Modeling the Effects of Porous Media in Dry Gas and Liquid Rich Shale on Phase Behavior

Abstract

Because of the confinement effects in shale formations, fluid flow is different compared to conventional reservoirs. The interactions between the fluid molecules and porous wall inside nanopores play such an important role that can change the phase behavior of the fluids. The fluids in shale reservoirs are usually stored in two forms, free fluids and adsorbed fluids. The region where free fluids are stored has negligible fluid-wall interactions while the region for adsorbed fluids is under strong pore wall influence. The current available equations of state cannot capture the phase behavior of the adsorbed phase in porous media due to the ignorance of the fluid-wall interactions. This paper discussed the effects of the fluid-wall interactions on fluid phase behavior from a modeling of of view.The production from shale reservoirs in the US has shifted from gas windows to condensate windows and oil windows recently due to low natural gas price. Liquid-rich shales, such as Barnett, Eagle Ford, and Marcellus are brought more attentions than ever before. Thus, it is critical to understand the fluid phase behavior and properties and their impacts on production in the condensate systems. Our work focuses on the predictions of fluid critical property change and fluid density change inside nanoporous media. Simplified Local-Density theory for single component coupled with modified Peng-Robinson Equation of State was used to predict the density profiles of dry gas (pure methane) in confined pores. The model was then extended to mixtures for the study of condensate systems.Our results showed that due to the fluid-wall interactions, the fluid density is not uniformly distributed across the pore. The fluid density is higher near the wall than that in the center region of the pore. It also showed that depending on fluid types, temperature, pressure and pore sizes, the fluid density profile would change. The pore size range we focused on was from 2 nm to 10 nm. In order to present the condensate system, a synthetic mixture of 75% methane and 25% n-butane is used. It is found that fluid composition is not uniform across the pore. Heavier component (n-butane) tends to accumulate near the wall while lighter component (methane) would like to stay in the center region of the pore. For a 10 nm wide pore, the composition of n-butane of the synthetic mixture can be as high as 66% close to the pore wall.

Confined Phase Envelope of Gas-Condensate Systems in Shale Rocks

“…A molecular layer density for methane at 80°C across of a 3.6 nm organic slit-pore is given based on Diaz et al (2009) The estimated pore pressure for the bulk phase measurements of methane is 4,413 psi. Similar analysis is presented in Ma & Jamili (2014). The example of histogram of pore diameter from MICP experiment in the shale rock is given also in the Figure 2 (Clarkson & Haghshenas (2012)), similar histogram associated to different shale rock is given in Figure 3 (Dhanapal et al, 2014).…”

“…The second correlation relevance to dimensionless shift of critical parameters pressure and temperature is presented in Ma et al (2013), Ma & Jamili (2014) …”

Effect of large gas-oil capillary pressure on production: A compositionally-extended black oil formulation

“…They also examined a three-component system and concluded that in addition to capillary pressure effects, liberation of lighter components from the oleic phase to the vapor phase further suppresses the bubble-point pressure in the nano-sized channels. In a theoretical study, Ma and Jamili (2014) showed that fluid densities in nano-pores are higher than bulk densities. They modified the Peng-Robinson equation of state to fit the pure fluid data by applying the local density model to consider adsorption and solid-fluid interactions.…”