Saline aquifer storage of CO2 has become recognized as an important strategy for climate change mitigation. Saline aquifers have very large estimated storage capacities, are distributed broadly across the globe, and have the potential for geologic scale retention times. With such large theoretical capacities available in saline aquifers, it is important to understand how heterogeneous rock property distributions can impact the effective storage capacity.

Laboratory core flooding experiments injecting CO2 into a saline water saturated Berea sandstone core have been conducted at reservoir conditions. Computed Tomography (CT) scans of the core show large spatial variations of CO2 saturation, even within a relatively homogeneous core. Numerical simulations of the experiment have been conducted to study the effect of sub core-scale heterogeneity, and the role of permeability in determining the sub core-scale saturation distribution in the core.

Numerical simulations of the experiment consistently showed that using traditional methods for estimating sub core-scale permeability, typically based solely on porosity distributions, results in sub core-scale saturation distributions which do not match experimental measurements. In this paper we develop a method for calculating sub core-scale permeability distributions based on capillary pressure measurements and porosity as an alternative to the traditional porosity only-based models. Using experimentally measured saturation and porosity distributions, and capillary pressure data to calculate permeability, simulations based on this new method show a substantial improvement both in the magnitude and spatial distribution of predicted saturation values. With this technique for accurately calculating permeability distributions, it is possible to study sub core-scale multiphase flow of brine and CO2 to understand how small scale heterogeneities influence the spatial distribution of CO2 saturation, and to improve our ability to predict storage capacity in saline aquifers.

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