In shale gas-condensate reservoirs, when the initial reservoir pressure is greater than the dewpoint pressure, the condensate/gas ratio (CGR) has been observed to decrease continuously as the pressure drops to less than the initial reservoir pressure. This abnormal behavior cannot be explained with conventional pressure/volume/temperature (PVT) models that ignore the presence of nanopores in shale rock. Herein, for the first time, we present a study that provides a physical explanation for the observed CGR trends by including the effect of nanopores on the fluid phase behavior and depletion of shale gas-condensate reservoirs. Our model uses multiscale PVT simulation by means of a pore-size-dependent equation of state (EOS). Two lean gas-condensate cases (shallow and deep reservoirs) are investigated. The simulation results show that hydrocarbons distribute heterogeneously with respect to pore size on the nanoscale. There are more intermediate to heavy hydrocarbons (C3–11+) but fewer light ends (C1–2) distributed in the nanopores than in the bulk region. At the end of depletion, because of confinement effects, large amounts of intermediate hydrocarbons are trapped in the nanopores, causing condensate recovery loss. Multiscale depletion simulations suggest that a decreasing CGR can occur at the beginning of production when the reservoir pressure is higher than the dewpoint pressure. Such behavior is caused by the nanopore depletion in the shale matrix, which is a process of selectively releasing light hydrocarbon components. We also present a novel approach to model the nonequilibrium fluid distribution between the fracture and nanopores using a simple local-equilibrium concept. Our results indicate that the nonequilibrium fluid distribution increases the CGR drop because of the compositional selectivity of the nanopore in favor of intermediate and heavy hydrocarbons.
NOTE: This paper is published as part of the 2021 SPE Reservoir Simulation Conference Special Issue.