WO2018031655A1

WO2018031655A1 - Stimuli-responsive polymer particles and methods of using thereof

Info

Publication number: WO2018031655A1
Application number: PCT/US2017/046095
Authority: WO
Inventors: Kishore K. Mohanty; Krishna PANTHI
Original assignee: Board Of Regents, The University Of Texas System
Priority date: 2016-08-09
Filing date: 2017-08-09
Publication date: 2018-02-15

Abstract

Disclosed herein are compositions comprising stimuli-responsive (e.g., salinity-responsive) polymer articles, as well as methods of using the compositions in oil recovery applications.

Description

STIMULI-RESPONSIVE POLYMER PARTICLES AND

METHODS OF USING THEREOF

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Serial No. 62/372,496, filed August 9, 2016, which is expressly incorporated herein by reference in its entirety.

BACKGROUND

Water injection used in oil production is where water is injected into the reservoir to stimulate production. Generally, water is injected for two reasons: (1) for pressure support of the reservoir (also known as voidage replacement), and (2) to sweep or displace the oil from the reservoir, and push it towards an oil production well. Normally only 20% of the oil in a reservoir can be extracted, but water injection increases that percentage (known as

the recovery factor) and maintains the production rate of a reservoir over a longer period of time.

At present, sweep recovery is limited by so-called "thief zones," whereby water preferentially travels through the more porous regions of the reservoirs, bypassing less permeable zones. Improved compositions and methods that facilitate the recovery of oil from within these "thief zones" will offer the opportunity to improve overall methods of oil recovery.

SUMMARY

Oil recovery can be improved by blocking thief zones, thereby forcing fluids (e.g., water and/or carbon dioxide) through less permeable regions of the formation. By forcing these fluids through less permeable regions of the formation, the fluids will drive oil trapped within these less permeable regions towards an oil production well.

Provided herein are compositions that include stimuli-responsive polymer particles that swell in response to a stimulus, such as a change in salinity, as well as oil recovery methods employing these compositions. The stimuli-responsive polymer particles can be dispersed in an aqueous carrier having a first salinity at which the stimuli-responsive polymer particles swell slightly (or not at all), such that the stimuli-responsive polymer particles have an average particle size suitable for injection into high permeability regions of a subsurface reservoir. When this composition is injected into a subsurface reservoir, the salinity-responsive polymer particles are deposited within high permeability regions of the subsurface reservoir. An aqueous composition having a second salinity (e.g., a salinity that is greater or less than the first salinity) can then be injected into the subsurface reservoir, causing the stimuli-responsive polymer particles to swell. As the stimuli-responsive polymer particles swell, they obstruct the high permeability regions of the subsurface reservoir (often referred to as "thief zones" or "streaks"). By blocking the high permeability regions of the subsurface reservoir, subsequent injections of fluid are forced to enter the remainder of the reservoir, more effectively sweeping the reservoir.

For example, provided herein are compositions that comprise a population of salinity- responsive polymer particles dispersed in an aqueous carrier. The salinity-responsive polymer particles can have an average particle size of from 1 micron to 1000 microns (e.g., from 5 microns to 500 microns, from 1 micron to 250 microns, from 5 microns to 250 microns, from 1 micron to 100 microns, from 5 microns to 100 microns, from 50 microns to 1000 microns, or from 50 microns to 500 microns). The salinity-responsive polymer particles can occupy a first volume when dispersed in an aqueous carrier having a first salinity, and a second volume when dispersed in an aqueous carrier having a second salinity. The second volume can be at least ten times greater (e.g., at least twenty times greater, or at least thirty times greater) than the first volume.

In some embodiments, the salinity-responsive polymer particles can be stable to changes in pH. For example, in some embodiments, the salinity-responsive polymer particles can exhibit relatively minimal changes in swelling across a wide range of pH values (e.g., across a range of pH values from 2 to 12.6, across a range of pH values from 4 to 10, across a range of pH values from 7 to 12.6, across a range of pH values from 9 to 12.6, or across a range of pH values from 2 to 7). Advantageously, the pH stability of the salinity-responsive polymer particles can render these particles compatible with a wide variety of enhanced oil recovery methods, including methods that employ alkaline floods and methods that include carbon dioxide flooding. In some embodiments, the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 4; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume,

In some embodiments, the salinity-responsive polymer particles can comprise a copolymer derived from one or more ethylenically unsaturated monomers. In certain cases, the one or more ethylenically unsaturated monomers can comprise acrylamide. In certain embodiments, the salinity-responsive polymer particles can comprise a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).

For example, the copolymer can be derived from 10% to 80% by weight (e.g., from 20% to 60% by weight, or from 25% to 45% by weight) acrylamide monomers, based on the total weight of the monomers that form the copolymer. In one embodiment, the copolymer can be derived from 30% to 40% by weight (e.g., about 35% by weight) acrylamide monomers, based on the total weight of the monomers that form the copolymer. The copolymer can be derived from 20% to 90% by weight (e.g., from 35% to 80% by weight, from 45% to 70% by weight) acid-containing monomers, based on the total weight of the monomers that form the copolymer. In one embodiment, the copolymer can be derived from 50% to 65% by weight (e.g., about 58% by weight) acid-containing monomers, based on the total weight of the monomers that form the copolymer.

In one embodiment, the salinity-responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0-15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).

In some cases, the one or more acid-containing monomers comprise sulfonic acid groups. For example, in some embodiments, the one or more acid-containing monomers are chosen from vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2- methacrylamido-2-methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3-acrylamido- 3-methylbutanesulfonic acid, and 2-acrylamido-2,4,4-trimethylpentanesulfonic acid. In certain embodiments, the one or more acid-containing monomers comprise 2-acrylamido-2- methylpropanesulfonic acid.

The one or more additional ethylenically-unsaturated monomers can comprise any suitable monomers. In certain embodiments, the one or more ethylenically-unsaturated monomers can comprise one or more poly ethylenically-unsaturated monomers (e.g., one or more diethylenically-unsaturated monomers, one or more triethylenically-unsaturated monomers, one or more tetraethylenically-unsaturated monomers, one or more pentaethylenically-unsaturated monomers).

In some embodiments, the salinity-responsive polymer particles can comprise a polysaccharide (co)polymer (e.g., a polysaccharide polymer or copolymer). For example, in some embodiments, the salinity-responsive polymer particles can comprise an alginate

(co)polymer (e.g., an alginate polymer or copolymer). In certain cases, the polysaccharide (co)polymer can comprise a blend of an alginate (co)polymer and a second (co)polymer. In these embodiments, the alginate (co)polymer and the second (co)polymer can be blended at varying weight ratios. For example, the alginate (co)polymer and the second (co)polymer can be present in the particles in a weight ratio of from 2:1 to 10:1 (e.g., from 4:1 to 8:1). The second (co)polymer can comprise, for example, chitosan.

As discussed above, compositions comprising the salinity-responsive polymer particles described herein can be used in oil and gas operations, including oil recovery operations.

