The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. Currently, the uncertainty in phase behavior is one of the greatest challenges in developing unconventional shale resources. The complex phase behavior is attributed to the broad range of pore sizes in shale. In macro-scale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nano-scale pores, the fluid behavior is significantly altered by confinement effects. The overall phase behavior of fluids in porous media of mixed pore sizes is yet to be understood.

In this paper, we present a multi-scale fluid phase behavior study. A pore-size-dependent equation of state (EOS) is used to describe the fluid by the confining pore diameter. The EOS confinement parameters for fluid-pore wall surface interaction are determined by experimental results from differential scanning calorimetry and isothermal adsorption of species C1~C14. The multi-scale phase equilibria are simulated by directly minimizing the total Helmholtz free energy. A modified Eagle Ford oil is used for the case study. Constant composition expansions (CCE) of dual-scale (bulk and 15 nm) and triple-scale (bulk, 15 nm, and 5 nm) systems are simulated. The first bubble emerges from the bulk region at a lightly suppressed "apparent" bubble point pressure. Below the bubble point, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multi-stage expansions. In the end, large amounts of intermediate to heavy hydrocarbons are retained in nanopores, implying a significant oil recovery loss in shale. The confinement effect also leads to near-critical phase behavior in small-scalenanopores (<5 nm).

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