**1. Introduction**

Worldwide, polymer flooding is extensively applied as a mobility control agent to increase the sweep efficiency of the displacing fluid during enhanced oil recovery (EOR). As stated by

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2018 The Author(s). Licensee IntechOpen. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

Perttamo, "[Compared] to conventional waterfloods on a timescale, polymer floods will accelerate the recovery process due to rapid viscosity build-up…. [that] will contribute to a faster and higher oil production. An incremental recovery factor of 5% [of the] original oil in place (OOIP) or more is regarded as a successful polymer application" [1]. Polymer flooding has been historically applied in light and medium gravity oil reservoirs. More recently, it has also been applied successfully in heavy oil reservoirs with oil viscosities ≥1200 cP, which expands the practical applicability of this EOR technique [2–11].

injection well such as in shearing devices during polymer dissolution, during recirculation of the polymer solution through centrifugal pumps, polymer flow through chokes and downhole valves under high differential pressure, and during the flow of polymers at high flow rates through the perforations of the reservoir rock and sand face [25]. The shear degradation of the polymer structure consists of the breakage of the macromolecule chain reducing its molecular weight, size, and viscosifying power. Thus, shear degradation is irreversible [17, 23, 26].

The shear degradability of EOR polymers is directly related to the polymer molecular structure, molecular weight, and chain flexibility. The physics of polymer mechanical degradation is reported in [26]. As indicated by Jouenne et al., "flexible polymer chains have the ability to be extended under elongational flow fields [and the] … stretching of the polymer chains can lead to chain rupture" [27]. For example, xanthan gum, which is a rigid rod-like biopolymer with a double-strand helical structure that aligns in the direction of the flow [26], displays a very high shear resistance because it does not stretch under shearing/elongations forces, which reduces the friction forces on the carbon/carbon backbone. On the contrary, the linear polyacrylamide homopolymer is highly flexible and therefore very sensitive to shear degradation. The shear stability of polyacrylamide is commonly improved by introducing negative acrylate groups to the backbone, since it provides rigidity by means of electrostatic repulsion.

of the acrylate groups inducing the coiling and folding of the polymer chain, which becomes less rigid and more flexible [17, 23]. Then, the stretching of the coiled (i.e., coiled-stretch transition) polymer chain under the influence of shear and elongational forces makes it vulnerable to chain breakage and irreversible shear degradation. Thus, the shear sensitivity of EOR

The shear stability of acrylamide copolymers can also be increased by introducing the polymer chain large functional hydrophobic groups such as the acrylamide tert-butyl sulfonate (ATBS) and the n-vinylpyrrolidone (n-VP) as they impart rigidity to the polymer structure [23]. The attachment of hydrophobic groups to the macromolecular backbone of EOR polymers to improve the shear and thermal stability, as well as the tolerance to brines with high salinity and hardness concentration, has been widely recognized. The main benefit of the incorporation of hydrophobic groups is as explained by Perttamo [1]: "the reorientation of the macromolecules due to polar and non-polar, results in [the] formation of hydrophobic associations between de incorporated hydrophobic groups," generating intramolecular and intermolecular associations forming supramolecular aggregates. These polymers are called associating hydrophobic polymers or hydrophobically modified polymers or for short associating polymers [1, 17, 19, 28, 29]. Under shear, these supramolecular aggregates can disassemble due to the reversible disruption of the hydrophobic bonds; therefore, at high shear rates, these systems show a remarkable shear-thinning behavior. As indicated by Dupuis et al. [19], these systems offer several benefits for field applications: "…reduced polymer concentration to achieve a required mobility ratio, extend the range of suitable reservoirs in terms of salin-

In this chapter, we evaluated the effectiveness of a supramolecular polymer-surfactant (SA-AP1) system as a mobility control agent for displacing heavy oil in high salinity and

, Ca2+, Mg2+) shelters the negative charges

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Nevertheless, the presence of electrolytes (e.g., Na+

ity, and facilitate the mixing, pumping, and injection procedures."

polymers increases with brine salinity [23].

