**2. Sand-pack flooding displacement tests**

The performance of the polymer AP1 and the SAP-AP1 system as a mobility control agent for heavy oil recovery was determined through routine oil sand-pack displacement tests at simulated reservoir conditions. The heavy oil used in these flooding tests was provided by Husky Energy Inc. (Calgary, AB, Canada) with a viscosity of 68,728 cP at 25°C that was adjusted to a viscosity of 2560 cP at 25°C by dilution with natural condensate produced from the McCully field, Corridor Resources Inc. (Sussex, NB, Canada). The density of the diluted crude oil was 0.954 g/ml at 25°C, the API corrected to 60°F was 15.27, and the interfacial tension (IFT) between the crude oil and the SAP-AP1 system was 0.032 dynes/cm at 25°C. The IFT was determined using a M6500 Spinning Drop Tensiometer manufactured by Grace Instrument (Houston, TX, USA). QUIKRETE® Premium Play Sand® (No. 1113), which is 100% quartz [30], was employed to prepare the unconsolidated sand packs. The sand-grain size distribution was determined by sieve analysis following the procedure described in [31], which conforms to ASTM C136/C136M-14. The sieve analysis indicated that the effective size of the sand, D10, and the uniformity coefficients, D60/D10, were 240 and 2.02 μm, respectively.

A total of four displacement tests were conducted at a temperature of 25°C using a brine concentration of 8.4 wt%. The synthetic brine composition was 6.9 wt% of NaCl, 0.18 wt% of MgCl<sup>2</sup> , 1.3 wt% of CaCl<sup>2</sup> , and 0.04 wt% of Na2 SO4 . Two displacement tests were conducted using the baseline polymer AP1 at the optimum concentration of 0.75 wt% (control tests) and two displacement tests were carried out using the optimum SAP-AP1 system which also contained a polymer concentration of 0.75 wt%. Displacement tests were carried out using a DCHH series core holder (pressure-tapped, biaxial-type loading) manufactured by Temco, Inc. (Tulsa, OK, USA). Two CFR series transfer vessels (Temco, Inc., Tulsa, OK, USA) were employed to displace brine, polymer, and crude oil through the sand pack. A Teledyne ISCO Syringe pump, model 100DX manufactured by Teledyne Isco, Inc. (Lincoln, NE, USA), was used to pump the fluids through the transfer vessels. Several PGT-30 series/stainless steel pressure gauges manufactured by Omega (Laval, Quebec, Canada) with an accuracy of 0.5% as a percent of full scale (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.

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

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).

The performance of the polymer AP1 and the SAP-AP1 system as a mobility control agent for heavy oil recovery was determined through routine oil sand-pack displacement tests at simulated reservoir conditions. The heavy oil used in these flooding tests was provided by Husky Energy Inc. (Calgary, AB, Canada) with a viscosity of 68,728 cP at 25°C that was adjusted to a viscosity of 2560 cP at 25°C by dilution with natural condensate produced from the McCully field, Corridor Resources Inc. (Sussex, NB, Canada). The density of the diluted crude oil was 0.954 g/ml at 25°C, the API corrected to 60°F was 15.27, and the interfacial tension (IFT) between the crude oil and the SAP-AP1 system was 0.032 dynes/cm at 25°C. The IFT was determined using a M6500 Spinning Drop Tensiometer manufactured by Grace Instrument (Houston, TX, USA). QUIKRETE® Premium Play Sand® (No. 1113), which is 100% quartz [30], was employed to prepare the unconsolidated sand packs. The sand-grain size distribution was determined by sieve analysis following the procedure described in [31], which conforms to ASTM C136/C136M-14. The sieve analysis indicated that the effective size of the sand, D10,

and the uniformity coefficients, D60/D10, were 240 and 2.02 μm, respectively.

