Abstract: A solids-control fluid for controlling flow of solids in a subterranean formation is disclosed herein. The solids-control fluid can include a diluent and a curable resin. The diluent can include a mutual solvent and an ethylene glycol. The curable resin can be dispersed within the diluent for controlling flow of solids in the subterranean formation.

Abstract: A method may include: introducing a treatment fluid into a subterranean formation, the treatment fluid comprising: an aqueous brine; and a hydrolysable resin precursor; allowing the hydrolysable resin precursor to hydrolyze in the subterranean formation to form at least a polymerizable resin precursor monomer; and allowing the polymerizable resin precursor monomer to polymerize to form a polymerized resin in the subterranean formation.

Abstract: A method and system pulse for treating a plurality of wells simultaneously includes applying a high pressure of fracturing fluid to one or more switching valves and repeatedly opening and closing the one or more switching valves to divert the fracturing fluid near instantaneously from one well to the other well to creating a pulse wave into the plurality of wells for fracturing subterranean formations. The one or more switching valves may be a single 3-way valve incorporating the function of two or more switching valves. This technique reduces wear of surface equipment including high pressure pumps that need only provide a constant pressure.

Abstract: A method including collecting exhaust gas comprising carbon dioxide (CO2) at a wellsite to provide a collected exhaust gas, separating CO2 from the collected exhaust gas to provide a separated CO2, and forming an alcohol product utilizing at least a portion of the separated CO2. The alcohol product can include methanol, ethanol, a precursor thereof, or a combination thereof.

Abstract: The present disclosure may relate to a method of remediating a wellbore. The method may comprise pumping a resin treatment fluid from a surface location to an annular space bounded by an outer diameter of a production tubular, wherein the resin treatment fluid comprises a liquid hardenable resin, a hardening agent, and a particulate bridging agent. The resin treatment fluid may gravity settle in the annular space to contact production equipment in the annular space such that at least a portion of the particulate bridging agent bridges across one or more damaged sections of the production equipment, wherein at least a portion of the liquid hardenable resin sets to form a hardened mass to seal the one or more damaged sections.

Abstract: A method including collecting exhaust gas comprising carbon dioxide (CO2) at a wellsite to provide a collected exhaust gas, separating CO2 from the collected exhaust gas to provide a separated CO2, and forming formic acid utilizing at least a portion of the separated CO2. At least a portion of the formic acid can be utilizing in a wellbore servicing fluid (e.g., a fracturing fluid) introduced downhole via a wellbore. The exhaust gas can be produced during a wellbore servicing operation at the or another wellbore. A system for carrying out the method is also provided.

Abstract: A method includes collecting exhaust gas comprising carbon dioxide (CO2) at a wellsite to provide a collected exhaust gas, separating CO2 from the collected exhaust gas to provide a separated CO2, and forming urea utilizing at least a portion of the separated CO2. A system for carrying out the method is also provided.

Abstract: A method including reacting, at a jobsite, a total dissolved solids (TDS) water with a gas comprising carbon dioxide (CO2) in the presence of a proton-removing agent to produce a CO2-reduced gas and an aqueous product comprising water and a precipitate, wherein the TDS water comprises produced water, wherein the precipitate comprises one or more carbonates, and wherein the CO2-reduced gas comprises less CO2 than the gas comprising CO2; and separating at least a portion of the water from the aqueous product to provide a concentrated slurry of the precipitate and a TDS-reduced water, wherein the TDS-reduced water comprises less TDS than the TDS water.

Abstract: An omniphobic emulsion comprising an aqueous continuous phase having dispersed therein a plurality of non-aqueous discontinuous phase droplets; wherein the non-aqueous discontinuous phase droplets are characterized by a droplet size of less than about 100 micrometers (?m); wherein each of the plurality of non-aqueous discontinuous phase droplets comprises a plurality of surfactant molecules and an omniphobic agent, wherein each surfactant molecule has a hydrophilic head portion and a hydrophobic tail portion; wherein each of the plurality of non-aqueous discontinuous phase droplets comprises the plurality surfactant molecules having the hydrophilic head portions disposed into a droplet outer layer with the hydrophobic tail portions extending inward from the droplet outer layer toward the omniphobic agent; and wherein the droplet outer layer encloses the omniphobic agent.

Abstract: Green hydrogen and solid carbon can be produced by reacting captured methane with a catalyst in a reaction chamber. A liquid base fluid can form a continuous phase within the reaction chamber with a plurality of liquid metal carrier droplets dispersed in the base fluid. The catalyst can be nano-sized particles that can coat the surfaces of the carrier droplets. Agitation can be supplied to the reaction chamber to maintain dispersion of the liquid metal carrier droplets and increase contact of the methane and catalyst particles. The reaction temperature can be less than the temperature required for water electrolysis or steam methane reforming processes. The green hydrogen and solid carbon can be used as a power source for wellsite equipment in the form of fuel cells to generate electricity or power or used to charge batteries.

Abstract: A slickwater fracturing fluid that includes a brine with dissolved solids, an anionic friction reducing additive, a polysaccharide, and a nanomaterial that includes nanoparticles with an average particle size between about 1 nm and about 500 nm. The polysaccharide and the anionic friction reducing additive synergistically reduce friction of the slickwater fracturing fluid so as to increase an injection rate of the slickwater fracturing fluid. Also, the polysaccharide, the anionic friction reducing additive, and the nanomaterial synergistically provide viscosity to the slickwater fracturing fluid so as to increase proppant transport capability. Also described is a method of fracturing a subterranean formation by pumping the slickwater fracturing fluid into a borehole and fracturing the subterranean formation with the slickwater fracturing fluid.

