WO2014139037A1 - Self-assembling polymer compositions for use in subterranean oil recovery - Google Patents

Abstract

A self-assembling polymer (SAP) composition useful in subterranean formations such as oil wells is described. The composition includes a polymer, and linking molecules that result in association of polymer molecules in aqueous solution e.g., brines. An exemplary composition includes cyclodextrin, sodium dodecyl sulfate and partially hydrolyzed polyacrylamide.

Description

SELF-ASSEMBLING POLYMER COMPOSITIONS FOR USE IN SUBTERRANEAN

OIL RECOVERY

Field of the Invention

The present invention relates to self-assembling polymer compositions useful in the stimulation of hydrocarbon production from subterranean formations, methods of use and preparation of the compositions.

Background

The use of polymers for enhanced oil recovery (EOR) as water mobility control agents have been extensively investigated (Sandiford, 1964; Jewett and Schurz, 1 970; Chang, 201 1 ; Chen et al., 1998). The main purpose of adding polymer to the injected water is to decrease the mobility of the injected water by increasing its viscosity to improve the oil displacement efficiency. Recently, it has been also proposed by several researchers (Wang et al. 2000; Xia et al. 2008; Huh and Pope, 2008; and Hou et al. 2009) that the higher the elasticity of the polymer the higher the oil recovery. Furthermore, polymers also induce some degree of permeability reduction due to the adsorption and/or mechanical retention of polymer molecules in the pore throats within the flooded volume of the matrix rock reservoir. Therefore, polymer EOR flooding is frequently applied when the waterflood mobility is high and/or when the reservoir heterogeneity is high (Sydansk, 2007).

In practice, hydrolyzed polyacrylamide (HPAM) and xanthan gums (biopolymers) are the typical polymers widely used in oil fields (Szabo, 1979; Sandvik and Maerker, 1977). The choice between HPAM and xanthan gums for EOR application depends on a number of factors. Although xanthan gums are more expensive than HPAM, they offer high viscosity generating ability, excellent stability under high salinity, temperature and mechanical conditions; properties that make xanthan gums favorable candidates for enhanced oil recovery (EOR) (Guo et al.1 999).

HPAM renders high thickening efficiency in fresh water due to the repulsion of the negative charges in the carboxylate groups that permit stretching of the polymer backbone. However, when salt is present, the hydrolyzed polyacrylamide molecules assume a balled up conformational mode, which results from the substantial shrinking of the electrostatic fields around the carboxylate groups. This ball-up form cannot generate the same viscosity as the stretched polymer chains in fresh water. Another concern is that in the presence of divalent ions such as Mg²⁺ and Ca²⁺ of "hard" brines, polymer molecules can form complexes with these cations, which are not soluble in water and will therefore precipitate from the solution. This phenomenon is usually associated with considerable reduction in solution viscosity. In EOR applications, rapid precipitation of HPAM at reservoir temperatures above 60^, which can result from the auto-hydrolysis of acrylamide groups which produce more negative charges, is particularly deleterious. The use of HPAM is thus limited in environments of high salinity and/or hardness, and in warm oil reservoirs (Seright, 2009).

An additional drawback of high molecular weight polyacrylamides is their sensitivity to mechanical degradation. If shear rates are very high during polymer flooding, polymer chains can be torn apart resulting in mechanical degradation (Maerker, 1975). Such degradation is irreversible and usually results in viscosity reduction, which can make polymer flooding less efficient in displacing oil. The susceptibility of polymers to mechanical shear represents a serious problem regarding their applicability as mobility control agents.

In recent years, research has been focused in improving the overall stability of polymers to broaden their application in oil fields. For instance, some special monomer groups have been introduced into the polymer backbone by copolymerization with acrylamides to form copolymers. However, the economics of these remain a barrier to their field-scale use (Doe et al. 1987).

One approach to enhance mechanical stability has been to substitute acrylamides with hydrophobic monomers through which polymer chains can be associated through hydrophobic interactions that protect the polymer backbone under mechanical shear. This type of polymer has the advantage of the presence of intermolecular associations in aqueous solution that increase the hydrodynamic size of the polymer chains and consequently the solution viscosity. These favorable properties make hydrophobic polymers potential agents for application in oil recovery, drilling fluid, and profile modification (Taylor and Nasr-EI-Din, 1998). Hydrophobically modified polymers are currently used for polymer flooding in heavy oil reservoirs in Canada and other oil fields worldwide (Taylor and Nasr-EI-Din, 2007; Luo and Zhao, 201 1 ; and Eoff 201 1 ). However, large scale use of these polymers is also a challenge, being relatively expensive because of the high cost of the hydrophobic monomer inputs and the multi-stage chemical synthetic processes (Taylor and Nasr-EI-Din, 1998; Reichenbach-Klinke, 201 1 ). Beyond the economics, the acrylamide-based polymers still suffer some degradation because of mechanical shear, and are susceptible to the effects of high salinity and/or hardness, and high temperatures described above.

Xanthan gum is a heteropolysaccharide derived from the protective coating of the bacterium Xanthomonas campestris that is commonly used as a food additive, rheology modifier, food thickener, and stabilizer (Davidson, 1980). The backbone of polysaccharide chain consists of repeating pentasaccharide units formed by two glucose units, two mannose units, and one glucuronic acid unit. In addition to the constituent sugars, acetate groups and pyruvic acid are also contained in the side chains (Chen and Sheppard, 1 980). Due to the rigidity of polysaccharide chain, xanthan gum undergoes very slight mechanical degradation, even when high shear stresses are imposed (Zaitoun, 2012). Nevertheless, this polymer is very susceptible to oxidative degradation when oxidizing agents are present. This kind of degradation plays an important role in the viscosity loss of xanthan gum solutions (Harris et al. 1971 ). Furthermore, several bonds in xanthan gum molecule such as acetyl groups (Ash et al, 1 983), pyruvate ketals, and glycosidic linkages (Seright and Henrici, 1990) are prone to hydrolytic cleavage that can reduce viscosity.

Viscous fingering during water flooding leaves a large amount of oil untouched in the reservoir due to the unfavorable mobility ratio between the injected water and the displaced oil, which lowers the amount of recovered oil. Polymer flooding is a well-recognized technique for mobility control in conventional oil recovery through the thickening of the displacing fluid in order to improve the mobility ratio. Many laboratory studies and field tests of polymer flooding have been reported for conventional oil recovery (Wang, et al. 2007; Kang, et al. 201 1 and Lvonete, et al. 2007), but it was not recommended for the displacement of heavy crude oil with viscosities greater than 200 cp (Taber et al. 1997). In certain heavy oil reservoirs, thermal recovery methods are not considered feasible, as in the case of the Alaskan North Slope oil field with over 20 billion barrels of heavy/viscous oil. In such cases, polymer flooding has been considered the most practical oil recovery method, there being a variety of contributing factors: increased oil price, low cost (affordability) of polymers, production of polymers with superior viscosifying ability through chemical modification (i.e. hydrophobic modified polymers), the increasing use of horizontal wells that can improve areal sweep efficiency and reduce polymer use requirements, and the injection of polymer above the parting pressure, which is beneficial to increase the polymer solution injectivity, to reduce the risk of mechanical degradation of polymer solutions and to increase the pattern sweep efficiency (Seright 201 0).

Summary

The inventor has formulated three self-assembling polymer (SAP) systems for polymer flooding which are use, for example, in enhanced oil recovery. Specific SAP formulations were derived from various polymers including a hydrolyzed polyacrylamide (HPAM), a xanthan gum (XG), and a hydrophobically modified sulfonated polyacrylamide (HMSPAM) polymer. The SAP-HPAM and SAP-XG systems were formed through polymer associations (via non (covalent) bonding interactions) with inclusion complexes of a surfactant and beta-cyclodextrin (β-CD). The formulation of the SAP-HMSPAM was based on the formation of inclusion complexes polymer:p-CD through the insertion of the pendant hydrophobic groups in the polymer backbone into the β-cyclodextrin (β-CD) cavities.

In one embodiment, the invention is a method of stimulating a subterranean formation penetrated by a well. The method includes:

introducing into the formation an aqueous treatment fluid containing a self- assembly polymer composition. The composition includes:

(i) water-soluble polymer molecules; and

(ii) a sequestering agent having a relatively hydrophobic interior

The polymer molecules have hydrophobic moieties associated therewith, as through covalent- or ionic-, or other bonding interaction (s) which are described in greater detail below, and exemplified in different studies. The hydrophobic moieties are received within the hydrophobic interior of the sequestering agent to create the assembly.

In one embodiment, hydrophobic moieties are provided by surfactant molecules, i.e., the moieties are covalently linked to hydrophilic moieties and so the surfactant molecules serve to promote the polymer assembly, being non-covalently bonded to the polymer molecules and the sequestering agent molecules.

According to an aspect of such an embodiment, the polymer, surfactant and sequestering agent are capable of being dissolved in water at a concentration of at least 5% by weight and the polymer composition is capable of imparting a resistance factor greater than a resistance factor for the polymer by itself at the same concentration as the polymer composition, as measured across a sandstone core of about 48 cm² by about 15 cm long. In such comparisons, the difference between a composition containing a sequestering agent an agent-free composition would vary from polymer to polymer, and depend upon conditions such as salinity, etc. An improvement as measured by the ratio of the resistance factors (agent- containing:agent-free) of 1 .1 , 1 .2 or greater can be observed.

In a preferred aspect, the sequestering agent is present in a sufficient concentration such that the aqueous treatment fluid has a G' and G" greater than an identical aqueous solution except for the presence of the sequestering agent.

In embodiments in which the surfactant is entirely sequestered the surface tension of the composition is about the same as a similar composition absent the surfactant and sequestering agent.

The surfactant can be anionic, cationic, zwitterioinic, or nonionic, although the illustrated examples used anionic surfactants. A surfactant typically has a tail having a hydrophobic portion, which can be a hydrocarbyl chain. A hydrocarbyl chain be C6-C30 straight chain or branched alkyl, C6-C30 cycloalkyl, C6-C18 aryl, alkylaryl, alpha-alkenyl, or internal alkyl alkenyl. The surfactant can include a straight or branched chain alkyl or alkenyl tail dimensioned to be received within the interior the interior of the cyclic sequestering agent.

In cases of anionic surfactant(s), the anionic portion can be provided by e.g., a sulfate, a sulfonate, or a carboxylate group. Particular tails of anionic surfactants include, but are not limited to, branched or linear (C10-C35) hydrocarbyl, (C1 0-C45) alkenyl, a sodium branched alcohol propoxylate sulfate (Cn(PO)_mS0₄Na, where C represents hydrocarbyl with n being the number of carbons therein, for n = 5 to 30, and (PO)m represents an -O-propyloxy linker -0-(CH₂C(CH₃)(H)-0)m- for m = 1 to 10), polypropylene (HO(CH₂C(CH₃)(H)-0)_p- for p = 1 to 1 0), and polyethylene ((HO(CH₂CH₂0)_q- for q 1 to 10). Other possibilities are one or more of olefin sulfonates (IOS for (C10-C35) alkenyl), or a sodium branched alcohol propoxylate sulfate (Cn(PO)_mSO₄Na). A particular anionic surfactant is sodium dodecyl sulfate.

