Summary
Saline-aquifer storage of carbon dioxide (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.
Many of these storage sites are not well characterized, and it is critical to
conduct detailed experiments and analysis to understand how features such as
heterogeneity can influence the theoretical storage capacity, spatial extent of
plume migration, and secondary trapping processes. Coreflooding experiments are
used routinely by the oil and gas industry for such analysis and provide a very
useful tool for studying saline-aquifer formations also. Numerical simulations
of these coreflooding experiments can provide insight beyond the experimental
measurements themselves, such as numerically studying how properties such as
relative permeability and capillary pressure affect CO2 distribution
in these systems under various flow conditions. However, accurate subcore-scale
simulations of these experiments have remained a challenge, and the issue of
how to represent subcore-scale permeability has not been resolved
previously.
Laboratory coreflooding 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 subcore-scale heterogeneity and the role of permeability in
determining the subcore-scale CO2 distribution in the core to
explain these very large spatial variations in CO2 saturation.
Numerical simulations of the experiment consistently showed that use of
traditional methods for estimating subcore-scale permeability, typically based
solely on porosity distributions, results in subcore-scale saturation
distributions that do not match experimental measurements. In this paper, we
develop a new method for calculating subcore-scale permeability distributions
on the basis of capillary pressure measurements and porosity distributions 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 absolute value and in the spatial
distribution of predicted CO2-saturation values. With this technique
for accurately calculating permeability distributions, it is possible to study
subcore-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 the fate of
stored CO2.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
26 January 2010
- Meeting paper published:
2 November 2009
- Revised manuscript received:
14 July 2010
- Manuscript approved:
19 July 2010
- Published online:
6 January 2011
- Version of record:
23 December 2011
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