Abstract: A method to control a heat transfer profile in a defined space, the method comprising the steps of introducing a thermally insulating packer fluid into the defined space such that the thermally insulating packer fluid forms a gelled solid and reduces a rate of heat transfer through the defined space as compared to a prior rate of heat transfer through the defined space before introducing the thermally insulating packer fluid, where the thermally insulating packer fluid comprises an acidic nanosilica dispersion and a polyamine.

Abstract: In one embodiment, a retarded acid system comprises an aqueous acid and a retarding surfactant. The aqueous acid may comprise from 5 wt. % to 25 wt. % of a strong acid, that is, an acid having a Ka greater than or equal to 0.01. The aqueous acid may further comprise from 75 wt. % to 95 wt. % water. The retarding surfactant may have the general chemical formula R—(OC2H4)X—OH where R is a hydrocarbon having from 11 to 15 carbon atoms and x is an integer from 6 to 10. The retarding surfactant may have a hydrophilic-lipophilic balance from 8 to 16.

Abstract: An invert-emulsion drilling fluid may include a dispersed aqueous phase including an aqueous base fluid, a continuous non-aqueous phase including a non-aqueous base fluid, and a first bridging package. The first bridging package may include one or more particulate carbonate materials. All of the particulate carbonate materials of the invert-emulsion drilling fluid may be part of the first bridging package. The first bridging package may have a trimodal particle size distribution such that the particle size distribution of the first bridging package includes three peaks, wherein each peak may be in the range of less than or equal to 300 microns in the particle size distribution. The invert-emulsion drilling fluid may be included in methods for reducing lost circulation in subterranean formations during drilling operations.

Abstract: A sealing composition for sealing an annulus of a wellbore includes from 20 weight percent to 97 weight percent epoxy resin based on the total weight of the composition. The epoxy resin comprising at least one of 2,3-epoxypropyl o-tolyl ether, alkyl glycidyl ethers having from 12 to 14 carbon atoms, or a compound having formula (OC2H3)—CH2—O—R1—O—CH2—(C2H3O), where R1 is a linear or branched hydrocarbyl having from 4 to 24 carbon atoms. The sealing composition also includes from 1 weight percent to 20 weight percent curing agent based on the total weight of the composition. Methods for sealing a wellbore annulus or casing-casing annulus includes introducing a spacer fluid to the wellbore, introducing the sealing composition to the wellbore, displacing the sealing composition into the annulus, and curing the sealing composition.

Abstract: A lost circulation material (LCM) is provided having an alkaline nanosilica dispersion and an ester activator. The alkaline nanosilica dispersion and the ester activator may form a gelled solid after interaction over a contact period. Methods of lost circulation control using the LCM are also provided.

Abstract: A lost circulation material (LCM) composition for sealing lost circulation zones in wellbores may include 50 weight percent to 97 weight percent epoxy resin, 2 weight percent to 30 weight percent curing agent, 0.1 weight percent to 40 weight percent weighting material, and 0.1 weight percent to 20 weight percent amide accelerator. The LCM composition may have a density of greater than or equal to 1121 kilograms per cubic meter and may be capable of being injected through a drill bit of a drill string into the lost circulation zone. The amide accelerator may enable the viscosity of the LCM composition to be reduced while providing a reduced cure time. The LCM compositions are suitable for treating high-injectivity lost circulation zones.

Abstract: A sealing composition for sealing an annulus of a wellbore includes from 20 weight percent to 97 weight percent epoxy resin based on the total weight of the composition. The epoxy resin comprising at least one of 2,3-epoxypropyl o-tolyl ether, alkyl glycidyl ethers having from 12 to 14 carbon atoms, or a compound having formula (OC2H3)—CH2—O—R1—O—CH2—(C2H3O), where R1 is a linear or branched hydrocarbyl having from 4 to 24 carbon atoms. The sealing composition also includes from 1 weight percent to 20 weight percent curing agent based on the total weight of the composition.

Abstract: Disclosed here are drilling fluid compositions containing linear alpha olefins, an invert emulsifier, a filtration control agent; and an inorganic mineral component including one or more of lime, calcium chloride, and barite. Also disclosed here are methods of using such compositions during drilling operations for recovery of hydrocarbons. Various other embodiments may be disclosed and claimed.

Abstract: Embodiments disclosed relate to a composition and a method of treating a formation. The method includes introducing a loss circulation material system through a wellbore into a formation, where the loss circulation material system is comprised of an esterified derivative of an epoxidized organic material and a curing agent. The esterified derivative of an epoxidized organic material has a formula of: where R? comprises H, a substituted or an unsubstituted (C1-C12) hydrocarbyl group; and where R? comprises a substituted or an unsubstituted (C2-C30) hydrocarbyl group, including where at least one oxygen atom is attached to two different adjacent carbon atoms of the (C2-C30) hydrocarbyl group. The method also includes maintaining wellbore conditions such that the loss circulation material system cures into a loss circulation material in the formation. The cured loss circulation material may withstand a pressure differential up to about 20,000 psid.

Abstract: Provided is a lost circulation material that may consist essentially of an alkaline nanosilica dispersion and a sodium bicarbonate activator. Further provided are methods that may control lost circulation in a lost circulation zone in a wellbore by introducing the lost circulation material such that it contacts the lost circulation zone and forms a gelled solid in the lost circulation zone.

