A salt-tolerant polymer microsphere plugging agent and a preparation method thereof, the agent being made of white oil, fumed silica, acrylamide monomer, acrylic acid, sorbitan fatty acid ester, N,N′-methylene bisacrylamide, ammonium persulfate, sodium bisulfite, hydrophilic surfactant and water. The present general inventive concept synthesizes salt-tolerant polymer microspheres with ultra-low interfacial tension by adopting inverse phase emulsion polymerization. The prepared polymer microsphere plugging agent is a new type of polymer microspheres with ultra-low interfacial tension, such that the tension can reach 4.3×10.sup.−3 mN/m, and the salt tolerance can reach 50000 mg/L salinity, which improves the problem of low interfacial tension and poor salt tolerance in existing polymer microspheres.

Methods of acidizing a subterranean formation penetrated by a wellbore that include the steps of (a) injecting into the wellbore at a pressure below subterranean formation fracturing pressure a treatment fluid having a first viscosity and including an aqueous acid and a gelling agent selected from the group consisting of Formulas I-XI and combinations thereof; (b) forming at least one void in the subterranean formation with the treatment fluid; and (c) allowing the treatment fluid to attain a second viscosity that is greater than the first viscosity.

Methods of acidizing a subterranean formation penetrated by a wellbore that include the steps of (a) injecting into the wellbore at a pressure below subterranean formation fracturing pressure a treatment fluid having a first viscosity and including an aqueous acid and a gelling agent selected from the group consisting of Formulas I-XI and combinations thereof; (b) forming at least one void in the subterranean formation with the treatment fluid; and (c) allowing the treatment fluid to attain a second viscosity that is greater than the first viscosity.

Methods and system for modeling wellbore treatment operations in which the flow of treatment fluids may be diverted are provided. In one embodiment, the methods comprise: receiving, at a processing component, one or more treatment operation inputs characterizing a treatment operation for a wellbore system comprising a wellbore penetrating at least a portion of a subterranean formation and a treatment fluid comprising a diverter, wherein at least one of the one or more treatment operation inputs comprises the inlet concentration of the diverter in the treatment fluid; and using the processing component to determine a wellbore system pressure distribution and a wellbore system flow distribution based, at least in part, on the one or more treatment operation inputs and a diversion flow model, wherein the diversion flow model captures an effect of the diverter on fluid flow in the wellbore system.

The rapid reaction of hydrofluoric acid with siliceous materials can make it difficult to increase the permeability of subterranean formations containing siliceous minerals. Methods for stimulating a subterranean formation can comprise: providing a latent hydrofluoric acid composition comprising a degradable matrix, and a hydrofluoric acid precursor dispersed in the degradable matrix; introducing a first treatment fluid containing the latent hydrofluoric acid composition in a non-dissolved form into a wellbore penetrating a subterranean formation comprising a siliceous material; differentially depositing the latent hydrofluoric acid composition upon a portion of the siliceous material in one or more locations; degrading at least a portion of the degradable matrix, thereby exposing at least a portion of the hydrofluoric acid precursor; converting the exposed hydrofluoric acid precursor into hydrofluoric acid; and reacting the hydrofluoric acid with the siliceous material where the latent hydrofluoric acid composition was deposited.

The rapid reaction of hydrofluoric acid with siliceous materials can make it difficult to increase the permeability of subterranean formations containing siliceous minerals. Methods for stimulating a subterranean formation can comprise: providing a latent hydrofluoric acid composition comprising a degradable matrix, and a hydrofluoric acid precursor dispersed in the degradable matrix; introducing a first treatment fluid containing the latent hydrofluoric acid composition in a non-dissolved form into a wellbore penetrating a subterranean formation comprising a siliceous material; differentially depositing the latent hydrofluoric acid composition upon a portion of the siliceous material in one or more locations; degrading at least a portion of the degradable matrix, thereby exposing at least a portion of the hydrofluoric acid precursor; converting the exposed hydrofluoric acid precursor into hydrofluoric acid; and reacting the hydrofluoric acid with the siliceous material where the latent hydrofluoric acid composition was deposited.

Well treatment operation comprises introducing nanosized particulates into a formation. The nanosized particulates are synthesized by combining PMIDA, a calcium source, a pH adjusting agent, and an aqueous medium. This combination results in a degradable (i.e., dissolvable) solid that can be used in heterogeneous formations like shale type rock reservoirs, as well as sedimentary rock formations like clastic, siliclastic, sandstone, limestone, calcite, dolomite, and chalk formations, and formations where there is large fluid leak-off due to stimulation treatments. The disclosed particulates may also be used for acidizing treatments in mature fields and deep water formations commonly characterized by high permeability matrices. The solubility of the particulates advantageously allows the material to act as a temporary agent having a lifespan that is a function of temperature, water flux, and pH, making it adaptable to various reservoir conditions with minimal to no risk of adverse effects on the reservoir.

Well treatment operation comprises introducing nanosized particulates into a formation. The nanosized particulates are synthesized by combining PMIDA, a calcium source, a pH adjusting agent, and an aqueous medium. This combination results in a degradable (i.e., dissolvable) solid that can be used in heterogeneous formations like shale type rock reservoirs, as well as sedimentary rock formations like clastic, siliclastic, sandstone, limestone, calcite, dolomite, and chalk formations, and formations where there is large fluid leak-off due to stimulation treatments. The disclosed particulates may also be used for acidizing treatments in mature fields and deep water formations commonly characterized by high permeability matrices. The solubility of the particulates advantageously allows the material to act as a temporary agent having a lifespan that is a function of temperature, water flux, and pH, making it adaptable to various reservoir conditions with minimal to no risk of adverse effects on the reservoir.

The flow of well treatment fluids may be diverted from a high permeability zone to a low permeability zone within a fracture network within a subterranean formation by use of a mixture comprising a dissolvable diverter and a proppant. At least a portion of the high permeability zone is propped open with the proppant of the mixture and at least a portion of the high permeability zone is blocked with the diverter. A fluid is then pumped into the subterranean formation and into a lower permeability zone of the formation farther from the wellbore. The diverter in the high permeability zones may then be dissolved at in-situ reservoir conditions and hydrocarbons produced from the high permeability propped zones of the fracture network. The mixture has particular applicability in the enhancement of production or hydrocarbons from high permeability zones in a fracture network located near the wellbore.

The flow of well treatment fluids may be diverted from a high permeability zone to a low permeability zone within a fracture network within a subterranean formation by use of a mixture comprising a dissolvable diverter and a proppant. At least a portion of the high permeability zone is propped open with the proppant of the mixture and at least a portion of the high permeability zone is blocked with the diverter. A fluid is then pumped into the subterranean formation and into a lower permeability zone of the formation farther from the wellbore. The diverter in the high permeability zones may then be dissolved at in-situ reservoir conditions and hydrocarbons produced from the high permeability propped zones of the fracture network. The mixture has particular applicability in the enhancement of production or hydrocarbons from high permeability zones in a fracture network located near the wellbore.