Numerical Simulation of Enhanced Oil Recovery Using a Gum Arabic Polymer

Numerical Simulation of Enhanced Oil Recovery Using a Gum Arabic Polymer.

ABSTRACT

Oil reserves are now located in hard-to-reach locations. This, combined with low oil prices, makes drilling for new reserves very expensive and risky. Enhanced oil recovery, which increases the amount of oil that can be recovered from a reservoir, should therefore be considered.

This work uses numerical simulation to determine the suitability of gum arabic as a polymer for EOR operations. This was done by matching core-flooding experiments using Eclipse.

Simulation gave a waterflooding oil recovery match of 53 % compared to the experimental recovery of 55 % while alkali-surfactant- polymer flooding gave an oil recovery match of 80.53 % compared to the experimental recovery of 82 %.

Extrapolating from core to field simulation, the ASP slug formulated increased total field oil production by increasing recovery from 62.48 %, at the end of the waterflooding, to 85.8 %. This demonstrates the potential of gum arabic for EOR operations.

INTRODUCTION

The average recovery factor using conventional primary and secondary production techniques to the economic limit is about 33 % (Gabriel, 1979; Wardlaw, 1996).

This implies that more than 60 % of oil is not recovered either because it is bypassed by the injected water, or it is too viscous to be displaced by the water.

Kevin and Raymond (1999) noted that recovery depended on a number of factors that include: the nature of crude oil, reservoir properties, existing technology and the prevailing economic climate. Water injection resuscitates the pressure of a depleted reservoir and displaces the oil.

However, due to its high mobility, water (which is less viscous than oil) tends to evade large volumes of the oil and breaks through to the producing well before adequately sweeping the reservoir (Green & Willhite, 1998).

This challenging characteristic of waterflooding eventually results in only part of the reservoir being exposed to the water for a realistic amount of time and to the injection scheme.

In addition, reservoir heterogeneity aggravates the injected water’s tendency to mobilize only the oil in regions with high permeability, which leads to an early breakthrough in that region (Green & Willhite, 1998).

REFERENCES 

Al Sofi, A. M., Liu, J. S., & Han, M. (2013). Numerical simulation of surfactant–polymer core flooding experiments for carbonates. J. Pet. Sci. Eng. 111:184–196

Ansarizadeh, M., Mary, P., & Strong, J. (2012). Alkaline surfactant polymer flooding to revitalize oil production from a mature water flooded field. SPE 155541-MS, SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, April 16–18

Arihara, N., Yoneyama, T., Akita, Y., & Xiang Guo, L. (1999). Oil Recovery Mechanisms of Alkali-Surfactant-Polymer Flooding. Society of Petroleum Engineers.

Avwioroko, J. E., Taiwo, O. A., Mohammed, I. U., Dala, J. A., & Olafuyi, O. A. A Laboratory Study of ASP Flooding on Mixed Wettability for Heavy Oil Recovery Using Gum Arabic as a Polymer. SPE 172401, Presented at SPE-NAICE, Annual Meeting, Lagos, August 5-7, 2014

Brooks, R. H. & Corey, A. T. (1964). Hydraulic Properties of Porous Media. Hydrology Papers, No. 3, Colorado State U., Fort Collins, Colorado.

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