Estimation of dynamic geologic CO 2 storage resources in the Illinois Basin, including effects of brine extraction, anisotropy, and hydrogeologic heterogeneity

Michelle R. Plampin¹Steven T. Anderson^1*Ashton M. Wiens¹Stefan Finsterle²

• ¹US Geological Survey, Reston, United States
• ²Finsterle GeoConsulting, LLC, Kensington, California, United States

Since the vast majority of carbon dioxide (CO2) storage resources in the United States are in deep saline aquifers, optimizing the use of this saline storage capacity will be crucial for efficient development of geologic CO2 storage (GCS) resources and basin-or larger-scale deployment of GCS in the country. Maximum CO2 injection rates can be enhanced by extracting brine from the CO2 storage unit. However, disposal of the extracted brine is both a technological and economic challenge. The lowest-cost option would likely be re-injection of the extracted brine into another subsurface unit above or below the CO2 storage unit. Therefore, it is important to estimate brine injectivity as it will constrain the potential to increase CO2 injectivity at a storage site that has access to multiple subsurface units where either CO2 or brines can be injected. Using the iTOUGH2 simulation-optimization framework, coupled with the non-isothermal, multiphase CO2-water-salt equation-of-state module ECO2N, we developed a computationally efficient method for evaluating optimization of simultaneous CO2 injection, brine extraction, and brine (re)injection at hypothetical storage sites deployed across a geologic basin. The Illinois Basin is ideal for testing our methodology because it contains multiple subsurface units with seals in between them to isolate injection of CO2 in one unit from interfering with the injection of either brine or CO2 in another unit above or below it. In addition, we investigated the relative effects of variation in key geologic parameters as well as two reservoir structures (hydrogeologic heterogeneity/anisotropy and homogeneity/isotropy) on CO2 injectivities and enhancement of CO2 injectivity through extracting brine. Results suggest that permeability, depth, and especially thickness of the storage unit could be the most influential parameters determining CO2 injectivity. They also suggest that only injecting CO2 into the storage unit with the greatest injectivity, enhancing that unit's injectivity by extracting brines, and disposing of the produced brines in other subsurface units could maximize total CO2 injectivity in limited regions of the Basin. At the majority of simulated injection locations, however, we found that injecting CO2 into all of the potential CO2 storage units is likely to maximize the accessible CO2 storage resource.