A composition of matter includes a liquid and nanoparticles suspended in the liquid. The nanoparticles each include silica, alumina, and an organosilicon functional group having a molecular weight of at least 200. A method includes functionalizing a surface of nanoparticles with an organosilicon functional group and dispersing the nanoparticles in a liquid to form a suspension. The functional group has a molecular weight of at least 200. The nanoparticles each include silica and alumina at a surface thereof.

Systems and methods for treating fracture faces and/or unconsolidated portions of a subterranean formation are provided. In some embodiments, the methods comprise: providing an aqueous alkali solution; introducing the aqueous alkali solution into at least a portion of a subterranean formation that comprises one or more fractures; contacting an aluminum component and a silicate component with the aqueous alkali solution to form a geopolymer on one or more fracture faces in the fractures; and placing a plurality of proppant particulates in the fractures.

A wellbore fluid comprising a first aqueous base fluid and a plurality of silica nanoparticles suspended in the first aqueous base fluid. The nanoparticles are present in the fluid in an amount to have an effect of decreasing a crystallization temperature by at least 4 to 55° F. as compared to a second aqueous base fluid without the silica nanoparticles.

The strength of a proppant or sand control particulate may be improved by coating the proppant to form a composite. The composite has enhanced compressive strength between about 34 to about 130 MPa and minimizes the spelling of fines at closure stresses in excess of 5,000 psi. Conductivity of fractures is further enhanced by forming a pack of the composites in the fracture.

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.

An oil recovery composition having a brine, a hydrolyzable polymer, and a monovalent cations to divalent cations ration in the range of about 2.5:1 to 3:1 is provided. An oil recovery composition may be formed from a brine recovered from production water and a polymer. A monovalent salt may be added to the brine recovered from production water to form a modified brine and achieve a modified monovalent cations to divalent cations ratio in the range of about 2.5:1 to 3:1. Processes for forming the oil recovery composition and enhanced oil recovery using the oil recovery composition are provided.

An oil recovery composition having a brine, a hydrolyzable polymer, and a monovalent cations to divalent cations ration in the range of about 2.5:1 to 3:1 is provided. An oil recovery composition may be formed from a brine recovered from production water and a polymer. A monovalent salt may be added to the brine recovered from production water to form a modified brine and achieve a modified monovalent cations to divalent cations ratio in the range of about 2.5:1 to 3:1. Processes for forming the oil recovery composition and enhanced oil recovery using the oil recovery composition are provided.

A method of treating a wellbore in a subterranean formation including introducing a first fluid into a formation, wherein the first fluid comprises: a first water soluble salt and a carrier; placing a second fluid into the formation, wherein the second fluid comprises: a second water soluble salt and a carrier, wherein the first fluid and second fluid produce a solid precipitate upon contact; and allowing the solid precipitate to form in-situ in the formation. An acid may be added to the wellbore after formation of the precipitate. The method may be also used for stabilizing a wellbore during drilling, and shutting off and reopening a region in a formation.

The present application provides a drill-in slurry containing an aqueous base fluid; a solid particulate material; a hygroscopic chelating agent; optionally an alkali formate; and optionally an additional ingredient such as a defoamer, a viscosity modifier, a stabilizer, soda ash or sodium bicarbonate. Methods for making the drill-in slurry and methods of using the drill-in slurry for drilling into a reservoir section or a producing section of a subterranean formation are also provided.

A method including providing a drilling fluid that comprises a base fluid, a weighting agent, and a sag stability enhancer, wherein the sag stability enhancer comprises polyethylene glycol (PEG) having a molecular weight of greater than or equal to about 200 g/mol; and placing the drilling fluid in a subterranean formation via a wellbore penetrating the subterranean formation. A method including forming a fluid comprising a base fluid, a weighting agent, and from about 0.5 ppb (1.4 kg/m.sup.3) to about 30 ppb (85.5 kg/m.sup.3) of a sag stability enhancer, wherein the sag stability enhancer comprises a glycol; and introducing the fluid into at least a portion of a well. A drilling fluid containing a base fluid, a weighting agent, and a sag stability enhancer comprising polyethylene glycol (PEG) having a molecular weight of greater than or equal to about 200 g/mol.