Abstract: Provided are water-soluble polymers that may include a water-soluble bipolymer, a water-soluble anionic terpolymer, and a water-soluble cationic terpolymer. The water-soluble polymers may include a reaction product of a first monomer that has a vinyl-containing group linked to a pendant carbohydrate moiety; a second monomer that has a vinyl group, a carbonyl group and a nitrogen; an anionic monomer in a water-soluble anionic terpolymer; and a cationic monomer in a water-soluble cationic terpolymer. Further provided are aqueous solutions that may include a water-soluble bipolymer, a water-soluble anionic terpolymer, and a water-soluble cationic terpolymer. Further provided are methods of use that may include introducing an aqueous solution into a formation such that the formation fractures, where the aqueous solution may include a water-soluble bipolymer, a water-soluble anionic terpolymer, and a water-soluble cationic terpolymer.

Abstract: Methods and systems including a composition of a hydratable polymer slurry comprising a hydrocarbon-based solvent. The hydrocarbon-based solvent includes a hydratable polymer powder and at least one of a polar surfactant, a hydrocarbon-soluble polymer, and/or an organophilic clay, wherein the polymer slurry is prepared at a temperature greater than 22° C. by mixing.

Abstract: Methods and systems including a composition of a hydratable polymer slurry comprising a hydrocarbon-based solvent. The hydrocarbon-based solvent includes a hydratable polymer powder and at least one of a polar surfactant, a hydrocarbon-soluble polymer, and/or an organophilic clay, wherein the polymer slurry is prepared at a temperature greater than 22° C. by mixing.

Abstract: A method of producing a 3D printed proppant comprises providing a 3D printing apparatus that produces the 3D printed proppant; distributing a layer of build material within a build chamber of the 3D printing apparatus, wherein the build material comprises metal, polymer, ceramic, composite, or combinations thereof; depositing a layer of binder material on the layer of build material; curing the binder material within the 3D printing apparatus; and repeating as necessary to produce the 3D printed proppant, wherein the 3D printed proppant has a particle size from 8 mesh to 140 mesh.

Abstract: Hydrogen may be produced from natural gas (e.g., methane). For example, a method for producing hydrogen from natural gas may include: introducing natural gas to a reactor, wherein the reactor contains therein a catalyst, wherein the catalyst includes a high entropy alloy, and wherein the high entropy alloy has an entropy, S, such that S?11.31 J K?1 mol?1; reacting the natural gas with the catalyst to form hydrogen gas and solid carbon; and separating the hydrogen gas from the solid carbon to produce a hydrogen stream comprising the hydrogen gas from the reactor.

Abstract: A formation treatment fluid may include a wettability alteration agent, a solvent, an injection gas, and an optional foaming agent. The wettability alteration agent may include a fluorinated surfactant, a silicon-based surfactant, charged nanoparticles partially modified with fluorine containing groups, or combinations thereof. Methods for altering a hydrocarbon-bearing reservoir surface wettability may include providing the formation treatment fluid, injecting the formation treatment fluid into the hydrocarbon-bearing reservoir, and recovering fluids produced from the hydrocarbon-bearing reservoir.

Abstract: A 3D printed proppant includes a core having support bars extending from the core to a shell, the shell encapsulating the core and the support bars. Another 3D printed proppant includes a porous core and a shell encapsulating the porous core, where the porous core has a porosity from 25% to 75%. The 3D printed proppant has a particle size from 8 mesh to 140 mesh. The core, the support bars, the porous core, the shell, or combinations thereof includes metal, polymer, ceramic, composite, or combinations thereof. Additionally, a method for producing a 3D printed proppant is provided.

Abstract: A formation treatment fluid may include a wettability alteration agent, a solvent, an injection gas, and an optional foaming agent. The wettability alteration agent may include a fluorinated surfactant, a silicon-based surfactant, charged nanoparticles partially modified with fluorine containing groups, or combinations thereof. Methods for altering a hydrocarbon-bearing reservoir surface wettability may include providing the formation treatment fluid, injecting the formation treatment fluid into the hydrocarbon-bearing reservoir, and recovering fluids produced from the hydrocarbon-bearing reservoir.

Abstract: A formation treatment composition that includes an aqueous fluid, at least omniphobic fluorochemical, and an acid is described. A method of attenuating acid reactivity of a formation rock is also described. The method includes injecting a formation treatment composition into a reservoir, contacting the omniphobic fluorochemical of the formation treatment composition with the rock, and mitigating a reaction between the acid of the formation treatment composition and the rock surface.

Abstract: A friction reducer includes a polysaccharide-graft-water-soluble polymer is provided. A polysaccharide in an amount of from about 0.1 to 50% by weight (wt. %) may make up the polysaccharide-graft-water-soluble polymer. A wellbore treatment fluid is provided that includes an aqueous base fluid and the friction reducer in an amount up to about 10% of the wellbore treatment fluid. A method of using a wellbore treatment fluid includes the step of introducing the wellbore treatment fluid as previously provided into a wellbore.

