Wellbore fluids including gelling polymers, and related methods of operating a wellbore

Abstract

A wellbore fluid includes a continuous phase comprising an oleaginous fluid, a discontinuous phase comprising a non-oleaginous fluid, an emulsion of the discontinuous phase in the continuous phase, at least one emulsifier disposed around droplets of the discontinuous phase, at least one gelling material comprising at least one of xanthan gum, scleroglucan gum, gellan gum, carrageenan gum, or curdlan gum, and at least one crosslinker dispersed within the non-oleaginous fluid of the discontinuous phase. Related methods and treatment fluids are also disclosed.

Description

TITLEWellbore fluids including gelling polymers, and related methods of operating a wellbore CROSS-REFERENCE TO RELATED APPLICATIONS 

[0001] This application claims the benefit of U.S. Provisional Application No. 63 / 554632 entitled “Wellbore Fluids Including Gelling Polymers, and Related Methods of Operating a Wellbore,” filed February 16, 2024, the disclosures of which are incorporated herein by reference in its entirety. 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 socalled “thief zones” including relatively large pores and a relatively high porosity such that 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. Such chemicals are often referred to as “lost circulation materials” (LCMs).

[0005] The pills may include one or more lost circulation materials formulated and configured to plug pores and openings of the formation within the thief zone. Conventional lost circulation 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. Furthermore, in some formations, the size of the pores, caverns, and vugs may be such that conventional lost circulation materials are not effective to seal the formation and prevent the loss of wellbore fluids (e.g., drilling fluids) to the formation. SUMMARY

[0006] In some embodiments, a wellbore fluid comprises a continuous phase comprising an oleaginous fluid, a discontinuous phase comprising a non-oleaginous fluid, an emulsion of the discontinuous phase in the continuous phase, at least one emulsifier disposed around droplets of the discontinuous phase, at least one gelling material comprising at least one of xanthan gum, scleroglucan gum, gellan gum, carrageenan gum, or curdlan gum, and at least one crosslinker dispersed within the non-oleaginous fluid of the discontinuous phase.

[0007] In some embodiments, a method of operating a wellbore comprises pumping a wellbore fluid though a drill string extending through the wellbore, and pumping a drilling fluid through the drill string to displace the wellbore fluid in the drill string and through a nozzle in a drill bit coupled to the drill string to expose the wellbore fluid to a shear rate greater than 10,000 sec-1 and cause the at least one crosslinker to contact the at least one gelling material and form a gel. The wellbore fluid comprises an oleaginous continuous phase, a non-oleaginous discontinuous phase, at least one emulsifier stabilizing an emulsion of the non-oleaginous discontinuous phase in the oleaginous continuous phase, at least one gelling material comprising at least one of xanthan gum, scleroglucan gum, gellan gum, carrageenan gum, or curdlan gum, and at least one crosslinker dispersed in the non-oleaginous discontinuous phase and not contacting the at least one gelling material in the oleaginous continuous phase.

[0008] In some embodiments, a wellbore fluid comprises a continuous phase comprising an oleaginous fluid, a discontinuous phase comprising a non-oleaginous fluid, an emulsion of the discontinuous phase in the continuous phase, at least one emulsifier disposed around droplets of the discontinuous phase, at least one gelling material comprising at least one of scleroglucan gum, gellan gum, i-carrageenan gum, kcarrageenan gum, or curdlan gum, and at least one crosslinker comprising cations of at least one of calcium, boron, zirconium, hafnium, magnesium, strontium, or iron dispersed within the non-oleaginous fluid of the discontinuous phase, the at least one crosslinker configured to contact the at least one gelling material responsive to exposure of the wellbore fluid to a shear rate of more than about 10,000 sec-1 to form a gel comprising the gelling material and the at least one crosslinker. BRIEF DESCRIPTION OF THE DRAWINGS

[0009] 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:

[0010] FIG. 1 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;

[0011] FIG. 2 is a simplified flow diagram illustrating a method of operating a wellbore, according to at least one embodiment of the disclosure;

[0012] FIG. 3 is a simplified graph illustrating the properties of various treatment fluids including different polymers in the presence of calcium and in the absence of calcium;

[0013] FIG. 4 is a graph illustrating the properties of various treatment fluids including different polymers in the presence of calcium and in the absence of calcium; and

[0014] FIG. 5A illustrates an alkoxylated ether acid including an alkoxylated fatty alcohol terminated with a carboxylic acid;

[0015] FIG. 5B is an illustration of a high acyl gellan structure; and

[0016] FIG. 5C is an illustration of a low acyl gellan. DETAILED DESCRIPTION

[0017] This disclosure generally relates to devices, systems, and methods for wellbore fluid compositions for downhole applications, such as mitigation of lost circulation using one or more lost circulation materials. The fluid composition may be used in a wellbore fluid, such as a drilling fluid, a treatment 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 composition may be referred to herein as a “lost circulation composition” and may include one or more additives (e.g., a “lost circulation material composition,” a “lost circulation material,” or a “lost circulation additive”).

[0018] Embodiments disclosed herein relate to wellbore fluids for downhole applications, and methods of selectively triggering the wellbore fluids to set up as a gel or substantially solid material upon disruption of the emulsion responsive to exposure shear forces. The lost circulation material composition may be provided in a wellbore fluid, such as of a treatment fluid. In some embodiments, the treatment fluid comprises an invert emulsion. The treatment fluid may include one or more components of a drilling fluids, such as a base fluid, the lost circulation material composition, and one or more additives. The lost circulation material composition may include one or more gelling materials (also referred to herein as “gelling agents”) and one or more crosslinkers formulated and configured to interact with one another responsive to exposure to a sufficient shear rate. The interaction of the gelling material and the one or more crosslinkers increases a strength of a gelatinous material (a gel) formed from the gelling material. The gel may reduce (e.g., prevent) loss of circulation of wellbore fluids in the formation.

[0019] The treatment fluid may include, for example, a base fluid, the lost circulation material composition, and one or more additives. The base fluid may include a continuous phase, and a discontinuous phase dispersed in the continuous phase. The continuous phase may include an oleaginous fluid and the discontinuous phase may include a non-oleaginous fluid (e.g., an aqueous fluid). A portion of the lost circulation material composition may be dispersed in the continuous phase and another portion of the lost circulation material composition may be dispersed in the discontinuous phase. The portion of the lost circulation material composition dispersed in the continuous phase may have a different material composition than the portion of the lost circulation material composition dispersed in the discontinuous phase.

[0020] The lost circulation material composition includes the one or more gelling materials and the one or more crosslinkers. The one or more gelling materials may be present in the continuous phase and the one or more crosslinkers may be present in the discontinuous phase. In some embodiments, the treatment fluid including the lost circulation material includes a stable emulsion wherein the one or more gelling materials are in the continuous phase and the one or more crosslinkers are present in the discontinuous phase.

[0021] The one or more gelling materials include one or more gums formulated and configured to form a gel responsive to exposure to one or more conditions. For example, the gelling materials may be configured to form a gel responsive to the one or more crosslinkers and / or responsive to exposure to a temperature greater than a particular temperature. The gelling materials may include one or more of xanthan, scleroglucan, gellan, carrageenan, curdlan, and a protein formulated and configured to form a solid or a gel responsive to denaturization.

[0022] In some embodiments, responsive to exposure to the non-oleaginous fluid, the gelling material may form a gel. The crosslinker may crosslink the gel and increase the strength of the gel. The crosslinker may include divalent metal cations, polyvalent metal cations, or both. By way of non-limiting example, the crosslinker may include ions of at least one of calcium, boron, zirconium, hafnium, magnesium, strontium, iron (e.g., Fe3+), or boron.