Yet other surfactants to be chosen from are ethylene oxide-propylene oxide- block polymers, ethoxylated surfactants, propylene oxide surfactants, mixtures of anionic and nonionic surfactants, zwitterionic surfactants, betaine amphoteric surfactants, ethoxylated cationic surfactants, alkyloxylate glycidyl ether sulfonates, alcohol based sulfonates, sodium methyl ester sulfonate, propoxylated sulfate, anionic alkylaryl surfactant based on olefin sulfonic acids, branched alpha olefin sulfonates (AOS), alcohol-alkoxy-sulfate, Guerbet alkkoxy sulfates, alkyl polyglycosides, and mixtures thereof.

In an aspect, the K_a of the surfactant and sequestering agent as measured at 25 °C in an aqueous solution containing 1 .05 w†% total dissolved salts can be at least 200, or at least 300, or at least 400, or at least 500, or at least 600 or at least 700, or is between 200 and 900, or between 200 and 800, or between 200 and 700, or between 300 and 700, or between 400 and 700.

The sequestering agent can be dimensioned to reversibly receive 2 or more surfactant molecules per sequestering agent molecule. Typically, the molar ratio of the surfactant to sequestering agent is between about 2:1 and about 3:1 , can be e.g., about 2:1 or about 3:1 .

Suitable water soluble polymers include, for example, one or more of xanthan gum, partially hydrolyzed polyacrylamide (HPAM), biopolymers, polyacrylamides, copolymers containing AMPS and acrylamide monomers, copolymers of vinylpyrrolidone and acrylamide, ter-polymers of vinylpyrrolidone, and acrylamide and acrylate, polyacrylate, a cellulose, a guar gum, a diutan, a wellan, a glucan, a glycan, a dextran, an alginate, a curdlan, a pullulan, methyl cellulose, hydroxyethylcellulose, hydroxypropyl cellulose, carboxymethylcellulose, carboxymethylhydroxyethylcellulose, sulfonated carboxymethylcellulose, sulfonated carboxymethylhydroxyethylcellulose, sulfonated hydroxyethylcellulose, sulfonated methylhydroxypropylcellulose, sulfonated methylcellulose, sulfonated ethylcellulose, sulfonated propylcellulose, sulfonated ethylcarboxymethylcellulose, sulfonated methylethylcellulose, sulfonated hydroxypropylmethylcellulose, guar, hydroxypropylguar, succinoglycan, and scleroglucan.

According to another broad embodiment, the invention is a method in which the water-soluble polymer is a hydrophobically modified water-soluble polymer and the hydrophobic moieties are provided by tails having hydrophobic portions covalently bonded to the polymer. Hydrophobic portions are thus received within the sequestering agent according to such embodiment.

In an aspect, the polymer and sequestering agent are capable of being dissolved in water at a concentration of at least 5% by weight and the polymer composition is capable of imparting a resistance factor greater than a resistance factor for the polymer by itself at the same concentration as the polymer composition, as measured across a sandstone core of about 48 cm² by about 15 cm long.

Suitable hydrophobically modified water-soluble polymers include one or more of hydrophobically modified sulfonated polyacrylamide, hydrophobically modified hydroxybutyl guar gum (HMHBG); hydrophobically modified hydroxylalkyl guar gums, hydrophobically modified water soluble poly(ethylene oxide)-PEO, hydrophobically modified polymers derived from acrylic acid, methaacrylic acid, homopolymer of acrylic acid, acenaphthylene, 1 -vinylnaphthalene, acenphthylene, polyacrylic acid, methyl methacrylate, styrene, methyl methacrylate-acrylic acid copolymer, Hydrophobically Modified Ethyl Hydroxyethyl Cellulose (HM-EHEC), Hydrophobically Modified Ethoxylated Urethane (HEUR) hydrophobically modified polyacrylates (HM-PA), Hydrophobically Modified polyethylene glycol (PEG), Hydrophobically modified polyether, Hydrophobically modified hydroxyethyl cellulose mixtures of diethyleneglycol monobutylether, mixtures of triethyleneglycol monobutylethers.

A hydrophobically modified water-soluble polymer can be a water-soluble polymer having hydrophobic tails randomly grafted to a polyelectrolyte polymeric backbone. Examples of suitable tails are (C12-C20) alkyl, poly(ethylene oxide), ethyl groups, C1 2 to C20, nonylphenol, pyrene and naphthalene units, and polypropylene oxide).

The polymer composition can be, for example, provided in the treatment fluid in an amount of from 0.02% to about 5% by weight of the treatment fluid.

A method of the invention can include admixing components (i) and (ii) to form the composition.

In embodiments, the sequestering agent is a cyclic molecule having a hydrophobic interior and a relatively hydrophilic exterior, and the hydrophobic portion of the surfactant is reversibly received within the hydrophobic interior of the sequestering agent. The sequestering agent can be a cyclic polysaccharide. The ring of the polysaccharide can include at least six monosaccharides. The ring can include six, seven or eight monosaccharide units. The monosaccharide units can be pentoses and/or hexoses. Monosaccharide units of the cyclic polysaccharide can be hexose monomers covalently linked to each other. The polysaccharide can be a- cyclodextrin, β-cyclodextrin or γ-cyclodextrin. The polysaccharide use in the examples is β-cyclodextrin. The sequestering agent is preferably not polymeric. A suitable internal cross-diameter of the sequestering agent is between about 6.0 A and about 6.5 A.

In another aspect, the invention is a method for preparing a self-assembled polymer. The method includes combining in an aqueous solution:

(i) a water-soluble polymer;

(ii) a surfactant having a hydrophobic portion and a hydrophilic portion; and

(iii) a sequestering agent having a relatively hydrophobic interior, capable of accepting a plurality of the hydrophobic portions of the surfactant.

Components (i), (ii) and (iii) can be as defined above.

Another aspect of the composition is an aqueous mixture of:

(i) a water-soluble polymer;

(ii) a surfactant having a hydrophobic portion and a hydrophilic portion; and (iii) a sequestering agent having a relatively hydrophobic interior, capable of accepting a plurality of the hydrophobic portions of the surfactant.

Again, components (i), (ii) and (iii) can be as defined above.

The invention includes a kit of components for a self-assembling polymer composition, the kit comprising components (i) to (iii).

In another aspect, the invention is a method for preparing a self-assembled polymer, the method comprising, combining in an aqueous solution:

(i) a hydrophobically modified water-soluble polymer; and

(ii) and a sequestering agent having a relatively hydrophobic interior, capable of accepting a plurality of the hydrophobic portions of the polymer.

Components (i) and (ii) can be as described above.

In another aspect, the invention is composition that is an aqueous mixture containing:

(i) a hydrophobically modified water-soluble polymer; and

(ii) a sequestering agent having a relatively hydrophobic interior, capable of reversibly accepting there into a plurality of hydrophobic portions of the polymer.

Components (i) and (ii) can be as described above, and can also be provided in the form of a kit.

In an aspect, the invention is use of a composition as described herein as a thickening agent, particularly for use in polymer flooding for an oil reservoir.

The invention is also a method of recovering liquid hydrocarbon from a hydrocarbon-containing formation, the method comprising:

(a) delivering a hydrocarbon recovery composition to at least a portion of the hydrocarbon containing formation and/or production pattern wherein the hydrocarbon recovery composition is as described herein.

Such a hydrocarbon containing formation can contain, for example, one or more of hydrocarbon that is condensate, extra light crude oil, light crude oil, light to medium crude oil, and conventional crude oil. The foregoing method can also include the step of (b) preparing the composition by admixing a sequestering agent, surfactant and water soluble polymer to form the hydrocarbon recovery composition prior to step (a).

The method can include the step of (b) preparing the composition by admixing a sequestering agent and hydrophobically-modified water soluble polymer to form the hydrocarbon recovery composition prior to step (a).

Such method can also include the step of (c) recovering hydrocarbon material from the formation after step (b).

A method of the invention can include treating a hydrocarbon containing formation, the method comprising:

(I) determining the level of salinity of water and optionally the temperature in the formation; and

(II) delivering a composition as described herein.

In another aspect, invention is a method of treating a hydrocarbon containing formation, the method comprising:

(i) determining one or more characteristics of the rock selected from porosity, permeability, and mineral composition, and the hydrocarbon saturation in the formation in which the hydrocarbon accumulation is contained;

(iii) delivering a composition as defined herein.

Such method can further include determining the chemical composition of the rock, and said selection is further made based on the hydrocarbon saturation in the reservoir or formation production pattern.

The formation can be a limestone formation, a mixed limestone-sandstone formation, a shale-limestone formation, etc.

In an aspect, the method can include determining the temperature within the formation and the selection can be based on said determination.

The invention thus also includes a product for preparing a surfactant composition for use in a hydrocarbon recovery operation, the product containing a surfactant, a sequestering agent and a water-soluble polymer. The surfactant and sequestering agent can be provided in a premixed package, or the surfactant and sequestering agent can be provided in separate packages. Relative amounts of the surfactant and agent in separate packages can be predetermined so that the contents of the first and second packages can be mixed in forming the composition without measuring the surfactant and agent.

As will be seen in the detailed examples, the SAP formulations described hereinbelow exhibit improved viscoelasticity, mechanical stability, tolerance to high brine salinity and hardness, and thermal stability. The flow behavior of the SAP systems within porous media at reservoir conditions indicates the feasibility of the use of these systems as mobility control agents and as in situ permeability modifiers. Likewise, the enhanced oil recovery performance of the SAP systems demonstrates their effectiveness in displacing heavy oil (1000 cp) by consistently producing higher incremental oil recoveries than the corresponding baseline polymers under the same experimental conditions.