Incremental oil recovery by polymer flooding is induced by the following mechanisms: reduction of the water-oil mobility ratio by means of the increased viscosity of the displacing phase (i.e., injected water) and reduction of viscous fingering, decrease of the water relative permeability due to polymer retention within the formation rock, diversion of the injected water to unswept reservoir regions, improvement of the water-injection profile (i.e., preventing crossflow between vertical heterogeneous layers), and the increase of oil fractional flow [4, 5, 12–21].

Field polymer-flood projects carry high chemical operating expenditures [5, 22]. Therefore, it is vital to carefully select the appropriate polymer chemistry for the specific reservoir characteristics. For instance, the practical applicability of polymer flooding is limited to reservoirs with moderate temperatures (i.e., <90°C) and formation brines containing low concentrations of divalent cations (e.g., Ca2+, Mg2+) to avoid the chemical degradation of the polymer guaranteeing the technical success of the process in a cost-effective fashion [12–17, 19, 23].

Divalent cations (i.e., Ca2+, Mg2+) significantly affect the viscosity of polymer solutions. The bridging effect of divalent cations with the negatively charged moieties (i.e., carboxyl groups) causes viscosity loss due to polymer coiling [12, 13, 15, 16, 23, 24]. Furthermore, the reaction of the carboxyl group with divalent cations causes polymer precipitation and phase separation [14]. Therefore, to compensate for the loss of viscosity, it is necessary to add higher polymer concentrations to the brine solution [12]. Alternatively, the reservoir could be conditioned before polymer flooding by injecting low-salinity water to prevent the mixing of the polymer slug with the high-salinity reservoir brine [16].

Several approaches have been taken to improve the chemistry of polymers to ensure their stability and functionality at elevated temperatures and in reservoir brine containing high salinity and hardness concentration. These polymeric systems have been customized by incorporating specific functional moieties that are covalently grafted onto the polymer structure. The attachment of sulfonic acid groups like allyl sulfonic acid, 2-acrylamido-2-methylpropane sulfonate (AMPS) and/or n-vinylpyrrolidone (n-VP) monomers increases the polymer resistance to hydrolysis and tolerance to high salinity and hardness. Shear stability and viscosifying power of polymers have been advanced by the introduction of hydrophobic groups like n-alkyl (i.e., ≥C<sup>6</sup> carbon numbers) acrylamide, styrene, ring structures, large and rigid side groups such as styrene sulfonic acid, n-alkyl maleimide, acrylamide-base long-chain alkyl acid, and 3-acrylamide-3-methyl butyric acid, among others [3, 13, 14, 17, 23, 24].

EOR polymers are shear sensitive, which is a downside for EOR applications. According to Zaitoun et al. [23] and Sheng et al. [17], shearing occurs within several devices during the different phases of polymer handling and injection process in the high flow rate region close to the injection well such as in shearing devices during polymer dissolution, during recirculation of the polymer solution through centrifugal pumps, polymer flow through chokes and downhole valves under high differential pressure, and during the flow of polymers at high flow rates through the perforations of the reservoir rock and sand face [25]. The shear degradation of the polymer structure consists of the breakage of the macromolecule chain reducing its molecular weight, size, and viscosifying power. Thus, shear degradation is irreversible [17, 23, 26].

Perttamo, "[Compared] to conventional waterfloods on a timescale, polymer floods will accelerate the recovery process due to rapid viscosity build-up…. [that] will contribute to a faster and higher oil production. An incremental recovery factor of 5% [of the] original oil in place (OOIP) or more is regarded as a successful polymer application" [1]. Polymer flooding has been historically applied in light and medium gravity oil reservoirs. More recently, it has also been applied successfully in heavy oil reservoirs with oil viscosities ≥1200 cP, which expands

Incremental oil recovery by polymer flooding is induced by the following mechanisms: reduction of the water-oil mobility ratio by means of the increased viscosity of the displacing phase (i.e., injected water) and reduction of viscous fingering, decrease of the water relative permeability due to polymer retention within the formation rock, diversion of the injected water to unswept reservoir regions, improvement of the water-injection profile (i.e., preventing crossflow between vertical heterogeneous layers), and the increase of oil fractional flow [4, 5, 12–21]. Field polymer-flood projects carry high chemical operating expenditures [5, 22]. Therefore, it is vital to carefully select the appropriate polymer chemistry for the specific reservoir characteristics. For instance, the practical applicability of polymer flooding is limited to reservoirs with moderate temperatures (i.e., <90°C) and formation brines containing low concentrations of divalent cations (e.g., Ca2+, Mg2+) to avoid the chemical degradation of the polymer guaran-

teeing the technical success of the process in a cost-effective fashion [12–17, 19, 23].

