Methods for equalizing flow into a wellbore using consolidated material are described. An unconsolidated material and a consolidation fluid are flowed into a wellbore formed in a hydrocarbon-bearing subterranean zone, and a permeability of the subterranean zone to flow fluid through the subterranean zone into the wellbore is non-uniform across an axial length of the wellbore. The unconsolidated material and the consolidation fluid are contacted across at least an axial segment of an inner surface of the wellbore, and the unconsolidated material is bound with the consolidated fluid to form a pack, in which the pack has a permeability that is more uniform than the permeability of the subterranean zone. A flow of fluids from the axial segment of the subterranean zone into the wellbore is controlled through the pack.

An actuation member for use in fracking operations, which immediately prior to fracking locates a sand screen at a desired location along a tubing liner and eliminates having to trip out the frac string prior to commencing production. The actuation member comprises a cylindrical hollow collet sleeve, with one or more radially-outwardly biased protuberances forming a unique profile which further matingly engages a corresponding mating profile on one of a plurality of sliding sleeve members in the tubular liner. A longitudinally-extending sand screen is provided, longitudinally slidable on the actuation member. A spring member, adapted to be forcibly compressed by the sand screen member when pressurized fluid is applied, and decompressed upon removal of pressurized fluid, is further provided on the actuation member.

Systems and methods for treating subterranean formations using deagglomerated inorganic clay particles are provided. In one embodiment, the methods comprise: providing a treatment fluid that comprises a base fluid, a consolidating agent, and a deagglomerated inorganic clay particle; introducing the treatment fluid into at least a portion of a subterranean formation so as to contact unconsolidated particles within the subterranean formation with the treatment fluid; and allowing the consolidating agent and the deagglomerated inorganic clay particle to consolidate at least a portion of the unconsolidated particulates in the portion of the subterranean formation.

Methods for treating a formation may include introducing components of a treatment solution into a wellbore such that the treatment solution contacts the formation to be treated, where the treatment solution may include urea, urease, a calcium ion source, one or more polysaccharides, a casein protein, a protease, an ionic compound, and a sugar, where the formation may have an amount of sand production before treatment and may be in fluid contact with the wellbore, and where an amount of sand production after treatment may be less than the amount of sand production before treatment. Consolidated sand structure compositions may include previously unconsolidated sand interlinked by inter-particle cementitious bonds comprising deposited calcium carbonate crystals, where the consolidated sand has a structural strength and the consolidated sand structure is porous to permit fluid flow through the composition.

A sand consolidation composition includes a hydrocarbon mixture comprising asphaltene, bitumen, or tar, and a binding agent, where the binding agent is an amino silane, and where the composition has a viscosity ranging from 5 to 20 cP at 20 to 25? C. A method of sand consolidation includes introducing the sand consolidation composition in a wellbore, contacting sand downhole with the sand consolidation composition, maintaining the wellbore such that a viscosity of the sand consolidation composition and the sand increases from an initial viscosity of the sand consolidation composition, introducing a thermochemical reagent comprising sodium nitrite and ammonium chloride such that it intimately intermingles downhole with the sand consolidation composition and releases a gas, and after a period, forming a productive consolidated sand.

Methods may include calculating a formation permeability for a subterranean formation from a combination of dielectric measurements and acoustic measurements, wherein the formation permeability is calculated according to the formula: k.sub.g=a(V.sub.x .sub.w/.sub.r).sup.b, where V.sub.x is either V.sub.p, V.sub.s, or V.sub.p/V.sub.s, is formation conductivity, .sub.w is water-filled porosity, and a and b are constants that are empirically determined for the frequency selected with respect to V.sub.x; and creating a design for a wellbore operation from the calculated formation permeability. Methods may also include obtaining a dielectric measurement from a downhole formation; obtaining an acoustic measurement from a downhole formation; and calculating a formation permeability from a combination of the dielectric measurement and the acoustic measurement.

Resin coatings are frequently formed in conjunction with performing a subterranean treatment operation. However, poor thermal conductivity and mechanical strength of resin coatings can be problematic in a downhole environment and eventually lead to their breakdown. Methods for enhancing a resin coating in a downhole environment can comprise: introducing a treatment fluid comprising a curable resin and a carbon nanomaterial into a wellbore penetrating a subterranean formation; forming a coating of the curable resin on a surface in the wellbore, the carbon nanomaterial being dispersed throughout the coating; and curing the curable resin to form a cured resin coating.

A method of injecting fluid into a formation, comprises exerting a mechanical force on a wall of a bore extending through a formation to modify the permeability of the formation; and injecting fluid into the modified formation. The mechanical force is exerted through inflation of at least one pressure deformable member mounted on a base member with a retaining ring.

Methods for treating a zone of a subterranean formation penetrated by a wellbore comprising: (A) introducing an acidizing fluid into the zone of the subterranean formation; (B) forming a treatment fluid comprising: (i) a first chemical having: (a) a single epoxy group; and (b) at least one alkoxy group on a silicon atom, wherein the first chemical is water soluble or dissolves with hydrolysis in an aqueous phase; and (ii) a second chemical having an amine group, wherein the second chemical is water soluble or dissolves with hydrolysis in an aqueous phase; and (C) introducing the treatment fluid through the wellbore into the zone of the subterranean formation. In various embodiments, the treatment fluid has a viscosity of less than 5 cP measured at a shear rate of 511 sec.sup.1.

Systems and methods for treating formation intervals including forming a low permeability layer on a surface of the interval and pumping a sand control treating solution through the layer, which diverts the flow into the formation permitting improved treatment uniformity and improved overall internal treatment.