[0023] A treatment fluid including the lost circulation material composition may be provided to the wellbore. In some embodiments, the treatment fluid is provided as a pill including a relatively small volume (e.g., less than 200 bbl) of material including the lost circulation composition. For example, the treatment fluid may include a relatively small volume of a drilling fluid including the lost circulation material composition. The treatment fluid may be referred to herein as a “lost circulation pill.” The treatment fluid may be followed by another wellbore fluid, such as, for example, a drilling fluid. In other words, after providing the treatment fluid to the wellbore, another wellbore fluid may be provided to the wellbore.

[0024] The treatment fluid may be pumped through a drill string extending through the wellbore. In some embodiments, after the treatment fluid is provided to the drill string, a drilling fluid comprising a material composition different than the treatment fluid (e.g., not including the lost circulation material composition) is pumped through the drill string to displace the lost circulation material composition in the drill string through one or more nozzles of a drill bit coupled to the drill string. The treatment fluid flows out of the drill string through the nozzles and to the annulus between the drill string and the earth formation. Pumping the drilling fluid provides sufficient shear rate to the treatment fluid to cause the emulsion to break and the gelling materials in the continuous oleaginous phase to contact the non-oleaginous fluid and the crosslinkers in discontinuous phase. In some embodiments, the shear rate is provided by the pump speed and the flow rate at which the drilling fluid is provided to the drill string and / or due to the flow of the treatment fluid through one or more nozzles of the drill bit. Responsive to contacting one another, the one or more gelling materials and the crosslinkers form a crosslinked gel configured, which may set within the thief zones of the formation. The treatment fluid is provided to one or more desired zones of the earth formation prior to forming a gel and while the treatment fluid is flowable, such as during the reaction between the gelling materials and the crosslinkers. After the treatment fluid is provided at the desired location, the treatment fluid may infiltrate the vugs, cavities, pores, and fractures of the thief zone and solidify in a gel. After forming the gel, the earth formation may continue to be drilled. The gel may reduce (e.g., prevent) the loss of wellbore fluids to the thief zones, facilitating circulation of the wellbore fluids during wellbore operations.

[0025] 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.

[0026] The drill string 105 may include several joints of drill pipe 108 connected endto-end through tool joints 109. The drill string 105 transmits drilling fluid through a central 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.

[0027] 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.

[0028] 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.

[0029] 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 fixedcutter 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.

[0030] 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, during drilling operations, a thief zone of the earth formation 101 having one or more cavities, vugs, caverns, pores, and / or fractures to which the drilling fluid is lost may be encountered. In some embodiments, the open volume in the zone of the earth formation 101 creates a void to which the circulating drilling fluid is lost. In some instances, the drilling fluid leaves the annulus between the drill string 105 and the earth formation 101 and enters (e.g., penetrates, infiltrates) the earth formation 101, resulting in the loss of circulation of the drilling fluid.

[0031] In some embodiments, such as when the thief zone is encountered, circulation (pumping) of the drilling fluid may be stopped and a lost circulation material composition may be provided to the drill string 105 to form a solid material (e.g., a gel) in the thief zone. The lost circulation material composition is provided in a wellbore fluid, which may also be referred to as a treatment fluid. The treatment fluid may comprise substantially the same material composition as the drilling fluid, except that the treatment fluid includes the lost circulation material composition. In some embodiments, the treatment fluid is provided in a relatively small volume (e.g., a volume of 200 barrels or less) to form the solid material within the thief zone.

[0032] The treatment fluid may include the lost circulation material composition including one or more gelling materials and one or more crosslinkers. As initially applied, the treatment fluid is provided as a liquid prior to the formation of the solid material (e.g., the gel). For example, as initially applied, the gelling material may not contact the crosslinker or the non-oleaginous fluid of the discontinuous phase. In other words, the gelling material and the crosslinker may not be substantially mixed together. As described herein, the treatment fluid may comprise an emulsion including the gelling material and the crosslinker. The gelling material may be formulated and configured to hydrate responsive to contacting the non-oleaginous fluid to form a gel responsive to breaking of the emulsion and contacting one another. The crosslinker may be formulated and configured to chemically react with the gel to form a crosslinked gel responsive to breaking of the emulsion and contacting one another. The crosslinked gel may comprise a substantially solid material substantially impermeable to wellbore fluids. In some embodiments, the treatment fluid flows to the thief zones prior to substantially completely forming a gel (e.g., crosslinking) and the gelling material and crosslinker react in the thief zone to form the crosslinked gel material. In some embodiments, the gelling material is present in a different phase of the treatment fluid than the crosslinker and the non-oleaginous fluid (e.g., water). For example, the gelling material may be present in a continuous oleaginous phase of the treatment fluid and the crosslinker may be present in a discontinuous non-oleaginous phase of the treatment fluid. Responsive to exposure to a sufficient shear force, the emulsion may be broken to facilitate contact between the gelling material and the non-oleaginous phase. In some embodiments, responsive to contact with the non-oleaginous phase (e.g., water) the gelling material may form a gel. The crosslinker may increase a strength of the gel.

[0033] The treatment fluid may comprise, for example, a base fluid comprising an emulsion including a continuous phase and a discontinuous phase dispersed in the continuous phase. The continuous phase may include an oleaginous fluid and the discontinuous phase may include a non-oleaginous fluid. The non-oleaginous fluid may comprise an aqueous fluid (e.g., water, brine), and the oleaginous fluid may comprise an oil or other hydrocarbon. The non-oleaginous fluid may be dispersed in the treatment fluid in substantially spherical form by agitation of a mixture of the non-oleaginous fluid and the oleaginous fluid in the presence of an emulsifier. In some embodiments, the continuous phase constitutes at least 70 volume percent of the discontinuous phase, such as at least about 75 volume percent, at least about 80 volume percent, or even at least about 85 volume percent of the discontinuous phase.

[0034] The treatment fluid may include the base fluid, at least one emulsifier, the lost circulation material composition, and one or more additives (e.g., one or more of hydratable clay materials, particulate materials, scavengers, bridging materials, viscosifiers, thinners (e.g., dispersion aids), weighting materials, filtration control agents, shale stabilizers, pH buffers, scavengers, emulsion activators, shale inhibitors, defoamers, foaming agents, scale inhibitors, solvents, rheological additives, or other additives).

[0035] The oleaginous fluid of the base fluid may include at least one of diesel oil, petroleum oil, a natural oil, mineral oil, a silicon oil, a synthetic oil, (e.g., hydrogenated and unhydrogenated olefins including polyalpha olefins, linear olefins, branched olefins, and internal olefins), polydiorganosiloxanes, siloxanes, organosiloxanes, ester oils, aliphatic esters, aliphatic ethers, aliphatic acetals, polydiorganosiloxanes, siloxanes, organosiloxanes, esters of fatty acids (e.g., straight chained, branched and cyclical alkyl ethers of fatty acids), or glycerides of fatty acids. The oleaginous fluid may be a liquid at about 25°C and may be immiscible with water.

[0036] The non-oleaginous fluid may include an aqueous fluid, such as one or more of water, sea water, brine, a salt-containing aqueous solution, or an aqueous solution including one or more water-miscible organic compounds. 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). The non-oleaginous fluid may be a liquid at about 25°C and may be immiscible with the oleaginous fluid. The non-oleaginous fluid may be capable of forming an emulsion with the oleaginous fluid.

[0037] In some embodiments, an internal phase (e.g., the dispersed, discontinuous phase) of the emulsion of the treatment fluid may include one or more salts. In other words, the non-oleaginous fluid includes the one or more salts. As described in further detail herein, the one or more salts may be formulated and configured to crosslink with the gelling material responsive to contacting the gelling material, such as after the emulsion is broken.

