The present disclosure generally relates to a system and methods for stimulation with particle-stabilized emulsion treatment fluids during hydraulic fracturing operations. A treatment fluid is disclosed, the treatment fluid including a continuous fluid phase, a dispersed fluid phase dispersed throughout the continuous fluid phase, a surfactant, and a plurality of solid particles adsorbed to an interface between the continuous and dispersed fluid phases thereby stabilizing the dispersed fluid phase in the continuous fluid phase. A method for treating a subterranean formation is disclosed, the method including providing a treating fluid comprising a plurality of solid particles adsorbed to an interface between a continuous fluid phase and a dispersed fluid phase, thereby stabilizing the continuous and dispersed fluid phases, and pumping the treating fluid under pressure via a pump to invert the emulsion so that at least a portion of the solid particles are deposited in the subterranean formation.

The present disclosure generally relates to a system and methods for stimulation with particle-stabilized emulsion treatment fluids during hydraulic fracturing operations. A treatment fluid is disclosed, the treatment fluid including a continuous fluid phase, a dispersed fluid phase dispersed throughout the continuous fluid phase, a surfactant, and a plurality of solid particles adsorbed to an interface between the continuous and dispersed fluid phases thereby stabilizing the dispersed fluid phase in the continuous fluid phase. A method for treating a subterranean formation is disclosed, the method including providing a treating fluid comprising a plurality of solid particles adsorbed to an interface between a continuous fluid phase and a dispersed fluid phase, thereby stabilizing the continuous and dispersed fluid phases, and pumping the treating fluid under pressure via a pump to invert the emulsion so that at least a portion of the solid particles are deposited in the subterranean formation.

Provided are compositions and methods of using a liquid suspension of hollow particles comprising a plurality of hollow particles, water, a suspending aid, and a stabilizer selected from the group consisting of a non-ionic surfactant, a latex, an oleaginous fluid, porous silica, and combinations thereof. The liquid suspension is homogenous. An example method includes statically storing the liquid suspension in a container for at least one week; wherein the liquid suspension maintains a difference in density from the top of the container to the bottom of the container of less than one pound per gallon while stored. The method further includes adding the liquid suspension to a treatment fluid; wherein the liquid suspension reduces the density of the treatment fluid; and introducing the treatment fluid into a wellbore penetrating a subterranean formation.

A method of treating in a subterranean formation including combining a demulsifier; proppant; an emulsifier; an oil base fluid; and aqueous base fluid to form an oil-external emulsified fluid; and introducing the oil-external emulsified fluid into the subterranean formation. A method of forming a wellbore fluid including combining proppant; a demulsifier; an aqueous base fluid, an oil base fluid, and an emulsifier to form a pre-emulsified fluid; and mixing the pre-emulsified fluid to form an oil-external emulsified fluid.

A method comprises: deriving fluid properties that provide for suspension of particulate diverting agents using a 3-dimensional flow model and based on a downhole temperature and at least one size characteristic of the particulate diverting agents; identifying a treatment fluid composition that comprises a nanoparticulate suspending agent and achieves the fluid properties using a relationship between the treatment fluid composition and the fluid properties; and preparing a treatment fluid or a treatment fluid additive based on the treatment fluid composition.

A method comprises: deriving fluid properties that provide for suspension of particulate diverting agents using a 3-dimensional flow model and based on a downhole temperature and at least one size characteristic of the particulate diverting agents; identifying a treatment fluid composition that comprises a nanoparticulate suspending agent and achieves the fluid properties using a relationship between the treatment fluid composition and the fluid properties; and preparing a treatment fluid or a treatment fluid additive based on the treatment fluid composition.

The disclosure generally refers to compositions and methods for treating subterranean formations that improve the recovery of hydrocarbons from the subterranean formations. The compositions include positively and negatively charged nanoparticles suspended in a carrier fluid that is not a drilling fluid and is free of cement and foaming agents. The populations of nanoparticles may be of different sizes, different materials, and comprise different ratios. The composition may also include: surface-active agents, such as surfactants, polymers; detergents; crystal modifiers; stabilizers, or hydronium. In some embodiments, the surface-active agents may bind to the surface of the positively or negatively charged nanoparticles. A subterranean formation may then be injected with the composition.

A brine resistant silica sol is described and claimed. This brine resistant silica sol comprises an aqueous colloidal silica mixture that has been surface functionalized with at least one moiety selected from the group consisting of a monomeric hydrophilic organosilane, a mixture of monomeric hydrophilic organosilane(s) and monomeric hydrophobic organosilane(s), or a polysiloxane oligomer, wherein the surface functionalized brine resistant aqueous colloidal silica sol passes at least two of three of these brine resistant tests: API Brine Visual, 24 Hour Seawater Visual and API Turbidity Meter.

A treatment fluid may comprise: a water having hardness at about 300 ppm or greater, a plurality of particulates, a swellable clay, a chelating agent at about 0.01% to about 5% by weight of the water (BWOW); and an alkali metal base at about 0.01% to about 5% BWOW, wherein the chelating agent and alkali metal base reduce the negative effect of the water on hydrating swellable clays.

A polymer breaking solution usable in fracking and other downhole applications comprises a solution of aqueous hydrogen peroxide, an anionic surfactant, a metal chelating agent, an acidic pH buffer, a soluble zinc compound, and in some embodiments, a viscosifying agent. In other embodiments, the solution may additionally comprise a linear hydrophobic surfactant. At treatment concentrations of between 500 ppm to 1,500 ppm, the solution is non-toxic and usable at a wide range of downhole temperatures (32° C. to 82° C.).