The phase behavior of reservoir fluids plays a fundamental role in predicting well performance and ultimate recovery. The uncertainty in phase behavior is currently 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 macroscale geometries such as fractures and macropores, the fluid behavior is bulk-like; in nanoscale 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 study on the effect of pore-size distribution on the phase behavior of shale-reservoir fluids in a multiscale-pore system. The global fluid-phase equilibria among different sizes of pores are simulated. 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 (DSC) and isothermal adsorption of species C1–14. The multiscale 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 (CCEs) 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” bubblepoint pressure. Below the bubblepoint, the liquid saturation in the bulk region drops sharply, but the fluids in the nanopores are undersaturated throughout the multistage 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-scale nanopores (<5 nm).