Accordingly, also provided are methods of hydrocarbon recovery that employ the compositions described herein. Methods for hydrocarbon recovery can comprise (a) providing a subsurface reservoir containing hydrocarbons there within; (b) providing a wellbore in fluid communication with the subsurface reservoir; (c) preparing an aqueous particle composition comprising a population of salinity-responsive polymer particles having a first volume dispersed in an aqueous carrier having a first salinity; (d) injecting the aqueous particle composition through the wellbore into the subsurface reservoir, thereby depositing the salinity-responsive polymer particles within high permeability regions of the subsurface reservoir; and (e) injecting an aqueous composition having a second salinity into the subsurface reservoir, thereby causing the population of salinity-responsive polymer particles within the high permeability regions of the subsurface reservoir to swell to a second volume. The second volume can be at least ten times (e.g., at least twenty times, or at least thirty times) greater than the first volume.

The aqueous particle composition can be any of the compositions described above. By way of example, in some embodiments, the aqueous particle composition can comprise a population of salinity-responsive polymer particles formed from a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii). In one embodiment, the salinity-responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0- 15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii). In these examples, the first salinity can be higher than the second salinity. In other examples, the aqueous particle composition can comprise a population of salinity- responsive polymer particles formed from an alginate (co)polymer (e.g., an alginate polymer or copolymer) or a blend of an alginate (co)polymer and a second (co)polymer (e.g., chitosan). In these examples, the second salinity can be higher than the first salinity. In some embodiments, the wellbore in step (b) can be an injection wellbore associated with an injection well. The methods of hydrocarbon recovery can further comprise providing a production well spaced apart from the injection well a predetermined distance and having a production wellbore in fluid communication with the subsurface reservoir. Injection of the aqueous composition having a second salinity in step (e) can increase the flow of hydrocarbons to the production wellbore. Methods can further comprise producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.

The aqueous composition having a second salinity can comprise a polymer (P) flooding solution, an alkaline-polymer (AP) flooding solution, a surfactant-polymer (SP) flooding solution, an alkaline- surfactant-polymer (ASP) flooding solution, or any combination thereof. In some cases, methods can further include injecting a polymer flooding solution, an AP flooding solution, a SP flooding solution, an ASP flooding solution, carbon dioxide, or any combination thereof into the subsurface reservoir following step (e), and producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.

DESCRIPTION OF DRAWINGS

Figure 1A includes photographs illustrating dry SSPP particles (left) and SSPP particles in DI water (right) at the same magnification.

Figure IB includes photographs illustrating similar sized dry particles after immersing in two different brines.

Figure 1C illustrates the swelling of 0.1 cc of SSPP particles in DI water (sample b) and NaCl solution (sample a).

Figures 2A-Figures 2C illustrate the swelling of SSPP particles as a function of NaCl concentration at 25°C. Figure 2A shows 0.1 cc of dry SSPP particles in different vials before the addition of brines, and Figure 2B shows the swollen SSPP particles after an hour in NaCl solutions of varying concentration. Figure 2C is a plot showing the swelling factor of SSPP particles as a function of salinity.

Figure 3A is a plot showing the swelling factor of SSPP particles as a function of time (in days) upon incubation in deionized water (diamond trace), 0.1% NaCl (square trace), and 20% NaCl (triangle trace) at room temperature.

Figure 3B is a plot showing the swelling factor of SSPP particles as a function of time (in days) upon incubation in deionized water (diamond trace), 0.1% NaCl (square trace), and 20% NaCl (triangle trace) at 60°C.

Figure 3C is a plot showing the swelling factor of SSPP particles as a function of time (in days) upon incubation in deionized water (diamond trace), 0.1% NaCl (square trace), and 20% NaCl (triangle trace) at 80°C.

Figure 4 is a plot detailing the oil recovery and pressure drop of core flood #1.

Figure 5 is a plot detailing the oil recovery and pressure drop of core flood #2.

Figure 6 is a plot detailing the oil recovery and pressure drop of core flood #3.

Figure 7 includes photographs illustrating the core and SSPP particles before and after flooding during core flood #3.

Figure 8 is a plot detailing the oil recovery and pressure drop of core flood #4.

DETAILED DESCRIPTION

In some embodiments, the salinity-responsive polymer particles can be stable to changes in pH. For example, in some embodiments, the salinity-responsive polymer particles can exhibit relatively minimal changes in swelling across a wide range of pH values (e.g., across a range of pH values from 2 to 12.6, across a range of pH values from 4 to 10, across a range of pH values from 7 to 12.6, across a range of pH values from 9 to 12.6, or across a range of pH values from 2 to 7). Advantageously, the pH stability of the salinity-responsive polymer particles can render these particles compatible with a wide variety of enhanced oil recovery methods, including methods that employ alkaline floods and methods that include carbon dioxide flooding.

In some embodiments, the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 2; the salinity -responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 12.6; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume. In some embodiments, the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 4; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume. In some

embodiments, the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 7; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 12.6; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume. In some

embodiments, the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 12.6; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume. In some

embodiments, the salinity-responsive polymer particles can occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 2; the salinity- responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 7; and the third volume is less than five times greater (e.g., less than three times greater) than the fourth volume. Salinity-responsive polymer particles can be formed from one or more (co)polymers, such as one or more acrylamide-containing (co)polymers or one or more alginate (co)polymers. As used herein, the terms "polymer," "polymers," "polymeric," and similar terms are used in their ordinary sense as understood by one skilled in the art, and thus may be used herein to refer to or describe a large molecule (or group of such molecules) that contains recurring units.

Polymers may be formed in various ways, including by polymerizing monomers and/or by chemically modifying one or more recurring units of a precursor polymer. A polymer may be a "homopolymer" comprising substantially identical recurring units formed by, e.g.,

polymerizing a particular monomer. A polymer may also be a "copolymer" comprising two or more different recurring units formed by, e.g., copolymerizing two or more different monomers, and/or by chemically modifying one or more recurring units of a precursor polymer. The term "terpolymer" may be used herein to refer to polymers containing three or more different recurring units. The term "polymer" as used herein is intended to include both the acid form of the polymer as well as its various salts. In some embodiments, the one or more (co)polymers forming the salinity -responsive polymer particles can be a (co)polymer useful for enhanced oil recovery applications.

In some embodiments, the salinity-responsive polymer particles can comprise a

(co)polymer derived from one or more ethylenically unsaturated monomers. In certain cases, the one or more ethylenically unsaturated monomers can comprise acrylamide. In certain embodiments, the salinity-responsive polymer particles can comprise a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).

Examples of acid-containing monomers include, for example, monomers comprising - COOH groups, such as acrylic acid or methacrylic acid, crotonic acid, itaconic acid, maleic acid or fumaric acid, monomers comprising sulfonic acid groups, such as vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2-methacrylamido-2- methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3-acrylamido-3- methylbutanesulfonic acid or 2-acrylamido-2,4,4-trimethylpentanesulfonic acid, or monomers comprising phosphonic acid groups, such as vinylphosphonic acid, allylphosphonic acid, N- (meth)acrylamidoalkylphosphonic acids or (meth)acryloyloxyalkyl-phosphonic acids.

In some cases, the one or more acid-containing monomers comprise sulfonic acid groups. For example, in some embodiments, the one or more acid-containing monomers are chosen from vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, 2-methacrylamido-2-methylpropanesulfonic acid, 2-acrylamidobutanesulfonic acid, 3- acrylamido-3-methylbutanesulfonic acid, and 2-acrylamido-2,4,4-trimethylpentanesulfonic acid. In certain embodiments, the one or more acid-containing monomers comprise 2- acrylamido-2-methylpropanesulfonic acid.

