Phase behavior and fluid properties in porous media are governed by not only fluid molecule-fluid molecule interactions but also fluid molecule-pore wall interactions. The current available equations of state consider only fluid molecule-fluid molecule interactions and neglect the interactions between the reservoir fluid molecules and the solid wall of the porous media. For conventional reservoirs, this assumption may be valid because the formation pore sizes are much larger than molecular mean free paths. However, in shale formations that are characterized by nanopores, the fluid molecule-pore wall interactions play such an important role that can change phase behavior and crticial properties of the reservoir fluids. Consequently, the critical temperatures and pressures of multi-component hydrocarbon mixtures under nanopores confinement are influenced strongly by fluid molecule-pore wall interactions.
This work investigates the effect of pore proximity in tight and shale formations on phase behavior and fluid properties of the reservoir fluids by modifying van der Waals equation of state. Effects of both fluid molecule-fluid molecule and fluid molecule-pore wall interactions are included in the newly proposed equation of state. Based on molecular simulation studies, correlations are developed to consider the effect of fluid molecule-pore wall interactions for each component required for phase equilibria calculations under nanopore confinement using the proposed equation of state.
Phase behavior calculations of a mixture of methane, n-butane and n-octane were studied under confinement effects for pore sizes ranging from 10 to 2 nm. In general, with the decrease of pore size, the two-phase region of the fluid mixture tends to shrink, which makes the fluid mixture behave more like a dry gas. The results indicate that bubble point and dew point pressures of the confined fluids are up to 150 psi and 300 psi higher than their correspondent bulk values. Also n-butane and n-octane tend to evaporate more when pore size dereases.
The confinement effects can cause the fluid mixture to behave similar to dry gas, which results in reduction in condensate banking and less near-wellbore permeability impairment in comparison to conventional reservoirs. This has several implications for reservoir and well performances. One is that we can observe increased gas rates and enhanced recoveries over the life of the field by modeling these effects in a numerical reservoir simulation package.