Brief Description of the Drawings

The invention will become more fully understood from the detailed description and the accompany figures, in which:

Figure 1 illustrates the sandpack flood test experimental set-up;

Figure 2 shows viscoelastic properties of the SAP-HPAM system : (a) viscous modulus (G"); and (b) elastic modulus (G');

Figure 3 shows viscoelastic properties of the SAP-XG System : (a) viscous modulus (G"); and (b) elastic modulus (G');

Figure 4 shows the effect of β-cyclodextrin addition on the rheological properties of the self-assembling polymer system : (a) viscous modulus (G"); and (b) elastic modulus (G');

Figure 5 shows the effect of molar ratio on the viscoelastic properties of the SAP-HPAM system: (a) viscous modulus (G") ; and (b) elastic modulus (G');

Figure 6 shows the effect of molar ratio on the viscoelastic properties of the

SAP-XG system: (a) viscous modulus (G"); and (b) elastic modulus (G');

Figure 7 illustrates proposed structures for the SAP-HPAM and SAP-XG systems;

Figure 8 pictorially illustrates formation of a proposed structure of the self- assembling system SAP-HMSPAM;

Figure 9 shows ¹H NMR spectra of (a) β-CD, (b) surfactant (S), and (c) inclusion complex; Figure 10 shows the corresponding curves for the determination of the stoichiometric molar ratio of the complexation: (a) surface tension of surfactant solution in the absence and presence of β-CD (S: -CD of 2:1 ); and (b) relationship between (So-S) and [CDo-1 /2(So-S)]^«[S]2 for the S: -CD system;

Figure 11 shows the mechanical degradation of the SAP-HPAM system and

HPAM: (a) effect of shearing time at a fixed shear rate, and (b) effect of shear rate at a fixed shearing time;

Figure 12 shows the mechanical degradation of the SAP-XG system and XG: (a) effect of shearing time at a fixed shear rate; and (b) effect of shear rate at a fixed shearing time;

Figure 13 shows the mechanical degradation of the self-assembling polymer (SAP-HMSPAM) system and the hydrophobically modified sulfonated polyacrylamide (HMSPAM) baseline polymer solution: (a) effect of shearing time at a fixed shear rate; and (b) effect of shear rate at a fixed shearing time;

Figure 14 shows the effect of salinity on the viscoelastic properties of SAP system: (a) viscous modulus (G"); and (b) elastic modulus (G');

Figure 15 shows the effect of salinity on the rheological properties of SAP system and xanthan gum : (a) loss modulus (G"); and (b) storage modulus (G');

Figure 16 shows the effect of salinity on the rheological properties of the HMSPAM baseline solution and the self-assembling polymer SAP-HMSPAM system as a function of angular frequency: (a) viscous modulus, G"; and (b) elastic modulus, G';

Figure 17 shows the shear viscosity of SAP-HPAM and HPAM as a function of aging time at 90 °C;

Figure 18 shows the thermal stability of SAP-XG system and xanthan gum ;

Figure 19 shows the shear viscosity of the SAP-HMSPAM and HMSPAM as a function of aging time at 90 °C;

Figure 20 shows the flow behavior of SAP-HPAM in porous media: (a) RF developed during injection of polymer solution; and (b) RRF developed during brine injection after polymer flooding; Figure 21 shows the flow behavior of SAP-XG in porous media: (a) RF developed during injection of polymer solution; and (b) RRF developed during brine injection after polymer flooding;

Figure 22 shows the differential pressure between the inlet and outlet of the sandpack during SAP-XG and xanthan gum flooding;

Figure 23 shows the flow behavior of the SAP-HMSPAM and HMSPAM solutions in porous media: (a) resistance factor, RF; (b) residual resistance factor, RRF; and (c) differential pressure across the sandpack during polymer flooding;

Figure 24 shows oil recovery as a function of PV of injected SAP-HPAM or HPAM;

Figure 25 shows oil recovery as a function of PV of injected SAP-XG or xanthan gum ;

Figure 26 shows cumulative heavy oil recovery as a function of volume of SAP-HMSPAM and HMSPAM injected; and

Figure 27 shows the produced water/oil ratio as a function of volume of SAP-

HMSPAM and HMSPAM injected.

Detailed Description

Experiments described herein display the ability of cyclodextrin molecules to form inclusion complexes by receipt into their cavities of one or more molecules which form self-associative polymer networks. These compositions display advantageous viscoelasticity, mechanical, thermal, brine salinity and hardness stability, establishing their feasibility for use in polymer flooding of conventional and heavy oil reservoirs. The experiments and results presented herein establish advantages obtainable through use of the invention. The present specification postulates underlying theories explaining how advantages of the invention are provided. Thus, without being limited to or bound by these theories, the present invention discloses a variety of products and methods for use in oil extraction, particularly as part of a polymer flooding operation.

Cyclodextrins are a class of naturally occurring receptors which are cyclic oligosaccharides constituted of six (a-CD), seven (β-CD), or eight (γ-CD) D- glucopyranose units. Their shape is a conical cylinder whose inner surface is hydrophobic and outer surface hydrophilic (Bricout et al. 2009). A cyclodextrin form inclusion complexes by receiving one or more molecules into its cavity, i.e. caging foreign molecules (guest) in its cavity (host). One or two guest molecules can be entrapped by one, two or three cyclodextrins (Martin, 2003; Harata, 2006; Jullian, 2009). The cavity of cyclodextrins accommodates hydrophobic molecules or hydrophobic residues of the guest molecule through non-covalent interactions, thus polar groups protrude and form hydrogen bonds with adjacent cyclodextrin/water molecules. The most significant interactions responsible for the formation of inclusion complexes are hydrophobic interactions and the formation of hydrogen bond links between the polar centers of the molecules (Rybachenko, 201 1 ).

Three types of inclusion compounds between cyclodextrins and guest molecules are recognized as partial inclusion, complete inclusion, and complexes with higher stoichiometry. Partial inclusion occurs if the guest molecule is extremely large compared to the cyclodextrin so that only the inclusion of a portion of the guest molecule takes place. If the guest molecule is small, then a complete or full inclusion in the cyclodextrin cavity can be formed. CDs inclusion complexes having 1 :1 stoichiometry are common and can occur if the guest has polar group(s); the polar group(s) are usually oriented outside the cavity and can interact with the peripheral OH groups of cyclodextrins through hydrogen bonding. Inclusion complexes of higher stoichiometry (e.g. 2:1 guest-host) can occur if the guest molecule is small in size; while 1 :2 inclusions can occur if the guest molecule is much larger than the cavity (Rybachenko, 201 1 ). For instance 1 :1 , 1 :2, 2:2, or even 1 :n stoichiometries involving n= 20-22 cyclodextrin macro cycles have been reported (Dodziuk, 2006; George and Desmettre, 1987).

Covalent bonds are not broken or formed during formation of the inclusion complex, thus the binding of guest molecules within the host cyclodextrin is not fixed or permanent but rather is a dynamic equilibrium. Binding strength depends on how well the "host-guest" components of the complex fit together and on specific local interactions between surface atoms. Complexes can be formed either in solution or in the crystalline state and water is typically the solvent of choice (Martin, 2003), which interacts only weakly with the cyclodextrin cavity. Alcohols are next in displacement strength increasing with the number of the methylene groups, i.e., CH₃OH < C₂H₅OH < C₃H₇OH, etc (Cyclobond Handbook, 2002). Inclusion in cyclodextrins can exert effects on the physicochemical properties of guest molecules as they are temporarily locked or caged within the host cavity giving rise to modifications of guest molecules, which are not achievable otherwise. These properties include solubility enhancement of highly insoluble guests, stabilisation of labile guests against degradative effects of oxidation, visible or UV light and heat, control of volatility and sublimation, and physical isolation of incompatible compounds. It is possible to take advantage of such effects in various contexts, such as chromatographic separation, taste modification by masking off flavours, unpleasant odours, and controlled release of drugs and flavours. Potential guests for molecular encapsulation in cyclodextrins include straight or branched chain aliphatics, aldehydes, ketones, alcohols, organic acids, fatty acids, surfactants, aromatics, gases, and polar compounds such as halogens, oxyacids, and amines (Martin 2003).

In the studies described herein, three self-assembling polymer systems were formulated. The first formulation was based on the use of hydrolyzed polyacrylamide to produce a self-assembling polymer network (SAP-HPAM) through nonbonding interactions with inclusion complexes surfactants-CD; which were confirmed via ¹ H- NMR. The stoichiometric molar ratio of the complexation was determined via surface tension. The second self-assembly formulation was derived from xanthan gum (SAP- XG) following the same principle of the SAP-HPAM. The third SAP formulation was developed using a hydrophobically modified sulfonated polyacrylamide (HMSPAM) polymer. In this case, the formulation of the SAP-HMSPAM was based on the direct complexation of the pendant hydrophobic groups in the polymer backbone into the β- cyclodextrin (β-CD) cavities (Kj0niksen et al. 2008; Koontz and Marcy, 2003; Li and Loh 2008). Surfactant was not added to this formulation.

The effects of chemical blends on the viscoelastic behavior of the self- associative polymers were examined to establish the optimum formulations; which were characterized for thermal and mechanical stability, and tolerance to high brine salinity and hardness.

As described in connection with studies of specific embodiments, SAP formulations described herein present one or more of the following advantages: (i) greater viscoelasticity due to the intermolecular associations; (ii) stronger shear- thinning behavior resulting from weak associations (Gref et al. 2006); (iii) a high propensity towards reforming after cessation of mechanical shear; and (iv) improved tolerance to high temperature, elevated brine salinity and hardness due to the stabilized networks. These advantages make these newly developed SAP systems suitable for polymer flooding in heavy oil recovery.

In another series of experiments, the flow behavior in porous media of the self-assembling polymer formulations was evaluated in terms of resistance factor and residual resistance factor. These flow behavior tests demonstrated that the SAP formulations showed lower mobility in sandpack compared to the corresponding baseline polymers. Likewise, the effectiveness of the self-assembling polymer formulations in displacing heavy oil (1000 cp) was evaluated and compared with the performance of the corresponding baseline polymers. Overall, the SAP formulations (SAP-HPAM, SAP-XG, and SAP-HMSPAM) render higher incremental oil recovery than the corresponding baseline polymers under the same experimental conditions. Therefore, these SAP formulations are contemplated for use in enhanced oil recovery applications.

Unless otherwise specified, or required by its context, the word "comprise" and "include", in their various forms, are to be construed as being inclusive and open ended, and not exclusive. Specifically, when used in this specification including claims, the terms "comprises", "comprising", "includes" and "including" and variations thereof mean the specified features, steps or components are included. These terms are not to be interpreted to exclude the presence of other features, steps or components. The term "consist", in its various forms is to be construed as being closed ended.

Materials and Experimental Methods

Materials

The baseline EOR polymers were partially hydrolyzed polyacrylamide

(HPAM), xanthan gum, and a hydrophobically modified sulfonated polyacrylamide (H MSP AM).

The HPAM samples were provided by Gel Technology Corporation (Midland, TX), with a 5% degree of hydrolysis (Ye et al. 1996). The xanthan gum was acquired from El Peto Products LTD (Ontario, Canada). The hydrophobic copolymer

(HMSPAM) was provided by BASF Construction Polymers GmbH. The anionic surfactant (Alfoterra L167-4S) was supplied by Sasol North America, Houston, TX. and the β-cyclodextrin was acquired from Cyclodextrin Technologies Development Inc. (Gainesville, FL) Table 1 lists general physical properties of these chemicals.