The one or more additional ethylenically-unsaturated monomers can comprise any suitable monomers. Examples of suitable additional monomers include, for example, acrylamide derivatives such as, for example, N-methyl(meth)acrylamide, Ν,Ν'- dimethyl(meth)acrylamide, and N-methylolacrylamide, N-vinyl derivatives such as N- vinylformamide, N-vinylacetamide, N-vinylpyrrolidone or N-vinylcaprolactam, and vinyl esters, such as vinyl formate or vinyl acetate, vinyl aromatic monomers (e.g., styrene), and (meth)acrylate monomers. (Meth)acrylate monomers can include esters of α,β- monoethylenically unsaturated monocarboxylic and dicarboxylic acids having 3 to 6 carbon atoms with alkanols having 1 to 12 carbon atoms (e.g., esters of acrylic acid, methacrylic acid, maleic acid, fumaric acid, or itaconic acid, with C1-C20, C1-C12, C1-C8, or C1-C4 alkanols). Exemplary acrylate and methacrylate monomers include, but are not limited to, methyl acrylate, methyl methacrylate, ethyl acrylate, ethyl methacrylate, butyl acrylate, butyl methacrylate, isobutyl (meth)acrylate, n-hexyl (meth)acrylate, ethylhexyl (meth)acrylate, n- heptyl (meth)acrylate, ethyl (meth)acrylate, 2-methylheptyl (meth)acrylate, octyl

(meth)acrylate, isooctyl (meth)acrylate, n-nonyl (meth)acrylate, isononyl (meth)acrylate, n- decyl (meth)acrylate, isodecyl (meth)acrylate, dodecyl (meth)acrylate, lauryl (meth)acrylate, tridecyl (meth)acrylate, stearyl (meth)acrylate, glycidyl (meth)acrylate, alkyl crotonates, vinyl acetate, di-n-butyl maleate, di-octylmaleate, acetoacetoxy ethyl (meth)acrylate,

acetoacetoxypropyl (meth)acrylate, hydroxyethyl (meth)acrylate, allyl (meth)acrylate, tetrahydrofurfuryl (meth)acrylate, cyclohexyl (meth)acrylate, 2-ethoxyethyl (meth)acrylate, 2- methoxy (meth)acrylate, 2-(2-ethoxyethoxy)ethyl (meth)acrylate, 2-ethylhexyl (meth)acrylate, 2-propylheptyl (meth)acrylate, 2-phenoxyethyl (meth)acrylate, isobornyl (meth)acrylate, caprolactone (meth)acrylate, polypropyleneglycol mono(meth)acrylate, polyethyleneglycol (meth)acrylate, benzyl (meth)acrylate, 2,3-di(acetoacetoxy)propyl (meth)acrylate,

hydroxypropyl (meth)acrylate, methylpoly glycol (meth)acrylate, 3,4-epoxycyclohexylmethyl (meth)acrylate, 1,6 hexanediol di(meth)acrylate, 1,4 butanediol di(meth) acrylate and combinations thereof.

In certain embodiments, the one or more ethylenically-unsaturated monomers can comprise one or more polyethylenically-unsaturated monomers (e.g., one or more

diethylenically-unsaturated monomers, one or more triethylenically-unsaturated monomers, one or more tetraethylenically-unsaturated monomers, one or more pentaethylenically-unsaturated monomers).

(co)polymer (e.g., an alginate polymer or copolymer). In certain cases, the polysaccharide (co)polymer can comprise a blend of an alginate (co)polymer and a second (co)polymer. In these embodiments, the alginate (co)polymer and the second (co)polymer can be blended at varying weight ratios. For example, the alginate (co)polymer and the second (co)polymer can be present in the particles in a weight ratio of from 2: 1 to 10: 1 (e.g., from 4:1 to 8: 1). The second (co)polymer can comprise, for example, chitosan, polylactic acid, poly glutamic acid, and PLGA (poly (lactic acid-co-glutamic acid)).

As discussed above, compositions comprising the salinity-responsive polymer particles described herein can be used in oil and gas operations, including oil recovery operations. The term "enhanced oil recovery" refers to techniques for increasing the amount of unrefined petroleum (e.g., crude oil) that may be extracted from an oil reservoir (e.g., an oil field). Using EOR, 40-60% of the reservoir's original oil can typically be extracted compared with only 20- 40% using primary and secondary recovery (e.g., by water injection or natural gas injection). Enhanced oil recovery may also be referred to as improved oil recovery or tertiary oil recovery (as opposed to primary and secondary oil recovery).

Examples of EOR operations include, for example, miscible gas injection (which includes, for example, carbon dioxide flooding), chemical injection (sometimes referred to as chemical enhanced oil recovery (CEOR), and which includes, for example, polymer flooding, alkaline flooding, surfactant flooding, as well as combinations thereof such as alkaline-polymer flooding or alkaline-surfactant-polymer flooding), microbial injection, and thermal recovery (which includes, for example, cyclic steam, steam flooding, and fire flooding). In some embodiments, the EOR operation can include a polymer (P) flooding operation, an alkaline- polymer (AP) flooding operation, a surfactant-polymer (SP) flooding operation, an alkaline- surfactant-polymer (ASP) flooding operation, a conformance control operation, or any combination thereof. The terms "operation" and "application" may be used interchangeability herein, as in EOR operations or EOR applications.

Also provided are methods of hydrocarbon recovery that employ the compositions described herein. Methods for hydrocarbon recovery can comprise (a) providing a subsurface reservoir containing hydrocarbons there within; (b) providing a wellbore in fluid

communication with the subsurface reservoir; (c) preparing an aqueous particle composition comprising a population of salinity -responsive polymer particles having a first volume dispersed in an aqueous carrier having a first salinity; (d) injecting the aqueous particle composition through the wellbore into the subsurface reservoir, thereby depositing the salinity- responsive polymer particles within high permability regions of the subsurface reservoir; and (e) injecting an aqueous composition having a second salinity into the subsurface reservoir, thereby causing the population of salinity-responsive polymer particles within the high permability regions of the subsurface reservoir to swell to a second volume. The second volume can be at least ten times (e.g., at least twenty times, or at least thirty times) greater than the first volume.

The aqueous particle composition can be any of the compositions described above. By way of example, in some embodiments, the aqueous particle composition can comprise a population of salinity -responsive polymer particles formed from a copolymer derived from one or more acrylamide monomers; one or more acid-containing monomers; and optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii). In one embodiment, the salinity -responsive polymer particles can comprise a copolymer derived from 25-45% by weight acrylamide monomers; 50-65% by weight acid-containing monomers; and 0-15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii). In these examples, the first salinity can be higher than the second salinity. In other examples, the aqueous particle composition can comprise a population of salinity-responsive polymer particles formed from an alginate (co)polymer (e.g., an alginate polymer or copolymer) or a blend of an alginate (co)polymer and a second (co)polymer (e.g., chitosan). In these examples, the second salinity can be higher than the first salinity.

In some embodiments, the wellbore in step (b) can be an injection wellbore associated with an injection well. The methods of hydrocarbon recovery can further comprise providing a production well spaced apart from the injection well a predetermined distance and having a production wellbore in fluid communication with the subsurface reservoir. Injection of the aqueous composition having a second salinity in step (e) can increase the flow of hydrocarbons to the production wellbore. Methods can further comprise producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.

