(457g) The Investigations of Reservoir Petrophysical Heterogeneity on the Storage Capacity and Injectivity: A Case Study from Dry Fork Carbonsafe Project, Powder River Basin, WY

To achieve the ambitious goal of net-zero carbon emissions in the middle of this century, one of must have approaches is commercial-scale implementation of geological storage of carbon dioxide (CO₂). Storing CO₂ in the subsurface requires understanding the movement (injectivity， sweep efficiency, and pore space utilization) of the injected CO₂ and ensuring that it remains in the target reservoir. Therefore, one of the critical tasks for a commercial-scale storage project is to characterize the reservoir property heterogeneity, and build and maintain static and dynamic models that will predict the reservoir performance throughout the lifecycle of the project. This case study shows that the reservoir petrophysical heterogeneity has a significant effects on the CO₂ injectivity and storage capacity of the targeted reservoirs.

The WY Dry Fork CarbonSAFE projects Phases I, II and III conducted by researchers from the UW and partners have documented that the Dry Fork CCS site is a promise CO₂ storage location characterized by its favorable geologic conditions (i.e., thick stacked saline aquifers and simple structure) and in close proximity to the CO₂ sources. However, Characterizing geological heterogeneity in three dimensions for CO₂ injection, storage and reservoir pressure management represents the greatest uncertainty. This uncertainty can be reduced significantly by integrating geophysical well logs interpretations, core observations and measurements, 3D seismic attribute analysis, facies and property modeling, and dynamic simulation.

The Dry Fork CCS site is located within the coal-rich Powder River Basin and about six miles north of Gillette, Wyoming. The reservoir intervals with the greatest potential for CO₂ storage are the Permian-Pennsylvanian Upper Minnelusa Formation, the Jurassic Hulett Sandstone, and the Lower Cretaceous Lakota Sandstone. Legacy well data, two stratigraphic test wells, more than 625 feet of core from UW PRB 1, 75 sidewall cores from UW PRB 2, complete log suite retrieved from both wells, a 9 square miles of 3-D seismic survey, inter well tomography, and field injection test are the basis of this construction.

To substantially reduce risk in modeling CO₂ storage in these reservoirs, researchers in Center for Economic Geology Research have integrated 3-D seismic attribute interpretations with results from well log analysis and core observations to construct rigorous geologic structural, facies, and property models that delineate reservoir geometries, lithofacies, porosity and permeability distributions, and fracture feature. Within the property models, we can now isolate individual reservoir horizons and construct maps of the distribution of petrophysical properties, and characterize the heterogeneous feature of petrophysical properties. Results of these modeling efforts are used to evaluate the reservoir petrophysical heterogeneity effects on injection feasibility, injected CO₂ migration and plume development, storage capacity, maximum injection pressure, reservoir pressure propagation, confining layer integrity, and determining the Area of Review for Class VI well application in a 576 mi² area around the Dry Fork Station.

The detailed static modeling provides a solid foundation for the CO₂ injection simulation. Various injection and storage scenarios run for the DF commercial scale CO₂ geological storage site. The simulation results show the heterogeneity of reservoir petrophysical property has prominent effects on the reservoir injectivity and storage capacity. This project results have significant utility in reducing risk for promoting commercial scale CO₂ storage in stacked deep saline aquifers in the Laramide Basins, Wyoming.