Research Papers: Petroleum Engineering

Core-Based Evaluation of Associative Polymers as Enhanced Oil Recovery Agents in Oil-Wet Formations

[+] Author and Article Information
Reza Askarinezhad

Department of Petroleum Engineering,
University of Stavanger (UiS),
Stavanger N-4036, Norway
e-mail: r.askarinezhad@gmail.com

Dimitrios Georgios Hatzignatiou

Department of Petroleum Engineering,
University of Houston (UH),
5000 Gulf Freeway, Energy Research Park,
Building 9, Room 217,
Houston, TX 77204-0945
e-mail: dghatzignatiou@uh.edu

Arne Stavland

International Research Institute of
Stavanger (IRIS),
Prof. Olav Hanssensvei 15,
Stavanger N-4021, Norway
e-mail: arne.stavland@iris.no

1Corresponding author.

Contributed by the Petroleum Division of ASME for publication in the JOURNAL OF ENERGY RESOURCES TECHNOLOGY. Manuscript received August 7, 2017; final manuscript received December 1, 2017; published online January 31, 2018. Assoc. Editor: Mohamed A. Habib.

J. Energy Resour. Technol 140(3), 032915 (Jan 31, 2018) (9 pages) Paper No: JERT-17-1418; doi: 10.1115/1.4038848 History: Received August 07, 2017; Revised December 01, 2017

Linear coreflood experiments are performed at 60 °C to test the effectiveness of a low molecular weight associative polymer as a displacing agent, and its ability to enhance oil recovery on chemically treated oil-wet Berea cores. Polymer injection tests revealed high mobility reductions (resistance factor (RF)) and reduced remaining oil saturations. Results obtained suggest that the incremental oil production is due to the high mobility reduction, as reported previously for water-wet porous media. The reduced remaining oil saturation is a function of the injected associative polymer treatment volume. Polymer mobility reduction is highly affected by the injected polymer velocity; this reduction is observed to be more significant at the lower velocity spectrum. Therefore, the established incremental oil production, even at reduced polymer injection rates (lower capillary numbers), could be explained by the increased mobility reduction. A correlation for the velocity-dependent mobility reduction is developed. Results are in agreement with previously reported ones in water-wet media and related to the enhanced oil recovery (EOR) nature of the injected associative polymer as opposed to the traditional mobility control of other polymer types. During injection, a column of oil-polymer emulsion is formed gradually in the separator causing operational difficulties and introducing produced fluid measurement (and core fluid saturations) uncertainties. Produced oil/water emulsion polymer volume content is used to correct overestimated oil production attributed to measurement uncertainties. Real-time resistivity measurements could also be a valuable tool for both fluids saturation monitoring and improved core fluids saturation evaluation in flooded porous media.

Copyright © 2018 by ASME
Your Session has timed out. Please sign back in to continue.


