 volume percent, or from about 3.0 volume percent to about 5.0 volume percent of the drilling fluid.

[0058] While the core-shell polymer particles 200 and the core-shell polymer particles 306 have been described and illustrated as each individually including a single core 202, 308 surrounded by the polymer (e.g., the respective shell 204 and the polymer 310), the disclosure is not so limited. In other embodiments, multiple core nanoparticles may besurrounded by a polymer and the core-shell polymer particles 200, 306 may individually include multiple nanoparticle cores. In some embodiments, each of the nanoparticle cores comprise substantially the same material composition. In other embodiments, at least one of the nanoparticle cores comprises a different material composition than at least another of the nanoparticle cores.

[0059] The drilling fluid may further include one or more additives selected based on the desired properties of the drilling fluid. As discussed above, and by way of non-limiting example, the one or more additional additives may include one or more of bridging agents, viscosifiers, thinners, weighting materials, filtration control agents, shale stabilizers, pH buffers, emulsifiers, corrosion inhibitors, emulsion activators, gelling agents, shale inhibitors, defoamers, surfactants, foaming agents, scale inhibitors, solvents, rheological additives, or other additives that may be suitable depending on the particular operation.

[0060] The bridging agents may include one or more of calcium carbonate, magnesium citrate, calcium citrate, calcium succinate, calcium maleate, calcium tartrate, magnesium tartrate, bismuth citrate, other suspended salts, mica, nutshells, or fibers.

[0061] Viscosifiers of the drilling fluid may include a material formulated and configured to increase the viscosity of the drilling fluid and, optionally, to facilitate formation of a filtercake between the earth formation 101 and one or more of (e.g., each of) the drill string 105, casing 107, and liners. The viscosifier may include, for example, a polymer (e.g., a copolymer) formed from at least one acrylamide monomer and at least one sulfonated anionic monomer. In other words, the viscosifier may include a reaction product of the at least one acrylamide monomer and at least one sulfonated anionic monomer. In other embodiments, the first component comprises a higher order copolymer and / or block copolymers, such as a terpolymer, a quaternary polymer, or another higher order polymer including the at least one acrylamide monomer and the at least one sulfonated anionic monomer.

[0062] The at least one acrylamide monomer may include one or more of acrylamide, unsubstituted acrylamide, methacrylamide, N-substituted acrylamides (e.g., alkylacrylamides, N-methylolacrylamide, N-isopropylacrylaminde, diacetone acrylamide, N-alkyl acrylamide (where alkyl is Ci to CM), and N,N-dialkyl acrylamides (where alkyl is Ci (e.g., N,N-dimethylacrylamide) to Cu), N-cycloalkane, N-(2-hydroxyethyl)acrylamide, N-isopropyl acrylamide, N-[3-(dimethylamino)propyl] acrylamide, or acryloyl morpholine). In embodiments wherein the at least one acrylamide monomer comprises an N-substituted acrylamide, the N-substituted acrylamide may comprise N,N- dialkyl acrylamides (e.g., N,N-dimethylacrylamide). The alkyl groups of the N,N-dialkyl acrylamides may be linear, branched, or cyclic. In some embodiments, the at least one acrylamide monomer comprises N,N-dimethylacrylamide.

[0063] The at least one sulfonated anionic monomer may include one or more of 2-acrylamido-2-methyl-propanesulfonic acid (also referred to as acrylamide tertiary butyl sulfonic acid (ATBS)), vinyl sulfonates, styrene sulfonic acid, allyl sulfonates, or styrene sulfonic acid. The at least one sulfonated anionic monomer may facilitate tolerance of the viscosifier to divalent cations in the drilling fluid brine, such as calcium and magnesium. In some embodiments, the at least one sulfonated anionic monomer is provided as a salt, such as an ammonium salt. For example, the at least one sulfonated anionic monomer may be provided as an ammonium salt of 2-acrylamido-2-methyl-propanesulfonic acid or a sodium salt of 2-acrylamido-2-methyl -propanesulfonic acid.