[0038] The one or more salts may provide a desired density to the treatment fluid. 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 (CaCl2), calcium bromide (CaBr2)), 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. In some embodiments, the salt comprises calcium chloride.

[0039] The salt may constitute from about 1.0 weight percent to about 30.0 weight percent of the treatment fluid, such as from about 1.0 weight percent to about 5.0 weight percent, from about 5.0 weight percent to about 10.0 weight percent, from about 10.0 to about 20.0 weight percent, or from about 20.0 weight percent to about 30.0 weight percent of the treatment fluid. However, the disclosure is not so limited, and the weight percent of the salt and the water in the treatment fluid may be different than that described.

[0040] The at least one emulsifier may include one or more materials formulated and configured to stabilize the treatment fluid. In some embodiments, the emulsifier comprises a surfactant formulated and configured to aid in the formation of the emulsion. The surfactant may be a surface active compound, such that the treatment fluid exhibits a higher concentration of the emulsifier at the surface or interface between the continuous phase and the discontinuous phase compared to in the rest of the emulsion. The surfactant may include amphiphilic organic compounds including both hydrophobic groups (“tails”) and hydrophilic groups (“heads”). Accordingly, a surfactant may include both an oil soluble component and a water soluble component and may be configured to lower the surface tension of a liquid, the interfacial tension between two liquids, or that between a liquid and a solid.

[0041] Emulsifiers that may be suitable for use in the treatment fluid may include, for example, one or more of fatty acids, soaps of fatty acids, amidoamines, polyamides, polyamines, fatty acid ester derivatives, ethoxylated fatty acids, ethoxylated alcohol, oleate esters, such as sorbitan monoleate, sorbitan dioleate, imidazoline derivatives or alcohol derivatives, or combinations of thereof. In some embodiments, the emulsifier comprises an amidoamine. By way of non-limiting example, in some embodiments a fatty acid (one or more of a C10 to C24 fatty acid, which may include linear and / or branched, and saturated and / or unsaturated fatty acids) may be reacted with one or more ethyleneamines (e.g., ethylenediamine, diethylenetriamine, triethylenetetraamine, tetraethylenepentaamine) to produce one or more of amides, polyamides, and / or amidoamines, depending on, for example, the molar ratio of the polyamine to the fatty acid. In one or more embodiments, the emulsifier may be a dimer poly-carboxylic C12 to C22 fatty acid, trimer poly-carboxylic C12 to C22 fatty acid, tetramer poly-carboxylic C12 to C22 fatty acid, mixtures thereof, or a polyamide wherein the polyamide is the condensation reaction product of a C12 to C22 fatty acid and a polyamine selected from the group consisting of diethylenetriamine, tri ethylenetetramine; and tetraethylenepentamine.

[0042] In some embodiments, the emulsifier may be an alkoxylated ether acid. The alkoxylated ether acid may be an alkoxylated fatty alcohol terminated with a carboxylic acid, represented by Structure (I) below and shown in FIG. 5A:(I),wherein R is C6-C24 or –C(O)R3 (where R3 is C10-C22), R1 is H or C1-C4, R2 is C1-C5 and n may range from 1 to 20. Such compounds may be formed by the reaction of an alcohol with a polyether (such as poly(ethylene oxide), poly(propylene oxide), poly(butylene oxide), or copolymers of ethylene oxide, propylene oxide, and / or butylene oxide) to form an alkoxylated alcohol. The alkoxylated alcohol may be reacted with an α-halocarboxylic acid (such as chloroacetic acid, chloropropionic acid, etc.) to form the alkoxylated ether acid. In some embodiments, n may be selected based on the lipophilicity of the compound and the type of polyether used in the alkoxylation. In some embodiments, where R1 is H (formed from reaction with poly(ethylene oxide)), n may be between 2 and 10, such as between 2 and 5, or between 2 and 4. In other embodiments, where R1 is –CH3, n may range up to 20. Further, selection of R (or R3) and R2 may also be based on the hydrophilicity of the compound due to the extent of polyetherification (i.e., number of n).

[0043] The concentration of the emulsifier in the treatment fluid may be at least about 12.8 kg / m3 (about 4.5 pounds per barrel (ppb)). For example, the concentration of the emulsifier may be within a range of from about 12.8 kg / m3 (about 4.5 ppb) to about 42.8 kg / m3 (about 15.0 ppb), such as within a range of from about 12.8 kg / m3 (about 4.5 ppb) to about 13.7 kg / m3 (about 4.8 ppb), from about 13.7 kg / m3 (about 4.8 ppb) to about 17.1 kg / m3 (about 6.0 ppb), from about 17.1 kg / m3 (about 6.0 ppb) to about 22.8 kg / m3 (about 8.0 ppb), from about 22.8 kg / m3 (about 8.0 ppb) to about 28.5 kg / m3 (about 10.0 ppb), from about 28.5 kg / m3 (about 10.0 ppb) to about 34.2 kg / m3 (about 12.0 ppb), or from about 34.2 kg / m3 (about 12.0 ppb) to about 42.8 kg / m3 (about 15.0 ppb).

[0044] As described above, the treatment fluid includes the lost circulation material composition. The lost circulation material composition includes at least one gelling material. In some embodiments, the lost circulation material further comprises at least one crosslinker. The at least one gelling material may be separate from the at least one crosslinker in the treatment fluid (e.g., in the treatment fluid, the at least one gelling material may not contact the crosslinker) until the treatment fluid is exposed to a sufficient shear rate to cause the gelling material to contact the crosslinker. For example, the at least one gelling material may be present in (e.g., dispersed in) the continuous oleaginous phase and the crosslinker may be present in (e.g., dispersed in) the discontinuous non-oleaginous phase of the emulsion of the treatment fluid.

[0045] The gelling material may include at least one natural or synthetic polymer. In some embodiments, the gelling material includes at least one naturally-occurring polymer, also referred to as a biopolymer. The gelling material may include at least one of guar (also referred to as “guar gum”), xanthan (also referred to as “xanthan gum), scleroglucan (also referred to as “scleroglucan gum”), gellan (also referred to as “gellan gum”), carrageenan (also referred to as “carrageenan gum”), or curdlan. In some embodiments, the gelling material includes a material formulated and configured to form a gel responsive to crosslinking. In some such embodiments, the gelling material includes at least one of guar, xanthan, scleroglucan, gellan, carrageenan, and scleroglucan. In some embodiments, the gelling material includes a material formulated and configured to form a gel responsive to exposure to a temperature, such as a temperature greater than about 80°C (about 176°F). For example, in some embodiments, the gelling material comprises curdlan and may form a gel responsive to exposure to a temperature of at least about 80°C (about 176°F).

[0046] In other embodiments, the gelling material comprises a protein. Responsive to exposure to one or more materials or one or more conditions, the protein may be formulated and configured to denature and form a gel. For example, responsive to exposure to a predetermined temperature, the protein may form a solid gel. By way of non-limiting example, the gelling material may include albumin and may form a gel responsive to exposure to a temperature greater than about 60°C (about 140°F). In other embodiments, responsive to exposure to an alkali material, an acid, a chaotropic agent (e.g., urea, guanidinium chloride, lithium perchlorate, sodium dodecyl sulfate), a detergent, a crosslinking agent (e.g., formaldehyde, glutaraldehyde), or to shaking, the protein may denature and form a gel. For example, the gelling material may include casein and may form a gel responsive to exposure to a pH less than about 4.6.

