Estimating the pressure-limited dynamic capacity and costs of basin-scale CO2 storage in a saline formation

Abstract

Deployment of carbon capture and storage (CCS) could be necessary to be able to satisfy baseload electricity demand, maintain diversity in the energy mix, and achieve mitigation of carbon dioxide (CO2) emissions at lowest cost (IPCC, 2015; U.S. DOE, 2016). If basin-, regional- or national-scale deployment of CCS is needed, it may be possible to store only a small fraction of the captured CO2 in oil and natural gas reservoirs. The vast majority would likely have to be stored in saline formations. Pressure buildup as a result of injecting CO2 into such reservoirs is expected to be an important source of risk associated with CO2 storage, and could constrain dynamic storage capacities (maximum injection rates) to be far below estimates based on access to theoretical storage resources. Estimates of CO2 storage costs based on an assumption of practical availability of the theoretical storage resource could lead to underestimation of the costs of CO2 storage. In this study, simulation results suggest that the pressure-limited dynamic CO2 storage capacity of the Mount Simon Sandstone could be less than 4% of the theoretical storage resource in this saline formation, and storage costs could be an order of magnitude higher than recent estimates. However, consideration of the geologic heterogeneity in this deep saline formation allowed definition of a high injectivity zone, and estimated costs of CO2 storage in this “sweet spot” of the reservoir approached recent estimates that did not include costs for pressure management.