Video: Robustness of Novel Low-Tension Gas LTG Floods in High Salinity and High Temperature Reservoirs
- Nhat Nguyen (The University of Texas at Austin) | Guangwei Ren (TOTAL E&P R&T, USA) | Khalid Mateen (TOTAL E&P R&T, USA) | Kun Ma (TOTAL E&P R&T, USA) | Haishan Luo (TOTAL E&P R&T, USA) | Valerie Neillo (TOTAL SA) | Quoc Nguyen (The University of Texas at Austin)
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- Society of Petroleum Engineers
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- 2019. Copyright is retained by the author. This presentation is distributed by SPE with the permission of the author. Contact the author for permission to use material from this video.
- Low-Tension Gas, variable permeability and injection rate, high salinity and temperature, Robustness, Foam and microemulsion
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Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.