Abstract: A treatment fluid system for reducing permeability of high permeability zones in a subterranean reservoir formation comprising a fluid composition comprising a nano-crosslinker, the nano-crosslinker comprising a nanomaterial, and a crosslinker, wherein the crosslinker comprises a chemical group selected from the group consisting of carbonyl, sulfhydryl, amine and imine, wherein the nano-crosslinker is produced by a method selected from the group consisting of pre-treating the nanomaterial with the crosslinker such that the crosslinker has been functionalized onto the nanomaterial, embedding the crosslinker on the nanoparticle, grafting the crosslinker onto the nanomaterial, and coating the crosslinker on the nanomaterial, a base polymer, and a base fluid, the base fluid operable to suspend the fluid composition, wherein the base fluid comprises water, wherein the treatment fluid system is operable to reduce permeability of a high permeability zone in the subterranean reservoir formation.

Abstract: A method includes mixing seawater with a two-part additive system configured to precipitate sulfate from the seawater; removing the sulfate precipitates from the seawater; and delivering the seawater into an oilfield reservoir.

Abstract: A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

Abstract: A polymer-encapsulated mineral acid solution and a method for forming the polymer-encapsulated mineral acid solution. Introducing a strong mineral acid solution to a monomer solution occurs such that a primary emulsion that is a water-in-oil type emulsion forms. Introducing the primary emulsion to a second aqueous solution forms a secondary emulsion that is a water-in-oil-in-water type double emulsion. The monomer in the secondary emulsion is cured such a polymerized shell forms that encapsulates the strong mineral acid solution and forms the capsule. The strong mineral acid solution has up to 30 wt. % strong mineral acid. A method of stimulating a hydrocarbon-bearing formation using the polymer-encapsulated mineral acid solution includes introducing a capsule suspension into a fissure in the hydrocarbon-bearing formation to be stimulated through a face in a well bore. The capsule is maintained within the fissure until the polymer shell degrades.

Abstract: A polymer-encapsulated mineral acid solution and a method for forming the polymer-encapsulated mineral acid solution. Introducing a strong mineral acid solution to a monomer solution occurs such that a primary emulsion that is a water-in-oil type emulsion forms. Introducing the primary emulsion to a second aqueous solution forms a secondary emulsion that is a water-in-oil-in-water type double emulsion. The monomer in the secondary emulsion is cured such a polymerized shell forms that encapsulates the strong mineral acid solution and forms the capsule. The strong mineral acid solution has up to 30 wt. % strong mineral acid. A method of stimulating a hydrocarbon-bearing formation using the polymer-encapsulated mineral acid solution includes introducing a capsule suspension into a fissure in the hydrocarbon-bearing formation to be stimulated through a face in a well bore. The capsule is maintained within the fissure until the polymer shell degrades.

Abstract: A fracturing fluid including a base fluid including salt water, a polymer, a crosslinker, and a nanomaterial. The crosslinker may include a Zr crosslinker, a Ti crosslinker, an Al crosslinker, a borate crosslinker, or a combination thereof. The nanomaterial may include ZrO2 nanoparticles, TiO2 nanoparticles, CeO2 nanoparticles; Zr nanoparticles, Ti nanoparticles, Ce nanoparticles, metal-organic polyhedra including Zr, Ti, Ce, or a combination thereof; carbon nanotubes, carbon nanorods, nano graphene, nano graphene oxide; or any combination thereof. The viscosity and viscosity lifetime of fracturing fluids with both crosslinkers and nanomaterials are greater than the sum of the effects of crosslinkers and nanomaterials taken separately.

