Phase behavior analysis of multi-component hydrocarbon in shale reservoir multi-scale pore systems using a modified Gibbs ensemble Monte Carlo molecular simulation

Shale resources have been crucial in the production of oil and gas. Over the past few years, the extraction of tight oil and gas has emerged as a major energy source. Shale reservoirs are complex, and understanding hydrocarbon phase behavior is essential for reserve estimation, reservoir simulation, production forecasting, and enhanced oil recovery. In this work, we build a multi-scale system using molecular simulation incorporating nano-scale pores with macro-scale pores to investigate the confinement effect on the phase behavior of reservoir fluids in shale rocks. Comparing with traditional single-scale models, the multi-scale model better mimics the feature (macropores + nanopores) of shale rocks. We simulate the constant composition expansion (CCE) experiment for multi-component hydrocarbon mixtures using the Gibbs ensemble Monte Carlo at imposed pressures (NPT-GEMC) technique to quantify the confinement effect on the saturation pressure and composition alterations of fluids in confined and bulk regions of the multi-scale systems. Our results indicate that due to adsorption in nanopores, there is a notable difference between the compositions of fluids in the bulk region and those in the confined region of the system. For the bubble-point pressure calculations of a methane-ethane binary mixture fluid, the first bubble in the bulk region appears at a higher pressure comparing to the bubble-point pressure of the same initial reservoir fluid in a conventional reservoir. The bubble-point pressure of the methane-ethane mixture increased by 5.8–12.4 % depending on confined volume fraction. For the dew-point pressure calculation of an Eagle Ford gas condensate reservoir fluid, there may exist a reservoir fluid type shift, which can lead to a disappearance of the saturation pressure due to progressive shrinkage of the two-phase envelope.