[0047] In some embodiments, the gelling material comprises scleroglucan. In some embodiments, the gelling material comprises carrageenan. The carrageenan may include sulfated polysaccharides. In some such embodiments, the gelling material may include one or more of kappa-carrageenan (k-carrageenan), iota-carrageenan (i-carrageenan), or lambdacarrageenan (λ-carrageenan), or another type of carrageenan. In some embodiments, the carrageenan includes one or both of k-carrageenan or i-carrageenan. In some embodiments, the carrageenan is substantially free of λcarrageenan.

[0048] A sulfation level (also referred to as a degree of sulfation or a sulfur content) of each of the k-carrageenan, the i-carrageenan, and the λcarrageenan may be different. The carrageenans may each include ester-sulfate groups (e.g., –OSO3-). For example, kcarrageenan may include one sulfate group (e.g., one ester-sulfate group) per disaccharide, i-carrageenan includes two sulfate groups (e.g., two ester-sulfate groups) per disaccharide, and λcarrageenan includes three sulfate groups (e.g., three ester-sulfate groups) per disaccharide.

[0049] In some embodiments, carrageenans having a lower degree of sulfation may exhibit greater gelling properties in the treatment fluid. In some embodiments, λcarrageenan may not exhibit gelling properties in the treatment fluid and the gelling material is substantially free of λcarrageenan. In some embodiments, the gelling material includes a mixture of k-carrageenan and i-carrageenan. In some embodiments, the gelling material comprises, consists essentially of, or consists of k-carrageenan. In other embodiments, the gelling material comprises, consists essentially of, or consists of icarrageenan. The gelling material may include from about 0 weight percent to about 100 weight percent of each of k-carrageenan and icarrageenan, the remaining portion of the gelling material including the other of the kcarrageenan and icarrageenan. For example, the gelling material may include from about 0 weight percent to about 100 weight percent of k-carrageenan, such as from about 0 weight percent to about 25 weight percent, from about 25 weight percent to about 50 weight percent, from about 50 weight percent to about 75 weight percent, or from about 75 weight percent to about 100 weight percent of k-carrageenan, the remaining portion of the gelling material comprising icarrageenan.

[0050] The gelling material may include gellan gum. The gellan gum may include repeating units of a tetrasaccharide, each repeating unit including two residues of Dglucose, one residue of L-rhamnose, and one residue of D-glucuronic acid. The gellan gum may include a linear tetrasaccharide of (1,4)-β-L-rhamnopyranosyl, (1,3)αDglucopyranosyl, (1,4)-β-D-glycuronopyranosyl, (1,4)-β-D-glucopyranosyl with O(2) Lglyceryl and O(6) acetyl substituents on the 3-linked glucose.

[0051] The gellan gum may include different levels of acylation, which may be referred to as “low-acyl” and “high-acyl” gellan gum, depending on the number of acetate groups bonded to the gellan gum. In some embodiments, native gellan gum includes high-acyl gellan gum including a greater degree of acylation than low-acyl gellan gum. For example, in deacylated gellan gum, the acyl groups present in the native polymer are removed by, for example, alkaline hydrolysis. High-acyl gellan gum may include a higher acyl content of glycerate and acetate groups in the glucose units; whereas low-acyl gellan gum may include a lower acyl content of glycerate and acetate groups in the glucose units. For example, high acyl gellan may include the structure illustrated in Structure (II) below (and as shown in FIG. 5B) and low acyl gellan may include the structure illustrated in Structure (III) below (and as shown in FIG. 5C), wherein n is an integer. (II);  (III);

[0052] In some embodiments, the gelling material includes gellan gum comprising, consisting essentially of, or consisting of low-acyl gellan gum. In other embodiments, the gelling material includes gellan gum comprising, consisting essentially of, or consisting of high-acyl gellan gum. In other embodiments, the gelling material comprises, consists essentially of, or consists of a mixture of low-acyl gellan gum and high-acyl gellan gum. The gelling material may include from about 0 weight percent to about 100 weight percent of each of low-acyl gellan gum and high-acyl gellan gum, the remaining portion of the gelling material including the other of the low-acyl gellan gum and high-acyl gellan gum. For example, the gelling material may include from about 0 weight percent to about 100 weight percent of low-acyl gellan gum, such as from about 0 weight percent to about 25 weight percent, from about 25 weight percent to about 50 weight percent, from about 50 weight percent to about 75 weight percent, or from about 75 weight percent to about 100 weight percent of low-acyl gellan gum, the remaining portion of the gelling material comprising high-acyl gellan gum.

[0053] In some embodiments, the gelling material includes curdlan. In some such embodiments, the gelling material may be formulated and configured to form a gel responsive to exposure to a predetermined temperature, such as a temperature of at least about 60°C (about 140°F), such as at least about 70°C (158°F), or at least about 80°C (about 176°F). In some embodiments, the curdlan forms a gel responsive to exposure to a temperature within a range of from about 80°C (about 176°F) to about 130°C (about 266°F), such as from about 80°C (about 176°F) to about 100°C (about 212°F), or from about 100°C (about 212°F) to about 130°C (about 266°F).

[0054] The gelling material may comprise, consist essentially of, or consist of one of (e.g., only one of) xanthan, scleroglucan, gellan, carrageenan, alginate, curdlan, or a protein formulated and configured to form a solid or a gel responsive to denaturization. In some embodiments, the gelling material comprises, consists essentially of, or consists of one of (e.g., only one of) scleroglucan, gellan, i-carrageenan, or k-carrageenan.

[0055] In some embodiments, the gelling material comprises mixture of xanthan, scleroglucan, gellan, carrageenan, curdlan, or a protein formulated and configured to form a solid or a gel responsive to denaturization. In some such embodiments, the properties of the gelling material and the gel formed from the gelling material may be tunable. For example, the gelling material may include a first material formulated and configured to crosslink with a crosslinker responsive to exposure to the crosslinker (e.g., responsive to exposure of the treatment fluid including the lost circulation material to a sufficient shear stress) to form a gel; and a second material formulated and configured to form a gel responsive to exposure to a predetermined temperature.

[0056] In addition to the gelling material, the lost circulation material may further include at least one crosslinker. In some embodiments, such as where the gelling material includes one or more of xanthan, scleroglucan, carrageenan (e.g., k-carrageenan and / or icarrageenan), or gellan gum, the lost circulation material further includes at least one crosslinker formulated and configured to react with (e.g., crosslink) the gelling material. In the treatment fluid comprising a stable emulsion, the at least one crosslinker may be located (dispersed) in a different phase than the gelling material. For example, in some embodiments, the at least one crosslinker is located in a discontinuous aqueous phase, and the gelling material is located in the continuous oleaginous phase. In some such embodiments, the at least one crosslinker is located in droplets of the discontinuous phase dispersed throughout the continuous phase. The at least one emulsifier may surround the droplets at the interface between the continuous phase and the discontinuous phase.

[0057] The at least one crosslinker may include a divalent cation. In other embodiments, the at least one crosslinker includes a polyvalent cation (e.g., a cation having a positive charge greater than 2). By way of non-limiting example, the at least one crosslinker may include cations of at least one of calcium (e.g., Ca2+), boron (e.g., B3+), zirconium (e.g., Zr4+), hafnium (e.g., Hf4+), magnesium (e.g., Mg2+), strontium (e.g., Sr2+), iron (e.g., Fe3+), aluminum (e.g., Al3+), or scandium (e.g., Sc3+). The at least one crosslinker may be present in the lost circulation material as a salt.

[0058] Responsive to exposure to a sufficient shear rate, the emulsion may be broken such that the gelling material is contacted by the crosslinker. Upon contacting one another, the gelling material and the crosslinker react to crosslink units of the gelling material and form a gel. For example, where the gelling material comprises i-carrageenan or kcarrageenan, the gelling material may be crosslinked. Without being bound by any particular theory, it is believed that the crosslinker interacts with one the hydroxyl groups of the i-carrageenan or k-carrageenan and that the sulfate groups of the λ-carrageenan hinder the crosslinker from crosslinking the λ-carrageenan. In other words, it is believed that λ-carrageenan does not crosslink with the crosslinker due to the presence of the ester-sulfate groups.