[0064] The viscosifier may constitute from about 0.5 weight percent to about 6.0 weight percent of the drilling fluid, such as from about 0.5 weight percent to about 1.0 weight percent, from about 1.0 weight percent to about 2.0 weight percent, from about 2.0 weight percent to about 3.0 weight percent, or from about 3.0 weight percent to about 6.0 weight percent of the drilling fluid. However, the disclosure is not so limited, and the weight percent of the viscosifier in the drilling fluid may be different than that described.

[0065] Wellbore fluid thinners may include lignosulfates, lignitic materials, modified lignosulfonates, polyphosphates, tannin, and polyacrylates. The thinners may facilitate improved rheological properties of the drilling fluid (e.g., a reduction in flow resistance) and a reduction in gel development. In addition, the thinner may reduce a thickness of filtercakes formed by the drilling fluid, counteract the effects of salts, and reduce the effects of water on the earth formation 101.

[0066] Weighting materials (also referred to as “weighting agents”) may include one or more of barite (BaSO4), iron oxide (e.g., Fe20s, Fe O^, calcium carbonate (CaCCh), magnesium carbonate (MgCCh), manganese oxide (MnsCk), or combinations thereof. Theweighting material may be present in the drilling fluid and facilitate increasing the density of the drilling fluid up to about 2.88 g / cm3(about 24 pounds per gallon (ppg)).

[0067] The pH buffer may include an amine stabilizer, such as one or more of triethanolamine (CeHisNCE) (TEOA), methyldiethanol amine (C5H13NO2) (MDEA), dimethylethanol amine (C4H11NO) (DMEA), diethanol amine (C4H11NO2) (DEA), monoethanol amine (MEA), cyclic organic amines, sterically hindered amines, amides of fatty acid, or other suitable tertiary, secondary, or primary amines and ammonia. In some embodiments, the pH buffer includes magnesium oxide.

[0068] The emulsifiers may include calcium polyvalent metal soaps, phosphate esters, fatty acids, fatty acid soaps, alkylbenzene sulfonate, lime, amidoamines, and imidazolines. The corrosion inhibitor may include iron oxide, aluminum bisulfate, zinc carbonate, zinc chromate, an amine, or another material. The gelling agent may include one or more of a clay and a crosslinked polyvinylpyrrolidone, an acrylamide copolymer, guar, sodium bentonite, or another material. The shale inhibitor may include one or more of amine tartaric salt, ammonium lauric salt, polyammonium, alkyl diammonium, an amphoteric polymer, an organosilicate polymer, a silicone polymer, or another material. Defoamers may include one or more of 2-octanol, oleic acid, paraffinic waxes, amide waxes, sulfonated oils, organic phosphates, silicone oils, mineral oils, or dimethylpolysiloxane.

[0069] The surfactants may include anionic surfactants, cationic surfactants, and / or non-ionic surfactants. The foaming agents may include a nonionic surfactant including polymeric materials. The scale inhibitors may include an acrylic acid polymer, a maleic acid polymer, or a phosphonate. The solvents may include hydrocarbon solvents.

[0070] A density of the drilling fluid may be within a range of from about 1,080 kg / m3to about 2,300 kg / m3, such as from about 1,080 kg / m3to about 1,200 kg / m3, from about 1,200 kg / m3to about 1,400 kg / m3, from about 1,400 kg / m3to about 1,600 kg / m3, from about 1,600 kg / m3to about 1,800 kg / m3, from about 1,800 kg / m3to about 2,000 kg / m3, or from about 2,000 kg / m3to about 2,300 kg / m3. However, the disclosure is not so limited, and the density of the drilling fluid may be different than that described.