TABLE 1

General Physical Properties of Materials used

Molecular Appearance Activity Density Water

Chemical Name Weight (g/mol) @ 20°C (wt %) (g/cm³) solubility

HPAM 7.7x 1 0⁶ Powder 1 00 - Soluble

Xanthan 2-5 x 1 0⁶ Powder 1 00 - Soluble

HMSPAM 6 x 1 0⁶ Powder 1 00 - Soluble

Surfactant 576 Liquid 30 1 .1 Soluble β-cyclodextrin 1 1 35 Powder 1 00 - Soluble

Experimental Methodology

Formulation of the Self-assembling Polymer Systems

Blend Concentration Effect

Polymer solutions, 1 wt % HPAM, 0.4 % xanthan gum, and 0.7 wt% HMSPAM concentrated were prepared by dissolving the polymer powders in brine (2.1 w†% TDS). Table 2 presents the composition of the synthetic brine used. To ensure complete dissolution of the polymer, the polymer-brine mixtures were shaken at room temperature for 1 -2 days using an IKA®KS 1 30 basic shaker. All polymer solutions used in this study were freshly prepared.

TABLE 2

Synthetic Brine Composition (2.1 wt% TDS)

Salts Concentration (wt %)

NaCI 1 .72

MgCI₂:6H₂0 0.09

CaCI₂ 0.32

Na₂S0₄ 0.009

TDS: Total Dissolved Solid β-cyclodextrin was added to the polymer solution and continually mixed using the shaker until the β-CD powder was totally dissolved in the solution. After which, the surfactant was added to the solution. The polymer/p-CD/surfactant mixtures were shaken at room temperature for 1 day to ensure the homogeneity of the chemical blend. Tables 3 and 4 show the experimental matrix followed to evaluate different blending concentrations of surfactant and β-cyclodextrin at a fixed surfactant to β- cyclodextrin (S^-CD) molar ratio of 2:1 and fixed polymer concentration for the SAP- HPAM and the SAP-XG systems, respectively. Table 5 presents the experimental matrix followed for the chemical blends tested during the formulation of the SAP- HMSPAM system.

TABLE 3

SAP-HPAM Experimental Matrix: Chemical Blend at a fixed S: -CD molar ratio of 2:1 Chemical Blend Concentration (wt %) Concentration (wt %) Concentration (wt %)

Number (#) HPAM Surfactant β-cyclodextrin

1 (Baseline) 1.0 0 0

2 1.0 0.4 0

3 1.0 0.6 0

4 1.0 0.8 0

5 1.0 0 0.4

6 1.0 0 0.6

7 1.0 0 0.8

8 1.0 0.4 0.4

9 1.0 0.6 0.6

10 1.0 0.8 0.8

11 1.0 1.0 1.0

TABLE 4

SAP-XG Experimental Matrix: Chemical Blend at a fixed S: -CD molar ratio of 2:1

Chemical Blend Concentration (wt%)

Number (#) Xanthan gum Surfactant β-cyclodextrin

1 (Baseline) 0.4 0 0

2 0.4 0.8 0

3 0.4 1.4 0

4 0.4 1.8 0

5 0.4 0 0.8

6 0.4 0 1.4

7 0.4 0 1.8

8 0.4 0.8 0.8

9 0.4 1.4 1.4

10 0.4 1.6 1.6

11 0.4 1.8 1.8

12 0.4 2.0 2.0 TABLE 5

SAP-HMSPAM Experimental Matrix: Chemical Blend at a fixed polymer

concentration

Chemical Blend

HMSPAM β-cyclodextrin Surfactant

Number (#)

(wt%) (ppm) (wt%)

1 (Baseline) 0.7 0 0

2 0.7 25 0

3 0.7 50 0

4 0.7 150 0

5 0.7 250 0

6 0.7 500 0

The effect of the chemical blends on the viscoelastic characteristics of the corresponding SAP systems was determined through rheological evaluation using a Bohlin Gemini HR 150 Nano Rheometer manufactured by Malvern Instruments. The rheometer was equipped with a 60mm (diameter) parallel plate measuring system using a gap size of 1 mm. Measurements were conducted at 25 °C. The rheological evaluation was conducted by performing first amplitude sweeps to determine the linear viscoelastic region (LVR) response of the samples. During the amplitude sweeps, the strain was ranged from 1 % to 100% at a fixed frequency of 1 Hz. Once the appropriate strains within the LVR were determined for the corresponding polymer systems, frequency sweeps were conducted to study the viscoelastic properties (elastic (G') and viscous (G") moduli) of the samples as a function of angular frequency, which was ranged from 0.01 to 100 rad/sec using a fixed strain within the LVR.

Surfactant:fi-CD Molar Ratio Effect

For formulations SAP-HPAM and SAP- XG, the effect of molar ratio of surfactant to β-CD (S: -CD) on the viscoelastic properties of systems was evaluated. The molar ratios evaluated were 4:1 , 3:1 , 2.5:1 , 2:1 , 1 .5:1 , 1 :1 , 0.5:1 . In these experiments, the concentration of the polymer was kept constant and the rheological measurements were conducted at 25°C.

¹H Nuclear Magnetic Resonance Spectrometry

¹H-nuclear magnetic resonance (NMR) spectra were recorded in D₂0 solution at 25 °C using an Oxford 300 MHz spectrometer. The chemical shifts are presented in terms of parts per million (ppm) with tetramethylsilane as the internal reference.

Surface-Tension Measurement at the Air/Water Interface

Surface tension was measured using a surface tensiometer (TensioCAD) manufactured by CAD Instruments (Les Essartsle-Roi, France). The temperature was controlled at 25 °C by a thermostat. The measuring procedure used was the Du Nouy ring. The standard deviation of surface tension measurements from the mean value was less than 0.3 mN-m^"1.

Mechanical Degradation

The evaluation of the mechanical stability of the SAP systems was performed according to the following experimental series:

1 . Mechanical degradation as a function of shearing time at a fixed shear rate.

The viscosity of the fresh SAPs and polymers solutions was measured at the shear rate of 6 s^"1. Then, the polymer solutions were sheared at 6 s^"1 for 1 h, after which it was allowed to relax for 10 min to erase any flow memory due to the applied stresses. After relaxation, viscosity was re-measured at 6 s^"1.

2. Mechanical degradation as a function of shear rate at a fixed shearing time.

As in the previous experimental series, the original viscosity of the fresh SAPs and polymers solutions was measured at 6 s^"1.

Then this sample was sheared at the corresponding shear rate for 1 h followed by 10 min relaxation, after which the viscosity was re-measured at 6 s^"1.The mechanical degradation of polymer solutions was quantified as viscosity loss (percentage), which is given in Equation (1 ):

Mechanical Degradation = Viscosity loss (%) = ^μ° ^μ x 100 (1 ) where μ₀, is the original viscosity of the fresh SAPs and polymers solutions measured at 6 s^~\ and μ is the viscosity of the polymer solution after shearing measured at 6 s^"1.

Salinity tolerance

The effect of brine salinity on the rheological properties (viscoelastic properties) of the optimum SAPs systems was evaluated by preparing the SAPs systems in synthetic brines having the following salinity concentrations: 0 (Distilled Water, DW), 2.1 wt% (21 ,000 ppm), 4.3 wt% (43,000 ppm), and 6.4 wt% (64,000 ppm). In addition, real reservoir brine with a salinity concentration of 7.76 w†% (77,600 ppm or 77,51 1 mg/L) provided by Husky Energy Inc., Canada was also used. Table 6 presents the composition of the synthetic brines.

TABLE 6

Synthetic Brine Compositions

Synthetic

Brine 2.1 wt% TDS 4.28 wt% TDS 6.42 wt% TDS

Concentration

Salts (wt %) Concentration (wt %) Concentration (wt %)

NaCI 1 .72 3.44 5.16

MgCI₂:6H₂0 0.09 0.18 0.27

CaCI₂ 0.32 0.64 0.96

Na₂S0₄ 0.009 0.018 0.027

TDS: Total Dissolved Solid

Thermal Stability

Thermal stability of the optimum SAPs systems was tested by placing sealed flasks containing the solutions in an oven at a constant temperature of 90 °C. The viscosity was measured along the thermal aging time.

Sandpack Flood Tests

The flow behavior of the SAPs systems and the baseline polymers within porous media was evaluated in sandpack flood tests carried out at 25 °C. The sandpacks were granular porous media composed of glass beads with average size ranging from 80 to 200 Mesh. The flow rate was calculated to render an average linear velocity of 1 ft/day. The sandpack was kept at a constant pressure of 550 psi using a back-pressure regulator as illustrated in Figure 1. Table 7 outlines the sandpack parameters for all the sandpack flood tests.

The experimental procedure was as follows.

1 . Injection of brine (2.1 w†%) into the sandpack until the differential pressure

(ΔΡ) between the inlet and outlet of the sandpack holder was constant.

2. Injection of polymer solution until the differential pressure (ΔΡ) between the inlet and outlet of the core holder was constant.

3. Resuming brine injection until the differential pressure (ΔΡ) was constant.

TABLE 7

Sandpack Parameters

Property HPAM SAP-HPAM XG SAP-XG HMSPAM SAP-HMSPAM

Permeability to brine, K_brine [D] 4.8 3.7 4.0 3.3 3.2 3.8

Length [cm] 15 15 15.0 15.0 15.0 1 5.0

Cross section area [cm²] 47.8 47.8 47.8 47.8 47.8 47.8

Porosity [%] 38.5 40 39.2 39.9 40.0 39.9

Pore Volume [ml] 261 .7 271 .9 266.8 270.1 271 .9 271 .0

System Pressure[psi] 550 550 550 550 550 550 Enhanced Oil Recovery (EOR) Tests

Sandpacks were initially saturated with brine and the basic properties of the porous media were determined as presented in Table 7. Then, this sandpack was flooded with heavy crude oil (1000 mPa.s at 25 °C) provided by Cenovus Energy Inc., Canada, until brine production ceased. At this point, water flooding was initiated at a constant flow rate of 1 ft/day until the produced water-oil ratio was higher than 99%. After that, one pore volume (1 PV) of polymer slug was injected followed by extended water flooding.

Results and Discussions

Blend Concentration Effect

The effect of S and β-CD blends on the viscoelastic properties of the SAP-

HPAM and the SAP-XG systems was evaluated through the viscous modulus (G") and elastic modulus (G') performance as a function of angular frequency, as shown in Figure 2 and Figure 3, respectively.