[0059] In embodiments where the gelling material comprises gellan gum, the crosslinker may crosslink the units of the gellan gum, such as at the carboxyl groups and / or the hydroxyl groups of the gellan gum. In some embodiments, the crosslinker comprises a divalent cation configured to crosslink the gellan gum and form a gel. The crosslinker may form a bridge between carboxyl groups of the gelling material to form the gel. In some embodiments, the gelling material comprises low acylated gellan gum. In other embodiments, the gelling material comprises high-acylated gellan gum.

[0060] A weight ratio of the gelling material to the crosslinker in the lost circulation material may be within a range of from about 0.20:1.0 to about 5.0:1.0, such as from about 0.20:1.0 to about 0.50:1.0, from about 0.50:1.0 to about 1.0:1.0, from about 1.0:1.0 to about 2.0:1.0, from about 2.0:1.0 to about 3.0:1.0, from about 3.0:1.0 to about 4.0:1.0, or from about 4.0:1.0 to about 5.0:1.0. In some embodiments, the lost circulation material includes a greater weight percent of the gelling material than the crosslinker. In other embodiments, the lost circulation material includes a greater weigh percent of the crosslinker than the gelling material. In other embodiments, such as where the gelling material comprises a material formulated and configured to form a gel responsive to exposure to a temperature (e.g., without a crosslinker), the lost circulation material may not include a crosslinker.

[0061] The gelling material may be present in the treatment fluid at a concentration within a range of from about 2.85 kg / m3 (about 1.0 ppb) to about 28.5 kg / m3 (about 10.0 ppb), such as from about 2.85 kg / m3 (about 1.0 ppb) to about 5.7 kg / m3 (about 2.0 ppb), from about 5.7 kg / m3 (about 2.0 ppb) to about 11.4 kg / m3 (about 4.0 ppb), from about 11.4 kg / m3 (about 4.0 ppb) to about 17.1 kg / m3 (about 6.0 ppb), from about 17.1 kg / m3 (about 6.0 ppb) to about 22.8 kg / m3 (about 8.0 ppb), or from about 22.8 kg / m3 (about 8.0 ppb) to about 28.5 kg / m3 (about 10.0 ppb). In some embodiments, gelling material is present in the treatment fluid at a concentration within a range of from about 5.7 kg / m3 (about 2.0 ppb) to about 11.4 kg / m3 (about 4.0 ppb).

[0062] The crosslinker may be present in the treatment fluid at a concentration within a range of from about 2.85 kg / m3 (about 1.0 ppb) to about 28.5 kg / m3 (about 10.0 ppb), such as from about 2.85 kg / m3 (about 1.0 ppb) to about 5.7 kg / m3 (about 2.0 ppb), from about 5.7 kg / m3 (about 2.0 ppb) to about 11.4 kg / m3 (about 4.0 ppb), from about 11.4 kg / m3 (about 4.0 ppb) to about 17.1 kg / m3 (about 6.0 ppb), from about 17.1 kg / m3 (about 6.0 ppb) to about 22.8 kg / m3 (about 8.0 ppb), or from about 22.8 kg / m3 (about 8.0 ppb) to about 28.5 kg / m3 (about 10.0 ppb). In some embodiments, crosslinker is present in the treatment fluid at a concentration within a range of from about 2.85 kg / m3 (about 1.0 ppb) to about 8.55 kg / m3 (about 3.0 ppb). In other embodiments, the crosslinker is present in the treatment fluid at a concentration within a range of from about 8.55 kg / m3 (about 3.0 ppb) to about 14.3 kg / m3 (about 5.0 ppb).

[0063] The lost circulation material may constitute from about 0.5 weight percent to about 10.0 weight percent of the weight percent of the treatment 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, from about 3.0 weight percent to about 4.0 weight percent, from about 4.0 weight percent to about 6.0 weight percent, from about 6.0 weight percent to about 8.0 weight percent, or from about 8.0 weight percent to about 10.0 weight percent of the treatment fluid. In some embodiments, the lost circulation constitutes less than about 5.0 weight percent of the treatment fluid, such as less than about 4.0 weight percent, or less than about 2.0 weight percent of the treatment fluid.

[0064] The treatment fluid may further include one or more additives selected based on the desired properties of the treatment fluid. As discussed above, and by way of non-limiting example, the one or more additional additives may include one or more of hydratable clay materials, particulate materials, scavengers, bridging materials, viscosifiers, thinners, weighting materials, filtration control agents, shale stabilizers, pH buffers, scavengers, emulsion activators, gelling materials, shale inhibitors, defoamers, foaming agents, scale inhibitors, solvents, rheological additives, or other additives that may be suitable depending on the particular operation.

[0065] The hydratable clay materials may include, for example, bentonite clay. The hydratable clay may comprise a non-organophilic clay. In some embodiments, the hydratable clay may improve the gel strength of the gel formed from the lost circulation material. The hydratable clay may constitute from about 28.5 kg / m3 (about 10.0 ppb) to about 57.0 kg / m3 (about 20.0 ppb) of the treatment fluid, such as from about 28.5 kg / m3 (about 10.0 ppb) to about 34.2 kg / m3 (about 12.0 ppb), from about 34.2 kg / m3 (about 12.0 ppb) to about 39.9 kg / m3 (about 14.0 ppb), from 39.9 kg / m3 (about 14.0 ppb) to about 45.6 kg / m3 (about 16.0 ppb), from about 45.6 kg / m3 (about 16.0 ppb) to about 51.3 kg / m3 (about 18.0 ppb), or from about 51.3 kg / m3 (about 18.0 ppb) to about 57.0 kg / m3 (about 20.0 ppb) of the treatment fluid.

[0066] The particulate materials may be formulated and configured to enhance the solidification of the gelling materials to form the solid gel (e.g., the crosslinked gel). In some embodiments, the particulate materials provide enhanced compressive strength to the resulting solid gel. The particulate materials may include fibers, such as synthetic fibers or natural fibers. By way of non-limiting example, the particulate materials may include one or more of polyesters, acrylic polymers, polyamides, polyolefins, polyaramides, polyurethanes, vinyl polymers, glass fibers, carbon fibers, regenerated cellulose (e.g., rayon), or natural fibers. Upon formation of the emulsion in the treatment fluid, the particulate materials may be dispersed in the oleaginous phase. After formation of the gel, the particulate materials may be dispersed in the gel and may provide increased strength to the gel.

[0067] The scavenger may include, for example, zinc oxide, which may function as a hydrogen sulfide (H2S) scavenger.

[0068] The bridging materials 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, fibers, or other building materials. In some embodiments, the building materials comprise calcium carbonate. The bridging material may be functionalized with one or more functional groups, such as one or more hydrophobic functional groups.

[0069] Viscosifiers of the treatment fluid may include a material formulated and configured to increase the viscosity of the wellbore 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, organic bentonite clay, an organic polymer (e.g., a cellulosic polymer), a polymer (e.g., a copolymer) formed from at least one acrylamide monomer and at least one sulfonated anionic monomer, or another polymer.

[0070] The viscosifier may constitute from about 0.5 weight percent to about 6.0 weight percent of the wellbore 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 wellbore fluid. However, the disclosure is not so limited, and the weight percent of the viscosifier in the wellbore fluid may be different than that described.

