Storing and Securing Carbon Dioxide in Depleted Shale Formations
Tao, Zhiyuan, Civil Engineering - School of Engineering and Applied Science, University of Virginia
Clarens, Andres, Civil & Env Engr, University of Virginia
Hydraulically fractured shale formations are being developed widely for oil and gas production. These fractured shales have a number of characteristics that could make them attractive candidates for geological carbon sequestration (GCS) once the formations have been depleted of oil and gas. They generally exist deep in the subsurface and have low permeability beyond the artificial fracture network that was created during well completion suggesting that they could be permanent repositories. In addition, gas pipeline and handling infrastructure at the surface that are used to produce gas/oil may be re-purposed to inject CO2, minimizing economic and environmental burdens. In spite of this promise, there are a number of technical questions about the viability of this approach. This dissertation seeks to answer critical geochemical and systems-level questions related to the carbon storage capacity in shale formations and strategies to mitigate the leakage risks associated with this technology.
To understand the overall CO2 storage capacity of depleted shale wells, a computational method was developed that is based on a unipore diffusion configuration to characterize governing gas-transport processes. The gas diffusion coefficient was estimated using historical production decline data while the ratio of adsorbed gas to free phase gas, water saturation and gas adsorption isotherms were obtained from the literature. The results suggest that the Marcellus Shale in the Eastern United States could store about 12 Gt of CO2 in 13 years, which is over 1/3 of total US CO2 emissions from stationary sources (e.g., power plants) over the same time period. The mass transfer kinetics of the system indicate that injection of CO2 would proceed several times faster than production of CH4, which for the Marcellus Shale is on the order of several decades. The model is found to be most sensitive to the ratio of adsorbed gas to the total gas which includes both adsorbed and free phase gas. The extension of the model to other locations, together with the harmonization of the results from all the published literature relevant to carbon storage in shale formations, reveals that the major shale formations in US could all store more than 30 Gt of CO2. Different shale formations have distinct petrophysical properties, including their rank, that would affect their storage potential.
To secure the injected CO2 in the fractured shale, a new method was developed to control the fluid flow properties in fractured shale formations. The approach is based on the injection of Ca-based silicate minerals into the fractures and pores as a cation donor. When reacted with CO2, it could alter the fluid conductivity or seal leakage pathways by leveraging the reactivity and kinetics of carbonation reactions of silicates at the depths and pressures of the shale formation. These silicate minerals could be added as either proppant materials during well completion or immediately before shutting down a well. Our results show that the pressures and temperatures of most shale formations are suitable for the carbonation reactions to proceed spontaneously and readily (e.g., >50% completion can be achieved within 1-2 days). Scanning Electronic Micrographic (SEM) analysis and X-ray Diffraction (XRD) techniques support the hypothesis that calcium carbonate will form in addition to amorphous silica under simulated reservoir conditions. The precipitated carbonate can effectively cement the rock and change the pore size distribution in the porous media. The production of silicate hydrate was also observed. This hydrate phase is likely to form via the re-combination of Ca2+ and amorphous silica, which are derived from the dissolution of Ca-silicate. Although the silicate hydrates have porosity of their own, when combined with carbonate precipitates, they may play a synergistic role in narrowing or clogging flow pathways. X-ray Tomography and 3D pore network modeling have been and will be continued to be deployed to better understand the mechanisms through which the reactive transport changes the pore structure and permeability. Future work will also explore ways in which these carbonation and hydration reactions can be leveraged in other applications to provide targeted control of permeability in the deep subsurface.
PHD (Doctor of Philosophy)
Shale, Carbon Management, Mineral Carbonation , Leakage Mitigation, Porous Media, Subsurface Hydrology
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