Geologic Sequestration Site Characterization (GSSC) -
Recovery Act: Modeling CO2 Sequestration in the Ozark Plateau Aquifer System
Project No: FE0002056
The University of Kansas (KU), BEREXO Inc., Bittersweet Energy Inc., Kansas Geological Survey, and the Kansas State University is studying potential CO2 storage sites which includes saline aquifers and depleted oil reservoirs within the Ozark Plateau Aquifer System (OPAS) in south-central Kansas. The study focuses on the Wellington Field, with an evaluation of the CO2-enhanced oil recovery (EOR) potential of its Mississippian chert reservoir and the storage potential in the underlying Cambro-Ordovician Arbuckle Group saline reservoir. A larger study of the Arbuckle Group saline reservoir is being undertaken over a 33 county area in south-central Kansas to evaluate regional CO2 storage potential. Additionally, the EOR potential of the Chester and Marrow Sandstone reservoirs are being evaluated. This study will demonstrate the integration of seismic, geologic, and engineering approaches to evaluate CO2 storage potential.
The project will estimate the CO2 storage potential of multiple formations within the OPAS by constructing integrated geological models followed by reservoir simulation studies. The effort will involve collecting available data, drilling three new wells through the Arbuckle Group, logging the newly drilled wells (Figure 1), coring a portion of the injection and confining zones in two of the new wells, and performing chemical and physical analyses on the samples. In addition, an analysis of the geochemistry of formation fluids will be conducted, and a simulation of fluid flow in the reservoir/aquifer and geochemical interactions between injected CO2 and formation fluids will occur. Ultimately, reservoir simulation studies will be conducted to determine CO2 injectivity in saline reservoirs and calculate the metric tons of CO2 stored in solution, as well as residual gas saturation, and mineral precipitates. The studies will evaluate the seal integrity needed to overcome the pressure increase from injection, seal porosity changes due to geochemical reactions, and used to develop an estimate of potential CO2 leakage as a fraction of injection. Near- and long-term simulations will be conducted to quantify free phase CO2, its distribution, and time of dissipation to understand plume growth, its area of influence, and attenuation in the presence of multiple aquitards, background aquifer flow, and its movement when encountering fault zones. Detailed risk analysis studies will be conducted with a Finite Element Heat and Mass (FEHM) simulator to estimate potential CO2 leakage (injection fraction) resulting from cement degradation in existing wells.