The viscous modulus of the HPAM solution shows a slight increase when mixed with the surfactant alone (Figure 2a); this could be due to hydrophobic interactions between surfactant and polyacrylamides through hydrogen bonding, which renders a slightly stronger network for the chemical blends numbers 2, 3, and 4; (Zhang ef al. 1994, Xin ef al. 2008). The addition of β-CD alone (chemical blend numbers 5, 6, and 7) to the HPAM solution causes a small decrease on viscosity, especially at low angular frequencies. This behavior can be attributed to the formation of very weak hydrogen bonds between the hydrogen located on the exterior of β-CD and the carboxylic groups of polyacrylamide, thus electrostatic repulsion in the molecular chains are concealed, which makes the molecule coil to shrink. On the contrary, a significant increase of the viscous modulus was observed at low angular frequencies when the HPAM solution was mixed with both S and β-CD (chemical blends numbers 8, 9, 1 0, and 1 1 ). It was also observed that the viscous modulus increases with increasing concentration of S: -CD until it reaches 0.8 w†%, when the viscous modulus of the SAP system stabilizes. A similar trend was also obtained for the elastic modulus as shown in Figure 2(b). Therefore, chemical blend number 10 produces the optimum SAP-HPAM network system in terms of viscoelasticity. The improved viscoelastic properties at low angular frequencies are very beneficial for EOR applications, because this superior viscoelasticity can improve not only the macroscopic displacement efficiency but also the microscopic displacement efficiency in oil recovery (Wang et al. 2001 ; Wu et al. 2007). Moreover, this SAP-HPAM also exhibits a similar shear-thinning behavior as the baseline HPAM, which makes it appropriate for the high flow rates at the injection pumps, valves, and flow lines during polymer flooding (Seright 2009).

In the case of the SAP-XG system, Figure 3a indicates that the loss modulus (G") of the polymer solution shows a slight increase when it is mixed with surfactant alone (Chemical blends # 2, 3, and 4). This is likely due to polysaccharide hydrogen, hydroxyl, and ionic carboxylate centers, which can form hydrogen bonding with surfactants. This bonding could establish weak networks between polymer chains and consequently slightly enhance the performance of G" (Zhang et al. 1994; Xin et al. 2008; Nedjhioui ef al., 2009; Mukherjee ef al. 2010). A better response of G" is observed when xanthan gum is blended with β-CD alone (Chemical Blends # 5, 6, and 7); while, Figure 3(a) shows a remarkable enhancement of G", when xanthan gum is mixed with both surfactant and β-CD (Chemical Blends # 8, 9, 10, 1 1 , and 12). The loss modulus (G") increases as the mixture concentration increases up to 1 .8 w†%, after which the values of G" reached the maximum performance.

This result implies that a concentration of 1 .8 w†% of surfactant and 1 .8 w†% of β-CD provides the highest increment of the viscous component of the SAP-XG system. A very similar trend was also obtained for the storage modulus as shown in Figure 3(b). Therefore, Chemical Blend # 1 1 produces the local optimum SAP system based on the increased values of both loss and storage moduli and/or on the overall viscoelasticity enhancement.

In the case of SAP-HMSPAM, Figure 4 displays the effect of β-CD addition on the rheological behavior of the SAP-HMSPAM system on the elastic modulus (G') and the viscous modulus (G") as a function of angular frequency. Figure 4 indicates that the addition of β-CD can enhance the viscoelasticity of the HMSPAM solution. The viscous modulus (G") increases as β-CD concentration increases up to 250 ppm, after which the viscosity stabilizes. This enhancement is pronounced at angular frequencies lower than 0.4 rad/sec, while at higher angular frequencies, the viscosity of the SAP-HMSPAM system is similar to the baseline polymer (Figure 4(a)). On the contrary, a significant improvement of polymer elasticity (G') is observed with the addition of β-CD to HMSPAM solution along the evaluated angular frequency range (Figure 4(b)). The maximum elasticity is reached when the β-CD concentration reaches 250 ppm. This concentration was thus selected as the optimum formulation for the SAP-HMSPAM system. The improvement of the viscoelastic properties, especially of the elastic properties, could be attributed to the "interlocking effect" of the polymer chains resulting from the caging of the pendant hydrophobic groups into the β-CD cavities, which causes intermolecular chain associations through nonbonding interactions in aqueous solutions. From an economic standpoint, the addition of only 150 ppm of β-CD might be more appropriate as the optimum concentration for cost reduction. Nonetheless, here, the β-CD concentration of 250 ppm was taken as the optimum based on the enhanced viscoelastic properties. Surfactanf.fi-CD Molar Ratio Effect

Given that this work involves surfactant receipt into the β-CD cavity in the presence of polyacrylamide molecules, it was considered important to evaluate the effect of S to β-CD molar ratio on the rheological properties of this polymeric system. Figure 5 presents the viscoelastic properties of the SAP-HPAM system as a function of molar ratio. Figure 5 indicates 2:1 (S: -CD) as the optimum molar ratio for the SAP-HPAM system in terms of viscoelasticity improvement. For the case of the SAP- XG system, Figure 6 shows that a molar ratio of 2:1 (S: β-CD) also offers the most noticeable enhancement of both G' and G". According to this observation, it is expected that the hydrophobic tails of two surfactants molecules are partially encapsulated into the cavity of a β-CD molecule forming a 2:1 inclusion complex; after which the supramolecular system (SAP-XG) is formed by self-assembling through nonbonding interactions between the S: -CD inclusion complexes and the branch chains of the heteropolysaccharide (xanthan gum backbones). The nonbonding interactions include hydrogen bonding and van der Waals forces (lliopulos et al. 1991 ; Zhang et al. 1994; and Xin et al. 2008).

Based on these observations, possible structures proposed for the SAP- HPAM and the SAP-XG are as illustrated in Figure 7, respectively. It is expected that the self-interaction between the baseline polymers (polyacrylamide and xanthan gum) and surfactant takes place first, followed by the intermolecular network assembly through inclusion complexes formed between β-CDs and the branched hydrophobic chains of the surfactant molecules. It has been well established that polyacrylamides can interact with anionic surfactants, in which the surfactant head groups are located in the proximity of polymer hydrophilic groups (COOH or COO- and CONH₂), by forming hydrogen bonds between surfactant head groups and polymer hydrophilic groups (lliopoulos et al. 1991 ; Zhang et al. 1994; Xin et al. 2008). Figure 7 indicates that the β-CD cavity locks the network assembly by partially including alkyl chains from two adjacent surfactant molecules, which stabilizes the network and accordingly generates improved viscoelastic properties. It is also well known that the relatively wide cavity of β-CD is able to accommodate two or more molecules as guests (Harata, 2006), which is in agreement with the experimental findings, that is, 2:1 (S^-CD) being the optimum molar ratio. The associated networks provide advanced viscoelastic properties to the resultant SAP- HPAM and SAP-XG systems. This supramolecular assembly occurs through noncovalent interactions in a dynamic equilibrium, in which the dissociation of the assembly is a relatively rapid process (Morillo 2006; Gref et al. 2006). This could explain the effect of shear rate on the viscoelasticity of the SAP-HPAM and SAP-XG systems; at high shear rates, the network structures are lost (dissociated) exhibiting a similar viscoelastic behavior to the baseline polymers. However, when shear rate becomes low, it is hypothesized that the self-association of the networks takes place and the corresponding viscoelasticities are recovered.

In the case of the SAP-HMSPAM, the hypothetical structure presented in Figure 8 is proposed; in which the β-CD cavities encapsulate the hydrophobic tails of the hydrophobic pendant groups from the polymer backbone.

¹H Nuclear Magnetic Resonance Spectrometry

Direct evidence of the formation of self-assembling inclusion complexes can be obtained from ¹H NMR spectroscopy. Insertion of guest molecules into the hydrophobic cavity will result in the chemical shift of guest and host molecules in the NMR spectrum (Schneider et al. 1998). Figure 9 (a) to (c) shows the ¹ H NMR spectra for β-CD, S, and the inclusion complex, respectively. The spectrum of the inclusion complex shows a chemical shift (up-field chemical shift) for protons H3 and H5, which indicates the inclusion of the surfactant hydrophobic tails inside the cavity of the β-CD. The chemical shifts observed indicate the formation of the S^-CD inclusion complex (Fernandes et al. 2005; Chen et al. 2006). Here, it was determined that the complexation of the surfactant with the β-CD follows a stoichiometry of 2:1 molar ratio, thus, it is suggested that partial insertion of two hydrophobic tails from two surfactant molecules into one β-CD cavity takes place with the remainder of the surfactant molecules outside the β-CD cavity folding over, which causes the chemical shift (up-field chemical shift) of all the external protons (H6, H4, H2, and H1 ) on the outside part of the β-CD as indicated by the ¹ HNMR spectrum of the inclusion complex in Figure 9(c). Surface-Tension Measurement at the Air/Water Interface

The formation of inclusion complexes was further demonstrated by measuring the surface tension of the surfactant (S) solution and the S: -CD solution as shown in Figures 10 (a) and (b). It is observed that the surface tension values of the S/β- CD solution are considerably greater than that of the β-CD-free surfactant solution at concentrations lower than the critical micelle concentration. That is because β-CD captures the hydrophobic chains into its cavity and makes the surfactant non- surface-active (Nelson and Warner, 1989). The association for 2:1 inclusion complexes of S and β-CD was further inferred from the results of the surface tension. The association constant expression in the premicellar region is given as follows in Equations (2) to (5):

CD + 2S CD^■ 2S (2)

Ka = [CD ^■ 2S]/[CD] ^■ [S]² (3)

Ka = 1 /2(So - S)/[CDo - 1 /2(So - S)] ^■ [S]² (4)

[CDo - 1 /2(So - S)] ^■ [S]² = 1/Ka^■ 1 /2(So - S) (5) where K_a is the association constant, CD-2S and S represent the inclusion complexes and free surfactant that can be determined from the relationships between the surface tension and concentration of S in the absence of β-CD (Lu et al. 1997), and CDo and So are the total initial concentration of β-CD and S, respectively. From Eq. (5), for the case of 2:1 inclusion, [CDo-1 /2(So-S)]-[S]² is expected to vary linearly with (So-S), which was experimentally proved as indicated in Figure 10(b).

Mechanical Degradation

Figure 11 plots the mechanical degradation of the SAP-HPAM system and HPAM as a function of shearing time (Figure 11 (a)) and shear rate (Figure 11 (b)), respectively. The SAP-HPAM network shows a remarkably higher resistance to mechanical shear compared with HPAM. The mechanical degradation behavior for the SAP-XG system and xanthan gum as a function of shearing time and shear rate is shown in Figure 12, which indicates that both polymer systems are sensitive to mechanical shear. Most of the viscosity loss occurs during the initial 40 minutes of shearing time (Figure 12(a)), after which viscosity loss levels off; behavior that has been previously reported (Maerker 1975; Warner 1976). When compared with xanthan gum, the SAP-XG system experiences less viscosity loss as a function of shearing time at a fixed shear rate. Likewise, as shown in Figure 12(b), both polymer systems suffered rapid mechanical degradation until the shear rate reached 20s^"1 , after which mechanical degradation slow down for the SAP-XG system, while it stabilizes for the baseline xanthan gum. Nevertheless, the SAP-XG system shows more resistance to mechanical shear than xanthan gum.

