Combined experimental, theoretical and molecular simulation approach for the description of the fluid phase behavior of hydrocarbon mixtures within shale rocks

An experimental, theoretical, and molecular simulation consolidated framework for the efficient characterization of the adsorption and fluid-phase behavior of multi-component hydrocarbon mixtures within tight shale rocks is presented. Fluid molecules are described by means of a top-down coarse-grained model where simple Mie intermolecular potentials are parametrized by means of the statistical associating fluid theory. A four-component (methane, pentane, decane, naphthalene) mixture is used as a surrogate model with a composition representative of commonly encountered shale oils. Shales are modeled as a hierarchical network of nanoporous slits in contact with a mesoporous region. The rock model is informed by the characterization of four distinct and representative shale core samples through nitrogen adsorption, thermogravimetric analysis, and contact angle measurements. Experimental results suggest the consideration of two types of pore surfaces: a carbonaceous wall representing the kerogen regions of a shale rock, and an oxygenated wall representing the clay-based porosity. Molecular dynamics simulations are performed at constant overall compositions at a temperature of 398.15 K (257 °F) and explore pressures from 6.9 MPa up to 69 MPa (1000-10000 psi). Simulations reveal that it is the organic nanopores of 1 and 2 nm that preferentially adsorb the heavier components, while the oxygenated counterparts show little selectivity between the adsorbed and free fluid. Upon desorption, this trend is intensified, as the fluid phase in equilibrium with a carbon nanopore becomes increasing leaner (richer in light components) and almost completely depleted of the heavy components which remain trapped in the nanopores and surfaces of the mesopores. Oxygenated pores do not contribute to this unusual behavior, even for the very tight pores considered. The results presented elucidate the relative importance of considering both the pore size distribution and the heterogeneous nature of the confining surfaces when theoretically describing adsorption and transport of oil through shale rocks, and they provide a plausible explanation for the abnormal continuous leaning of shale gases seen during field production.