Estimating the pressure-limited CO2 injection and storage capacity of the United States saline formations: Effect of the presence of hydrocarbon reservoirs

The U.S. Geological Survey (USGS) national assessment of carbon dioxide (CO₂) storage capacity evaluated 192 saline Storage Assessment Units (SAUs) in 33 U.S. onshore sedimentary basins that may be utilized for CO₂ storage (see USGS Circular 1386). Similar to many other available models, volumetric analysis was utilized to estimate the initial CO₂injection and storage capacity of these SAUs based on aquifer characteristics and buoyant and residual trapping. The factor being almost always overlooked in most CO₂ storage capacity models is that many of the evaluated SAUs contain large numbers of both conventional and unconventional discovered and undiscovered oil and gas reservoirs. The hydrocarbon production and pressure distribution of the resident oil and gas reservoirs may be negatively influenced by the propagated CO₂ plume and pressure front resulting from a CO₂ injection and storage operation in the surrounding SAU.

To have a more realistic and accurate estimation of CO₂ injection and storage capacity in saline formations, a model was previously developed that considers the CO₂ injectivity of a given formation, underground pressure build-up limitations imposed by the rock fracturing pressure and the presence of hydrocarbon reservoirs within these aquifers. The developed method estimates the pre–brine extraction, pressure-limited CO₂ injection and storage capacity of a saline formation by applying 3D numerical simulation only on the effective injection area (A_eff) surrounding each CO₂ injection well utilizing TOUGH2-ECO2N simulation software.