Figure 13 plots the mechanical degradation of SAP-HMSPAM system and HMSPAM as a function of shearing time (Figure 13(a)) and shear rate (Figure 13(b)), respectively. Both polymeric systems are very sensitive to mechanical shear under these experimental conditions. For instance, the mechanical degradation as a function of shearing time presented in Figure 13(a) indicates that the HMSPAM experienced approximately 25% of viscosity loss when subjected to a shear rate of 6 sec^"1 during 1 hour, while the SAP-HMSPAM suffered 30% viscosity loss. However, the residual viscosity of the SAP-HMSPAM system is 944 mPas, while the residual viscosity of the base HMSPAM is 356 mPas. These results indicate that after 1 hour of shearing at a fixed shear rate, the residual viscosity of the SAP-HMSPAM system is 165% higher that the residual viscosity of the base HMSPAM. Likewise, as the shear rate was increased from 6 to 100 sec^"1 , a viscosity loss of 29% was seen for the HMSPAM solution and 35% for the SAP system. Again, the residual viscosity of the SAP-HMSPAM system (850m Pas) is 145% higher than the residual viscosity of the baseline HMSPAM (347 mPas). The mechanical degradation seen for these polymer systems at relatively low shear rates is not likely the result of polymer chains breakage, but rather disentanglement and alignment (orientation) of polymer chains along the flow field under shear stresses (Barnes, 1997), and/or dissociation of the interconnected hydrophobic groups among polymer chains, or dissociation of the complexation HMSPAM: -CD. It is expected that upon cessation of mechanical shear, re-association of the inclusion complexes would take place for both polymer solutions. The improved mechanical stability of the SAPs systems may result from the "interlocking effect" of the polymers chains through the inclusion complexes, which shelters the polymer chains from mechanical shear. Salinity tolerance

Conventional EOR polymers exhibit a strong decrease in their thickening properties with salinity and hardness (Rashidi et al. 2010). Therefore, a higher dosage of polymer is required to generate the desired viscosity in brine, which makes polymer flooding less economic, especially in fields having very high salinity brines. Figure 14 presents the performance of viscous modulus (G") and elastic modulus (G') for the SAP-HPAM system and HPAM as a function of brine salinity. As anticipated, the viscoelasticity of both polymeric systems are markedly influenced by brine salinity due to the reduced electrostatic repulsion of the negatively charged hydrolyzed carboxylate pendant groups on the HPAM backbone that results in a coil- up mode of the polymer chains (Sydansk, 2007). Nonetheless, the SAP-HPAM network system exhibits a superior anti salinity behavior compared with HPAM. It seems that even at significant high salinities and hardness (7.76 w†%), the associations between the surfactant and the pendant acrylamide groups in the HPAM backbone remain strong and sheltered by the partial inclusion of the surfactant (S) alkyl chains into the β-CD cavity, which provides stability, rigidity, and strength to the entire HPAM backbone chain in the network. This interlocking offsets the complete collapse and/or shrinking of the polymer backbone chain despite the screening and collapsing of the local negatively charged double layer formed around the carboxylate species.

Figures 15(a) and 15(b) display the performance of the loss modulus and storage modulus as a function of brine salinity and angular frequency for the SAP- XG system and xanthan gum. The SAP-XG system also presents a much better viscoelastic performance than xanthan gum in the range of salinity concentrations and angular frequencies evaluated in this work. For instance, the loss modulus (G") appreciably outperforms xanthan gum (Figure 15(a)). The same trend is observed for the storage modulus (G') in Figure 15(b). The superior anti-salinity behavior shown by the SAP-XG system might be explained through the self-association of the polysaccharide chains and the inclusion complexes, which provide stability, rigidity, and strength to the entire network. The excellent performance of the SAP-XG system in the high salinity formation water (77,600 ppm), suggests the potential applicability of this system in reservoirs having brines with unusually high salinity and hardness. Figure 16 presents the salinity effect on the rheological properties (G' and G") of HMSPAM and SAP-HMSPAM versus angular frequency. Figure 16 shows that the rheological properties (G' and G") of HMSPAM, which derives from acrylamide, are significantly affected by the presence of electrolytes in the aqueous solution (brine), regardless of the presence of the pendant hydrophobic groups in the polymer backbone that can associate and minimize their exposure to the solvent (Taylor 2003). In this case, a higher polymer dosage is required to compensate for the salinity effect, especially in formation brines containing elevated salinity concentrations up to 7.76 w†% (77,600 ppm or 77,51 1 mg/l) as is the case of the formation brine provided by Husky Energy. On the contrary, the SAP-HMSPAM system shows a superior performance in the presence of electrolytes, even at the highest salinity concentration of 77,51 1 mg/l.

Thermal Stability

HPAM is known to be sensitive to temperature due to the hydrolysis of acrylamides (Doe et. al, 1 987), which causes a reduction in viscosity-enhancing function. Thus, thermal stability of EOR polymers is one of the critical factors related to their applicability in EOR. Figure 17 plots the corresponding shear viscosity as a function of thermal aging time. Figure 17 indicates that the viscosity of both polymeric systems significantly decreases during the first 25 hours of thermal aging and then levels off, which suggests that the hydrolysis reaction and/or oxidation reactions are nearly complete. This trend has been previously reported (Ryles, 1988). Figure 17 also indicates that the SAP-HPAM system still shows three times higher viscosity than HPAM; even though thermal degradation had taken place after 120 hours of aging time. This result may be attributed to the large number of hydrophobic interactions and entanglements in the solution that can stabilize the network against augmented polymer chain mobility at high temperature and can also minimize the exposure to solvent (Kj0niksen et al. 2008, Zou et al. 2012). Therefore, the SAP-HPAM system is especially advantageous compared with the currently used HPAM in high temperature reservoirs.

Figure 18 displays the effect of storage time at a temperature of 90°C on the shear viscosities of the SAP-XG system and xanthan gum. It shows that both systems undergo thermal degradation that might be caused by oxidative reactions of the polysaccharide chains at high temperatures (Glass et al. 1983; Lambert and Rinaudo, 1985). Nevertheless, the SAP-XG system displays a higher shear viscosity than xanthan gum at the end of the testing period (30 days of aging). In any case, these observations point to the enhanced thermal stability of the SAP-XG system, an advantage for EOR polymer flooding operations. The improved thermal stability of the self-assembling system could be attributed to the formation of supramolecular aggregates and/or possible entanglement of the molecular chains that restricts the motion of the polysaccharide chains at high temperatures (Kj0niksen et al. 2008; Zou et al. 2012).

Figure 19 plots the shear viscosity measured at a shear rate of 6 sec^"1 at 25 °C as a function of aging time. The viscosity of both polymeric systems significantly drops within the first 50 hours of aging time and then levels off, which suggests the completion of the hydrolysis reaction. Similar observations have been previously reported for acrylamide-based polymers (Davison and Mentzer, 1982; Ryles, 1 988). Figure 19 clearly demonstrates that the SAP-HMSPAM system still shows a noticeable higher viscosity after 120 hours of aging, 132 mPas, which is 66% higher than the HMSPAM solution (45 mPas) under the same experimental conditions. In other words, at the end of the aging testing period, the SAP system shows a higher residual viscosity (17%) than the residual viscosity of the base HMSPAM (14%). This indicates that the "interlocking effect" of the HMSPAM chains by the β-CD cavities can stabilize the associated structure and make it more thermally stable (Kj0niksen et al. 2008; Chiu and Liu, 2010; Zou et al. 201 2).

Sandpack Flood Tests

The flow behavior of SAP network system compared with HPAM was evaluated through the determination of the resistance factor {RF) and the residual resistance factor {RRF), which are given in Equations 6 and 7, respectively. RF \s a measure of the mobility control capacity or the effective viscosity of the polymer solution in porous media, whereas RRF \s an indication of the permeability reduction induced by polymer retention. Figure 20(a) plots the RF values as a function of injected PV of polymer solution. During the entire polymer flooding process, the SAP-HPAM system generated significantly higher RF values than the HPAM, which shows the effectiveness of this polymeric system in terms of mobility control functionality. This is important for successful polymer flooding in EOR applications. It is known that to achieve a better sweep efficiency, the mobility ratio, which is defined as the mobility (λ = relative permeability/ viscosity) of the displacing fluid (i.e., water) divided by the mobility of the displaced fluid (i.e., oil) must be equal or less than 1 . However, in heavy oil reservoirs, it is not feasible to have the viscosity of polymer solution comparable with that of the crude oil to establish a favorable mobility ratio (M < 1 ). In this case, permeability reduction (RRF) would contribute to reducing the mobility of the displacing fluid especially in heterogeneous formations. Therefore, on the basis of both mobility control ability and permeability reduction (Figure 20(b)), system described herein is a promising candidate for both conventional and heavy oil reservoirs in contrast to the baseline HPAM, even under harsh reservoir conditions.

Figure 21 (a) shows the resistance factor {RF) developed by the SAP-XG as a function of the volume of fluid injected expressed as pore volumes. The SAP-XG system generates significantly larger RF values than xanthan gum under the same experimental conditions. This observation confirms the enhanced effective viscosity and improved mobility control ability of the SAP-XG system during polymer flooding.

The RRF as a function of pore volume injected, presented in Figure 21 (b), indicates that the SAP-XG system induces a higher porous media permeability reduction than the xanthan gum. For instance, the SAP-XG system produces a final RRF value of 65, which means that the original permeability of the system (3.33 Darcies) was reduced by 65 times; this permeability reduction might be caused by the combined effect of polymer adsorption onto porous media and mechanical retention of the enlarged molecular size of the SAP-XG system due to supramolecular associations (Meister et al. 1980). Nevertheless, total plugging of the porous media was not observed during polymer flooding through the sandpack, as evidenced by the differential pressure performance presented in Figure 22. The fact that the differential pressure increases as a function of pore volume but eventually levels off indicates that the polymer system propagated through the entire length of the sandpack system.

Figures 23(a) to 23(c) show the flow behavior of the SAP-HMSPAM and

HMSPAM polymeric systems in porous media. The RF values gradually increased with the volume of polymer solution injected and then reached a plateau, at which steady state conditions were achieved for the polymer flooding process. The SAP- HMSPAM system generated RF values (flFsteady = 2604) that are more than two times higher than the baseline HMSPAM (/7Fs_teady=1 1 84). These high values of RF at the low flow rate of 1 ft/day (low flux) are in agreement with previous results (Seright et al. 201 1 ) at similar experimental conditions. The effect of larger fluxes on the RF o\ these polymers was not determined here, but the RRF values obtained by injecting up to 20 PV of brine at the end of the polymer injection as presented in Figure 23(b) demonstrates that the SAP-HMSPAM system and the baseline HMSPAM might be causing pore plugging due to polymer retention. These results suggest that the hydrodynamic size reached by the self-associative polymers (SAP- HMSPAM system and HMSPAM) in aqueous solutions might be too large compared to the size of the pore throats in the sandpack. If these associative polymers were injected into the sandpack at larger flow rates (flux>1 ft/day), the dissociation or disruption of the large hydrophobic associations and/or clusters could occur (Seright et al. 201 1 ). In any case, the large retention of these self-assembling systems might take place by multiple-layer adsorption through hydrophobic associations, which might be accelerated by further associations of polymer chains that are not in direct contact with the solid surfaces as has been previously reported (Argillier et al. 1 996; Vol pert et al. 1 998).