[0071] Fluid thinners may include lignosulfates, lignitic materials, modified lignosulfonates, polyphosphates, tannin, and polyacrylates. The thinners may facilitate improved rheological properties of the wellbore 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 wellbore fluid, counteract the effects of salts, and reduce the effects of water on the earth formation 101.

[0072] Weighting materials (also referred to as “weighting agents”) may include one or more of barite (BaSO4), iron oxide (e.g., Fe2O3, Fe3O4), calcium carbonate (CaCO3), magnesium carbonate (MgCO3), manganese oxide (Mn3O4), or combinations thereof. The weighting material may be present in the wellbore fluid and facilitate increasing the density of the wellbore fluid up to about 2.88 g / cm3 (about 24 pounds per gallon (ppg)).

[0073] A density of the treatment fluid may be within a range of from about 1,080 kg / m3 to about 2,500 kg / m3, such as from about 1,080 kg / m3 to about 1,200 kg / m3, from about 1,200 kg / m3 to about 1,400 kg / m3, from about 1,400 kg / m3 to about 1,600 kg / m3, from about 1,600 kg / m3 to about 1,800 kg / m3, from about 1,800 kg / m3 to about 2,000 kg / m3, from about 2,000 kg / m3 to about 2,200 kg / m3, or from about 2,200 kg / m3 to about 2,500 kg / m3. However, the disclosure is not so limited, and the density of the treatment fluid may be different than that described.

[0074] FIG. 2 is a simplified flow diagram illustrating a method 200 of operating a wellbore, according to at least one embodiment of the disclosure. In some embodiments, the method 200 includes providing a pill of the treatment fluid to the wellbore 102 to form a gel in the earth formation 101. The method 200 includes mixing an emulsifier with an oleaginous fluid (that will form a continuous phase), as shown in act 202. The oleaginous fluid and the emulsifier may include one or more of the respective oleaginous fluids and emulsifiers described above.

[0075] After mixing the emulsifier with the oleaginous fluid, the method 200 includes mixing a gelling material and one or more additional additives with the oleaginous fluid, as shown in act 204. The gelling material may include one or more of the gelling materials described above. In addition, the one or more additional additives may include one or more of the additives described above, such as one or more of hydratable clay materials, particulate materials, scavengers, bridging materials, viscosifiers, thinners, weighting materials, filtration control agents, shale stabilizers, pH buffers, scavengers, emulsion activators, gelling materials, shale inhibitors, defoamers, foaming agents, scale inhibitors, solvents, rheological additives.

[0076] The method 200 may further include mixing a non-oleaginous fluid with the oleaginous fluid to form an emulsion, as shown in act 206. The non-oleaginous fluid may include one or more of the non-oleaginous fluids described above. In some embodiments, the non-oleaginous fluid comprises an aqueous fluid, such as water or brine. In some embodiments, the non-oleaginous fluid is mixed with the oleaginous fluid such that the mixture is not exposure to a shear rate greater than a predetermined amount, such as less than about 10,000 sec-1, less than about 50,000 sec-1, less than about 30,000 sec-1, less than about 20,000 sec-1, or less than about 10,000 sec-1. By way of non-limiting example, the non-oleaginous fluid is added to the oleaginous fluid with a paddle-type system.

[0077] In some embodiments, a volume percent of the non-oleaginous is greater than a volume percent of the oleaginous fluid. The relatively lower volume percent of the oleaginous fluid may cause the one or more additives to be water wet upon breaking the emulsion.

[0078] After mixing the non-oleaginous fluid with the oleaginous fluid, the method 200 further includes mixing at least one crosslinker with the non-oleaginous fluid in the emulsion to form a treatment fluid, as shown in act 208. The at least one crosslinker may include one or more of the crosslinkers described above. In some embodiments, the at least one crosslinker is mixed with the non-oleaginous prior to mixing the non-oleaginous with the oleaginous fluid in act 206.

[0079] Responsive to forming the treatment fluid, the method 200 further includes pumping the treatment fluid through a wellbore, as shown in act 210. Pumping the treatment fluid in the wellbore may include pumping the treatment fluid through a drill string (e.g., the drill string 105). In some embodiments, at least a portion of (e.g., all of) the volume of the drill string is filled with the treatment fluid.

[0080] The method 200 further includes pumping a drilling fluid through the wellbore, as shown in act 212. For example, after filling at least a portion of the drill string with the treatment fluid, the drilling fluid may be pumped through the wellbore 102. Pumping the drilling fluid through the drill string may cause the treatment fluid to exit the drill string, such as through a nozzle of a drill bit (e.g., drill bit 110) coupled to an end of the drill string. As the treatment fluid passes through the nozzle and into the annulus between the drill string and the earth formation 101, the treatment fluid may be exposed to a shear rate sufficient to break the emulsion and cause the crosslinker to contact the gelling material and form a gel. In some embodiments, the treatment fluid is exposed to a shear rate greater than about 10,000 sec-1, such as greater than about 20,000 sec-1, greater than about 30,000 sec-1, greater than about 40,000 sec-1, greater than about 50,000 sec-1, or greater than about 100,000 sec-1. For example, the treatment fluid may be exposed to a greater shear rate than the shear rate the treatment fluid was exposed to during act 210.

[0081] In some embodiments, sufficient drilling fluid is provided to the wellbore such that the treatment fluid flows into and is placed in one or more cavities, vugs, voids, fractures, or caverns. The drilling fluid may be substantially similar to the treatment fluid, except that the treatment fluid may not include the lost circulation material. In addition, the drilling fluid may include a relatively greater volume percent of the oleaginous phase than the treatment fluid. For example, the drilling fluid may include a greater volume percent of the oleaginous fluid than of the non-oleaginous fluid.

[0082] Responsive to pumping the drilling fluid through the wellbore, the method 200 further includes forming a solid material from the gelling material, as shown in act 214. For example, responsive to exposure to the shear rate, the gelling material may mix with the crosslinker and may begin to crosslink and form the solid material (e.g., a gel). The solid material may remain in the one or more cavities, vugs, voids, fractures, or caverns and substantially reduce (e.g., prevent) loss of wellbore fluids during further wellbore operations.

[0083] The method 200 may further include drilling the earth formation while circulating the drilling fluid through the wellbore, as shown at act 216. The wellbore fluid may facilitate removal of cuttings from the wellbore as the drilling fluid circulates through the wellbore.

[0084] In some embodiments, the method 200 does not include mixing a crosslinker with the gelling material to form the solid material. For example, in some embodiments, the gelling material is exposed to a sufficient temperature to cause the gelling material to crosslink and form a solid material. For example, the gelling material may be exposed to a temperature greater than about 60°C, such as greater than about 80°C to form the solid material.

[0085] Forming the treatment fluid to include the lost circulation material including a gelling material formulated and configured to form a gel in-situ (e.g., in the wellbore) facilitates placement of the gelling material to a desired location within the earth formation 101 prior to forming the gel. For example, the gelling material and the crosslinker may contact one another responsive to exposure to a sufficient shear rate downhole (e.g., within the wellbore), such that the gelling material begins to form a gel in-situ, within the wellbore and / or within the earth formation. In addition, the solid material formed from the gelling material may exhibit stable properties and may remain as a solid material within the earth formation at conditions within the earth formation. The solid material may substantially reduce (e.g., prevent) loss of circulation materials to the earth formation. EXAMPLESExample 1

[0086] Treatment fluids including different polymers were created to test the response of the different polymers to exposure to calcium. Each of xanthan, guar, diutan, carboxymethylated starch, and λ-carrageenan were compared to see the response of each polymer to calcium. The treatment fluids were each oil-in-water emulsions including an oleaginous continuous phase, a non-oleaginous discontinuous phase, an emulsifier and included 1.5 ppb of the polymer. Treatment fluids that included calcium had 700 ppm calcium. FIG. 3 is a chart comparing the response of each polymer to exposure to calcium. The viscosity of each treatment fluid was measured at about 65.6°C (about 150°F).