Sorbie, K. S. , 1991, Polymer-Improved Oil Recovery, Blackie, London. [CrossRef]
Taylor, K. C. , and Nasr-El-Din, H. A. , 1998, “Water-Soluble Hydrophobically Associating Polymers for Improved Oil Recovery: A Literature Review,” J. Pet. Sci. Eng., 19(3–4), pp. 265–280. [CrossRef]
Needham, R. B. , and Doe, P. H. , 1987, “Polymer Flooding Review,” J. Pet. Technol., 39(12), pp. 1503–1507.
Sheng, J. J. , Leonhardt, B. , and Azri, N. , 2015, “Status of Polymer-Flooding Technology,” J. Can. Pet. Technol., 54(2), pp. 116–126.
Reichenbach-Klinke, R. , Stavland, A. , Langlotz, B. , Wenzke, B. , and Brodt, G. , 2013, “New Insights Into the Mechanism of Mobility Reduction by Associative Type Copolymers,” SPE Enhanced Oil Recovery Conference, Kuala Lumpur, Malaysia, July 2–4, SPE Paper No. SPE-165225-MS.
Wever, D. A. Z. , Picchioni, F. , and Broekhuis, A. A. , 2011, “Polymers for Enhanced Oil Recovery: A Paradigm for Structure–Property Relationship in Aqueous Solution,” Prog. Polym. Sci., 36(11), pp. 1558–1628. [CrossRef]
Ahmed, S. , Elraies, K. A. , Tan, I. M. , and Hashmet, M. R. , 2017, “Experimental Investigation of Associative Polymer Performance for CO2 Foam Enhanced Oil Recovery,” J. Pet. Sci. Eng., 157, pp. 971–979. [CrossRef]
Liu, R. , Pu, W. F. , and Du, D. J. , 2017, “Synthesis and Characterization of Core–Shell Associative Polymer That Prepared by Oilfield Formation Water for Chemical Flooding,” J. Ind. Eng. Chem., 46, pp. 80–90. [CrossRef]
Reichenbach-Klinke, R. , Stavland, A. , Strand, D. , Langlotz, B. , and Brodt, G. , 2016, “Can Associative Polymers Reduce the Residual Oil Saturation?,” SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, Mar. 21–23, SPE Paper No. SPE-179801-MS.
Zhong, C. , Luo, P. , Ye, Z. , and Chen, H. , 2009, “Characterization and Solution Properties of a Novel Water-Soluble Terpolymer for Enhanced Oil Recovery,” Polym. Bull., 62(1), pp. 79–89. [CrossRef]
Tan, H. , Tam, K. C. , and Jenkins, R. D. , 2001, “Network Structure of a Model HASE Polymer in Semidilute Salt Solutions,” J. Appl. Polym. Sci., 79(8), pp. 1486–1496. [CrossRef]
Hwang, F. S. , and Hogenesch, T. E. , 1993, “Fluorocarbon-Modified Water-Soluble Cellulose Derivatives,” Macromolecules, 26(12), pp. 3156–3160. [CrossRef]
Zhang, R. , Ye, Z. , Peng, L. , Qin, N. , Shu, Z. , and Luo, P. , 2013, “The Shearing Effect on Hydrophobically Associative Water-Soluble Polymer and Partially Hydrolyzed Polyacrylamide Passing Through Wellbore Simulation Device,” J. Appl. Polym. Sci., 127(1), pp. 682–689. [CrossRef]
Alexis, D. , Varadarajan, D. , Kim, D. H. , Winslow, G. , and Malik, T. , 2016, “Evaluation of Innovative Associative Polymers for Low Concentration Polymer Flooding,” SPE Improved Oil Recovery Conference, Tulsa, OK, Apr. 11–13, SPE Paper No. SPE-179696-MS.
Maia, A. M. S. , Borsali, R. , and Balaban, R. C. , 2009, “Comparison Between a Polyacrylamide and a Hydrophobically Modified Polyacrylamide Flood in a Sandstone Core,” Mater. Sci. Eng. C, 29(2), pp. 505–509. [CrossRef]
Askarinezhad, R. , Hatzignatiou, D. G. , and Stavland, A. , 2017, “Associative Polymers as Enhanced Oil Recovery Agents in Oil-Wet Formations: A Laboratory Approach,” 19th European Symposium on Improved Oil Recovery, Stavanger, Norway, Apr. 24–27. http://earthdoc.eage.org/publication/publicationdetails/?publication=87924
Askarinezhad, R. , Hatzignatiou, D. G. , and Stavland, A. , 2017, “Disproportionate Permeability Reduction of Water-Soluble Silicate Gelants—Importance of Formation Wettability,” SPE Prod. Oper., 32(3), pp. 362–373. [CrossRef]
Abeysinghe, K. P. , 2013, “A Novel Approach to Surfactant Flooding Under Mixed-Wet Conditions,” Ph.D. thesis, University of Stavanger, Stavanger, Norway. https://brage.bibsys.no/xmlui/handle/11250/183701
Virnovsky, G. A. , Vatne, K. O. , Skjaeveland, S. M. , and Lohne, A. , 1998, “Implementation of Multirate Technique to Measure Relative Permeabilities Accounting,” SPE Annual Technical Conference and Exhibition, New Orleans, LA, Sept. 27–30, SPE Paper No. SPE-49321-MS.
Anderson, W. G. , 1986, “Wettability Literature Survey—Part 3: The Effects of Wettability on the Electrical Properties of Porous Media,” SPE J. Pet. Technol., 38(12), pp. 1371–1378. [CrossRef]
Archie, G. E. , 1942, “The Electrical Resistivity Log as an Aid in Determining Some Reservoir Characteristics,” Trans. AIME, 146(1), pp. 54–62. [CrossRef]
Hilchie, D. W. , 1984, “A New Water Resistivity Versus Temperature Equation,” Ninth International Formation Evaluation Symposium, Paris, France, Oct. 24–26, No. SPWLA-1984-vXXVn4a3.


Grahic Jump Location
Fig. 3

Schematic diagram of the two-phase steady-state relative permeability measurement setup

Grahic Jump Location
Fig. 2

Contact angle (water/oil) at room temperature

Grahic Jump Location
Fig. 1

Air/water contact angle on wettability altered Berea core samples

Grahic Jump Location
Fig. 4

Two-phase water/oil relative permeability in a chemically treated oil-wet Berea

Grahic Jump Location
Fig. 5

Pressure gradient and the water saturation during water and polymer injection

Grahic Jump Location
Fig. 6

Polymer flooding on oil-wet Berea core sample at waterflood-residual-oil saturation (Sorw) condition—Pressure gradient, RF, and electrical resistivity index (RI) during polymer flooding

Grahic Jump Location
Fig. 7

Oil recovery factor versus injected water phase (water/polymer) during water and polymer flooding. Water flooding was initiated at 99.2% water cut with a remaining oil saturation of So = 0.33 [16].

Grahic Jump Location
Fig. 8

Mobility reduction as function of polymer-flow shear rate

Grahic Jump Location
Fig. 9

Multirate test on waterflood in oil-wet and oil-flood in water-wet media; normalized residual wetting-phase saturation as a function of capillary number Nc

Grahic Jump Location
Fig. 11

Saturation adjustments, measured RI during polymer injection and the equivalent calculated RI based on brine-oil model

Grahic Jump Location
Fig. 10

Saturation adjustments using real-time electrical resistivity measurements

Grahic Jump Location
Fig. 12

Overlap of brine and polymer laboratory-bulk-resistivity data measured at different temperatures—computed extended data at higher temperatures show the same behavior

Grahic Jump Location
Fig. 13

Core-sample temperature ramp prediction using real-time electrical resistivity data



Some tools below are only available to our subscribers or users with an online account.

Related Content

Customize your page view by dragging and repositioning the boxes below.

Related Journal Articles
Related eBook Content
Topic Collections

Sorry! You do not have access to this content. For assistance or to subscribe, please contact us:

  • TELEPHONE: 1-800-843-2763 (Toll-free in the USA)
  • EMAIL: asmedigitalcollection@asme.org
Sign In