Abstract: A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

Abstract: A treatment fluid system for reducing permeability of high permeability zones in a subterranean reservoir formation comprising a fluid composition comprising a nano-crosslinker, the nano-crosslinker comprising a nanomaterial, and a crosslinker, wherein the crosslinker comprises a chemical group selected from the group consisting of carbonyl, sulfhydryl, amine and imine, wherein the nano-crosslinker is produced by a method selected from the group consisting of pre-treating the nanomaterial with the crosslinker such that the crosslinker has been functionalized onto the nanomaterial, embedding the crosslinker on the nanoparticle, grafting the crosslinker onto the nanomaterial, and coating the crosslinker on the nanomaterial, a base polymer, and a base fluid, the base fluid operable to suspend the fluid composition, wherein the base fluid comprises water, wherein the treatment fluid system is operable to reduce permeability of a high permeability zone in the subterranean reservoir formation.

Abstract: A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

Abstract: A stabilized emulsified acid composition for deep carbonate formation stimulation is provided. The stabilized acid emulsion composition includes a petroleum operable to provide a barrier between an acid and a reservoir rock, the acid operable to react with the reservoir rock to dissolve the reservoir rock and produce a wormhole, a functional framework operable to stabilize the stabilized acid emulsion, an emulsifier operable to stabilize the stabilized acid emulsion, and a corrosion inhibitor operable to provide protection against corrosion for the metal components of a well. The petroleum can be diesel. The acid can be hydrochloric acid. The functional framework can be selected from the group comprising surface-modified clay-based material, zeolites, hybrid organic-inorganic materials, covalent-organic framework materials, and boron nitride nanotubes, and combinations thereof. The functional framework can be a surface-modified clay material selected from an organoclay.

Abstract: Gelled fluids include a gellable organic solvent, an aluminum crosslinking compound, and a mutual solvent. The gelled fluids may be prepared by combining an aluminum crosslinking compound and a first volume of a gellable organic solvent to form a pre-solvation mixture; gelling the pre-solvation mixture to form a pre-solvated gel; combining the pre-solvated gel with a formulation fluid to form a gellable mixture, the formulation fluid comprising a second volume of the gellable organic solvent; and gelling the gellable mixture to form the gelled fluid.

Abstract: A fracturing fluid system for increasing hydrocarbon production in a subterranean reservoir formation comprising a fluid composition and a base fluid, the fluid composition comprising a nano-crosslinker, and a base polymer; and the base fluid operable to suspend the fluid composition, the base fluid comprising water; wherein the fluid composition and the base fluid are combined to produce the fracturing fluid system, wherein the fracturing fluid system is operable to stimulate the subterranean reservoir formation. In certain embodiments, the nano-crosslinker is an amine-containing nano-crosslinker and the base polymer is an acrylamide-based polymer. In certain embodiments, the fracturing fluid systems comprise proppants for enhancing hydraulic fracturing stimulation in a subterranean hydrocarbon reservoir.

Abstract: Provided in this disclosure, in part, are methods, compositions, and systems for degrading organic matter, such as kerogen, in a subterranean formation. Further, these methods, compositions, and systems allow for increased hydraulic fracturing efficiencies in subterranean formations, such as unconventional rock reservoirs. Also provided in this disclosure is a method of treating kerogen in a subterranean formation including placing in the subterranean formation a composition that includes a first oxidizer including a persulfate and a second oxidizer including a bromate.

Abstract: A composition for use as a pressure-tolerant dual-crosslinker gel in a fracturing fluid that comprises polymer, the polymer operable to increase the viscosity of a fluid; boron-containing crosslinker, the boron-containing crosslinker operable to crosslink the polymer; and a transition metal oxide additive, the transition metal oxide additive operable to crosslink the polymer.

Abstract: A fracturing fluid system for increasing hydrocarbon production in a subterranean reservoir formation comprising a fluid composition and a base fluid, the fluid composition comprising a nano-crosslinker, and a base polymer; and the base fluid operable to suspend the fluid composition, the base fluid comprising water; wherein the fluid composition and the base fluid are combined to produce the fracturing fluid system, wherein the fracturing fluid system is operable to stimulate the subterranean reservoir formation. In certain embodiments, the nano-crosslinker is an amine-containing nano-crosslinker and the base polymer is an acrylamide-based polymer. In certain embodiments, the fracturing fluid systems comprise proppants for enhancing hydraulic fracturing stimulation in a subterranean hydrocarbon reservoir.