[0071] In use and operation, the fluid loss material may be added to a wellbore fluid, such as to a drilling fluid. The fluid loss material may plug pores of the earth formation 101 to substantially reduce the volume of wellbore fluid (e g., drilling fluid) lost to theearth formation 101. FIG. 4 is a simplified schematic illustrating the interaction of the fluid loss material within an earth formation 101, according to at least one embodiment of the disclosure. The earth formation 101 may include pores 402. Neighboring portions of the earth formation 101 may define pore throats 404 defined by relatively narrower portions of the earth formation 101. The fluid loss material including core-shell polymer particles 406 may substantially plug the pore throats 404 defined within the earth formation 101 to substantially reduce (e.g., prevent) a volume of the wellbore fluid lost to porous regions of the earth formation 101. The core-shell polymer particles 406 may correspond to the coreshell polymer particles 200 or the core-shell polymer particles 306 described above with reference to FIG. 2 and FIG. 3. As described above, the core-shell polymer particles 406 may include a core 408 and a polymer shell 410. Without being bound by any particular theory, it is believed that the rigid structure of the core 408 of the core-shell polymer particles 406 substantially reduce (e.g., prevent) the deformation of the core-shell polymer particles 406 responsive to exposure to excessive pressures (e.g., such as encountered within the wellbore 102 and the earth formation 101). Since the core 408 does not substantially deform, the core-shell polymer particles 406 may plug the pore throats 404, reducing infiltration of the wellbore fluid into the earth formation 101. By way of comparison, conventional fluid loss materials comprising gels may deform under earth formation pressures, causing such fluid loss materials to infiltrate the porous regions of the earth formation 101.

[0072] In some embodiments, the fluid loss material may form a filtercake on surfaces of the earth formation 101, such as between the wellbore 102 (e.g., the drill string 105, liners) and the earth formation 101.

[0073] FIG. 5 is a simplified flow diagram illustrating a method 500 of operating a wellbore, according to at least one embodiment of the disclosure. The method 500 includes pumping a drilling fluid including a fluid loss material into an earth formation, as shown at act 502. The fluid loss material may include one or more of the fluid loss materials described above. The drilling fluid may include, for example, a base fluid, the fluid loss material, and one or more additives, as described above. The fluid loss material may be provided to the drilling fluid as an emulsion, or as a solid.

[0074] The method 500 may further include drilling the earth formation while pumping the drilling fluid into the earth formation, as shown at act 504. In some embodiments, the drilling fluid is circulated through the drill string, out of the drill bit, and through the annulus between the drill string and the earth formation. The drilling fluid may facilitate removal of cuttings from the wellbore as the drilling fluid circulates through the wellbore.

[0075] With continued reference to FIG. 5, the method 500 may include forming a fdtercake on surfaces of the earth formation, as shown at act 506. In some embodiments, a filtercake is formed on surfaces of the earth formation defining the wellbore. The filtercake may be formed of and include the fluid loss material. For example, the filtercake may include the core-shell polymer nanoparticles, wherein the nanoparticle cores are dispersed in the polymer shell. In some embodiments, the polymer shells of the core-shell polymer nanoparticles form a substantially continuous network.

[0076] In some embodiments, the method 500 may further include, responsive to forming a filtercake on surfaces of the earth formation, continuing drilling the earth formation. For example, additional zones (e.g., intermediate zones, hydrocarbon producing zones) of the earth formation may be drilled after forming the filtercake on surfaces of the earth formation (e.g., such as on surfaces of the earth formation within an intermediate zone).

[0077] The embodiments of drilling fluids and the fluid loss materials have been primarily described with reference to wellbore drilling operations; the drilling fluids and the fluid loss materials described herein may be used in applications other than the drilling of a wellbore. In other embodiments, drilling fluids and fluid loss materials according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, drilling fluids and fluid loss materials of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole,” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

[0078] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not allfeatures of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers’ specific goals, such as compliance with system-related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0079] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0080] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition,deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0081] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

[0082] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

CLAIMSWhat is claimed is:

1. A wellbore fluid, comprising: a base fluid; and a swellable fluid loss material comprising core-shell polymer particles, each core-shell particle comprising: a core comprising a nanoparticle; and a shell comprising a polymer coupled to the core, the polymer comprising at least one of: a reaction product of acrylamide and 2-acrylamido-2-methyl- propanesulfonic acid crosslinked with methylene bisacrylamide and tetra ethylene glycol diacrylate; a polyamine crosslinked with a polyglycidyl ether; a polyol crosslinked with epichlorohydrin or divinyl sulfone; a polyvinyl ester crosslinked with a triallyl ether; styrene-butadiene rubber; or polymethylmethacrylate.

