(484e) Geologic Characterization and Fluid-Flow Modeling for Commercial-Scale CO2 Injection and Storage in the Mt. Simon Sandstone Storage Complex

Several large-scale carbon dioxide (CO₂) storage projects are currently underway in the Illinois Basin, with the potential to contribute to the commercial deployment of carbon capture utilization and storage (CCUS) across the US. To develop these projects, extensive efforts are required to characterize and model the geology and fluid flow of the subsurface geologic formations where CO₂ will be stored.

This study focuses on the geologic characterization and fluid-flow modeling conducted for the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Illinois storage corridor project, Phase 3. A stratigraphic test well was drilled and logged in eastern McLean County, Illinois, to evaluate the injectivity and storage resource of the Mt. Simon storage complex, which comprises the Mt. Simon Sandstone (stratigraphically subdivided into upper, middle, and lower), Eau Claire shale, and Argenta formation.

Using geophysical logs and formation cores from the test well, along with geophysical logs from two nearby wells, three geocellular models of the storage complex were developed with permeability estimations from three different methods (the difference in average permeability of Mt. Simon among the three models was within 20%). The “most-likely” model was chosen and calibrated to the local structural and reservoir properties of the formations. The depositional environment of the Mt. Simon Sandstone varies across its subdivisions vertically, from deltaic environment in upper Mt. Simon, fluvial dominated environment in middle Mt. Simon, to a fluvial-aeolian environment in lower Mt. Simon. As such, the properties in the model were heterogeneous both laterally and vertically. The calibrated geocellular model covers an area of 20 miles (32 km) by 20 miles (32 km) with an average thickness of 2977 ft (907 m). The storage unit, the Mt. Simon sandstone, is 1980-ft (604-m) thick with average porosity and permeability of 11% and 50 mD. The Arkose zone, the most porous and permeable 200-ft (61-m) thick interval at the bottom of the Mt. Simon Sandstone, has average porosity and permeability of 16% and 308 mD.

Fluid-flow modeling was conducted using the four geocellular models described above. A sensitivity study was completed to understand how various factors (including well inclination, the distance between wells, perforation interval, permeability, and porosity) affect maximum CO₂ injection rate, CO₂ plume size, and pressure front, thus determining an injection strategy that could meet the injection goal.

Sensitivity on well inclination showed that CO₂ could be injected at a maximum CO₂ injection rate of 1.2 Mt/yr to 2.5 Mt/yr via a vertical well by perforating the entire Arkose zone. A slant well with various vertical angles (45–78°, measured from vertical) going through the Arkose zone allowed an increase of 4–34% in the maximum CO₂ injection rate as the perforated length increased due to the slant well’s angle. A horizontal well with a perforated length of 1000 ft (304.8 m) to 5000 ft (1524 m) allowed an increase of 22–200% in the maximum injection rate. When CO₂ was injected via a vertical well at a rate of 1 Mt/yr, the CO₂ plume radius was around 1.4–1.5 mi (2.3–2.4 km) at 12-year injection and 1.6–1.8 mi (2.6–2.9 km) at 20-year injection. The CO₂ plume radius increased by ~4% at 50-year post injection.

When multiple vertical wells were considered at the well site, the well locations were determined considering pressure interference among wells, distance to future monitoring wells, and land availability. Sensitivity on the distance between wells showed that shorter distances between the injectors yielded smaller CO₂ plume size but had little effect on the pressure front. In this study, the optimal distance between wells was 0.5–1 mi (0.8–1.6 km) to minimize the plume size while maintaining an injection rate of 1.5 Mt/yr.

Sensitivity on the perforation interval of a vertical well showed that perforating the Arkose zone yielded a smaller pressure front than injecting into the less porous and permeable 500-ft (152-m) thick interval in the upper part of the formation. Sensitivity on porosity and permeability showed that a 20% increase in porosity decreased the CO₂ plume radius by 9% at 20-year injection and 7% at 50-year post injection. A 20% change in permeability had little effect on the CO₂ plume size.

The findings from this study serve as a reference for early-stage commercial CO₂ storage site development. Future work will involve updating the models and incorporating additional geologic data to further refine the site evaluation process.