Optimization of surfactant-polymer flooding for enhanced oil recovery

Chemical enhanced oil recovery applications continue to face a variety of obstacles, particularly in high saline and high-temperature reservoirs, in addition to high chemical prices. This issue creates difficulty in developing optimal recipes that can withstand these extreme circumstances and so achieve maximal hydrocarbon recovery at the lowest feasible cost. The usefulness of surfactant polymer (SP) in mobilizing oil and increasing sweep efficiency in carbonate rocks is assessed in this article. A thermo-viscosifying polymer and an acrylamido tertiary butyl sulfonate (ATBS)/acrylamide (AM) copolymer were employed. Surfactants of various grades of amphoteric carboxybetain are used. These potential chemicals were chosen after a thorough study of previous research, which included long-term thermal stability, fluid rheology, interfacial tension, adsorption, and microfluidic tests. The contact angles were measured using a captive drop analyzer at high pressure and high temperature. The core-flooding experiments for slug size and injection sequence optimization were carried out using 12-inch long and 1.5-inch diameter limestone cores. For two weeks, the samples were aged. The trials were carried out at 90 degrees C. The seawater (SW) salinity utilized in the injection was 57,000 ppm. The findings highlighted the importance of surfactant-polymer interactions in wettability and fluid rheology. The best chemical combination was carboxybetaine (0.05 wt%) and ATBS/AM (0.25 wt%) which recovered 31.29% of the residual oil saturation (ROS), or 11.63% of the original oil in place (OIIP). The optimal slug size was 3.5 PV, which recovered 34.21% of the ROS and 17.05% of the OIIP. The optimum injection sequence was the co-injection of surfactant and polymer SW-S1P1-SW, which extracted 31.29% of the ROS and 11.63% of the OIIP. The recoveries were discovered to be related to the slug's size. The chemical injection sequence was critical to the eventual oil recovery. Among the other sequences, SW-SP-SW had the highest recovery (SW-P-S-SW, SW-S-SW-P-SW, and SW-P-SW-S-SW). This is thought to be owing to the compounds' synergistic impact. We found that there is no systematic optimization process that combines the effect of chemicals, slug size, and sequence in one study, which gave us the motivation to cover the research gap.

Automated summary

This article evaluates the feasibility of using surfactant polymer (SP) in high saline and high-temperature reservoirs and identifies the optimal chemical combination, slug size, and injection sequence to achieve maximum oil recovery.