The aqueous composition having a second salinity can comprise a polymer (P) flooding solution, an alkaline-polymer (AP) flooding solution, a surfactant-polymer (SP) flooding solution, an alkaline- surfactant-polymer (ASP) flooding solution, or any combination thereof. In some cases, methods can further include performing any of the EOR operations described above following step (e), and producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir. For example, methods can further comprise injecting a polymer flooding solution, an AP flooding solution, a SP flooding solution, an ASP flooding solution, carbon dioxide, or any combination thereof into the subsurface reservoir following step (e), and producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.

By way of non-limiting illustration, examples of certain embodiments of the present disclosure are given below.

EXAMPLES

The goal of this research is to improve oil recovery by reducing bypassing due to fractures, common in hydrocarbon reservoirs, including carbonate reservoirs. Salinity sensitive polymeric particles (SSPP) were synthesized, which can plug fractures in reservoir rocks and divert fluid flow into the matrix. SSPP swell in brine; the swelling is a function of brine salinity. SSPP expand many times (-70 times) in DI water, but swell only about 3 times in very high salinity (20 wt% NaCl) brine. The swelling of the particles is independent of pH in the range of 2 to 12.6. The swelling process is reversible with salinity. These particles are stable at 60°C for at least several months. Core flood results show that these small particles can be transported through fractures during high salinity brine injection and plug the fractures during low salinity brine injection. Subsequent injectant fluid flow can then be diverted into the matrix, thereby recovering oil from previously unswept matrix. As a consequence, SSPP injection can be utilized to increase waterflood recovery in cores with full fractures and half fracture connected to the inlet. SSPP placement can also increase oil recovery for tertiary miscible floods.

Introduction

Carbonate reservoirs contain about 50-60% of the world's oil and gas reserves. Many carbonate reservoirs are heterogeneous and fractured with their fracture permeability several times higher than their matrix permeability. Because of the fractures, carbonate reservoirs have very low oil recovery during water or gas floods. Injected fluids flow through the high- permeability fractures bypassing the oil in the low permeability matrix.

A wide variety of methods have been tried to remedy the problem, including cementing, in situ polymer gel formation, and preformed particle injection. Mechanical methods (e.g., cementing) work only in the near wellbore regions. The injected fluids find the high permeability layers away from the well bore and flow primarily in these layers. Chemical methods, such as in situ polymer gel formation, can plug high permeability layers. However, in situ gelation has the problem of damaging both high and low permeability layers and it is not often effective in fractures. In depth gel treatment is difficult because of many reasons including the effect of salts and minerals on the reaction of gelants and segregation of gelants and crosslinkers during long distance propagation in reservoirs.

Conformance techniques have been developed that involve preformed gels, including size-controlled microgels, bright water, and preformed particle gels (PPG). Size-controlled microgels are preformed particles by crosslinking polymers under shear. When injected into a porous medium, they can flow through the pores but adsorb, thus reducing the conductivity of flow channels. They can be injected into porous media to reduce the permeability of flow channels. They can reduce water relative permeability higher than the oil relative permeability; however, it is difficult to place these particles selectively in different layers.

Bright water includes polymeric microparticles (0.1 to 3 micron) with both labile and stable internal crosslinks. These particles are temperature and time sensitive. They can be injected into the formation with a cooler brine (than the reservoir temperature) in a shrunken state. As the temperature increases inside the reservoir, the labile bonds de-crosslink and the particles expand, blocking the flow in the porous medium. The original particles are small enough to flow through the pores of the rock and can be placed very deep into the reservoirs. The residual resistance factors increase due to particle expansion over a large volume to provide the deep diversion of the fluids. The particles have to be of a prescribed size to invade the desired high permeability zone and not the other zones. These particles are too small for blocking fractures.

Preformed particle gels (PPG) include swellable polymeric particles. The swelling of PPGs is a function of temperature and pH. These particles can have a particle size on the order of microns to mm and can plug high permeability channels as well as fractures. PPGs are environmentally friendly and not sensitive to reservoir minerals and formation water salinity. Swollen particles can pass through pore throats smaller than their size depending on the pressure gradient.

PPGs overcome some drawbacks of other methods, including gelation time and uncertainties of gelation because of segregation, temperature, and pressure. Studies suggest that preformed gel has a better placement than gels formed in situ. Microgels can be injected into porous media without plugging. As a consequence, these microgels are good candidates for water shutoff.

Here, stimuli-responsive preformed polymeric gel particles are synthesized and investigated for application in formation fractures. These particles are sensitive to brine salinity, and hence are called salinity- sensitive polymeric particles (SSPP). In some cases, these particles can swell in low salinity brines. Conceptually, a slurry of these particles in a high salinity brine can be injected into a fractured well which would place the SSPP in the fractures. Then, a low salinity brine can be injected, which would expand the particles and plug the fractures, thereby diverting fluids into the tighter matrix of the formation. In other cases, these particles can swell in high salinity brines. Conceptually, a slurry of these particles in a low salinity brine can be injected into a fractured well which would place the SSPP in the fractures. Then, a high salinity brine can be injected, which would expand the particles and plug the fractures, thereby diverting fluids into the tighter matrix of the formation.

Laboratory coreflood experiments have been conducted to evaluate the effectiveness of SSPP for waterflood and EOR processes in fractured carbonate cores. The experimental procedures and the results are described next.

Materials and Methods

Synthesis of SSPP (Acrylamide) Particles: The SSPP polymer is synthesized by polymerization reaction consisting of an aqueous mixture of acrylamide, 2-Acrylamido-2- methylpropanesulfonic acid, water, pentasodium diethylenetriamine pentaacetate,

methylenebisacrylamide, and polyethyleneglycol diacrylate as a dispersed phase and a mixture of kerosene, Polyoxyethylene (20) sorbitan monooleate (Tween-80), and sorbitan sesquiolate as the continuous phase.

Specifically, an aqueous phase was prepared by mixing 16.49 gm acrylamide, 37.5 gm of 58% 2-Acrylamido-2-methylpropanesulfonic acid, 2 gm water, 0.1 gm of 40% pentasodium diethylenetriamine pentaacetate, 0.3 gm of 1% solution of methylenebisacrylamide, and 3.6 gm polyethyleneglycol diacrylate. A continuous organic phase was prepared by mixing 33.6 gm of kerosene, 6 gm Polyoxyethylene (20) sorbitan monooleate (Tween-80), and 0.4 gm sorbitan sesquiolate.

A monomer emulsion was then prepared by mixing the aqueous phase and the organic phase, followed by stirring for about 4 hours. The emulsion was then deoxygenated with nitrogen for 30 minutes, and polymerization was initiated using a sodium bisulfite/sodium bromate redox pair at room temperature. The reaction mixture was then heated at about 80°C for an additional 2 hours. Next, the mixture was cooled to room temperature and filtered to remove any remaining liquid. The white solid polymer was heated at 60°C for 2 days to remove solvent, and the dry polymer was crushed and sieved to isolate a population of SSPP particles having the desired particle size.

Synthesis ofSSPP2 (Chitosan-Alginate) Particles: 5 wt% sodium alginate was dissolved in DI by stirring. 0.8 wt% chitosan solution was prepared by the addition of chitosan to distilled water. Then, chitosan solution and alginate solution were mixed to prepare a solution that was 2.5 wt% sodium alginate and 0.4 wt% chitosan. The solution was stirred for several hours, then poured or injected dropwise to a 1 wt% CaCl₂ solution to afford spherical polymer droplets. Once the particles were formed, the particles were dried in an oven at 60°C for about two days. The size of the spherical particles prepared by this process could be varied by injecting the solution into the calcium chloride solution using different sized syringe needles.

