Pore-scale Analysis of CO₂-brine Displacement in Berea Sandstone and Its Implications to CO₂ Injectivity

Dassault Systèmes, San Francisco, USA

^* Corresponding author: Guangyuan.SUN@3ds.com

Abstract

For storage in deep saline formations, where CO₂ is injected into the pore spaces of rocks previously occupied by saline groundwater (brine), relative permeability is a key input parameter for predictive models. CO₂ injectivity is considered to reach the maximum value at the CO₂ endpoint relative permeability when brine saturation becomes irreducible. The objective of this study is to investigate the effect of viscosity ratio, interfacial tension and wettability on relative permeability during CO₂-brine drainage. A multiphase lattice Boltzmann model (LBM) is employed to numerically measure pore-scale dynamics in CO₂-brine flow in the sample of Berea sandstone. CO₂/brine with interfacial tension from 30 to 45 mN/m and viscosity ratio from 0.05 to 0.17 (the range of values expected for typical storage reservoirs conditions) are carried out to systematically assess the influence on the relative permeability curves. Although CO₂ storage in sandstone saline aquifers is predominantly water wet, there are contradictory results as to the magnitude of the contact angle and its variation with fluid conditions. Therefore, the range of wetting conditions is studied to gain a better insight into the effect of wettability on supercritical CO₂ displacement. In this study, it is observed that interfacial tension variations play a trivial impact while both of viscosity ratio and wettability are likely to have a significant effect on relative permeability curves under representative condition of storage reservoirs. We also perform a near-wellbore scale geomechanics analysis to investigate the impact of relative permeability on CO₂ injectivity. The result shows that water-wet condition facilitates the CO₂ injection when there is no fracture induced.