A fluid design with enhanced proppant-carrying capacity utilizes a low-viscosity fluid with high proppant carrying capacity and low required power for injection into a hydrocarbon-bearing, subterranean formation. A preferred viscosifying agent that comprises a copolymer polymerized from an acrylic acid monomer and a monomer selected from: a) at least one carboxylic acid monomer; b) at least one C.sub.1 to C.sub.5 alkyl ester and/or at least one C.sub.1 to C.sub.5 hydroxyalkyl ester of acrylic acid or methacrylic acid; c) one crosslinking monomer; and optionally d) at least one α,β-ethylenically unsaturated monomer, may be used to produce a fracturing fluid that has the pumpability of a slick water fluid and the proppant-carrying ability of a cross-linked gel. An optimization process to optimize hydraulic fracture design evaluates and quantifies the proppant-carrying capacity of the invented fluid and its impact in the proppant transport during fracturing.

A spherical organic nano boron crosslinker with a PAMAM core and a preparation method thereof, and a gel fracturing fluid. A chemical structure of the spherical organic nano boron crosslinker is shown as follows: ##STR00001##
In the formula, n=0, 1, 2 or 3; and ##STR00002##

Compositions and methods for fracturing a subterranean formation are presented. Also provided are compositions and methods for reducing friction-related losses in a well treatment fluid. In general, the compositions include a copolymer that includes one or more vinylphosphonic acid (“VPA”) monomers.

Disclosed herein is a wellbore servicing fluid comprising a scale inhibitor, a surfactant, and an aqueous fluid comprising sulfate in an amount of from about 100 ppm to about 10,000 ppm based on the total weight of the aqueous fluid. The wellbore servicing fluid can be used as a fracturing fluid in a method of servicing a wellbore penetrating a subterranean formation. The wellbore servicing fluid can mitigate the formation of scales, prevent water blockage, and increase hydrocarbon production.

A method of stimulating petroleum production includes introducing a fracturing fluid into a petroleum formation, thereby creating at least one fracture to stimulate the petroleum production. The fracturing fluid is introduced into the petroleum formation at a pressure above the breakdown pressure of the formation. The fracturing fluid includes a plurality of proppants each including a proppant particle and a coating. The coating includes a hydrophobic coating, a cross-linked hydrogel, or both. From 1 to 50 wt. % of the plurality of proppants includes micro proppants having a particle size ranging from 0.5 to 150 μm, and from 50 to 99 wt. % of the plurality of proppants includes macro proppants having a particle size of 100 mesh or greater.

The invention is directed to delayed gelation agents comprising a degradable polymeric cage containing therein one or more gelation agents. The cage degrades in situ, e.g, in an oil reservoir, thus releasing the gelation agent(s), which can then crosslink second polymers in situ to form a gel.

A dry polymer powder for use in enhanced petroleum recovery without being prehydrated before being added to water or brine to be introduced into a wellhead. The dry polymer powder consisting of at least one of a polyacrylamide, a copolymer of acrylamide and acrylic acid, a functionalized derivatives thereof, a galactomannan, or cellulosic polymer or derivatives thereof, and the polymer can be crosslinked or not crosslinked, provided that if they are homo- or co-polymers of acrylic acid, they are not crosslinked. The dry polymer powder is sized between two size limits, namely at least about 85 wt % of particles of a size smaller than about 40-mesh, and at least 75 wt % of particles of a size greater than 200-mesh, which size range ensures that the dry polymer powder will efficiently hydrate in the water or brine within about one minute without forming fisheyes.

A fluid including: (i) a continuous aqueous phase, wherein the continuous aqueous phase has total dissolved solids in a concentration of at least 30,000 mg/l; (ii) an alkyl amido quaternary amine; (iii) a polymer, wherein the polymer is water-soluble or water-hydratable; and (iv) a crosslinker for the polymer. The continuous aqueous phase of the fluid can include a water source selected from the group consisting of flowback water, produced water, and any combination thereof. Methods include: (A) forming a fluid according to any of the various embodiments of the disclosure, and (B) introducing the fluid into a well. For example, the fluid can be used as a fracturing fluid for fracturing a treatment zone of a well.

The present invention relates to an ultra-high temperature organic cross-linked fracturing fluid system consisting of the following components at mass percentages: 0.6 wt % of a supramolecular star-shaped polymer, 0.5˜1.0 wt % of formaldehyde solution, 0.02˜0.04 wt % of resorcinol, 0.05˜0.2 wt % of an ammonium catalyst and the rest being water, wherein the supramolecular star-shaped polymer is a β-cyclodextrin-modified branched monomer F-β-CD that serves as a core and is grafted with acrylamide, acrylic acid, hydrophobic monomers and surface-active macromolecular monomers to form a supramolecular star-shaped polymer; the ammonium salt catalyst is one or more of ammonium chloride, ammonium bicarbonate, ammonium acetate, ammonium citrate, ammonium benzoate and ammonium oleate. The ultra-high temperature organic cross-linked fracturing fluid system of the present invention uses a supramolecular star-shaped polymer as a thickener, an organic crosslinker as a crosslinker and an ammonium salt as a catalyst to form a fracturing fluid having low costs, an appropriate cross-linking time and stable viscosity at an ultra-high temperature, which is suitable for large-scale promotion and use and have an prospect of wide applications.

A method of treating a subterranean formation including providing a treatment fluid comprising a hardenable acid curable resin and a hydrolysable strong acid ester. The treatment fluid is combined with a diluent fluid and is introduced into a subterranean formation. Upon the hydrolyzing of the ester in the formation and the contacting of unconsolidated proppants, the treatment method produces consolidated proppants.