Abstract: A method of stimulating the inflow of oil and/or gas from the wellbore, in particular, a hydraulic fracturing method, is disclosed. The method of hydraulic fracturing comprises the stages: injecting a slug of a proppant-free fluid through the well into a formation for hydraulic fracture creation and propagation; injecting a slug of proppant-laden slurry into the formation to create a proppant pack in the hydraulic fracture; injecting a slug of slurry that contains a fluid and the polyelectrolyte complex-based proppant aggregates to create permeable channels in the near-wellbore area of the hydraulic fracture; injecting a slug of a displacement fluid into the well. This sequence of operations allows avoiding the proppant slurry overdisplacement deep into the hydraulic fracture, maintaining high fracture conductivity, and increasing the well productivity.

Abstract: Described herein are methods for on the fly mixing of retarded acidizing fluids containing acid, a water-soluble acid retarding agent (RA), and optionally a viscoelastic surfactant (VES), and for on the fly mixing of diversion fluids containing VES and RA in the same equipment. Also described are methods of controlling the preparation of such fluids based on feedback composition analyses.

Abstract: Methods include pumping a fracturing pad fluid into a subterranean formation under conditions of sufficient rate and pressure to create at least one fracture in the subterranean formation, the fracturing pad fluid including a carrier fluid and a plurality of bridging particles, the bridging particles forming a bridge in a fracture tip of a far field region of the formation. Methods further include pumping a first plurality of fibers into the subterranean formation to form a low permeability plug with the bridging particles, and pumping a proppant fluid comprising a plurality of proppant particles.

Abstract: Methods for treating subterranean wells involve treating fluids that contain water and a plurality of water dispersible nanoparticles. The nanoparticles may be nanocellulose, rod-like nanoparticles, nanotubes or halloysite or combinations thereof. The water dispersible nanoparticles form one or more aggregates that plug formation pores and may control fluid flow into the formation as well as fluid flow from the formation into a wellbore.

Abstract: A fluid for treating a subterranean formation includes a solvent, a rheology modifier, and a composition that includes a mixture of cellulose fibers and cellulose nanoparticles. The cellulose nanoparticles have a positive zeta potential in a range of about +100 mV to about +10 mV, and a length in a range of from about 50 nm to about 500 nm, and the cellulose fibers have a length from about 50 microns to about 500 microns.

Abstract: Treatment fluids containing a mixture of cellulose fibers and cellulose nanoparticles and methods for treating a subterranean formation are disclosed. The methods include introducing a treatment fluid into a subterranean formation, the treatment fluid containing a mixture of cellulose fibers and cellulose nanoparticles.

Abstract: Well treatment compositions comprise water, a polysaccharide and cellulose fibers. The cellulose fibers may have lengths between 100 nm and 10 mm, and diameters between 4 nm and 40 ?m. The compositions may be used as spacer fluids during well cementing operations. The spacer fluids may prevent commingling of a cement slurry with a drilling fluid. The drilling fluid may be water-base, oil-base, synthetic-base or an emulsion.

Abstract: Methods of treating a subterranean formation include forming a treatment fluid including a hydrophilic fiber coated with a water soluble polymer and a crosslinking agent.

Abstract: This method is designed to facilitate the well treatment with the possibilities for non-uniform/heterogeneous proppant placement in the extended and branched fractures produced by hydraulic fracturing. The essence of the method is to inject a proppant-bearing gel into the wellbore drilled into a productive formation. The low-viscosity fracturing fluid is injected into the wellbore together with the gel fluid (simultaneously or in turns). The method also provides for the injection of gas into the proppant-bearing gel and/or the low-viscosity fluid. The gas can be injected upstream of the junction point, at the junction point, or downstream of the junction point of the flows of the proppant-bearing gel and the low-viscosity fluid. The method further provides for the division of the gel fluid into the separate agglomerates with their subsequent injection into the fractures in the subterranean formation to form the proppant structures in the fracture.

Abstract: Methods include combining an amount of water and an acid retarding agent (RA), where the amount of water is present in an amount up to about 5 times the mass of the RA, inclusive, and wherein the RA includes at least one salt compound. An amount of acid is dissolved in the combined amount of water and RA to form a composition, where the amount of acid is a molar ratio of acid:RA of between 4.0 and 0.2, inclusive, and wherein the amount of acid is up to about 36% by weight of total weight of the composition. The composition is injected into a wellbore penetrating a subterranean formation at a pressure, which may be less than the fracture initiation pressure of the subterranean formation in some cases, while in other cases equal to or greater than the fracture initiation pressure.