[0087] As seen in FIG. 3, calcium does not substantially affect the viscosity or the gelling properties of xanthan, diutan, or guar. The carboxymethylated starch exhibits a relatively lower viscosity in the presence of calcium than in the absence of calcium. Accordingly, not all polymers exhibit an increase in viscosity or gelling properties responsive to exposure to calcium. Example 2

[0088] Treatment fluids including xanthan and scleroglucan were prepared. The treatment fluids were similar to the treatment fluids of Example 1 and included oil-in-water emulsions including an oleaginous continuous phase, a non-oleaginous discontinuous phase, an emulsifier and included 1.5 ppb of the polymer. Each of the treatment fluids was also exposed to calcium 700 ppm calcium. FIG. 4 is a chart illustrating the viscosity of each of the treatment fluids at about 65.6°C (about 150°F). With reference to FIG. 4, the scleroglucan exhibits an increase in viscosity responsive to exposure to calcium, whereas the effect of calcium on xanthan is minimal. Example 3

[0089] Aqueous solutions including different polymers (e.g., different polysaccharide polymers) were prepared to compare the gelling response of the different polymers to each other in the presence of calcium cations (e.g., in the presence of CaCl2 salt) and without the calcium cations. Some of the polymers exhibited improved gelling properties responsive to exposure to calcium, while other polymers did not exhibit a response to the presence of calcium. Each aqueous solution included 4.0 ppb of the noted polymer, an emulsifier, and 1 ppb of triethanolamine (a pH buffer). The aqueous solutions were hot rolled at a temperature of about 82.2°C (about 180°F) for about 150 minutes. The aqueous solutions that included the calcium cations included 3.0 ppb of 25% by weight calcium chloride.

[0090] The gelling properties of each of the aqueous solutions was measured using a rotational couette viscometer at different rotation speeds. At each rotational speed (RPM), the viscosity of the aqueous solutions was measured at different temperatures after hot rolling. The viscosity of each aqueous solution was measured at about 32.2°C (about 90°F), about 48.9°C (about 120°F), and about 65.6°C (about 150°F). Table 1 below includes the performance of guar, xanthan, scleroglucan, and low-acyl gellan without calcium. Table 2 includes the performance of high-acyl gellan, i-carrageenan, k-carrageenan, and λcarrageenan without calcium. Table 3 below includes the performance of the guar, xanthan, scleroglucan, and low-acyl gellan in the presence of calcium, and Table 4 includes the performance of the high-acyl gellan, i-carrageenan, k-carrageenan, and λcarrageenan in the presence of calcium.Table 14 ppb polymer, no calcium GuarXanthanScleroglucanLow-Acyl GellanTemp (°F)90120150901201509012015090120150600 RPM163.3148.5138.774.670.669.992.286.883.6110.095.076.3300 RPM140.5127.5118.364.562.662.077.874.773.187.071.056.8200 RPM128.9116.5107.559.458.257.871.669.067.676.060.248.1100 RPM111.299.390.252.151.951.962.761.160.260.345.736.06 RPM54.742.734.836.636.636.642.941.438.525.117.212.63 RPM43.931.825.034.332.532.540.938.334.320.913.910.010s42.732.325.21.033.133.140.537.033.721.114.7 10M45.035.427.043.643.843.841.941.741.537.622.514.5 Table 24 ppb polymer, no calcium High-Acyl Gellani-carrageenank-carrageenanλ-carrageenanTemp (°F)90120150901201509012015090120150600 RPM110.095.076.331.422.718.084.067.455.297.883.673.1300 RPM87.071.056.818.913.410.557.943.934.770.759.751.4200 RPM76.060.248.114.09.87.645.433.526.157.647.840.4100 RPM60.345.736.08.35.74.528.620.015.139.631.726.16 RPM25.117.212.62.72.03.23.22.42.06.04.33.63 RPM20.913.910.02.72.82.72.32.11.53.52.82.310s21.114.7 5.35.35.14.12.92.03.93.53.510M37.622.514.55.14.95.54.97.22.33.93.93.7 Table 34 ppb polymer, 3 ppb 25% CaCl2 GuarXanthanScleroglucanLow-Acyl GellanTemp (°F)90120150901201509012015090120150600 RPM163.4147.2133.576.571.268.7Formed a strong gel after hot rollingGelled solid immediately upon addition of CaCl2300 RPM139.6125.5112.465.362.561.0200 RPM126.7113.6100.859.857.856.8100 RPM107.095.183.252.150.950.46 RPM46.437.228.436.335.634.03 RPM34.526.419.233.932.730.910s35.225.619.434.033.733.510M37.026.420.247.948.947.9 Table 44 ppb polymer, 3 ppb 25% CaCl2 High-Acyl Gellani-carrageenank-carrageenanλ-carrageenanTemp (°F)90120150901201509012015090120150600 RPMGelled solid immediately upon addition of CaCl285.364.230.9136.2150.338.976.456.844.8300 RPM65.849.123.3111.7104.923.452.938.329.6200 RPM55.442.319.0101.684.917.142.530.022.1100 RPM41.732.514.384.160.310.028.419.013.46 RPM16.314.35.150.817.71.74.13.11.63 RPM14.112.74.748.014.41.72.64.21.010s18.218.25.358.515.32.53.32.09.610M64.660.939.754.818.43.73.11.81.4 

[0091] With combined reference to Table 1 through Table 4, the guar exhibited a relatively high viscosity both with and without the presence of calcium (e.g., the viscosity of guar was not affected by the presence of calcium). Similarly, the viscosity of xanthan appeared to be unaffected by the presence of calcium. The λ-carrageenan appeared to exhibit a lower viscosity in the presence of calcium. By way of contrast, the low-acyl gellan gum and the high-acyl gellan gum exhibited a relatively low viscosity without calcium, and gelled immediately upon the addition of calcium chloride and prior to hot rolling. The scleroglucan exhibited an increased viscosity in the presence of calcium. For example, upon the addition of calcium chloride, the scleroglucan maintained flowability, but after hot rolling, the scleroglucan gelled. The i-carrageenan and the k-carrageenan exhibited a higher viscosity responsive to exposure to calcium. Accordingly, the gelling properties of treatment fluid may be tuned (e.g., controlled) by using different polymers and / or by forming a treatment fluid including more than one type of polymer. Example 4

