Fluid phase behavior in multi-scale shale reservoirs with nano-confinement effect

Abstract

Shale reservoirs are featured by widely distributed micro-scale fractures and nano-scale pores. The phase behavior of reservoir fluids in these complex environments remains uncertain. Hence, an efficient model is developed to investigate the fluid phase behavior in multi-scale shale reservoirs based on a pore-size-dependent equation of state. The porous space is discretized into specific sizes of nanopores and fractures regions. Phase equilibrium calculations for pure components, binary mixtures and multi-component shale oils show that adsorption and critical properties shifts display opposite effects on a fluid distribution, and the shifts in the critical properties are the main reason for more lighter components present in nanopores. The nano-confinement effect enhances the ability of CO2 to enter nanopores. An innovative multi-scale model of partial equilibrium is developed to explore changes in fluid properties during pressure depletion. The results reveal that gas appears in the fracture region, while the confined fluids within nanopores are always kept in the oil phase. Lighter components within nanopores are rapidly released as pressure drops. However, the content of heavier components within nanopores gradually decreases if the pressure stabilizes for a while, meaning that a slow pressure drop is more conducive to the recovery of shale oil from nanopores.