The SSPP2 particles were found to be salinity sensitive, though in a slightly different fashion than the SSPP particles. SSPP2 particles swell as the salinity increases in the range of 0-10%, beyond 10% salinity the swelling decreases. The pH also affects the size slightly; the size is slightly larger in the range of 3-5.5 pH compared to the neutral pH. Notably, the SSPP2 particles were found to be stable when held at a salinity and temperature. The SSPP2 particles were found to be stable for at least for a month at 80°C. The salinity sensitivity of these particles was opposite that of the SSPP (more swelling at low salinity for SSPP). As such, SSPP2 particles could have particular utility in high salinity reservoirs.

Brine: Salt solutions were prepared using sodium chloride (NaCl), calcium chloride (CaCl₂), magnesium chloride (MgCl₂), sodium iodide (Nal), sodium phosphate (Na₃P04), or combinations thereof.

Crude oil: Crude oil (of 52 cp viscosity at the room temperature) diluted with 20 wt% cyclohexane was used; viscosity of the diluted oil at room temperature was 14 cp.

Rock: Texas cream limestone cores of low permeability (about 35 mD or lower) were used.

Swelling of the SSPP: The swelling property of SSPP particles was tested at different concentrations of salts. Either one particle or a known amount (by volume) of particles were mixed with several brines and equilibrated for a few days with continuous recording of the size or volume change. To see the effect of salts other than NaCl, experiments were conducted with CaCl₂, MgCk, Nal and Na₃P04. The swelling property and stability of these particles was studied at different temperatures ranging from 25°C (room temperature) to 125°C at three different salinities (0 wt% NaCl, 0.1 wt% NaCl, and 20 wt% NaCl) for more than a month. The 20 wt% NaCl brine is referred to here as the "high salinity brine" and the 0.1 wt% brine is referred to here as the "low salinity brine." To study the effect of pH on SSPP particles, brine pH was varied from 2 to 12.6 at 25°C.

Core Flood Experiments : Four core flood experiments were performed. Table 1 lists the core properties for the core floods. Cores were approximately 1.5" in diameter and 12" in length. The cores were first vacuum saturated with oil. One core flood experiment (Core flood #1) was performed in a core without a fracture, as a reference. Rest of the core floods were conducted in cores with fractures. Cores were fractured after being saturated with oil. Sand was used to prop the fractures; sand size was 300 μιη in all the experiments. The SSPP used in Core flood #2 was about 500 μιη, but in the rest of the experiments, 32 μιη SSPP was used. Each experiment is described in detail in the Table 1.

Table 1. Properties of the cores used in core flood experiments.

k (mD)

Core Length Diameter before/after Φ PV Soi

Flood Material Fracture (inch) (inch) fracture (%) (ml) (%)

Texas cream No fracture

1 11.61 1.48 34.2 29 95 100 limestone

Texas cream Fracture; pre19.2 (before)

2 11.45 1.48 28.1 90.6 100 limestone packed SSPP 293 (after)

Texas cream Fracture; 35.8 (before)

3 11.65 1.48 28.9 95 100 limestone injected SSPP 2970 (after)

Texas cream Half fracture; 29.4 (before)

^■4- 11.42 1.48 19.6 63 100 limestone injected SSPP 31.8 (after)

Core Flood #1: During Core flood #1, the oil-saturated core was flooded with the high salinity brine (at a superficial velocity of lft/day) followed by the low salinity brine. The lower salinity water flood does not do much in this core flood, but is used in the other experiments to swell the polymeric particles. Toluene was injected next to mimic a miscible (e.g. CO2) flood at a low pressure. Oil recovery and pressure drop were monitored. This is the base case for an unfractured core.

Core Flood #2: In this core flood experiment, the oil-saturated core was taken out from the core -holder and cut longitudinally into two halves. A layer of sand and SSPP mixture was placed between the two halves and the composite core was put back into the same core-holder. The core was again flooded with oil to fill the fracture with oil. The core was then flooded with the high salinity brine (at a superficial velocity of 1 ft/day) followed by the low salinity brine (0.1 wt% NaCl brine). The low salinity brine was supposed to swell the SSPP and redirect the brine in to the matrix. This flood was followed by an acidified low salinity brine injection to test the sensitivity of SSPP to acids. This flood was followed by toluene injection (which mimics a miscible CO2 flood). This experiment was designed to show the effect of SSPP in a fractured rock if it can be placed properly in the fracture.

Core Flood #3: In Core flood #3, the oil saturated core was taken out from the core- holder and cut in to two halves similar to the core in Core flood #2. A layer of sand (0.5 ml) was placed between the two halves and the composite core was put back into the same core- holder. No SSPP was placed in the fracture. The core was flooded with oil to fill the fracture. Water flood was conducted with a 20 wt% NaCl brine, the high salinity brine (at the rate of lft/day) until no more oil was produced. Then a slurry of 32 micron SSPP in the high salinity brine was injected at the same flow rate. After injecting 1 PV of the slurry, another 7 ml of the high salinity brine was injected to displace the particles out of the inlet line. Then the low salinity brine (0.1 wt% NaCl solution) was injected at the same flow rate followed by toluene. This experiment was designed to show the effect of SSPP in a fractured rock when pumped into the fracture.

Core Flood #4: This core flood experimental procedure was exactly the same as that of Core flood #3 with one exception. The fracture was placed only in the upstream half of the core. The amount of SSPP injected was half the amount in Core flood #3. In many reservoirs, the fractures do not go all the way from injection wells to the production wells. This "half fracture" mimics that scenario.

Results and Discussion

Swelling of SSPP Particles on Hydration: Dry SSPP particles were immersed in deionized water (DI) and several brines. Figure 1A shows the swelling of particles upon immersion in DI water. The particles swell 3-4 times their original size in the linear scale (equivalent to 27 to 64 times in volume) in DI water. Figure IB shows the effect of NaCl concentration on swelling. The swelling decreases as the salt concentration increases. The swelling tendency in different salts was investigated to determine if the quality of salt has different effect. For this, equal quantities of dry particles were immersed in a 10 wt% solution of different salts such as Na₃P0₄, CaCl₂, MgCl₂ and Nal. The swelling factor was almost same in all cases including in NaCl. So the swelling does not significantly depend on the type of salt. In another test, two sets of 0.1 cc dry particles were put in test tubes and DI water and 20 wt% NaCl brine were added. The swollen state of the particles is shown in Figure 1C. The particles seem to swell about 32 times their original volume in DI water compared to about 3 times in 20 wt% NaCl. The reversibility of the swelling was tested by taking the DI water swollen particles and adding salt to form the 20 wt% NaCl brine, as shown in Figure 1C right panel. The particles shrink back to a smaller size. The swelling process is sensitive to salinity and reversible. The particles swell fairly fast (within one hour).

