Confined fluid interfacial tension and minimum miscibility pressure prediction in shale nanopores

CO2 miscible flooding is considered to be a cost-effective and efficient method for improving shale oil recovery. The minimum miscibility pressure (MMP) between CO2 and shale oil in nanopores is a crucial parameter for assessing the viability of miscible flooding. Experimental methods are often inadequate for capturing phase transition behaviors at the nanoscale. Therefore, it is essential to establish a comprehensive theoretical model to explore the phase behavior and miscibility of fluids confined in nanopores. Besides, the real shale formations have highly heterogeneous pore spaces, where the effect of pore size distribution on the MMP prediction should be properly addressed. In this research, a thermodynamic model that accounts for the nano-confinement effect is proposed to describe the interfacial tensions (IFTs) and MMPs profiles based on the vanishing interfacial tension (VIT) method. Firstly, a modified Peng-Robinson equation of state (PR-EOS) was employed for the vapor–liquid equilibrium (VLE) calculations at the nanopores by considering the capillary pressure effect and critical properties shift. Secondly, the model validation and the effect of temperature, pore radius, alkane type, and injected gas components on IFTs and MMPs were launched to analyze the nano-confinement effect. Finally, the model was applied to real shale oil to explore how pore size distribution affected the MMP in nanopores. The simulation results show that IFTs and MMPs calculated by the proposed model match very well with the experimental and molecular dynamic simulation (MD) results. The critical properties shift is the main cause for IFT and MMP reduction compared with capillary pressure. The MMPs of CO2-alkanes initially increase and then decrease with increasing temperature in nanopores. The IFTs and MMPs increase with pore radius, carbon number of alkanes. However, the IFTs and MMPs become less sensitive to pore size when the pore radius exceeds 15 nm. Higher C2H6 & C3H8 mole fractions decrease the MMP of confined fluids, while higher CH4 mole fraction increases MMP. The MMPs calculated by considering the pore size distribution are lower than those calculated using the average pore radius. Therefore, the mixing rule should be considered when the pore size distribution is provided. We hope this model can give a more precise depiction of fluid phase behaviors in shale reservoirs, thereby facilitating the development of shale oil.