Abstract: A formation treatment fluid may include a wettability alteration agent, a solvent, an injection gas, and an optional foaming agent. The wettability alteration agent may include a fluorinated surfactant, a silicon-based surfactant, charged nanoparticles partially modified with fluorine containing groups, or combinations thereof. Methods for altering a hydrocarbon-bearing reservoir surface wettability may include providing the formation treatment fluid, injecting the formation treatment fluid into the hydrocarbon-bearing reservoir, and recovering fluids produced from the hydrocarbon-bearing reservoir.

Abstract: A 3D printed proppant includes a core having support bars extending from the core to a shell, the shell encapsulating the core and the support bars. Another 3D printed proppant includes a porous core and a shell encapsulating the porous core, where the porous core has a porosity from 25% to 75%. The 3D printed proppant has a particle size from 8 mesh to 140 mesh. The core, the support bars, the porous core, the shell, or combinations thereof includes metal, polymer, ceramic, composite, or combinations thereof. Additionally, a method for producing a 3D printed proppant is provided.

Abstract: Provided are water-soluble polymers that may include a water-soluble bipolymer, a water-soluble anionic terpolymer, and a water-soluble cationic terpolymer. The water-soluble polymers may include a reaction product of a first monomer that has a vinyl-containing group linked to a pendant carbohydrate moiety; a second monomer that has a vinyl group, a carbonyl group and a nitrogen; an anionic monomer in a water-soluble anionic terpolymer; and a cationic monomer in a water-soluble cationic terpolymer. Further provided are aqueous solutions that may include a water-soluble bipolymer, a water-soluble anionic terpolymer, and a water-soluble cationic terpolymer. Further provided are methods of use that may include introducing an aqueous solution into a formation such that the formation fractures, where the aqueous solution may include a water-soluble bipolymer, a water-soluble anionic terpolymer, and a water-soluble cationic terpolymer.

Abstract: A friction reducer includes a polysaccharide-graft-water-soluble polymer is provided. A polysaccharide in an amount of from about 0.1 to 50% by weight (wt. %) may make up the polysaccharide-graft-water-soluble polymer. A wellbore treatment fluid is provided that includes an aqueous base fluid and the friction reducer in an amount up to about 10% of the wellbore treatment fluid. A method of using a wellbore treatment fluid includes the step of introducing the wellbore treatment fluid as previously provided into a wellbore.

Abstract: Downhole fluid compositions including a base fluid and an effective amount of a synthetic hydratable polymer system including a hydrophobically modified, cross-linked polyacrylate polymer, a hydrophilic, anionic, high molecular weight, cross-linked polyacrylic acid polymer, or mixtures and combinations thereof, where the effective amount is sufficient to achieve a desired viscosity profile and a desired breaking profile in the present of a breaking system in the absence of natural hydratable polymers.

Abstract: Methods and compositions using gel compositions in treatment fluids employed in subterranean operations. A method includes providing a degradable gel precursor as a solid or dispersion in which substantially all the water has been removed, the degradable gel precursor being formed by a combination of a monomer and a degradable crosslinking agent of formula R1-[A]-[R3]—[B]—R2, wherein R1 and R2 may be the same or different, and includes at least one group selected from a substituted or unsubstituted ethylenically unsaturated group, N-acryloyl, O-acryloyl, vinyl, allyl, maleic anydride, a derivative thereof, and a combination thereof, A and B comprise optional bridging units, and R3 comprises a degradable group or polymer, the method including placing the degradable gel precursor in an aqueous base fluid thereby forming a treatment fluid which includes a degradable gel, and placing the treatment fluid into a subterranean formation.

Abstract: Methods are provided that include a method comprising: providing an emulsified treatment fluid comprising an oleaginous phase, an aqueous phase, a consolidating agent, and an emulsifying agent that comprises at least one convertible surfactant described by a one of the disclosed formulae, and placing the subterranean treatment fluid in a subterranean formation.

Abstract: Methods are provided that include a method comprising: providing an emulsified treatment fluid comprising an oleaginous phase, an aqueous phase, a consolidating agent, and an emulsifying agent that comprises at least one convertible surfactant described by a one of the disclosed formulae, and placing the subterranean treatment fluid in a subterranean formation.

Abstract: Methods are provided that include a method comprising providing a viscosified treatment fluid comprising a base fluid and a gelling agent that comprises a clarified xanthan; and placing the viscosified treatment fluid into at least a portion of a subterranean formation. In some embodiments, the method comprises placing the viscosified treatment fluid into at least a portion of a subterranean formation at a pressure sufficient to create or enhance at least one fracture in the subterranean formation. In some embodiments, the viscosified treatment fluid may also comprise a plurality of particulates. In some embodiments, the viscosified treatment fluids may be placed into at least a portion of a pipeline. Additional methods are also provided.

Abstract: Herein provided are methods for producing degradable particulates at a drill site, and methods related to the use of such degradable particulates in subterranean applications. In one embodiment, the present invention provides a method comprising: providing a treatment fluid, the treatment fluid comprising degradable particulates, the degradable particulates having been made by an emulsion method at a drill site; and introducing the treatment fluid into a well bore penetrating a subterranean formation at the drill site.