Effect of Salinity : To evaluate the effect of salinity on swelling of the SSPP particles,

0.1 cc of SSPP particles was immersed in brines of NaCl concentration ranging from 0 wt % (DI water) to 20 wt% at 25°C and the swelling factor was measured after an hour. Figures 2A- 2C detail the experimental result. Figure 2A shows the 0.1 cc dry particles in different vials before the addition of salt solutions. Figure 2B shows the swollen particles after an hour in salt solutions. Figure 2C shows a plot of salinity vs. the swelling factor. These particles swell about 35 times in DI water; the swelling factor decreases sharply with salinity up to about 1 wt% salinity and then gradually decreases with salinity. At the 20 wt% salinity, the swelling factor is only about 3.

Effect of Temperature: The swelling property and stability of the SSPP particles was studied by incubating the samples at different temperatures: 25°C (RT), 60°C, and 80°C, for more than a month. The results are illustrated in Figures 3A-3C. At room temperature, the

SSPP particles swell to their short-term equilibrium size within an hour. The swelling factor increases slightly (30 to 35 for DI water) over a month. The particles are stable for more than two months all the salinities studied. At 60°C, the swelling factor more than doubles within 25 days and attains a second equilibrium value (about 70 for DI water and 32 for 0.1 wt% NaCl brine). The SSPP particles were stable in all the brines studied for more than two months. At

80°C, the swelling factor more than doubles within 20 days and attains a second equilibrium value (about 70 for DI water and 40 for 0.1 wt% NaCl brine). The SSPP particles do not degrade much in 20% NaCl brine, but swell only about 3 times. The SSPP particles begin degrading after approximately one month in DI water. Thus, at a constant salinity, the swelling factor generally increases as the temperature increases.

Effect of pH on SSPP Particles: The effect of pH on the SSPP particles was also studied by dispersing them in both acidic and basic aqueous solutions having pHs ranging from 2 to 12.6. The swelling factor did not change with pH.

Core Floods: Four core floods were conducted to evaluate the effect of SSPP in fractured media. The injection schemes for the core floods are summarized in Table 2. Core flood #1 is the base case in a non-fractured core. Core flood #2 was conducted in a fractured core, but a mixture of sand and SSPP was placed in the fracture during the core assembly. Core flood #3 was similar to Core flood #2, but the core was assembled with only sand in the fracture. SSPP was injected into the fracture after the first water flood. Core flood #4 was similar to Core flood #3, but the fracture was only six inch long at the upstream half of the core.

Table 2. Core flood fluid injection sequence.

Cumulative Oil

Core Initial Recovery Flood Fracture Proppant Fluid Injection Sequence (%OOIP)

6.7 PV of 20 wt NaCl 58.1

N/A

1 No 2 PV of 0.1 wt NaCl 59.3

2 PV of Toluene 75.1

4.25 PV of 20 wt NaCl 43.2

4.6 PV of 0.1 wt NaCl 63.2

2 Yes Sand + SSPP

1.23 PV of 0.1 wt NaCl, pH 2 63.6

2 PV of Toluene 85.7

6.37 PV of 20 wt NaCl 22.7

0.85 PV of SSPP+20 wt NaCl

3 Yes Sand 0.08 PV of 20 wt NaCl

5.95 PV of 0.1 wt NaCl 58.3

2 PV of Toluene 79.0

6.4 PV of 20 wt NaCl 38.8

4 Yes, half Sand 0.25 PV of SSPP+20 wt NaCl 39.2

0.08 PV of 20 wt NaCl 5.68 PV of 0.1 wt NaCl 55.6

2 PV of Toluene 81.3

Core Flood #1: The core properties are listed in Table 1 and the injection sequence is summarized in Table 2. This core flood was conducted in a Texas cream limestone core without fractures, as a base case. About 6.7 PV of high salinity brine (20 wt% NaCl) was injected at a flow rate of 0.065 ml/min (1 ft/day). The high salinity brine was followed by a low salinity brine (0.1 wt% NaCl), which was further followed by toluene. Figure 4 shows the oil recovery and pressure drop during the flood. This flood recovered 58% OOIP during high salinity brine injection and about 2% additional oil was produced during the low salinity injection. The extra oil is due to the continuation of the water flood and has little to with the salinity change. The residual oil saturation to waterflood is about 40%. During the injection of 2 pore volumes of toluene, oil was displaced miscibly; the cumulative oil recovery increased to about 75%. The remaining oil saturation is still 25% because the rock is tight and

heterogeneous; the miscible flood is unstable.

The pressure drop during the high salinity brine injection increased from about 8 psi initially to about 11 psi and gradually decreased to about 5 psi, typical of a waterflood. The pressure drop did not change much during the low salinity water injection, but the pressure drop increased to about 11 psi during toluene injection and again decreased to about 4.5 psi. The pressure drop increased during toluene injection because of the mobilization of oil.

Core Flood #2: In this flood, the core had a fracture along its length which was filled with a mixture of sand and SSPP. The core properties are given in the Table 1 ; oil production and pressure drop are shown in Figure 5. The core was first flooded with a high salinity brine (20 wt% NaCl) for about 4.3 PV. The high salinity brine swelled the SSPP in the fracture slightly (about 3 times) and thus the water was forced into the matrix to some extent. The oil recovery was 43% OOIP at the end of the high salinity waterflood. Then the low salinity brine (0.1 wt% NaCl) was injected for about 4.5 PV. This brine swells the SSPP in the fracture about 15 times. The fracture plugs up with the swollen SSPP and the water is redirected into matrix. Thus the oil recovery increased to 63%. The pressure drop increases from 13 psi to 43 psi during this flood and comes down to about 25 psi at the end of this flood. This waterflood oil recovery is similar to the oil recovery in the unfractured core (Core flood #1). Thus the SSPP is effective in blocking the fracture. The sensitivity of the SSPP in the fracture to acidic brine was tested next. One PV of an acidic, low salinity brine (0.1 wt% NaCl, pH 2) was injected. Oil recovery and pressure drop remained about the same. This implies that the particle shape or size did not change due to the acidic environment.

The acidified water flood was further followed by toluene injection; this flood mimics a

C0₂ flood above miscibility pressure. The oil recovery increased from 63% to 86%. Toluene was redirected into the matrix where it miscibly displaced the oil. The pressure drop increased to about 39 psi during oil mobilization and then decreased to about 25 psi. This experiments shows that SSSP is effective in blocking the flow of miscible solvents in the fracture and redirecting it to the matrix.

The pressure drop during oil injection before fracture was 56 psi and after fracture was about 4 psi. So the 25 psi at the end of the experiment predicts that the core fracture is very nicely plugged due to the swelling of applied SSPP particles.

Core Flood #3: Core flood #2 showed that the SSPP can be effective if placed in the fractures. In Core flood 3, we test if SSPP can be pumped into an existing fracture and be swollen in place. The fracture had a layer of sand. The properties of the core are listed in Table 1 and the injection scheme is summarized in Table 2. The oil recovery and pressure drop are shown in Figure 6. The core was first flooded with the high salinity brine until no more oil was produced. The oil recovery was about 23% OOIP. It was low because most of the water was channeling through the fracture; some water did imbibe into the matrix. The pressure drop was very low (less than 1 psi) indicating fracture-dominated flow.