The SAP-HMSPAM system offers the largest polymer retention within the porous media, which indicates its potential use as an in situ permeability modifier. Under the experimental conditions of this work (flux: 1 ft/d), the SAP-HMSPAM system reduces the original porous media permeability by a factor of 233 (from 3.77 to 0.01 61 8 Darcies). Figure 23(c) further corroborates these observations, where the SAP-HMSPAM system generates the highest differential pressure across the sandpack.

Enhanced Oil Recovery (EOR) Tests

Figure 24 presents the performance of the SAP-HPAM system and the performance of the baseline HPAM in displacing oil. Table 8 summarizes the results of the oil recovery process, which indicates that during the initial water flooding production stage (8 PV), the oil recovery only reaches approximately 36.5% 001 P (original oil in place). The implementation of polymer flooding followed by an extended waterflooding step significantly improves the oil displacement and oil recovery (Figure 24). The oil mobilization and production was initiated after 0.4 PV of polymer solution. The SAP-HPAM system produced 1 9% more incremental oil than the baseline HPAM under the same experimental conditions.

TABLE 8

Summary of Oil Recovery Process by SAP-HPAM and HPAM

Water flooding Polymer flooding

Residual oil Final oil Incremental Oil recovery saturation Oil recovery recovery oil recovery Polymer Injected, PV (% OOIP) (%) (% OOIP) (% OOIP) (% OOIP)

HPAM 8 36.4 61 .7 32.3 69.2 32.8 SAP-HPAM 8 36.7 62.0 42.7 89.1 52.4

In the case of SAP-XG, only 1 .9% of incremental oil was produced if compared to xanthan gum as shown in Table 9 and Figure 25, this might be caused by large retention of SAP-XG within the porous media.

TABLE 9

Summary of Sandpack Flood Tests by SAP-XG and Xanthan Gum

Water flooding Polymer flooding

Oil Final oil Incremental

Injected, Oil recovery Residual oil recovery recovery oil recovery

Polymer PV (% OOIP) saturation (%) (% OOIP) (% OOIP) (% OOIP)

Xanthan gum 8 31 .5 65.1 48.2 83.4 51 .9

SAP-XG 8 32.7 63.9 47.3 86.5 53.8

Figures 26 and 27 display the performance of the SAP-HMSPAM and HMSPAM systems in displacing heavy oil, and Table 10 summarizes the results of the heavy oil displacement tests (conducted by duplicate). As Table 10 indicates, during the initial waterflooding production stage (8 PV), the recovery of heavy oil reaches a maximum value around 36% of the original oil in place. The implementation of polymer flooding followed by an extended waterflooding step significantly increases the displacement and recovery of heavy oil (Figure 26). The SAP-HMSPAM system produces the highest incremental heavy oil recovery (53.2% and 54.5%), followed by the baseline HMSPAM (46.3% and 48.8%). In all cases, the mobilization and production of heavy oil is initiated after the injection of 0.4 PV of polymer solution. During the extended waterflooding, incremental oil recovery continues to increase slightly for the SAP-HMSPAM system and HMSPAM until oil recovery levels off. The SAP-HMSPAM system produces 7% more incremental oil than the application of the base HMSPAM.

TABLE 10

Summary of Sandpack Flood Tests by SAP-HMSPAM and HMSPAM

Water flooding Polymer flooding

Residual oil Oil Final oil Incremental Injected, Oil recovery saturation recovery recovery oil recovery

Polymer PV (% OOIP) (%) (% OOIP) (% OOIP) (% OOIP)

HMSPAM 8 36.3 62.3 30.1 82.5 46.2

HMSPAM 8 34.5 61 .4 30.7 83.3 48.8

SAP-HMSPAM 8 27.1 72.9 43.3 80.4 53.2

SAP-HMSPAM 8 33.41 63.6 47.8 87.9 54.5

Figure 27 displays the effect of polymer flooding on the produced WOR. In all cases, the initial WOR is 99.9%. According to Figure 27, after the injection of 0.2 PV of the SAP-HMSPAM solution, a significant decrease of WOR occurs until it reaches a value around 28% (0.6 PV), after which, the WOR starts to increase very slowly to 48% at the end of polymer flooding (1 .0 PV). During the extended waterflooding stage, WOR continues to increase steadily until it reached 99.7%. Similar trend was observed for the baseline HMSPAM. However, for the HMSPAM system, the decrease in WOR was delayed until 0.4 PV of polymer solution was injected. It is important to highlight that the SAP-HMSPAM system offers the best performance in controlling the produced WOR during polymer flooding. It provides the fastest and longest decrease of the produced WOR (widest amplitude of the WOR curve, below a value of 63%). The noticeable reduction in the WOR demonstrated the enhanced sweep efficiency as a result of polymer flooding, so that less volume of injected water are required and consequently produced, which would decrease the operational costs caused by water handling and disposal.

These results indicate that significant volumes of heavy oil can be recovered by polymer flooding if chemically robust, stable, and cost-effective polymers (i.e. cost per unit of viscosity) are used after secondary oil recovery (i.e. waterflooding), as demonstrated in this work.

The self-assembling systems showed improved viscoelastic properties in comparison to baseline polymers.

The SAP systems exhibit a stronger shear-thinning behavior and reformability after cessation of mechanical shear.

The SAP systems show superior stability to mechanical degradation, tolerance to high salinity concentration, and elevated temperature.

The SAP systems show excellent mobility control capability and great potential as in situ permeability modifier.

The SAP systems consistently produce higher incremental oil recovery that the baseline polymers at the same experimental conditions.

Primary advantages of the self-assembling systems described herein include

(1 ) improved viscoelasticity due to the associated network; (2) injectable into porous media. The self-associations take place through noncovalent interactions (Gref et al. 2006). Host-guest interactions are not fixed or permanent but rather in a dynamic equilibrium, in which the dissociation of inclusion complexes is a relatively rapid process (Morillo 2006). These weak interactions can explain the observation that when these SAP systems are subjected to high shear rate, the network structures are lost, and exhibit a similar viscoelastic behavior as the baseline polymers, which make them more injectable near the wellbore. When the shear rate becomes low, for example, far away from the injection well or deep into the reservoir, the associated structure is reformed and viscoelasticity is recovered; and (3) lower interfacial tension. The presence of an EOR surfactant lowers the interfacial tension between the oil phase and the water phase that boost the microscopic displacement efficiency.

Although the foregoing invention has been described in some detail by way of illustration and example for purposes of clarity of understanding, it is apparent to those skilled in the art that certain minor changes and modifications will be practiced. Therefore, the description and examples should not be construed as limiting the scope of the invention.

The contents of all references, publications, patents, and patent applications disclosed herein are hereby incorporated by reference in their entirety.

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Claims

1 . A method of stimulating a subterranean formation penetrated by a well, the method comprising:

introducing into the formation an aqueous treatment fluid containing a self- assembly polymer composition comprising:

(i) water-soluble polymer molecules; and

(ii) a sequestering agent having a relatively hydrophobic interior; and wherein the polymer molecules have hydrophobic moieties associated therewith, which moieties are received within said hydrophobic interior of the sequestering agent to create said assembly.

2. The method of claim 1 , wherein said hydrophobic moieties are provided by surfactant molecules covalently linked to hydrophilic moieties for non-covalent bonding to the polymer molecules.

3. The method of claim 2, wherein the polymer, surfactant and sequestering agent are capable of being dissolved in water at a concentration of at least 5% by weight and the polymer composition is capable of imparting a resistance factor greater than a resistance factor for the polymer by itself at the same concentration as the polymer composition, as measured across a sandstone core of about 48 cm² by about 15 cm long.

4. The method of claim 2 or 3, wherein the sequestering agent is present in a sufficient concentration such that the aqueous treatment fluid has a G' and G" greater than an identical aqueous solution except for the presence of the sequestering agent.

5. The method of claim 2 or 3, wherein the surface tension of the composition is about the same as a similar composition absent the surfactant and sequestering agent.

6. The method of any one of claims 2 to 5, wherein the surfactant is anionic, cationic, zwitterioinic, or nonionic.

7. The composition of any one of claims 2 to 6, wherein the surfactant comprises a tail having a hydrophobic portion.

8. The composition of claim 7, wherein the hydrophobic portion comprises a hydrocarbyl chain.

9. The composition of claim 8, wherein the hydrocarbyl chain comprises C6-C30 straight chain or branched alkyl, C6-C30 cycloalkyl, C6-C18 aryl, alkylaryl, alpha- alkenyl, or internal alkyl alkenyl.

10. The composition of any one of claims 6 to 9, including at least one anionic surfactant.

1 1 . The composition of claim 10, wherein the anionic portion of the anionic surfactant is provided by a sulfate, a sulfonate, or a carboxylate group.

12. The composition of claim 1 1 , wherein the tail of the anionic surfactant is a branched or linear (C10-C35) hydrocarbyl, (C10-C45) alkenyl, a sodium branched alcohol propoxylate sulfate (C_n(PO)_mS0₄Na, where C represents hydrocarbyl with n being the number of carbons therein, for n = 5 to 30, and (PO)_m represents an -O-propyloxy linker -0-(CH₂C(CH₃)(H)-0)m- for m = 1 to 10), polypropylene (HO(CH₂C(CH₃)(H)-0)_p- for p = 1 to 10), and polyethylene ((HO(CH₂CH₂0)_q- for q 1 to 10).

13. The composition of claim 1 2, wherein the anionic surfactant is one or more of olefin sulfonates (IOS for (C10-C35) alkenyl), or a sodium branched alcohol propoxylate sulfate (C_n(PO)_mS0₄Na).

14. The composition of any one of claims 1 0 to 12, wherein the anionic surfactant comprises sodium dodecyl sulfate.

15. The composition of claim 6, wherein the surfactant is selected from the group consisting of ethylene oxide-propylene oxide-block polymers, ethoxylated surfactants, propylene oxide surfactants, mixtures of anionic and nonionic surfactants, zwitterionic surfactants, betaine amphoteric surfactants, ethoxylated cationic surfactants, alkyloxylate glycidyl ether sulfonates, alcohol based sulfonates, sodium methyl ester sulfonate, propoxylated sulfate, anionic alkylaryl surfactant based on olefin sulfonic acids, branched alpha olefin sulfonates (AOS), alcohol- alkoxy-sulfate, Guerbet alkkoxy sulfates, alkyl polyglycosides, and mixtures thereof.

16. The method of any one of claims 2 to 1 5, wherein the K_a of the surfactant and sequestering agent as measured at 25 °C in an aqueous solution containing 1 .05 w†% total dissolved salts is at least 200, or at least 300, or at least 400, or at least 500, or at least 600 or at least 500, or is between 200 and 900, or between 200 and 800, or between 200 and 700, or between 300 and 700, or between 400 and 700.

