A Framework for Incorporating Nanopores in Compositional Simulation to Model the Unusually High GOR Observed in Shale Reservoirs

Abstract

Abstract The fluid phase behavior in shale reservoirs differs from the conventional fluid phase behavior because of the nanopores in shale rock. In many shale oil reservoirs, the producing gas-oil ratio (GOR) is significantly higher than what would be produced from a bulk-state conventional reservoir. The phase behavior alteration in nanopores arises from the fluid-pore wall interaction within the nano-scale confining geometry. Recently, many approaches have been developed to thermodynamically model the fluid phase behavior in nanopores. An adequate and efficient method to incorporate the nano-confined phase behavior in engineering practice is highly desired. In this work, we present a practical framework to incorporate the nanopores in compositional simulation for shale reservoirs. This approach enables engineers to incorporate the macro- to nano-scale phase equilibria from a pore-size-dependent equation of state into current compositional simulators, which use cubic equation of state. The procedures include bulk fluid characterization, simulation of multi-scale confined depletion by a pore-size-dependent equation of state, re-training the cubic equation of state, tuning relative permeability and applying in composition simulation. The simulation predicts higher GOR with nanopores, in agreement with the higher-than-normal GOR observed with shale oil wells, and the GOR fluctuations are found in association with various reservoir drainage areas. The simulated production behavior gives mechanistic insight into the effect of nano-confinement fluid behavior on shale reservoir depletions.