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Phase Behavior and Minimum Miscibility Pressure of Confined Fluids in Organic Nanopores


 Phase equilibrium of shale fluid is highly disturbed due to liquid adsorption and capillary pressure in densely-developed organic nanopores. And the miscibility phenomenon between gas and oil is also changed during gas injection for enhanced oil recovery (EOR). Therefore, it is imperative to develop a general framework of theoretical models and algorithm to investigate the effect of pore proximity on phase behavior and miscibility of confined fluids in shale formations.
 In this study, first, an improved vapor/liquid equilibrium (VLE) calculation model is presented to calculate the phase behavior of confined fluids based on our modified Peng-Robinson equation of state (A-PR-EOS) which can reflect the effect of adsorption. The capillary pressure across the interface and the critical property shift of pure component are also taken into account. An improved Young-Laplace equation is utilized to simulate capillarity and the shifted critical properties can be obtained using the A-PR-EOS. Then, a prediction process for the phase behavior of a quaternary mixture (CO2, CH4, n-C4H10, n-C10H22) is performed, and the results are compared against the experimental data from previous literature, yielding an average error of 1.29%. Results indicate that the presence of nanopore confinement could decrease the density difference between the liquid and vapor phase of the quaternary mixture, and thus induce the reduction of interfacial tension (IFT). As pore size becomes smaller, the IFT decreases rapidly, especially when the pore radius (Rp) is less than 20 nm. Furthermore, the vanishing interfacial tension (VIT) algorithm and the modified VLE procedure are applied to determine the minimum miscibility pressure (MMP) of Bakken shale oil with CO2. The MMP is reduced from 20.2 MPa at 50 nm pores to 17.5 MPa at 20 nm pores. Hence, the reduction of pore size leads to a decrease in MMP, i.e. the CO2 and the reservoir fluid could reach miscibility at a lower pressure, which is beneficial for CO2-EOR.
 The proposed model could provide a consistent description of fluid phase behavior over the whole range of pore sizes in the Bakken, and could be applied to guide the development of shale hydrocarbon reservoirs, such as reserves and production estimates.