The SSPP used in this flood was 32 micron size. 4 cc of SSPP was dispersed in 100 cc of 20 wt% NaCl and 0.8 PV of the suspension was injected from an accumulator which has piston. This injection was followed by 7 cc of high salinity brine to clear the inlet line. The SSPP in the high salinity brine was slightly swollen and got injected into the fracture. Then the low salinity brine (0.1 wt% NaCl) was injected for about 6 PV; this brine expanded the particles in the fracture. Thus the pressure drop increased to about 180 psi. This pressure drop forced the brine into the matrix and oil got displaced. Cumulative oil recovery increased to 59% OOIP, again similar to the water flood recovery of the unfractured core. This experiment demonstrates that it is possible to place the SSPP in the fracture where it can be swollen to blocking the fracture and redirect water into the matrix. Finally, 2 PV of toluene was injected as a miscible injectant. Pressure drop remained high and toluene was redirected into the matrix where it displaced the oil. The cumulative oil recovery increased to 80% OOIP. The SSPP is useful in blocking the fractures for both water floods and miscible floods.

The state of the SSPP and the core at different stages are shown in Figure 7. Figure 7, panel a shows the Texas Cream lime stone core before oil saturation; Figure 7, panel b shows the oil saturated core before creating a fracture. The oil saturated core was cut in to two halves (Figure 7, panel c) and in the flat surface of one half piece many scratches were made and a layer of sand was placed (Figure 7, panel d). The two core halves were combined (Figure 7, panel e) and put inside a core holder. After core flood experiment was over, the core was taken out of the core holder (Figure 7, panel f) and the two halves were separated to see the placement of SSPP. Figure 7, panel g shows SSPP throughout the length of the core. Figure 7, panel h shows the upstream side of the core before injecting SSPP and Figure 7, panel i shows the upstream side at the end of the experiment. A lot of SSPP can be seen on the inlet surface of the core. When the gel layer is removed from the inlet surface, the SSPP placed in the fracture can be seen in Figure 7, panel j. Figures 7, panel k and Figure 7, panel 1 show the downstream end of the core; many SSPP particles can be seen in the outlet end. Thus the polymeric particles did propagate through the fracture. The deposition of these particles in the inlet and outlet faces increased the pressure drop.

Core Flood #4: In this flood the oil- saturated core was cut longitudinally in the upstream half and a layer of sand was placed in this fracture. As in other experiments, the core was first flooded with the high salinity brine for about 6.4 PV. After no more oil was recovered, 10 cc of SSPP dispersion in the high salinity brine was injected. The total amount of SSPP injected was 1 cc dry SSPP. SSPP concentration in the dispersion was about 10%; SSPP could be injected quicker to prevent sedimentation of the particles. After injecting 10 cc of the dispersion, 7 cc of the high salinity brine was injected again to prevent plugging in the inlet line. Then 5.7 PV of the low salinity brine was injected followed by 2 PV of toluene injection.

Figure 8 shows the oil recovery and pressure drop during the flood. About 39% OOIP was recovered during the high salinity brine injection. The upstream half of this core is fractured and the downstream half is non-fractured. In the fractured core (Core flood #3), the water flood recovery was about 20% and it was 60% in the non-fractured core (Core flood #1).

Thus a 39% water flood recovery for this core makes sense. The oil recovery increased to 56% after the low salinity brine injection; again similar to the water flood recovery from the non- fractured core. The extra oil recovery is because of the swelling of the particles and the plugging of the fracture. During toluene injection, additional 25 % OOIP was recovered. The pressure drop increased during low salinity brine injection after SSPP placement. Again, during toluene injection the pressure drop first increased to about 30 psi and again decreased to about 15 psi and became stable. This core simulates fractures that are connected to injection well, but do not propagate all the way to the production wells. SSPP can be used in such fractures to redirect water or miscible solvent into the matrix.

The pressure drops during different stages of the floods are presented in Table 3 along with the initial oil permeability. The core did not have a fracture in Core flood #1. The oil permeability for core #1 is same because it was not fractured. In Core flood #2, the effective oil permeability increased from 19 md to 293 md because the fracture was filled with both sand and SSPP. In Core flood 3, the effective oil permeability increased even higher (from 36 md to 2970 md) because the fracture was propped with some sand. The oil permeability changes slightly before and after fracture in Core flood #4 because the fracture goes through only half the length. The pressure drop with the high salinity brine is higher in the fractured cores #2 and #3, because the SSPP swell about 3 times in this brine. For cores #1 and #4, the pressure drop after the water flood is dominated by the matrix flow and depends on the end point water relative permeability. In all the cases with SSPP, the pressure drop increases significantly with the low salinity brine because SSPP expands more than 15 times. Similar high pressure drops are also observed in toluene floods. This increased pressure gradient diverts the fluid into the matrix and displaces oil.

Table 3. Permeability and pressure drop change in core flood experiments.

Oil, k (mD) Pressure Drop (psi) (at 1 ft/day flow rate)

Before After

Core Before After Fracture Fracture 20% 0.1%

Flood Fracture Fracture (oil) (oil) NaCl NaCl Toluene

1 34.2 N/A 17.3 17.3 6 5 4.5

2 19.2 293 56 4.0 20 44 56

3 35.8 2970 16.6 0.4 1.3 80 96

4 29.4 31.8 13.4 12.4 11 30 15 Conclusions

Salinity sensitive polymeric particles are synthesized in this study which can plug fractures in reservoir rocks and divert fluid flow into the matrix. These polymeric particles decrease bypassing due to high permeability fractures. The following conclusions can be drawn from the study:

1. SSPPs swell in brine; the swelling is a function of brine sanility. SSPP expand many times (-70 times) in DI water, but swell only about 3 times in very high salinity (20 wt% NaCl) brine.

2. The swelling of the particles is independent of pH in the range of 2 to 12.6.

3. The swelling process is reversible with salinity.

4. These particles are stable in brine up to 60°C for at least several months.

5. These particles can be transported through fractures in high salinity brine where they swell only about 3 times. Injection of a low salinity brine expands the particles, plugs the fractures and diverts the fluids into the matrix.

6. The oil recovery in a fractured core depends on the ratio of the fracture permeability to matrix permeability. In Core flood #3, the oil recovery due to water flood before SSPP injection was 22% OOIP. After SSPP placement the water flood recovery increased to 58% OOIP which is close to water flood recovery in a non-fractured core (Core flood #1).

7. SSPP injection also increases waterflood recovery in a core with a half fracture connected to the inlet.

8. The SSPP placement also increases oil recovery due to a miscible injectant after water flood.

Abbreviations

AM Acrylamide

CaCl₂ Calcium chloride

DI Deionized water

EOR Enhanced Oil Recovery

MgCl₂ Magnesium chloride

mD Milli Darcy

OOIP Original oil in place

PPG Preformed particle gel PV Pore volume

RT Room temperature

SSPP Salinity sensitive polymeric particles

NaCl Sodium chloride

Nal Sodium iodide

Na₃P0₄ Sodium phosphate

The compositions and methods of the appended claims are not limited in scope by the specific compositions and methods described herein, which are intended as illustrations of a few aspects of the claims. Any compositions and methods that are functionally equivalent are intended to fall within the scope of the claims. Various modifications of the compositions and methods in addition to those shown and described herein are intended to fall within the scope of the appended claims. Further, while only certain representative compositions and methods steps disclosed herein are specifically described, other combinations of the compositions and method steps also are intended to fall within the scope of the appended claims, even if not specifically recited. Thus, a combination of steps, elements, components, or constituents may be explicitly mentioned herein or less, however, other combinations of steps, elements, components, and constituents are included, even though not explicitly stated.

