**5. Water-to-oil ratio**

AP1 was 0.5, while the average end RRF value for the SAP-AP1 system was 0.02, suggesting insignificant pore plugging and/or permeability reduction due to polymer retention, which is

The performance of the SAP-AP1 system and baseline AP1 polymer as mobility control agents for the displacement and recovery of heavy oil is displayed in **Figure 4**, which plots the percent of cumulative oil recovery as a function of volume of fluid injected and flooding stage. **Figure 4** reveals that the average oil recovery during the waterflooding stage was about 30% for all the displacement tests. The combined average cumulative oil recovery produced by polymer flooding and post-polymer waterflooding for the Baseline tests # 1.1 and # 2.1 was 37%, respectively, after subtracting the average oil recovery attributed to the initial waterflooding stage. Whereas, the combined average cumulative oil recovery produced by flooding and post-polymer waterflooding for the SAP-AP1 tests # 1.1 and # 2.1 was 56%, respectively, after subtracting the average oil recovery attributed to the initial waterflooding stage. These experimental observations demonstrate that the SAP-AP1 system produced an additional incremental oil recovery of 19% relative to the baseline AP1 polymer. In this analysis, average values of cumulative oil recovery were used as an alternative to the individual results from each of the displacement tests to provide a conservative assessment of the experimental results in terms of heavy oil recovery. This approach was necessary to avoid the overestimation of oil recovery from polymer flooding and the post-polymer waterflooding stage, because the oil and water separation process after polymer flooding was found to be a difficult and lengthy process, even though several experimental steps were carried out to achieve the most

The ratio of remaining to initial oil saturation as a function of volume of fluid injected and

**Figure 4.** Percentage of cumulative oil recovery versus volume of fluid injected and flooding stage: (a) Baseline # 1.1 and

injection step is presented in **Figure 5** for the baseline polymer and SAP-AP1 system.

expected in unconsolidated and/or high permeability porous media [37, 42].

**4. Heavy oil recovery**

232 Cyclodextrin - A Versatile Ingredient

effective separation of water from the produced oil.

SAP-AP1 # 1.2 and (b) Baseline # 2.1 and SAP-AP1 # 2.2.

During waterflooding of heavy oil, "the adverse mobility ratio between the viscous oil and the water induces high-water-cut production and poor sweep efficiency" [2]. Polymer flooding decreases the mobility of the injected water (i.e., augmented water viscosity) reducing the watercut production levels. **Figure 6** presents the water/oil ratio (WOR) as a function of volume of fluid injected and the flooding stage for the baseline polymer and the SAP-AP1 system tests.

**Figure 6** indicates that the average WOR at the end of the initial waterflooding stage for the displacement tests was about 10. As soon as the polymer flooding stage (i.e., baseline polymer AP1 and/or SAP-AP1 system) was initiated, WOR continuously decreased as the volume of polymer injection increased, reaching a minimum WOR value at the end of the polymer flooding stage. The WOR curves in **Figure 6** show that the SAP-AP1 system was more efficient in reducing and controlling the water-oil ratio by providing a faster response and lower average

Overall, the SAP-AP1 system offers the potential for increasing heavy oil recovery at eco-

Supramolecular Polymer-Surfactant System for Heavy Oil Recovery

http://dx.doi.org/10.5772/intechopen.75368

235

We thank Nayef Alayad (Chemical Engineering Department, University of New Brunswick) for helping with the sand-pack displacement tests. We gratefully acknowledge Sasol Chemicals, SNF Floerger, Husky Energy Inc., and Corridor Resources Inc. for providing samples of surfactant, polymer, heavy oil, and natural condensate employed in this study. Financial support from the University of New Brunswick through the Sabbatical Research Grant and the Canada

Foundation for Innovation, CFI, research grant is greatly appreciated.

Chemical Engineering Department, University of New Brunswick, Fredericton,

[1] Perttamo EK. Characterization of Associating Polymer (AP) Solutions. Influences on flow behavior by the degree of hydrophobicity and salinity [thesis]. The University of

[2] Delamaide E, Zaitoun A, Renard G, Tabary R. Pelican Lake field: First successful application of polymer flooding in a heavy-oil reservoir. SPE Reservoir Evaluation & Engi-

[3] Kang PS, Lim JS, Huh C. A novel approach in estimating shear-thinning rheology of HPAM and AMPS polymers for enhanced oil recovery using artificial neural network. In: The Twenty-third International Offshore and Polar Engineering Conference; Jun

[4] Koh H, Lee VB, Pope GA. Experimental investigation of the effect of polymers on residual oil saturation. Society of Petroleum Engineers. February 1, 2018. pp. 1-17. DOI:

[5] Li K, Sun W, Li F, Qu Y, Yang Y. Novel method for characterizing single-phase polymer

[6] Seright RS. How much polymer should be injected during a polymer flood? Review of

30-Jul 5, 2013; Anchorage, Alaska: ISOPE-I-13-171; 2013. pp. 81-85

previous and current practices. SPE Journal. 2017;**22**(01):1-8

nomically favorable conditions.

**Acknowledgements**

**Author details**

New Brunswick, Canada

Bergen; 2013

neering. 2014;**17**(03):340-354

10.2118/179683-PA

flooding. SPE Journal. 2014;**19**(04):695-702

**References**

Laura Romero-Zerón\* and Xingzhi Jiang

\*Address all correspondence to: laurarz@unb.ca

**Figure 6.** WOR versus volume of fluid injected and flooding stage: (a) Baseline # 1.1 and SAP-AP1 # 1.2 and (b) Baseline # 2.1 and SAP-AP1 # 2.2.

WOR value of 1.9. Whereas, the baseline AP1 polymer rendered a minimum average WOR value of 3.9 at the end of the polymer flooding stage. The WOR curves also show that immediately after the post-polymer waterflooding stage was initiated, an abrupt increase of the water to oil ratio took place that continued until the end of the post-polymer waterflooding stage. As explained by Seright "once brine injection [post-polymer flooding] begins, viscous fingering and [porous media] heterogeneities will quickly lead to severe channeling" [of the water to the production end] [6]. These results demonstrate that the optimum SAP-AP1 system offers superior mobility control functionality relative to the baseline AP1 polymer. The structural strength of the SAP-AP1 system is more effective in generating a stable viscous displacement that promotes a more efficient volumetric heavy oil sweep, a faster WOR reduction, and accelerated heavy oil recovery.