2. The wellbore fluid of claim 1, wherein the wellbore fluid comprises a drilling fluid.

3. The wellbore fluid of claim 1, wherein the shell comprises a polyol comprising poly(vinyl alcohol) crosslinked with sorbitol polyglycidyl ether.

4. The wellbore fluid of claim 1, wherein the nanoparticle comprises at least one of silica, zirconia, hafnia, alumina, boron oxide, zinc oxide, magnesium oxide, calcium oxide or iron oxide.

5. The wellbore fluid of claim 1, wherein the nanoparticle is functionalized with one or more hydrophobic groups.

6. The wellbore fluid of claim 5, wherein the polymer is chemically bonded to the one or more hydrophobic groups.

7. The wellbore fluid of claim 1, wherein the nanoparticle has a dimension within a range of from about 5 nm to about 25 nm.

8. The wellbore fluid of claim 1, wherein the polymer comprises a polyvinyl ester comprising at least one of poly(vinyl acetate), poly(vinyl propionate), or poly (vinyl laurate).

9. The wellbore fluid of claim 1, wherein the polymer comprises the reaction product of acrylamide and 2-acrylamido-2-methyl-propanesulfonic acid.

10. The wellbore fluid of claim 1, wherein the polymer comprises a polyamine comprising at least one of polyethyleneimine or poly etheramine.

11. The wellbore fluid of claim 1, wherein the polymer comprises at least one of styrene-butadiene rubber or polymethylmethacrylate.

12. The wellbore fluid of claim 1, wherein the swellable fluid loss material constitutes from about 0.1 weight percent to about 5.0 weight percent of the wellbore fluid.

13. The wellbore fluid of claim 1, wherein the core constitutes from about 0.1 weight percent to about 20.0 weight percent of the core-shell polymer particle.

14. A wellbore fluid, comprising: a base fluid; and a fluid loss material comprising core-shell polymer particles comprising: core nanoparticles; and a polymer shell encapsulating the core nanoparticles, the polymer shell comprising at least one of: a crosslinked polymer comprising a reaction product of at least one of: a reaction product of acrylamide and 2-acrylamido- 2-methyl -propanesulfonic acid and at least two crosslinkers; a crosslinked polyvinyl ester; a crosslinked polyamine; or a polyol crosslinked with epichlorohydrin or divinyl sulfone; styrene butadiene rubber; or polymethylmethacrylate.

15. The wellbore fluid of claim 14, wherein the at least two crosslinkers are selected from the group consisting of methylene bisacrylamide, tetra ethylene glycol diacrylate, a polyglycidyl ether, epichlorohydrin, and divinyl sulfone.

16. The wellbore fluid of claim 14, wherein: the polymer shell comprises a crosslinked polymer; and crosslinkers constitute from about 0.1 weight percent to about 5.0 weight percent of the crosslinked polymer.

17. The wellbore fluid of claim 14, wherein the polymer shell encapsulates a plurality of core nanoparticles.

18. A method of operating a wellbore, the method comprising: pumping a drilling fluid into a wellbore extending through an earth formation, the drilling fluid comprising: a base fluid; and a fluid loss material comprising: a reaction product of acrylamide and 2-acrylamido-2-methyl- propanesulfonic acid crosslinked with at least two crosslinkers; a polyamine; a polyol crosslinked with at least one of epichlorohydrin or divinyl sulfone; a polyvinyl ester crosslinked with a triallyl ether; styrene-butadiene rubber; and polymethylmethacrylate.

19. The method of claim 18, further comprising drilling the earth formation while pumping the drilling fluid into the earth formation.

20. The method of claim 18, wherein pumping a drilling fluid into a wellbore comprises pumping a drilling fluid comprising a reaction product of acrylamide and 2-acrylamido-2- methyl-propanesulfonic acid crosslinked with methylene bisacrylamide and tetra ethylene glycol diacrylate into the wellbore.

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