The phase behavior of hydrocarbons in liquid-rich shale formations deviates from their bulk phase behavior due to the nanoconfinement effects in the extensive nanopores of shale rocks. While the phase behavior in nanopores has been widely investigated, the macroscopic phase behavior in the complex nanopore networks of shale rocks remains poorly understood. To address this critical problem, we have recently developed a novel pore-network-based upscaling framework that allows for deriving the macroscopic phase behavior for shale rocks accounting for size- and geometry-dependent nanoconfinement effects (Chen et al., 2021). Here, we apply the pore-network-based upscaling framework to examine the influences of pore geometry and heterogeneous surface wettability on the macroscopic phase behavior using three example nanopore networks. The results show that pore geometry and heterogeneous surface wettability have a relatively minor impact on the macroscopic phase behavior, and (as reported in our prior study) pore size distribution is the primary controlling factor. Conversely, pore geometry and heterogeneous surface wettability are shown to significantly modify the spatial distribution of fluid phases and components in the nanopore networks, which further modifies the two-phase constitutive relationships (e.g., capillary pressure saturation curve and relative permeability saturation curve).
Phase behavior plays an important role in hydrocarbon recovery from reservoirs, especially liquid-rich shale reservoirs. In liquid-rich shale reservoirs, the rocks oftentimes contain extensive nanometer-scale pore spaces, within which the phase behavior deviates from the bulk behavior. Such deviation appears to result from the so-called nanoconfinement effects—including large pressure difference across the fluid-fluid interfaces (i.e., capillary pressure) and strong interaction between hydrocarbon molecules and the pore wall (i.e., fluid-wall interaction) as demonstrated by nanofluidic experiments and molecular-level simulations (Luo et al., 2015, Barsotti et al., 2016, Jin and Firoozabadi, 2016, Zhong et al., 2018, Liu and Zhang, 2019). To date, such experimental insights and molecular-level understandings are challenging to be directly incorporated into reservoir-scale simulations. In the reservoir-scale simulators, the phase behavior is simulated using the so-called phase equilibrium model. The model assumes thermodynamic equilibrium between different fluid phases—i.e., the chemical potential or fugacity is equal among all phases for any prescribed temperature and pressure—such that mathematical formulations can be derived and solved to quantify the phase behavior (Michelsen, 1982a, 1982b). While the standard phase equilibrium model—assuming equal pressure among different fluid phases and no fluid-wall interaction—can successfully simulate the bulk phase behavior, it failed to predict the phase behavior in nanopores.
