Numerical study of the role of critical dimensionless numbers associated with multiphase flow in 3D porous media using lattice Boltzmann modeling

Abstract

Multiphase flow in porous media is of great practical interest in many engineering fields, including geological CO2 sequestration, enhanced oil recovery, and ground water contamination and remediation. In order to advance the fundamental understanding of multiphase flow in natural, 3D porous media, the role of the critical dimensionless numbers associated with multiphase flow, including contact angle, viscosity ratio, and capillary number, is investigated using lattice Boltzmann (LB) modeling. In this study, the pore structure information was extracted from micro computed tomography (Micro-CT) scanned images and then used as internal boundary conditions in a pore-scale LB simulator to simulate multiphase flows within the pore space. A Berea sandstone core sample was scanned in three sections, and then two phase flow simulations were performed for each section. The LB-simulated fluid distribution agreed well with Micro-CT scanned images, which validated the LB simulation capability. To the best of our knowledge, it is the first time that comprehensive interactions between contact angle, viscosity ratio, and capillary number are demonstrated in a real 3D sandstone rock. Simulation results showed that increasing contact angle causes an increase in wetting phase relative permeability and a reduction in non-wetting phase relative permeability. Increasing capillary number will increase both wetting phase and non-wetting phase relative permeabilities, because higher inertial force favors the mobility of both fluids. Increasing viscosity ratio (defined as the ratio of non-wetting phase viscosity to wetting phase viscosity) caused the distance between wetting phase relative permeability curves larger, whereas the distance between non-wetting phase curves smaller. This is because the lubrication effect was stronger when the wetting phase (brine) viscosity was reduced, leading to enhanced non- wetting fluid (CO2) relative permeability. We also simulated the relative permeabilities of both phases after the fluid injection direction and sample location were changed. The results showed that the change in non-wetting phase relative permeability was larger. This indicates that there is stronger spatial heterogeneity and anisotropy in larger pore networks because the non- wetting fluid tended to occupy larger pore space. . The combination of numerical simulation and experiment measurements is promising for advancing fundamental understanding of relative permeability and providing guidance to the design and interpretation of experimental studies. Moreover, special attention should be paid to these micro-scale heterogeneities for relative permeability analysis; insight gained from the studies of small-scale heterogeneity will benefit the understanding of permeability upscaling in geological formations.

AAPG Datapages/Search and Discovery Article #90335 © 2018 AAPG 47th Annual AAPG-SPE Eastern Section Joint Meeting, Pittsburgh, Pennsylvania, October 7-11, 2018