A crosslinked polymer comprising reactants of a first repeating unit, a second repeating unit, and a crosslinker that react to form the crosslinked polymer, wherein the first repeating unit is a sulfonic acid-containing monomer present from 50% to 99% by weight of the reactants, wherein the second repeating unit is selected from the group consisting of an N-vinyl amide-containing monomer, a terminal double bond-containing monomer, and any combination thereof, and is present from 1% to 50% by weight of the reactants, and wherein the crosslinker comprises at least two olefinic bonds, and is present in the range of about 9% to about 25% by weight of the reactants.

A crosslinked polymer comprising reactants of a first repeating unit, a second repeating unit, and a crosslinker that react to form the crosslinked polymer, wherein the first repeating unit is a sulfonic acid-containing monomer present from 50% to 99% by weight of the reactants, wherein the second repeating unit is selected from the group consisting of an N-vinyl amide-containing monomer, a terminal double bond-containing monomer, and any combination thereof, and is present from 1% to 50% by weight of the reactants, and wherein the crosslinker comprises at least two olefinic bonds, and is present in the range of about 9% to about 25% by weight of the reactants.

This disclosure relates to methods of treating a subterranean formation or cement construction in the presence of one or more contaminants using a hydrogel composition that contains a poly-alkene maleic anhydride copolymer, a polyethylene glycol, and an aqueous carrier.

This disclosure relates to methods of treating a subterranean formation or cement construction in the presence of one or more contaminants using a hydrogel composition that contains a poly-alkene maleic anhydride copolymer, a polyethylene glycol, and an aqueous carrier.

A method includes injecting an aqueous-based injection fluid into a wellbore at a first temperature, where the aqueous-based injection fluid includes phase-changing nanodroplets having a liquid core and a shell. The method also includes exposing the phase-changing nanodroplets to a second temperature in the wellbore that is greater than or equal to a boiling point of the liquid core to change a liquid in the liquid core to a vapor phase and expand the phase-changing nanodroplets, thus removing debris from the wellbore and surrounding area.

A method includes injecting an aqueous-based injection fluid into a wellbore at a first temperature, where the aqueous-based injection fluid includes phase-changing nanodroplets having a liquid core and a shell. The method also includes exposing the phase-changing nanodroplets to a second temperature in the wellbore that is greater than or equal to a boiling point of the liquid core to change a liquid in the liquid core to a vapor phase and expand the phase-changing nanodroplets, thus removing debris from the wellbore and surrounding area.

A method for enhanced oil recovery from a hydrocarbon bearing subterranean formation includes withdrawing hydrocarbons from a production well extending into the formation, identifying a high permeability streak in the formation, and injecting a dense CO.sub.2 composition from an injection well into the high permeability streak. The dense CO.sub.2 composition includes dense CO.sub.2 and a thickener soluble in the dense CO.sub.2. The thickener includes copolymer. The method includes, after injecting the dense carbon dioxide composition into the high permeability streak, injecting an aqueous treatment fluid into the formation. The dense CO.sub.2 composition blocks the high permeability streak to divert at least a portion of the aqueous treatment fluid into bypassed regions of the formation during the injecting of the aqueous treatment fluid, and the injecting of the aqueous treatment fluid into the hydrocarbon bearing subterranean formation drives hydrocarbons in the hydrocarbon bearing subterranean formation towards the production well.

A chelating agent can be used to enhance secondary hydrocarbon-fluid recovery during waterflooding operations. A composition can include a fluid and a chelating agent. The chelating agent can increase the viscosity of the fluid, which can enhance the efficacy of the waterflooding operations. The chelating agent can also form complexes with divalent cations in precipitates and solids formed by the divalent cations. The complexes can keep the cations in a soluble form until the composition exits the production well, which can prevent precipitates from forming in the production well and blocking pore throats in the production well.

A chelating agent can be used to enhance secondary hydrocarbon-fluid recovery during waterflooding operations. A composition can include a fluid and a chelating agent. The chelating agent can increase the viscosity of the fluid, which can enhance the efficacy of the waterflooding operations. The chelating agent can also form complexes with divalent cations in precipitates and solids formed by the divalent cations. The complexes can keep the cations in a soluble form until the composition exits the production well, which can prevent precipitates from forming in the production well and blocking pore throats in the production well.

Described herein are treated polymers comprising a polyacrylamide homopolymer or a copolymer thereof having at least 30 mol % acrylamide residue content and a weight average molecular weight in the range of 1×10.sup.5 g/mol to 1×10.sup.8 g/mol, and 0.1 wt % to 10 wt % of a C1-C6 alkyl ricinoleate based on the weight of the mixture of polymer and alkyl ricinoleate. The polymers are in powder form and include less than about 30 wt % water based on the powder weight. The treated polymer powders dissolve rapidly in water and develop very little or even no insoluble gel upon diluting with water, even when the water is produced water or connate. The treated polymer solutions are useful for in-the-field rapid dilution for applications such as papermaking, flocculation, beneficiation, wastewater treatment, and enhanced oil recovery.