Apparent Liquid Permeability in Mixed-Wet Shale Permeable Media

Abstract

Apparent liquid permeability (ALP) in ultra-confined permeable media is primarily governed by the pore confinement and fluid–rock interactions. A new ALP model is required to predict the interactive effect of the above two on the flow in mixed-wet, heterogeneous nanoporous media. This study derives an ALP model and integrates the compiled results from molecular dynamics (MD) simulations, scanning electron microscopy, atomic force microscopy, and mercury injection capillary pressure. The ALP model assumes viscous forces, capillary forces, and liquid slippage in tortuous, rough pore throats. Predictions of the slippage of water and octane are validated against MD data reported in the literature. In up-scaling the proposed liquid transport model to the representative-elementary-volume scale, we integrate the geological fractals of the shale rock samples including their pore size distribution, pore throat tortuosity, and pore-surface roughness. Sensitivity results for the ALP indicate that when the pore size is below 100 nm pore confinement allows oil to slip in both hydrophobic and hydrophilic pores, yet it also restricts the ALP due to the restricted intrinsic permeability. The ALP reduces to the well-established Carman–Kozeny equation for no-slip viscous flow in a bundle of capillaries, which reveals a distinguishable liquid flow behavior in shales versus conventional rocks. Compared to the Klinkenberg equation, the proposed ALP model reveals an important insight into the similarities and differences between liquid versus gas flow in shales.

New Model of Oil Migration in Shale Nanopores Considering Microscopic Deformation Induced by Stress and Pore Pressure

“…The average size of IM nanopores is usually at least 1 order of magnitude larger than that of OM nanopores. 13,50,51 Therefore, the oil migration in IM nanopores and OM nanopores needs to be calculated with different parameters.…”

New Model of Relative Permeability for Two-Phase Flow in Mixed-Wet Nanoporous Media of Shale

“…It can be seen from eqs and that the velocity distribution in the nanopore is related to the viscosity of the fluid near the wall and the slip length. In shale nanoporous media, there are both organic and inorganic pores . Due to different wettabilities, the viscosity of the fluid near the wall and the slip length of different fluids in organic and inorganic pores are different.…”

“…In shale nanoporous media, there are both organic and inorganic pores. 28 Due to different wettabilities, the viscosity of the fluid near the wall and the slip length of different fluids in organic and inorganic pores are different. The effect of wettability on the slip length and viscosity of the near-wall fluid can be quantitatively described as 29,30 l C (cos 1)…”

Stochastic-based liquid apparent permeability model of shale oil reservoir considering geological control

“…Although an extensive body of studies have discussed the reconstruction of realistic shale, understanding that the liquid flow, especially oil in their dominant nanopores, is still in its infancy (Falk et al 2015;Fan et al 2020;Sun et al 2019). Classical fluid mechanics, like the Hagen-Poiseuille (H-P) equation, usually assumes that there is no velocity slip between liquid and solid wall.…”

“…However, parameters in their equations, like natural relaxation time, are difficult to determine. In recent years, molecular dynamics simulation (MDS) has become an effective tool to obtain the slip length of hydrocarbon flow in nanopores (Fan et al 2020;Zhan et al 2020). Wang et al (2016a;2016c) used MDS to study the octane flow in OM (simplified as graphene), quartz and calcite nanopores.…”