Numerical simulation study on miscible EOR techniques for improving oil recovery in shale oil reservoirs

• Main Authors: Dheiaa Alfarge, Mingzhen Wei, Baojun Bai
• Format: Article
• Language: English
• Published: SpringerOpen 2017-08-01
• Series: Journal of Petroleum Exploration and Production Technology
• Subjects: CO2-EOR in unconventional reservoirs; Miscible gases EOR techniques in shale oil plays; Comparitive study on miscible gases EOR techniques; CO2-EOR huff-n-puff operations; Unconventional EOR techniques; Natural gases based EOR techniques in shale reservoirs
• Online Access: http://link.springer.com/article/10.1007/s13202-017-0382-7

Abstract Shale formations in North America such as Bakken, Niobrara, and Eagle Ford have huge oil in place, 100–900 billion barrels of oil in Bakken only. However, the predicted primary recovery is still below 10%. Therefore, seeking for techniques to enhance oil recovery in these complex plays is inevitable. Although most of the previous studies in this area recommended that CO2 would be the best EOR technique to improve oil recovery in these formations, pilot tests showed that natural gases performance clearly exceeds CO2 performance in the field scale. In this paper, two different approaches have been integrated to investigate the feasibility of three different miscible gases which are CO2, lean gases, and rich gases. Firstly, numerical simulation methods of compositional models have been incorporated with local grid refinement of hydraulic fractures to mimic the performance of these miscible gases in shale reservoirs conditions. Implementation of a molecular diffusion model in the LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) model has been also conducted. Secondly, different molar-diffusivity rates for miscible gases have been simulated to find the diffusivity level in the field scale by matching the performance for some EOR pilot tests which were conducted in Bakken formation of North Dakota, Montana, and South Saskatchewan. The simulated shale reservoirs scenarios confirmed that diffusion is the dominated flow among all flow regimes in these unconventional formations. Furthermore, the incremental oil recovery due to lean gases, rich gases, and CO2 gas injection confirms the predicted flow regime. The effect of diffusion implementation has been verified with both of single porosity and dual-permeability model cases. However, some of CO2 pilot tests showed a good match with the simulated cases which have low molar-diffusivity between the injected CO2 and the formation oil. Accordingly, the rich and lean gases have shown a better performance to enhance oil recovery in these tight formations. However, rich gases need long soaking periods, and lean gases need large volumes to be injected for more successful results. Furthermore, the number of huff-n-puff cycles has a little effect on the all injected gases performance; however, the soaking period has a significant effect. This research project demonstrated how to select the best type of miscible gases to enhance oil recovery in unconventional reservoirs according to the field-candidate conditions and operating parameters. Finally, the reasons beyond the success of natural gases and failure of CO2 in the pilot tests have been physically and numerically discussed.