Abstract: A polymer-encapsulated mineral acid solution and a method for forming the polymer-encapsulated mineral acid solution. Introducing a strong mineral acid solution to a monomer solution occurs such that a primary emulsion that is a water-in-oil type emulsion forms. Introducing the primary emulsion to a second aqueous solution forms a secondary emulsion that is a water-in-oil-in-water type double emulsion. The monomer in the secondary emulsion is cured such a polymerized shell forms that encapsulates the strong mineral acid solution and forms the capsule. The strong mineral acid solution has up to 30 wt. % strong mineral acid. A method of stimulating a hydrocarbon-bearing formation using the polymer-encapsulated mineral acid solution includes introducing a capsule suspension into a fissure in the hydrocarbon-bearing formation to be stimulated through a face in a well bore. The capsule is maintained within the fissure until the polymer shell degrades.

Abstract: A fracturing fluid including a base fluid including salt water, a polymer, a crosslinker, and a nanomaterial. The crosslinker may include a Zr crosslinker, a Ti crosslinker, an Al crosslinker, a borate crosslinker, or a combination thereof. The nanomaterial may include ZrO2 nanoparticles, TiO2 nanoparticles, CeO2 nanoparticles; Zr nanoparticles, Ti nanoparticles, Ce nanoparticles, metal-organic polyhedra including Zr, Ti, Ce, or a combination thereof; carbon nanotubes, carbon nanorods, nano graphene, nano graphene oxide; or any combination thereof. The viscosity and viscosity lifetime of fracturing fluids with both crosslinkers and nanomaterials are greater than the sum of the effects of crosslinkers and nanomaterials taken separately.

Abstract: A polymer-encapsulated mineral acid solution and a method for forming the polymer-encapsulated mineral acid solution. Introducing a strong mineral acid solution to a monomer solution occurs such that a primary emulsion that is a water-in-oil type emulsion forms. Introducing the primary emulsion to a second aqueous solution forms a secondary emulsion that is a water-in-oil-in-water type double emulsion. The monomer in the secondary emulsion is cured such a polymerized shell forms that encapsulates the strong mineral acid solution and forms the capsule. The strong mineral acid solution has up to 30 wt. % strong mineral acid. A method of stimulating a hydrocarbon-bearing formation using the polymer-encapsulated mineral acid solution includes introducing a capsule suspension into a fissure in the hydrocarbon-bearing formation to be stimulated through a face in a well bore. The capsule is maintained within the fissure until the polymer shell degrades.

Abstract: Gelled hydrocarbon fracturing fluids and their methods of preparation and use are provided. The gelled hydrocarbon fracturing fluid includes a hydrocarbon fluid, a phosphate ester, a crosslinker and a viscosifier. The crosslinker may include iron, aluminum, or combinations thereof and the viscosifier may include clay, graphite, carbon nanotubes, metallic oxide nanoparticles, and combinations thereof. The method of preparation includes combining a hydrocarbon fluid, phosphate ester, and crosslinker to form a baseline fluid. A viscosifier is added to the baseline fluid to form a gelled hydrocarbon fracturing fluid. The method of use includes treating a subterranean formation by contacting a subterranean formation with a gelled hydrocarbon fracturing fluid and generating at least one fracture in the subterranean formation.

Abstract: Fracturing a reservoir includes providing a pad fluid to the reservoir via a wellbore in a well to create fractures in the reservoir, providing a fracturing fluid to the fractures via the wellbore, providing a geopolymer precursor fluid to the fractures via the wellbore, shutting in the wellbore at a wellbore pressure, thereby allowing the geopolymer precursor fluid to harden and form geopolymer proppant pillars in the fractures. Providing the geopolymer precursor fluid to the fractures includes pulsing quantities of the geopolymer precursor fluid into a continuous flow of the fracturing fluid or alternately pulsing quantities of the geopolymer precursor fluid and the fracturing fluid. An elapsed time between pulsing the quantities of the geopolymer precursor fluid is between 2 seconds and 20 minutes.