Adaptability Evaluation of Combined Secondary and Tertiary CO2 Gravity-Stabilized Flooding in Tight Oil Reservoirs

Abstract Tight oil reservoirs are characterized by significant pore-throat heterogeneity, strong reservoir heterogeneity, and poor water injectivity, which substantially constrain the recovery efficiency of conventional waterflooding. The combined approach of secondary fine waterflooding and CO2 gravity-stabilized flooding can effectively expand the swept volume, improve fluid flow conditions, and further enhance oil recovery. However, existing adaptability evaluation methods predominantly rely on single experimental or simulation techniques, often resulting in deviations from actual field performance. To address this limitation, this study proposes a comprehensive adaptability evaluation methodology for combined secondary and tertiary CO2 gravity-stabilized flooding in tight oil reservoirs. A comprehensive dynamic analysis was conducted to assess the performance of secondary fine waterflooding, optimize well patterns and well spacing, and identify the potential distribution of remaining oil. Physical experiments of CO2 gravity-stabilized flooding were subsequently performed to reveal the effects of CO2 on fluid properties and the mechanisms of enhanced oil recovery. Based on these findings, an adaptability evaluation index system was established, considering reservoir properties, reservoir conditions, fluid properties, and development parameters. The index weights were determined using the Analytic Hierarchy Process (AHP). The proposed method was applied to a typical block in the Changqing W tight oil reservoir in China. The comprehensive adaptability evaluation coefficient was calculated, and the target reservoir was classified as suitable for CO2 gravity-stabilized flooding. Numerical reservoir simulations were further conducted to optimize key development parameters. The results suggest that the optimal conversion timing to CO2 gravity-stabilized flooding is when the water cut reaches 60%–70%. Continuous CO2 injection is recommended, with an injection rate of approximately 20000 m3/d and an injection-production ratio of approximately 1.5. Based on the evaluation results, a development plan was formulated and implemented in the field. After three years of application, cumulative incremental oil production reached 642000 tons, and the staged recovery factor increased by 11 percentage points, validating the applicability and engineering significance of the proposed method. This study establishes a scientific and systematic adaptability evaluation approach that can provide technical support and theoretical guidance for enhancing oil recovery and improving the efficiency of tight oil reservoir development.