Abstract: A well treatment fluid having an acidic nanosilica dispersion, an epoxy resin, and a polyamine activator. The acidic nanosilica dispersion and the polyamine activator may form a gelled solid after interaction over a time period. Methods of reducing water production using the well treatment fluids are also provided.

Abstract: A method includes introducing an epoxy resin system to a wellbore defect in a wellbore. The epoxy resin system comprises a polyhedral oligomeric silsesquioxane (POSS) epoxy resin with at least one reactive group and a curing agent. The method includes maintaining the epoxy resin system in the wellbore such that a cured epoxy resin system product forms in the wellbore defect.

Abstract: A well bore cementing system may comprise a spacer fluid and a cement slurry. The spacer fluid may be positioned within a well bore, and the spacer fluid may comprise a first surfactant package comprising one or more surfactants. The cement slurry may be positioned within the well bore, and the cement slurry may comprise a second surfactant package comprising one or more surfactants.

Abstract: This disclosure relates to a foamable resin composition containing a nitrogen gas-generating compound and methods of using the composition for loss circulation control.

Abstract: A corrosion inhibiting cement composition for reducing corrosion of wellbore casings is disclosed that includes from 10 weight percent to 70 weight percent cement precursor, from 5 weight percent to 70 weight percent water, from 0.1% to 60% by weight of cement amine corrosion inhibitor, where the amine corrosion inhibitor comprises a polyethylene polyamine. A method for reducing corrosion of wellbore casings includes dispensing the corrosion inhibiting cement compositions into the annulus and allowing the corrosion inhibiting cement composition to cure to form a hardened cement, where the corrosion inhibiting cement composition includes a cement composition and the amine corrosion inhibitor.

Abstract: A method of reducing corrosion in tubular strings installed in wellbores includes dispensing an accelerated cement composition into a wellbore annulus, a casing-casing annulus, or both, the accelerated cement composition comprising a cement composition and an accelerant composition, where: the cement composition comprises a cement precursor and water; the accelerant composition comprises triethanolamine; and a concentration of the triethanolamine in the accelerated cement composition is greater than or equal to 10,000 parts per million by weight; allowing the accelerated cement composition to cure in the annulus to form a cured cement, where the triethanolamine reacts with a metal of the tubular string, the reaction forming a protective layer on the surfaces of the tubular string that inhibits dissolution of iron from the metal of the tubular string.

Abstract: Drilling fluid compositions include invert emulsion fluids having an oleaginous phase, an aqueous phase, and an emulsifier composition that includes an ethoxylated alcohol compound and a polyaminated fatty acid compound. The ethoxylated alcohol compound has the formula R1—(OCH2CH2)n—OH, where R1 is a hydrocarbyl group having from 8 to 22 carbon atoms and n is from 1 to 8. The ethoxylated alcohol compound has a Hydrophilic-Lipophilic Balance (HLB) of less than or equal to 6. The polyaminated fatty acid compound has the formula R2—CO—NH—CH2—CH2—N(COR2)—CH2—CH2—NH—CO—R3, where R2 is a hydrocarbyl group having from 1 to 20 carbon atoms and R3 is a hydrocarbyl group having from 1 to 10 carbon atoms or an alkylene carboxylate group having formula —R4—COOH, where R4 is a saturated or unsaturated hydrocarbylene having from 1 to 10 carbon atoms. Methods of drilling wells include operating a drill in a wellbore in the presence of drilling fluid compositions.

Abstract: Drilling fluid compositions and methods for using drilling fluid compositions are provided with enhanced anti-bit balling properties that include an aqueous-based fluid, one or more drilling fluid additives, and an anti-bit balling additive. The anti-bit balling additive may be an epoxidized ?-olefin and the drilling fluid may include the anti-bit balling additive in an amount ranging from about 0.5 ppb to about 20 ppb. Methods for using the drilling fluid compositions may further include mixing an aqueous base fluid with one or more drilling fluid additives and an anti-bit balling additive, wherein the anti-bit balling additive includes epoxidized ?-olefin and the drilling fluid may include the anti-bit balling additive in an amount ranging from about 0.5 ppb to about 20 ppb, and introducing the drilling fluid to a subterranean formation.

Abstract: In accordance with one or more embodiments of the present disclosure, a method of consolidating sands in a subterranean formation penetrated by a wellbore may comprise contacting sand particles in the subterranean formation with a treatment fluid to form coated sands; where the treatment fluid comprises a multicomponent epoxy, a base fluid, and an amine hardening agent, the multicomponent epoxy comprising a diglycidyl ether resin and a monoglycidyl ether resin. The method further allowing the amine hardening agent to cure the multicomponent epoxy and form the consolidated sands.

Abstract: An invert oil-based mud (OBM) may include an oleaginous continuous phase, an aqueous internal phase, and an emulsifier. The emulsifier may include one or more of the group consisting of epoxidized methyl oleate, epoxidized methyl linoleate, and epoxidized methyl ?-linolenate. The invert OBM may contain the emulsifier in an amount of the range of 0.1 to 10 wt. % (weight percent), relative to the total weight of the OBM.