Influence of Heterogeneity on Relative Permeability for CO2/Brine: CT Observations and Numerical Modeling

Abstract

The determination of relative permeability of CO2/brine fluids under reservoir condition is critical for the design of CO2 injection strategy and prediction of CO2 behavior underground through reservoir simulation. For some reservoirs only heterogeneous samples are available for measurement. Heterogeneity, such as layering or cross bedding lamination can commonly be seen in sandstone cores. The effects and mechanism of core-scale heterogeneities on macroscopic scale relative permeability must be well-addressed. Here we report two sets of laboratory core flooding experiments using Berea sandstone for steady-state measurement of relative permeability of CO2/Brine at reservoir condition [1]. Berea sandstone is relatively homogeneous but has strong bedding or lamination structures. Two Berea samples were used (cored along the directions parallel to and perpendicular to the bedding, and named Berea-1 and Berea-2 respectively). We recorded the pressure and discharge volume to get the relative permeability curves for both samples; and utilized the X-ray computed tomography to estimate the distributions of porosity and CO2 (or Brine) saturation for Berea-2. The measured phase relative permeability of Berea-2 sample is greatly deviated from Berea-1. To further investigate the effects of core-scale heterogeneity on the measurement of relative permeability, we carried out a series numerical simulation on core scale using Tough2ECO2N code with building models based on X-ray CT scan images. By comparing the numerical results, we found the heterogeneity of capillary pressure field under one injection direction plays a dominant role in CO2/brine saturation patterns, flow regime and apparent relative permeability model.