Abstract: A slickwater fracturing fluid that includes a brine with dissolved solids, an anionic friction reducing additive, a polysaccharide, and a nanomaterial that includes nanoparticles with an average particle size between about 1 nm and about 500 nm. The polysaccharide and the anionic friction reducing additive synergistically reduce friction of the slickwater fracturing fluid so as to increase an injection rate of the slickwater fracturing fluid. Also, the polysaccharide, the anionic friction reducing additive, and the nanomaterial synergistically provide viscosity to the slickwater fracturing fluid so as to increase proppant transport capability. Also described is a method of fracturing a subterranean formation by pumping the slickwater fracturing fluid into a borehole and fracturing the subterranean formation with the slickwater fracturing fluid.

Abstract: Foamed treatment fluids for use in subterranean formations are provided. In one embodiment, a method of using a foamed treatment fluid comprises: introducing a foamed treatment fluid into a wellbore penetrating at least a portion of a subterranean formation at or above a pressure sufficient to create or enhance one or more fractures in the subterranean formation, wherein the foamed treatment fluid comprises an aqueous base fluid, one or more surfactants, a natural gas, and a plurality of nanoparticles.

Abstract: A variety of systems, methods and compositions are disclosed, including, in one method, a method may comprise providing a proppant-free fracturing fluid; providing a proppant composition, wherein the proppant composition comprises proppant particulates and degradable thermoplastic particulates; introducing the proppant-free fracturing fluid into a subterranean formation at an injection rate above a fracture gradient to create or enhance at least one fracture in the subterranean formation; introducing the proppant composition into the at least one fracture; and allowing the proppant composition to form a proppant pack in the fracture, wherein the degradable thermoplastic particulates are degradable to generate voids in the proppant pack.

Abstract: A method of treating a highly permeable subterranean formation that is penetrated by a wellbore to form a frac pack in the formation adjacent to a desired wellbore interval is provided. The method comprises (a) injecting a first high efficiency fracturing fluid into the formation to form a fracture in the formation that propagates from a near-wellbore region of the formation into a far-field region of the formation. Thereafter, high strength proppant is placed in a portion of the fracture in the near-wellbore region of the formation, and low strength proppant is placed in a portion of the fracture near the far-field region of the formation using low viscosity fluids. Subsequently, a high strength proppant is squeezed into a portion of the fracture in the near-wellbore region of the formation to assure that the fracture is completely packed.

Abstract: Methods of diverting fluid flow, controlling fluid loss, and/or providing zonal isolation in subterranean formations are provided. In some embodiments, the methods comprise: providing a particulate material that comprises an electrically controlled propellant; placing the particulate material in at least a first portion of the subterranean formation; introducing a treatment fluid into the subterranean formation; and allowing the particulate material to at least partially divert the flow of the treatment fluid away from the first portion of the formation.

Abstract: A variety of systems, methods and compositions are disclosed for delayed release of a resin curing agent. An example method may comprise introducing a treatment fluid comprising a resin and delayed release curing agent particulates into a subterranean formation, wherein the delayed release curing agent particulates comprises a carrier, a curing agent disposed on the carrier, and a coating; degrading the coating; and curing the resin in the subterranean formation.

Abstract: A variety of systems, methods and compositions are disclosed, including, a method comprising: providing a fracturing fluid comprising: a carrier fluid; a micro-proppant; and a degradable micro-fiber; pumping the fracturing fluid into a wellbore penetrating a subterranean formation; and creating or extending at least one fracture in the subterranean formation. A fracturing fluid comprising: a carrier fluid; a micro-proppant; and a degradable micro-fiber. A method comprising: isolating a perforated zone in a wellbore; pumping into the perforated zone a pad fluid above a fracture gradient of a formation penetrated by the wellbore to create a plurality of fractures within the formation; pumping into the perforated zone a fracturing fluid above the fracture gradient; pumping into the perforated zone a diverting fluid below the fracture gradient; and repeating the step of pumping into the perforated zone the fracturing fluid after the step of pumping into the perforated zone the diverting fluid.

Abstract: Creating a fracture network extending from a wellbore into a subterranean formation. The method includes introducing a series of fluids into the fracture network in a subterranean formation, thereby forming a proppant pack in the fracture network. The series of fluids comprise: a microproppant slurry comprising a microproppant having an average diameter less than about 25 microns; a proppant slurry comprising a proppant having an average diameter of about 75 microns to about 500 microns; and a sweep fluid having a microproppant weight percentage by weight of the sweep fluid that is from 0 to about the same of the microproppant weight percentage in the microproppant slurry by weight of the microproppant slurry. The introduction of the microproppant slurry is not immediately followed by introduction of the proppant slurry. The introduction of the proppant slurry is not immediately followed by introduction of the microproppant slurry.

Abstract: A variety of systems, methods and compositions are disclosed, including, a method that may comprise providing a fracturing fluid comprising: a carrier fluid; a micro-proppant; and a degradable micro-fiber. The method further may comprise pumping the fracturing fluid into a wellbore penetrating a subterranean formation. The method further may comprise creating or extending at least one fracture in the subterranean formation.