The term "comprising" and variations thereof as used herein is used synonymously with the term "including" and variations thereof and are open, non-limiting terms. Although the terms "comprising" and "including" have been used herein to describe various embodiments, the terms "consisting essentially of and "consisting of can be used in place of "comprising" and "including" to provide for more specific embodiments of the invention and are also disclosed. Other than where noted, all numbers expressing geometries, dimensions, and so forth used in the specification and claims are to be understood at the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claims, to be construed in light of the number of significant digits and ordinary rounding approaches.

Unless defined otherwise, all technical and scientific terms used herein have the same meanings as commonly understood by one of skill in the art to which the disclosed invention belongs. Publications cited herein and the materials for which they are cited are specifically incorporated by reference.

Claims

WHAT IS CLAIMED IS:

1. A composition comprising a population of salinity -responsive polymer particles dispersed in an aqueous carrier;

wherein the salinity-responsive polymer particles occupy a first volume when dispersed in an aqueous carrier having a first salinity;

wherein the salinity-responsive polymer particles occupy a second volume when dispersed in an aqueous carrier having a second salinity; and

wherein the second volume is at least ten times greater than the first volume.

2. The composition of any of the preceding claims, wherein the second volume is at least twenty times greater than the first volume.

3. The composition of any of the preceding claims, wherein the second volume is at least thirty times greater than the first volume.

4. The composition of any of the preceding claims, wherein the salinity-responsive polymer particles have an average particle size of from 1 micron to 1000 microns.

5. The composition of any of the preceding claims, wherein the salinity-responsive polymer particles have an average particle size of from 5 microns to 500 microns.

6. The composition of any of the preceding claims, wherein the salinity-responsive polymer particles are stable to changes in pH, such that the salinity-responsive polymer particles occupy a third volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 4; the salinity -responsive polymer particles occupy a fourth volume when dispersed for one hour in an aqueous carrier having a third salinity and a pH of 10; and the third volume is less than five times greater than the fourth volume,

7. The composition of any of the preceding claims, wherein the salinity-responsive polymer particles comprise a copolymer derived from one or more ethylenically unsaturated monomers.

8. The composition of claim 7, wherein the one or more ethylenically unsaturated monomers comprise acrylamide.

9. The composition of any of the preceding claims, wherein the salinity-responsive polymer particles comprise a copolymer derived from:

(i) one or more acrylamide monomers;

(ii) one or more acid-containing monomers;

(iii) optionally one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).

10. The composition of claim 9, wherein the salinity-responsive polymer particles comprise a copolymer derived from 10% to 80% by weight acrylamide monomers, based on the total weight of the monomers that form the copolymer.

11. The composition of claim 9 or 10, wherein the salinity -responsive polymer particles comprise a copolymer derived from 20% to 60% by weight acrylamide monomers, based on the total weight of the monomers that form the copolymer.

12. The composition of any of claims 9-11, wherein the salinity-responsive polymer particles comprise a copolymer derived from 25% to 45% by weight acrylamide monomers, based on the total weight of the monomers that form the copolymer.

13. The composition of any of claims 9-12, wherein the salinity-responsive polymer particles comprise a copolymer derived from 20% to 90% by weight acid-containing monomers, based on the total weight of the monomers that form the copolymer.

14. The composition of any of claims 9-13, wherein the salinity-responsive polymer particles comprise a copolymer derived from 35% to 80% by weight acid-containing monomers, based on the total weight of the monomers that form the copolymer.

15. The composition of any of claims 9-14, wherein the salinity-responsive polymer particles comprise a copolymer derived from 45% to 70% by weight acid-containing monomers, based on the total weight of the monomers that form the copolymer.

16. The composition of any of claims 9-18, wherein the salinity-responsive polymer particles comprise a copolymer derived from:

(i) 25-45% by weight acrylamide monomers;

(ii) 50-65% by weight acid-containing monomers;

(iii) 0-15% by weight one or more additional ethylenically-unsaturated monomers, excluding monomers (i) and (ii).

17. The composition of any of claims 9-16, wherein the one or more acid-containing monomers comprise sulfonic acid groups.

18. The composition of any of claims 9-17, wherein the one or more acid-containing monomers are chosen from vinylsulfonic acid, allylsulfonic acid, 2-acrylamido-2- methylpropanesulfonic acid, 2-methacrylamido-2-methylpropanesulfonic acid, 2- acrylamidobutanesulfonic acid, 3-acrylamido-3-methylbutanesulfonic acid, and 2-acrylamido- 2,4,4-trimethylpentanesulfonic acid.

19. The composition of any of claims 9-18, wherein the one or more acid-containing monomers comprise 2-acrylamido-2-methylpropanesulfonic acid.

20. The composition of any of claims 9-19, wherein the one or more additional

ethylenically-unsaturated monomers comprise one or more polyethylenically-unsaturated monomers.

21. The composition of any of claims 1-6, wherein the salinity-responsive polymer particles comprise a polysaccharide (co)polymer.

22. The composition of claim 21, wherein the polysaccharide (co)polymer comprises an alginate (co)polymer.

23. The composition of claim 21 or 22, wherein the polysaccharide (co)polymer comprises a blend of an alginate (co)polymer and a second (co)polymer.

24. The composition of claim 23, wherein the second (co)polymer comprises chitosan.

25. The composition of claim 23 or 24, wherein the alginate (co)polymer and the second (co)polymer are present in a weight ratio of from 2: 1 to 10: 1.

26. The composition of any of claims 23-25, wherein the alginate (co)polymer and the second (co)polymer are present in a weight ratio of from 4: 1 to 8: 1.

27. A method for hydrocarbon recovery, comprising:

(a) providing a subsurface reservoir containing hydrocarbons there within;

(b) providing a wellbore in fluid communication with the subsurface reservoir;

(c) preparing an aqueous particle composition comprising a population of salinity- responsive polymer particles having a first volume dispersed in an aqueous carrier having a first salinity;

(d) injecting the aqueous particle composition through the wellbore into the subsurface reservoir, thereby depositing the salinity-responsive polymer particles within high permeability regions of the subsurface reservoir;

(e) injecting an aqueous composition having a second salinity into the subsurface reservoir, thereby causing the population of salinity-responsive polymer particles within the high permeability regions of the subsurface reservoir to swell to a second volume;

wherein the second volume is at least ten times greater than the first volume.

28. The method of claim 27, wherein the aqueous particle composition is a composition defined by any of claims 1-26.

29. The method of claim 27 or 28, wherein the wellbore in step (b) is an injection wellbore associated with an injection well, and the method further comprises

providing a production well spaced apart from the injection well a predetermined distance and having a production wellbore in fluid communication with the subsurface reservoir, and

wherein the aqueous composition having a second salinity in step (e) increases the flow of hydrocarbons to the production wellbore.

30. The method of claim 29, wherein the method further comprises producing production fluid from the production well, the production fluid including hydrocarbons obtained from the subsurface reservoir.

31. The method of any of claims 27-30, wherein the aqueous composition having a second salinity comprises a polymer flooding solution, an AP flooding solution, a SP flooding solution, an ASP flooding solution, or any combination thereof.

32. The method of any of claims 27-31, wherein the method further includes injecting a polymer flooding solution, an AP flooding solution, a SP flooding solution, an ASP flooding solution, carbon dioxide, or any combination thereof into the subsurface reservoir following step (e).