The present invention relates to artificially reducing the porosity of any potential flow paths in the near-wellbore region of a well or in permeable zones within or surrounding a well. In doing so, the permeability in this the targeted region will be significantly reduced, thus, preventing unwanted flow of subsurface fluids. The present invention concerns a method comprising applying a first and second solution comprising scale precursors to the porous media, wherein following this application, at least a portion of the scale precursors form at least two insoluble salts. Additionally, the present invention concerns a kit of parts comprising the first and second solutions.

The present invention relates to a method for sealing and/or consolidating a subterranean formation, wherein a gelling aqueous solution comprising an alkaline solution of potassium silicate, acetic acid and an aluminate is prepared and injected into the subterranean formation.

Drill-in fluids disclosed herein comprise an aqueous base fluid, a viscosifier, a fluid loss control additive, and a degradable bridging agent comprising a degradable high strength polymetaphosphate material capable of undergoing an irreversible degradation downhole. The present disclosure further relates to a method for controlling fluid loss through a subterranean surface by using the drill-in fluid for form a filter cake on the subterranean surface. Also provided is a method of degrading a filter cake with an aqueous fluid or aqueous acidic fluid, wherein the filter cake is produced from the drill-in fluid. Further provided is a specific order of addition of constituents of the drill-in fluid, which results in improved filter cake performance and/or filter cake removal.

Polyacrylamide (PAM)-coated nanosand that may be a relative permeability modifier (RPM) and that is applied to treat a wellbore in a subterranean formation. The treatment may be for excess water production. The PAM-coated nanosand is PAM-hydrogel-coated nanosand. The PAM-coated nanosand os nanosand coated with PAM hydrogel. The PAM hydrogel includes crosslinked PAM in water. Application of the PAM-coated nanosand may reduce water production from the subterranean formation into the wellbore. The PAM hydrogel of the PAM-coated nanosand may expand in a water zone of the subterranean formation to restrict water flow into the wellbore. The PAM hydrogel of the PAM-coated nanosand may contract in an oil zone of the subterranean formation so not to significantly restrict crude oil flow into the wellbore.

A spacer fluid includes an aphron generating component, a polymer, a lost circulation material, and a weighting agent component.

Methods for separating fluids with a barrier pill within a downhole environment are provided. The method includes introducing a barrier pill fluid into the wellbore containing a first fluid to form the barrier pill on top of the first fluid in the wellbore and introducing a second fluid into the wellbore. The barrier pill separates the first fluid and the second fluid. The barrier pill includes a viscoelastic surfactant and an aqueous fluid, such as a brine containing water and about 5 wt % to about 50 wt % of a salt.

A method of preparing a polymer-sand nanocomposite for water shutoff. The method includes applying a surface polymerization to sand particles. The surfaced polymerization formed by combining a polymerization initiator dissolved in a solvent with the sand particles to form a precursor sand mixture, combining a co-monomer and additional polymerization initiator in the presence of graphene, where the graphene is not functionalized, to form a precursor polymer mixture, and combining the precursor sand mixture and the precursor polymer mixture to form a sand-copolymer-graphene nanocomposite. The method further includes drying the sand-copolymer-graphene nanocomposite, preparing a polymer hydrogel, and combining the polymer hydrogel and the sand-copolymer-graphene nanocomposite to crosslink the components and form the polymer-sand nanocomposite. The associated method of forming a barrier to shut off or reduce unwanted production of water in a subterranean formation utilizing the polymer-sand nanocomposite is also provided.

A silicon oxide Janus nanosheets relatively permeability modifier (RPM) for carbonate and sandstone formations. The silicon oxide Janus nanosheets RPM may be used to treat a water and hydrocarbon producing carbonate or sandstone formation to reduce water permeability in the formation and increase the production of hydrocarbons. The silicon oxide Janus nanosheets RPM for carbonate formations includes a first side having negatively charged functional groups and a second side having alkyl groups. The silicon oxide Janus nanosheets RPM for sandstone formations includes a first side having positively charged functional groups and a second side having alkyl groups. The negatively charged functional groups may include a negatively charged oxygen group groups and hydroxyl groups. The positively charged functional groups may include amino groups and an amine. Methods of reducing water permeability using the silicon oxide Janus nanosheets RPM and methods of manufacturing the silicon oxide Janus nanosheets RPM are also provided.

An oil-based drilling fluid composition, includes a base fluid and a treating agent. The base fluid comprises a base oil and an inhibitor; the treating agent comprises an organic soil, a main emulsifier, an auxiliary emulsifier, a plugging agent, a weighting agent, a humectant, an alkaline regulator and a filtrate reducer. 5-25 parts by weight of the inhibitor, 5-12 parts by weight of the organic soil, 1-6 parts by weight of the main emulsifier, 2-8 parts by weight of the auxiliary emulsifier, 3-18 parts by weight of the plugging agent, 5-30 parts by weight of the weighting agent, 2-6 parts by weight of the humectant, 2-7 parts by weight of the alkaline regulator and 2-10 parts by weight of the filtrate reducer are used, based on 100 parts by weight of base oil.

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.