Abstract: A composition, treatment fluid and method using hydrolyzable fines. A treatment fluid, which may optionally include a high solids content fluid (HSCF) and/or an Apollonianistic solids mixture, includes a fluid loss control agent comprising a dispersion of hydrolyzable fines, optionally with one or more of a surfactant, plasticizer, dispersant, degradable particles, reactive particles and/or submicron particles selected from silicates, ?-alumina, MgO, ?-Fe2O3, TiO2, and combinations thereof.

Abstract: A wellbore is internally sealed using nanoparticles. Permeability properties are determined for a particular formation, along with its pore throat size distribution. A wellbore internal sealant (nanoparticle treatment fluid) is designed based on the determined permeability properties and pore throat size distribution. The nanoparticle treatment fluid is introduced into the formation. Pore throats within the formation are plugged by nanoparticles in the nanoparticle treatment fluid. Internal sealing reduces leak-off from filtercake damage, and also eliminates build-up of surface filtercake. Sealing the pore-structure of a particular wellbore zone alleviates the need for additional lost circulation material, resulting in a very thin filtercake and significantly reducing the chance of differential sticking. Oil-based muds can be replaced with water-based equivalents.

Abstract: Methods of treating a subterranean formation penetrated by a well bore, by diverting treatment fluid stages from zones of higher permeability to zones of lower permeability with an acid precursor material and fibers. The acid precursor material has an average particle size less than 1000 microns.

Abstract: The disclosure claimed herein relates to well systems for various fluids production, in particular, for production of fluids from hydrocarbon-containing formations using hydraulic fracturing process. According to the proposed method, injecting into well of fracturing fluid not containing proppant is performed to form a fracture in the formation, after which fracturing fluid is injected into the wellbore in pulse mode; the pulse mode provides at least one pulse of injecting fracturing fluid containing proppant, and at least one pulse of proppant-free fluid. Also, methods for fluid production and injection are proposed. Methods for fluids production, injection and recovery using hydraulic fracturing method are proposed. The proposed method increase the well lifetime due to reduced fluid flow impact on fracture walls and proppant clusters.

Abstract: A method is described for treating a subterranean formation penetrated by a wellbore including injecting into the formation a treatment fluid including a rheological modifier; at least one viscoelastic surfactant (VES) at a concentration of between about 0.1 and about 10 percent by weight; and a formation-dissolving agent selected from the group consisting of hydrochloric acid, formic acid, acetic acid, lactic acid, glycolic acid, sulfamic acid, malic acid, citric acid, tartaric acid, maleic acid, methylsulfamic acid, chloroacetic acid, aminopolycarboxylic acids, 3-hydroxypropionic acid, polyaminopolycarboxylic acids, salts thereof and mixtures of said acids and salts.

Abstract: This method is designed to facilitate the well treatment with the possibilities for non-uniform/heterogeneous proppant placement in the extended and branched fractures produced by hydraulic fracturing. The essence of the method is to inject a proppant-bearing gel into the wellbore drilled into a productive formation. The low-viscosity fracturing fluid is injected into the wellbore together with the gel fluid (simultaneously or in turns). The method also provides for the injection of gas into the proppant-bearing gel and/or the low-viscosity fluid. The gas can be injected upstream of the junction point, at the junction point, or downstream of the junction point of the flows of the proppant-bearing gel and the low-viscosity fluid. The method further provides for the division of the gel fluid into the separate agglomerates with their subsequent injection into the fractures in the subterranean formation to form the proppant structures in the fracture.

Abstract: Methods disclosed for reducing the loss of a circulating fluid in a wellbore to an adjacent subterranean formation during a wellbore operation include coiled tubing milling, cleanout and gravel-packing operations. The methods include placing, either before, during, or before and during the operation, a first acid precursor material, and optionally fibers, in contact with the subterranean formation adjacent to the wellbore to at least partially form a temporary reservoir barrier and reduce hydraulic conductivity between the wellbore and the subterranean formation. The first acid precursor material has a first average particle size of about 3000 microns or less.

Abstract: A cement composition including an aqueous fluid, inorganic cement, a foaming agent, a gas generating agent, and a stabilizer composition comprising graphene oxide. The cement composition is placed in a subterranean well and allowed to set and form a set cement. The presence of the graphene oxide results in the set cement having a greatest percent deviation from a measured slurry density of less than about 1.5%.

Abstract: Described herein are methods for treating a subterranean formation penetrated by a wellbore with a retarded acidizing fluid containing an acid and an acid retarding agent, the concentrations of which are adjusted based on measured parameter values of the formation. Also described is a method for treating a subterranean formation by introducing an acid to the formation following the introduction of an acid retarding agent to the formation. Also described is a method for acid fracturing a subterranean formation including reducing the concentration of an acid retarding agent contained in a retarded acidizing fluid over the course of the acid fracturing operation.

Abstract: Described herein are aqueous composition(s) containing water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent. Further described are methods of making and using such compositions.