Divalent cations (i.e., Ca2+, Mg2+) significantly affect the viscosity of polymer solutions. The bridging effect of divalent cations with the negatively charged moieties (i.e., carboxyl groups) causes viscosity loss due to polymer coiling [12, 13, 15, 16, 23, 24]. Furthermore, the reaction of the carboxyl group with divalent cations causes polymer precipitation and phase separation [14]. Therefore, to compensate for the loss of viscosity, it is necessary to add higher polymer concentrations to the brine solution [12]. Alternatively, the reservoir could be conditioned before polymer flooding by injecting low-salinity water to prevent the mixing of the polymer slug with the

Several approaches have been taken to improve the chemistry of polymers to ensure their stability and functionality at elevated temperatures and in reservoir brine containing high salinity and hardness concentration. These polymeric systems have been customized by incorporating specific functional moieties that are covalently grafted onto the polymer structure. The attachment of sulfonic acid groups like allyl sulfonic acid, 2-acrylamido-2-methylpropane sulfonate (AMPS) and/or n-vinylpyrrolidone (n-VP) monomers increases the polymer resistance to hydrolysis and tolerance to high salinity and hardness. Shear stability and viscosifying power of polymers have been advanced by the introduction of hydrophobic groups like

groups such as styrene sulfonic acid, n-alkyl maleimide, acrylamide-base long-chain alkyl

EOR polymers are shear sensitive, which is a downside for EOR applications. According to Zaitoun et al. [23] and Sheng et al. [17], shearing occurs within several devices during the different phases of polymer handling and injection process in the high flow rate region close to the

acid, and 3-acrylamide-3-methyl butyric acid, among others [3, 13, 14, 17, 23, 24].

carbon numbers) acrylamide, styrene, ring structures, large and rigid side

the practical applicability of this EOR technique [2–11].

226 Cyclodextrin - A Versatile Ingredient

high-salinity reservoir brine [16].

n-alkyl (i.e., ≥C<sup>6</sup>

The shear degradability of EOR polymers is directly related to the polymer molecular structure, molecular weight, and chain flexibility. The physics of polymer mechanical degradation is reported in [26]. As indicated by Jouenne et al., "flexible polymer chains have the ability to be extended under elongational flow fields [and the] … stretching of the polymer chains can lead to chain rupture" [27]. For example, xanthan gum, which is a rigid rod-like biopolymer with a double-strand helical structure that aligns in the direction of the flow [26], displays a very high shear resistance because it does not stretch under shearing/elongations forces, which reduces the friction forces on the carbon/carbon backbone. On the contrary, the linear polyacrylamide homopolymer is highly flexible and therefore very sensitive to shear degradation. The shear stability of polyacrylamide is commonly improved by introducing negative acrylate groups to the backbone, since it provides rigidity by means of electrostatic repulsion. Nevertheless, the presence of electrolytes (e.g., Na+ , Ca2+, Mg2+) shelters the negative charges of the acrylate groups inducing the coiling and folding of the polymer chain, which becomes less rigid and more flexible [17, 23]. Then, the stretching of the coiled (i.e., coiled-stretch transition) polymer chain under the influence of shear and elongational forces makes it vulnerable to chain breakage and irreversible shear degradation. Thus, the shear sensitivity of EOR polymers increases with brine salinity [23].

