Because of commodity pricing, the production from organic rich shales such as Barnett, Woodford, Eagle Ford and Marcellus has shifted significantly away from the dry natural gas window into the more profitable condensate and liquid hydrocarbon (oil) windows. The current production practices, however, are based mainly on field experience of the operators and far from being a methodological approach for an optimized production. This is mainly due to the fact that our understanding of condensation, capillarity and multi-phase flow dynamics in shale reservoirs is at an infancy stage. It is currently not known, for example, if and where the condensation takes place in the reservoir, and what is the impact of the shale matrix on the this phenomenon. In this paper we argue that answering these questions using conventional laboratory measurement techniques is a difficult task because the fluid properties and the phase behavior of the hydrocarbons could be influenced by the nanoporous nature of these rocks.

Monte Carlo simulations are conducted to investigate pure hydrocarbon vapor-liquid coexistence and critical properties under confinement. The results show a pore size dependence of these thermo-physical properties. Phase diagrams generated using ternary (C1, C4, and C8) mixtures under reservoir conditions show a two-phase envelop shift due to pore size dependence. We show the importance of the results performing a shale gas in-place calculation using Ambrose's equation where the equation of state parameters, z-factor, gas formation volume factor, and adsorbed-phase density values are all adjusted for a range of effective pore size. The corrections on the free and the sorbed gas in-place estimates are significant. Furthermore, we predicted reserves from wet gas, condensate, and volatile oil reservoirs using compositional flow simulation. It is shown that the liquid production from nanoporous rocks is enhanced due to a significant decrease in the bubble point and dew point pressures.

URTeC 1624453

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