Abstract
We studied the effects of supercritical carbon dioxide (scCO2) on the matrix permeability of reservoir rocks from the Eagle Ford, Utica, and Wolfcamp formations. We measured permeability using argon before exposure of the samples to scCO2 over time periods ranging from days to weeks. We measured permeability (and the change of permeability with confining pressure) when both argon and scCO2 were the pore fluids. In all three formations, we generally observe a negative correlation between initial permeability and carbonate content—the higher the carbonate content, the lower the initial permeability. In clay- and organic-rich samples, swelling of the matrix resulting from adsorption decreased the permeability by about 50% when the pore fluid was scCO2 although this permeability change is largely reversible. In carbonate-rich samples, dissolution of carbonate minerals by carbonic acid irreversibly increased matrix permeability, in some cases by more than one order of magnitude. This dissolution also increases the pressure dependence of permeability apparently due to enhanced mechanical compaction. Despite these trends, we observed no general correlation between mineralogy and the magnitude of the change in permeability with argon before and after exposure to scCO2. Flow of scCO2 through μm-scale cracks appears to play an important role in determining matrix permeability and the pressure dependence of permeability. Extended permeability measurements show that while adsorption is nearly instantaneous and reversible, dissolution is time-dependent, probably owing to reaction kinetics. Our results indicate that the composition and microstructure of matrix flow pathways control both the initial permeability and how permeability changes after interaction with scCO2. Electron microscopy images with Back-Scattered Electron (BSE) and Energy Dispersive Spectroscopy (EDS) revealed dissolution and etching of calcite minerals and precipitation of calcium sulfide resulting from exposure to scCO2.
Highlights
IntroductionIt is not yet economically viable to inject carbon dioxide into saline formations [2]
2, provides a brief summary of the processes/phenomena αβVdown Lμ involved with each sample and its net increase/decrease caused by interk = of permeability
We used eight cores from Eagle Ford, Utica, and Wolfcamp formations, with carbonate content ranging from 4% to 71% and the range of “clay+TOC” content varying from 1% to
Summary
It is not yet economically viable to inject carbon dioxide into saline formations [2]. Storage of carbon dioxide (CO2 ) in unconventional formations has gained a lot of attention in recent years (e.g., [3,4]). Employing CO2 as the hydraulic fracturing fluid in unconventional formations is a potential approach to economically sequester CO2 [5,6]. These formations are consisted of ultrafine-grained rocks termed as “shale” with a combination of different minerals including clays, carbonates, quartz, feldspars, and pyrite, as well as organic matter [7]
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