The S reservoir is a typical Middle Eastern carbonate formation characterized by a formation temperature of 89 °C, salinity of 200,000 mg/L, and permeability below 1 mD. It exhibits low and continuously declining formation pressure and single-well productivity, making water flooding inefficient. Therefore, it is essential to evaluate the feasibility of gas injection to supplement reservoir energy and provide a theoretical basis for selecting suitable injection media and parameters for field development. To address these challenges, a high-temperature and high-pressure NMR online gas displacement and long-core flooding experimental system was established. Gas expansion, minimum miscibility pressure, and dynamic core displacement experiments were conducted and integrated with numerical simulations to examine the effects of gas type, injection timing, and injection rate on microscopic displacement behavior, recovery efficiency, and flow characteristics in ultra-low-permeability carbonate reservoirs. The results indicate that, in such tight formations, macroscopic flow follows non-Darcy behavior with a distinct threshold pressure gradient, while microscopically, gas diffusion from larger pores into smaller throats promotes oil displacement. The coupling between molecular diffusion and the threshold pressure gradient jointly governs ultimate recovery efficiency, providing new insights into gas injection mechanisms in ultra-low-permeability carbonate reservoirs. Experimental findings further demonstrate that crude oil in the S reservoir exhibits a large saturation pressure difference and low viscosity. Gas injection enhances the elastic expansion capacity of crude oil by 13.68%–19.54% and reduces its viscosity by 8.08%–12.23%. Under the current formation pressure (34.45 MPa), CO 2 and hydrocarbon gas achieve miscible flooding, whereas N 2 remains immiscible. Miscible flooding improves small-pore oil utilization by approximately 20%, and considering both miscibility and displacement efficiency, hydrocarbon gas is recommended as the preferred injection medium. Compared with N 2 immiscible flooding, hydrocarbon gas—under pulse or continuous injection—achieves more than 50% recovery. The optimal conditions for miscible flooding include an injection rate of 0.0811–0.0908 m/d, injection pressure above the MMP, and an injection–production ratio of 1:1, resulting in a maximum recovery efficiency of up to 76%. This study establishes both a theoretical and experimental foundation for optimizing gas injection in ultra-low-permeability carbonate reservoirs and demonstrates practical relevance by improving gas–oil mobility control, reducing emulsion stability, and enhancing separation efficiency during surface fluid processing.
Wang et al. (Sun,) studied this question.