Numerical estimations of storage efficiency for the prospective CO2 storage resource of shales

Hydrocarbon-bearing shale formations might be an attractive geologic reservoir for permanent carbon dioxide (CO2) storage. Shale formations applicable for storage require previous hydrocarbon production to deplete a reservoir, hydraulic fracturing to provide a highly-permeable stimulated zone, sufficient depths (generally > 800 m or 2600 feet) to maintain CO2 in a supercritical state, and an overlying seal to prevent CO2 migration to underground sources of drinking water and into the atmosphere. CO2 is stored in shale as a free phase within fractures and matrix pores, and as a sorbed phase on organic matter and clay minerals. Recently in our previous work, we presented a screening-level assessment methodology for CO2 storage in shales using a volumetric approach. The approach deals with reduction of CO2 storage through estimations of efficiency factors based on petrophysical properties (i.e., bulk volume, porosity, sorption, etc.) and their limitations on fluid transport. Here, we conducted numerical simulations using the FRACGEN/NFFLOW simulator to study the CO2 injection into a depleted hydro-fractured shale reservoir to estimate storage efficiencies using a range of reservoir parameters and injection scenarios. Specifically, the ranges for two efficiency factors, Eϕ and ES, measure the effectiveness of free and sorbed CO2 storage. These efficiency factors were estimated to have P10 to P90 probability ranges of 0.15 to 0.36 for Eϕ and 0.11 to 0.24 for ES, reported after 60 years of CO2 injection.