17. The method of any one of claims 2 to 16, wherein the sequestering agent is dimensioned to reversibly receive 2 or more surfactant molecules per sequestering agent molecule.

18. The method of any one of claims 2 to 17, wherein the molar ratio of the surfactant to sequestering agent is about 2:1 or 3:1 .

19. The method of any one of claims 16 to 18, wherein the surfactant comprises a straight or branched chain alkyl or alkenyl tail dimensioned to be received within the interior the interior of the cyclic sequestering agent.

20. The method of any one of claims 2 to 1 9, wherein the water soluble polymer is selected from xanthan gum, partially hydrolyzed polyacrylamide (HPAM), biopolymers, polyacrylamides, copolymers containing AMPS and acrylamide monomers, copolymers of vinylpyrrolidone and acrylamide, ter-polymers of vinylpyrrolidone, and acrylamide and acrylate, polyacrylate, a cellulose, a guar gum, a diutan, a wellan, a glucan, a glycan, a dextran, an alginate, a curdlan, a pullulan, methyl cellulose, hydroxyethylcellulose, hydroxypropyl cellulose, carboxymethylcellulose, carboxymethylhydroxyethylcellulose, sulfonated carboxymethylcellulose, sulfonated carboxymethylhydroxyethylcellulose, sulfonated hydroxyethylcellulose, sulfonated methylhydroxypropylcellulose, sulfonated methylcellulose, sulfonated ethylcellulose, sulfonated propylcellulose, sulfonated ethylcarboxymethylcellulose, sulfonated methylethylcellulose, sulfonated hydroxypropylmethylcellulose, guar, hydroxypropylguar, succinoglycan, and scleroglucan.

21 . The method of claim 1 , wherein the water-soluble polymer is a hydrophobically modified water-soluble polymer and said hydrophobic moieties are provided by hydrophobic tails covalently bonded to the polymer.

22. The method of claim 21 , wherein the polymer and sequestering agent are capable of being dissolved in water at a concentration of at least 5% by weight and the polymer composition is capable of imparting a resistance factor greater than a resistance factor for the polymer by itself at the same concentration as the polymer composition, as measured across a sandstone core of about 48 cm² by about 15 cm long.

23. The method of claim 21 or 22, wherein the hydrophobically modified water- soluble polymer is selected from the group consisting of hydrophobically modified sulfonated polyacrylamide, hydrophobically modified hydroxybutyl guar gum (HMHBG); hydrophobically modified hydroxylalkyl guar gums, hydrophobically modified water soluble poly(ethylene oxide)-PEO,hydrophobically modified polymers derived from acrylic acid, methaacrylic acid, homopolymer of acrylic acid, acenaphthylene, 1 -vinylnaphthalene, acenphthylene, polyacrylic acid, methyl methacrylate, styrene, methyl methacrylate-acrylic acid copolymer, Hydrophobically Modified Ethyl Hydroxyethyl Cellulose (HM-EHEC), Hydrophobically Modified Ethoxylated Urethane (HEUR) hydrophobically modified polyacrylates (HM-PA), Hydrophobically Modified polyethylene glycol (PEG), Hydrophobically modified polyether, Hydrophobically modified hydroxyethyl cellulose mixtures of diethyleneglycol monobutylether, mixtures of triethyleneglycol monobutylethers, and mixtures of any of the foregoing.

24. The method of claim 21 or 22, wherein the hydrophobically modified water- soluble polymer is a water-soluble polymer having said hydrophobic tails randomly grafted to a polyelectrolyte polymeric backbone.

25. The method of claim 21 or 22, wherein said hydrophobic tails comprise one or more of (C1 2-C20) alkyl, polyethylene oxide), ethyl groups, C12 to C20, nonylphenol, pyrene and naphthalene units, and polypropylene oxide).

26. The method of any one of claims 1 to 25, wherein the polymer composition is present in the treatment fluid in an amount of from 0.02% to about 5% by weight of the treatment fluid.

27. The method of any one of claims 1 to 26, further comprising forming the composition by admixing components (i) and (ii).

28. The method of any one of claims 1 to 27, wherein the sequestering agent is a cyclic molecule having a hydrophobic interior and a relatively hydrophilic exterior, and the hydrophobic portion of the surfactant is reversibly received within the hydrophobic interior of the sequestering agent.

29. The method of claim 28, wherein the sequestering agent comprises a cyclic polysaccharide.

30. The method of claim 29, wherein the ring of the polysaccharide comprises at least six monosaccharides.

31 . The method of claim 30, wherein the ring contains six, seven or eight monosaccharide units.

32. The method of any one of claims 29 to 31 , wherein the monosaccharide units are pentoses and/or hexoses.

33. The method of claim 32, wherein the monosaccharide units of the cyclic polysaccharide are hexose monomers covalently linked to each other.

34. The method of claim 33, wherein the polysaccharide is a-cyclodextrin, β-cyclodextrin or γ-cyclodextrin.

35. The method of claim 34, wherein the polysaccharide is β-cyclodextrin.

36. The method of any one of claims 1 to 35, wherein the sequestering agent is not polymeric.

37. The method of claim 36, wherein the internal cross diameter of the sequestering agent is between about 6.0 A and about 6.5 A.

38. A method for preparing a self-assembled polymer, the method comprising, combining in an aqueous solution:

(i) a water-soluble polymer;

(ii) a surfactant having a hydrophobic portion and a hydrophilic portion; and

(iii) a sequestering agent having a relatively hydrophobic interior, capable of accepting a plurality of the hydrophobic portions of the surfactant.

39. The method of claim 38, wherein component (i) is as defined by claim 20.

40. The method of claim 38 or 39, wherein component (ii) is as defined by any one of claims 6 to 15.

41 . The method of any one of claims 38 to 40, wherein component (iii) is as defined by any one of claims 28 to 36.

42. A composition comprising an aqueous mixture of:

(i) a water-soluble polymer;

(ii) a surfactant having a hydrophobic portion and a hydrophilic portion; and (iii) a sequestering agent having a relatively hydrophobic interior, capable of accepting a plurality of the hydrophobic portions of the surfactant.

43. The composition of claim 42, wherein component (i) is as defined by claim 20.

44. The composition of claim 42 or 43, wherein component (ii) is as defined by any one of claims 6 to 15.

45. The composition of any one of claims 42 to 44, wherein component (iii) is as defined by any one of claims 28 to 36.

46. A kit of components for a self-assembling polymer composition, the kit comprising components (i) to (iii) as defined by any one of claims 43 to 45.

47. A method for preparing a self-assembled polymer, the method comprising, combining in an aqueous solution:

(i) a hydrophobically modified water-soluble polymer; and

(ii) a sequestering agent having a relatively hydrophobic interior, capable of accepting a plurality of the hydrophobic portions of the polymer.

48. The method of claim 47, wherein component (i) is as defined by any one of claims 23 to 25.

49. The method of claim 47 or 48, wherein component (ii) is as defined by any one of claims 6 to 15.

50. A composition comprising an aqueous mixture of:

(i) a hydrophobically modified water-soluble polymer; and

(ii) a sequestering agent having a relatively hydrophobic interior, capable of reversibly accepting thereinto a plurality of hydrophobic portions of the polymer.

51 . The composition of claim 50, wherein component (i) is as defined by any one of claims 23 to 25.

52. The composition of claim 50 or 51 , wherein component (ii) is as defined by any one of claims 6 to 15.

53. A kit of components for a self-assembling polymer composition, the kit comprising components (i) and (ii) as defined by claim 51 or 52.

54. Use of a composition as a thickening agent, the composition being defined by any one of claims 42 to 45 and 50 to 53, wherein the thickening agent is used in polymer flooding for an oil reservoir.

55. Use according to claim 54, wherein the thickening agent comprises between 0.1 and 10 w†% of the aqueous formulation to be injected.

56. A method of recovering liquid hydrocarbon from a hydrocarbon-containing formation, the method comprising:

(a) delivering a hydrocarbon recovery composition to at least a portion of the hydrocarbon containing formation and/or production pattern wherein the hydrocarbon recovery composition comprises an aqueous solution comprising a composition as defined by any one of claims 42 to 45 and 50 to 53.

57. The method of claim 56, wherein the hydrocarbon containing formation contains one or more of hydrocarbon that is condensate, extra light crude oil, light crude oil, light to medium crude oil, and conventional crude oil.

58. The method of claim 55 or 56, wherein the composition is as defined by any one of claims 42 to 45, and further comprising the step of (b) preparing said composition by admixing said sequestering agent, surfactant and water soluble polymer to form the hydrocarbon recovery composition prior to step (a).

59. The method of claim 55 or 56, wherein the composition is as defined by any one of claims 50 to 53, and further comprising the step of (b) preparing said composition by admixing said sequestering agent and hydrophobically-modified water soluble polymer to form the hydrocarbon recovery composition prior to step (a).

60. The method of any one of claims 56 to 59, further comprising the step of (c) recovering hydrocarbon material from the formation after step (b).

61 . A method of treating a hydrocarbon containing formation, the method comprising:

(I) determining the level of salinity of water and optionally the temperature in the formation; and

(II) delivering a composition as defined by any one of claims 42 to 45 and 50 to 53 into the formation.

62. A method of treating a hydrocarbon containing formation, the method comprising: (i) determining one or more characteristics of the rock selected from porosity, permeability, and mineral composition, and the hydrocarbon saturation in the formation in which the hydrocarbon accumulation is contained;

(iii) delivering a composition as defined by any one of claims 42 to 45 and 50 to 53 into the formation.

63. The method of any one of claims56 to 62, further comprising the step of determining the chemical composition of the rock, and said selection is further made based on the hydrocarbon saturation in the reservoir or formation production pattern.

64. The method of any one of claims 56 to 62, wherein the formation comprises a limestone formation, a mixed limestone-sandstone formation or a shale-limestone formation.

65. The method of any of claims 56 to 64, further comprising determining the temperature within the formation and wherein said selection is further based on said determination.

66. A product for preparing a surfactant composition for use in a hydrocarbon recovery operation, the product comprising a surfactant, a sequestering agent and a water-soluble polymer.

67. The product of claim 66, wherein the surfactant and sequestering agent are provided in a premixed package.

68. The product of claim 67, wherein the surfactant and sequestering agent are provided in separate packages.

69. The product of claim 68, wherein the relative amounts of the surfactant and agent in the packages are predetermined so that the contents of the first and second packages can be mixed in forming the composition without measuring the surfactant and agent.

70. Use of the composition as defined by any one of claims 42 to 45 and 50 to 53, for use in recovery of oil from an underground formation.

71 . A method comprising the steps of: providing a treatment fluid comprising the composition as defined by any one of claims 42 to 45 and 50 to 53; and placing the treatment fluid in at least a portion of a subterranean formation.

72. The method of claim 71 , wherein said method is an enhanced oil recovery method.