[0092] Additional treatment fluids similar to the treatment fluids formed in Example 3 were formed, except that the treatment fluids included a lower concentration of the polymer. The treatment fluids included 1.5 ppb of the polymer. The gelling properties of each of the treatment fluids was measured using a rotational couette viscometer at different rotation speeds. Table 5 below includes the performance of guar, xanthan, scleroglucan, and low-acyl gellan without calcium. Table 6 includes the performance of high-acyl gellan and λcarrageenan without calcium. Table 7 below includes the performance of the guar, xanthan, scleroglucan, and low-acyl gellan in the presence of calcium, and Table 8 includes the performance of the high-acyl gellan and λcarrageenan in the presence of calcium.Table 51.5 ppb polymer, no calcium GuarXanthanScleroglucanLow-Acyl GellanTemp (°F)90120150901201509012015090120150600 RPM29.524.320.422.520.418.920.318.617.4Gelled. Firmer gel than high-acyl gellan300 RPM21.617.514.719.217.416.116.515.614.6200 RPM18.114.412.018.917.614.514.914.213.2100 RPM13.110.28.317.613.713.112.812.011.26 RPM2.51.71.28.77.46.27.46.45.33 RPM1.51.10.87.66.35.96.65.34.310s1.81.20.813.1 7.27.66.15.110M1.61.40.811.19.87.29.87.85.7 Table 61.5 ppb polymer, no calcium High-Acyl Gellanλ-carrageenanTemp (°F)9012015090120150600 RPMGelled. Gelled even at 1.0 ppb CaCl231.926.022.2300 RPM21.317.014.7200 RPM16.813.211.0100 RPM11.78.47.56 RPM1.61.21.23 RPM1.21.43.910s1.61.44.310M3.71.22.1 Table 71.5 ppb polymer, 3 ppb 25% CaCl2 GuarXanthanScleroglucanLow-Acyl GellanTemp (°F)90120150901201509012015090120150600 RPM29.223.520.024.722.220.789.677.975.7Gelled solid immediately upon addition of CaCl2300 RPM21.317.114.419.718.217.266.357.253.5200 RPM17.914.211.617.316.115.355.548.146.1100 RPM12.79.88.114.313.512.942.837.735.66 RPM2.62.01.68.47.76.917.715.514.33 RPM1.91.41.37.56.76.414.912.911.810s4.51.84.99.27.48.014.112.312.310M2.12.12.012.911.09.420.718.015.5 Table 81.5 ppb polymer, 3 ppb 25% CaCl2 High-Acyl Gellanλ-carrageenanTemp (°F)9012015090120150600 RPMGelled solid immediately upon addition of CaCl213.38.67.0300 RPM7.95.84.0200 RPM5.94.13.0100 RPM3.62.31.66 RPM0.40.40.33 RPM0.40.40.510s0.61.82.010M1.01.21.4 

[0093] With combined reference to Table 5 through Table 8, even at a relatively lower concentration of the polymer (about 1.5 ppb), some of the treatment fluids exhibited a response to calcium. For example, the low-acyl gellan and the high-acyl gellan exhibited gelling, even at 1.0 ppb of calcium chloride. The gel formed from the low-acyl gellan exhibited a relatively higher firmness than the gel formed from the high-acyl gellan. The i-carrageenan and the k-carrageenan turned solid at room temperature. Accordingly, even at lower concentrations of the polymers, some of the polymers exhibit a gelling response responsive to exposure to calcium (e.g., low-acyl gellan, high-acyl gellan, i-carrageenan, and k-carrageenan).

[0094] The embodiments of wellbore (e.g., treatment) fluids including the lost circulation material compositions described herein have been primarily described with reference to wellbore drilling operations; the treatment fluids including the lost circulation material compositions described herein may be used in applications other than the drilling of a wellbore. In other embodiments, treatment fluids including the lost circulation material compositions 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, treatment fluids including the lost circulation material compositions 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.

[0095] 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 all features 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.

[0096] 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.

[0097] 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.

[0098] 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.

[0099] 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

1. A wellbore fluid, comprising:a continuous phase comprising an oleaginous fluid;a discontinuous phase comprising a non-oleaginous fluid;an emulsion of the discontinuous phase in the continuous phase;at least one emulsifier disposed around droplets of the discontinuous phase;at least one gelling material comprising at least one of xanthan gum, scleroglucan gum, gellan gum, carrageenan gum, or curdlan gum; andat least one crosslinker dispersed within the non-oleaginous fluid of the discontinuous phase.

2. The wellbore fluid of claim 1, wherein the at least one crosslinker is configured to contact the at least one gelling material responsive to exposure of the wellbore fluid to a shear rate of at least about 10,000 sec-1.

3. The wellbore fluid of claim 1, wherein the at least one gelling material comprises gellan gum.

4. The wellbore fluid of claim 1, wherein the at least one gelling material comprises high-acyl gellan gum.

5. The wellbore fluid of claim 1, wherein the at least one gelling material comprises i-carrageenan or k-carrageenan.

6. The wellbore fluid of claim 1, wherein the at least one gelling material is substantially free of λ-carrageenan.

7. The wellbore fluid of claim 1, wherein the at least one crosslinker comprises a divalent cation.

8. The wellbore fluid of claim 1, wherein the at least one crosslinker comprises a polyvalent cation.

9. The wellbore fluid of claim 1, wherein the at least one crosslinker comprises cations of at least one of calcium, boron, zirconium, hafnium, magnesium, strontium, or iron.

10. The wellbore fluid of claim 1, wherein the at least one gelling material is present in the wellbore fluid at a concentration within a range of from about 2.85 kg / m3 to about 28.5 kg / m3.

11. The wellbore fluid of claim 1, wherein the discontinuous phase constitutes at least about 70 volume percent of the wellbore fluid.

12. The wellbore fluid of claim 1, wherein the at least one emulsifier comprises one or more of a fatty acid, a soap of a fatty acid, an amidoamine, a polyamide, a fatty acid ester derivative, an ethoxylated fatty acid, an ethoxylated alcohol, an oleate ester, an imidazoline derivative, or an alcohol derivative.

13. The wellbore fluid of claim 1, wherein the at least one crosslinker is present in the wellbore fluid at a concentration within a range of from about 2.85 kg / m3 to about 28.5 kg / m3.

14. The wellbore fluid of claim 1, wherein the at least one gelling material is dispersed in the oleaginous fluid of the continuous phase, the at least one crosslinker configured to react with the at least one gelling material to form a solid material responsive to breaking the emulsion.

15. The wellbore fluid of claim 1, wherein the at least one gelling material comprises curdlan gum.

16. A method of operating a wellbore, the method comprising:pumping a wellbore fluid though a drill string extending through the wellbore, the wellbore fluid comprising:an oleaginous continuous phase;a non-oleaginous discontinuous phase;at least one emulsifier stabilizing an emulsion of the non-oleaginous discontinuous phase in the oleaginous continuous phase;at least one gelling material comprising at least one of xanthan gum, scleroglucan gum, gellan gum, carrageenan gum, or curdlan gum; andat least one crosslinker dispersed in the non-oleaginous discontinuous phase and not contacting the at least one gelling material in the oleaginous continuous phase; andpumping a drilling fluid through the drill string to displace the wellbore fluid in the drill string and through a nozzle in a drill bit coupled to the drill string to expose the wellbore fluid to a shear rate greater than 10,000 sec-1 and cause the at least one crosslinker to contact the at least one gelling material and form a gel.

17. The method of claim 16, wherein pumping a wellbore fluid through a drill string comprises pumping a wellbore fluid comprising a gelling material comprising at least one of scleroglucan gum, gellan gum, i-carrageenan gum, k-carrageenan gum, or curdlan gum through the drill string.

18. The method of claim 16, wherein pumping a wellbore fluid through a drill string comprises pumping a wellbore fluid comprising a gelling material comprising at least one of i-carrageenan gum of k-carrageenan gum through the drill string.

19. The method of claim 16, wherein pumping a wellbore fluid through a drill string comprises pumping a wellbore fluid comprising a crosslinker comprising calcium cations through the drill string.

20. A wellbore fluid, comprising:a continuous phase comprising an oleaginous fluid;a discontinuous phase comprising a non-oleaginous fluid;an emulsion of the discontinuous phase in the continuous phase;at least one emulsifier disposed around droplets of the discontinuous phase;at least one gelling material comprising at least one of scleroglucan gum, gellan gum, i-carrageenan gum, k-carrageenan gum, or curdlan gum; andat least one crosslinker comprising cations of at least one of calcium, boron, zirconium, hafnium, magnesium, strontium, or iron dispersed within the non-oleaginous fluid of the discontinuous phase, the at least one crosslinker configured to contact the at least one gelling material responsive to exposure of the wellbore fluid to a shear rate of more than about 10,000 sec-1 to form a gel comprising the gelling material and the at least one crosslinker. 

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