The shear stability of acrylamide copolymers can also be increased by introducing the polymer chain large functional hydrophobic groups such as the acrylamide tert-butyl sulfonate (ATBS) and the n-vinylpyrrolidone (n-VP) as they impart rigidity to the polymer structure [23]. The attachment of hydrophobic groups to the macromolecular backbone of EOR polymers to improve the shear and thermal stability, as well as the tolerance to brines with high salinity and hardness concentration, has been widely recognized. The main benefit of the incorporation of hydrophobic groups is as explained by Perttamo [1]: "the reorientation of the macromolecules due to polar and non-polar, results in [the] formation of hydrophobic associations between de incorporated hydrophobic groups," generating intramolecular and intermolecular associations forming supramolecular aggregates. These polymers are called associating hydrophobic polymers or hydrophobically modified polymers or for short associating polymers [1, 17, 19, 28, 29]. Under shear, these supramolecular aggregates can disassemble due to the reversible disruption of the hydrophobic bonds; therefore, at high shear rates, these systems show a remarkable shear-thinning behavior. As indicated by Dupuis et al. [19], these systems offer several benefits for field applications: "…reduced polymer concentration to achieve a required mobility ratio, extend the range of suitable reservoirs in terms of salinity, and facilitate the mixing, pumping, and injection procedures."

In this chapter, we evaluated the effectiveness of a supramolecular polymer-surfactant (SA-AP1) system as a mobility control agent for displacing heavy oil in high salinity and hardness concentration. The SAP-AP1 system was formulated via self-assembling driven by β-CD host-guest complexation, divalent cation bridges (i.e., Ca2+ or Mg2+), hydrophobic interactions, and hydrogen bonding, among others. The SAP-AP1 system contains 0.75 wt% of an associating polymer (AP1), 0.007 wt% (70 ppm) of an anionic surfactant, and 0.007 wt% (70 ppm) of β-CD prepared in saline solution. Detailed information on the formulation and properties of the SAP-AP1 system is provided in the preceding chapter of this book.

(FS) were installed at the inlet of the core holder (P1), at the inlet cap to monitor the overburden pressure (POP), and two pressure gauges along the core holder (P2 and P3). **Figure 1** shows a simplified schematic of the experimental set-up used during the sand-pack displacement tests. The sand-pack properties, such as pore volume (PV), porosity (*ϕ*), and permeability to brine (*k*) were determined following routine procedures as outlined in [32, 33]. **Table 1** presents the

Heavy oil sand-pack displacement tests were carried out following a fluid injection scheme of four stages: heavy oil injection, waterflooding, polymer flooding, and post-polymer water-

flow velocity of 0.0116 m/s (0.91 ft./day). During the heavy oil injection stage, oil was continuously injected until the production of brine stopped, which corresponds to a volume of oil

Afterward, the oil-saturated sand packs were waterflooding to displace oil by injecting brine

a volume of brine equivalent to 6 pore volumes (6 PV). Right after the waterflooding stage was completed, 1 pore volume of AP1 or SAP-AP1 polymer solution was injected at a flow rate of

vious waterflooding stage [34]. Finally, a post-polymer waterflooding step was immediately initiated at the end of the polymer flooding stage. A total volume of 6.5 pore volumes of brine

time, pressure readings, and the corresponding volumes of the fluids (brine and oil) produced

/min to displace the unrecovered or "remaining" oil that was bypassed during the pre-

/min until no more oil was produced, which corresponds to

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/min. In each of the injection stages, the injection

/min, which is equivalent to a

sand-pack properties for each of the displacement tests.

equivalent to three pore volumes (3 PV).

(8.4 wt%) was injected at a flow rate of 0.98 cm<sup>3</sup>

**Figure 1.** Experimental set-up for sand-pack displacement tests.

(8.4 wt%) at a flow rate of 0.98 cm<sup>3</sup>

0.98 cm3

flooding. All the fluids were injected at a flow rate of 0.98 cm<sup>3</sup>

In this chapter, we begin by describing the sand-pack core-flooding displacement test and the properties of the unconsolidated porous media and fluids (i.e., heavy oil and brine) employed. Next, we discuss the viscosifying power of the baseline AP1 polymer and the SAP-AP1 system during flow through porous media by means of the resistance factor (RF). Polymer retention in porous media is also analyzed through the residual resistance factor (RRF). The effectiveness of both polymer AP1 and the SAP-AP1 system in recovering heavy oil is analyzed next. Finally, we discuss the effect of AP1 and SAP-AP1 on the water to oil production ratio (WOR).
