Optimization of control parameters in alkaline-surfactant-polymer (ASP) flooding for enhanced oil recovery: a simulation approach

This study explores the application of Alkaline-Surfactant-Polymer (ASP) flooding in “Reservoir-S,” a relatively new and small reservoir located in the Upper Assam Basin. With five years of production history and an estimated Stock Tank Oil Initially in Place (STOIIP) of 1.946 MMsm³, “Reservoir-S” exhibits a recovery factor of approximately 8.2% at End of History (EOH, i.e., September 2022). The objective of this research is to develop an optimal ASP flooding strategy to enhance the recovery factor through reservoir simulation. The three-dimensional (3D) reservoir model utilized for this study incorporates monthly time stepping and grid dimensions of 50 m x 50 m x 0.5 m, employing the Eclipse black oil simulator for sensitivity analyses. This analysis compares the incremental recovery factor of ASP flooding against traditional primary and secondary recovery strategies. The primary production strategy includes four existing producers plus two additional wells, while the secondary strategy adds three water injection wells alongside the existing producers. A total of 250 sensitivity simulations were conducted to determine the optimal parameters for ASP flooding, including injection rates, and concentrations of alkali, surfactant, and polymer, as well as the duration of the ASP slug injection. Sensitivity analysis was performed over a broad range of concentrations: alkali (1–64 kg/m³), polymer (0.4–2.8 kg/m³), and surfactant (1–5 kg/m³), with injection spans varying from 2 to 16 years and injection rates ranging from 50 to 400 sm³/day. The results indicated that the optimal ASP flooding parameters are a polymer concentration of 0.8 kg/m³, a surfactant concentration of 2 kg/m³, and an alkali concentration of 27 kg/m³. The optimal ASP slug injection span was determined to be 8 years, followed by 8 years of chase water injection at a rate of 250 sm³/day per well. Implementing this ASP strategy increased the recovery factor by 0.72% by April 2040, the end of the prediction period, compared to the secondary production strategy, which achieved a recovery factor of 27%. Further sensitivity analysis was conducted to assess the impact of the optimal ASP recipe with and without new infill producer wells. The results showed minimal deviation in recovery factors, indicating that the ASP strategy’s effectiveness is robust even without additional drilling. This scenario highlights substantial cost savings in capital expenditure, as the implementation of the optimal ASP strategy without drilling new infill wells can significantly reduce drilling costs.