SO4

, and 0.04 wt% of Na2

A total of four displacement tests were conducted at a temperature of 25°C using a brine concentration of 8.4 wt%. The synthetic brine composition was 6.9 wt% of NaCl, 0.18 wt% of MgCl<sup>2</sup>

baseline polymer AP1 at the optimum concentration of 0.75 wt% (control tests) and two displacement tests were carried out using the optimum SAP-AP1 system which also contained a polymer concentration of 0.75 wt%. Displacement tests were carried out using a DCHH series core holder (pressure-tapped, biaxial-type loading) manufactured by Temco, Inc. (Tulsa, OK, USA). Two CFR series transfer vessels (Temco, Inc., Tulsa, OK, USA) were employed to displace brine, polymer, and crude oil through the sand pack. A Teledyne ISCO Syringe pump, model 100DX manufactured by Teledyne Isco, Inc. (Lincoln, NE, USA), was used to pump the fluids through the transfer vessels. Several PGT-30 series/stainless steel pressure gauges manufactured by Omega (Laval, Quebec, Canada) with an accuracy of 0.5% as a percent of full scale

. Two displacement tests were conducted using the

,

properties of the SAP-AP1 system is provided in the preceding chapter of this book.

**2. Sand-pack flooding displacement tests**

228 Cyclodextrin - A Versatile Ingredient

1.3 wt% of CaCl<sup>2</sup>

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 sand-pack properties for each of the displacement tests.

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 waterflooding. All the fluids were injected at a flow rate of 0.98 cm<sup>3</sup> /min, which is equivalent to a 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 equivalent to three pore volumes (3 PV).

Afterward, the oil-saturated sand packs were waterflooding to displace oil by injecting brine (8.4 wt%) at a flow rate of 0.98 cm<sup>3</sup> /min until no more oil was produced, which corresponds to 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 0.98 cm3 /min to displace the unrecovered or "remaining" oil that was bypassed during the previous 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 (8.4 wt%) was injected at a flow rate of 0.98 cm<sup>3</sup> /min. In each of the injection stages, the injection time, pressure readings, and the corresponding volumes of the fluids (brine and oil) produced

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


**Table 1.** Sand-pack properties.

were monitored. Material balance was applied to determine oil and water saturations, as well as the percentage of oil recovered from each injection stage. More details of the experimental procedure employed during the sand-pack displacement tests are provided in [35].

The results obtained from the displacement tests were analyzed by plotting the resistance factor (RF), the residual resistance factor (RRF), percentage of cumulative oil recovery, ratio of remaining oil saturation over initial oil saturation (*S*ro/*S*oi), and water oil ratio (WOR) as a function of volume of fluid injected. The volume of fluid injected was expressed as a fraction of pore volume normalized by porosity and permeability using the capillary bundle parameter [36–39] to compare the displacement tests at the same porosity and permeability reference.

intra- and intermolecular interactions (i.e., decomplexation and complexation of host-guest interactions, breaking and reforming of hydrophobic interactions, and hydrogen bonds, among others) under the influence of the shear forces imposed during the flow process. Eventually, equilibrium of the shear forces and the flow resistance forces of the network structures are reached, and the RF curves leveled off. The stabilization of the RF curves also suggests that propagation of the SAP-AP1 systems and the baseline polymers took place along the sand-pack systems. These observations agree with previous research on flow behavior of associating polymers through porous media [28, 38, 44]. Overall, the optimum SAP-AP1 formulation consistently provides higher resistance factors and consequently a better mobility control than the

**Figure 2.** RF versus volume of fluid injected: (a) Baseline # 1.1 and SAP-AP1 # 1.2 and (b) Baseline # 2.1 and SAP-AP1 # 2.2.

Supramolecular Polymer-Surfactant System for Heavy Oil Recovery

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The performance of both polymers AP1 and SAP-AP1 in terms of the residual resistance factor, RRF, is presented in **Figure 3(a)** and **3(b)**, which plots RRF values as a function of volume of brine injected for tests Baseline # 1.1 and SAP-AP1 # 1.2 and Baseline # 2.1 and SAP-AP1 # 2.2, respectively. **Figure 3** indicates that the RRF curves for both systems decrease continuously as the volume of brine injected increases that eventually stabilize. The average end RRF value for the

**Figure 3.** RRF versus volume of fluid injected: (a) Baseline # 1.1 and SAP-AP1 # 1.2 and (b) Baseline # 2.1 and SAP-AP1 # 2.2.

baseline polymer AP1.
