Assessment of Factors Influencing CO2 Storage Capacity and Injectivity in Eastern U.S. Gas Shales

摘要

Organic-rich gas shales appear to behave similarly to coal and desorb methane while preferentially adsorbing CO2. In addition, the pore volume containing "free" (non-adsorbed) methane is expected to be available for CO2 storage, especially where previous hydraulic fracturing has enhanced injectivity. In theory, CO2 injection into organic-rich gas shale could provide dual benefits of incremental recovery of methane and secure CO2 storage. This paper will report on research to date, sponsored by the U.S. Department of Energy, to assess factors influencing effective CO2 storage capacity and injectivity in the Marcellus Shale in the Eastern United States. Geological characterization was conducted that estimated total gas in-place and theoretical maximum CO2 storage capacity within the Marcellus Shale. Theoretical maximum CO2 storage capacity assumes 100% of methane in-place, either as adsorbed or "free" gas, is replaced by injected CO2. Detailed reservoir characterization was conducted to determine depth, thickness, total organic carbon, effective porosity, apparent gas saturation, CO2 and methane adsorption isotherms, and permeability. Total gas in-place and maximum CO2 storage capacity are extrapolated for the study area where depth to the Marcellus exceeds 915 meters (3,000 feet). Estimated total theoretical maximum CO2 storage capacity is 1.12 million metric tonnes per square kilometer (MMt/km2), of which adsorbed CO2 storage capacity is estimated to be 0.72 MMt/km2. Detailed reservoir simulation was performed to develop a better understanding of the shale characteristics influencing storage capacity and injectivity. The work focuses on areas that may be optimal for CO2 storage due to over-pressured reservoir conditions, attractive shale thickness, and current gas production. A reservoir model was developed based on these data, and reservoir simulation was performed using Advanced Resources International's proprietary reservoir simulator COMET3. Simulated production results were compared to available data within the study area to demonstrate that the reservoir models are representative of existing field conditions. CO2 injection rates are estimated via simulation to predict the incremental volume of methane produced, the total volume of CO2 to be potentially stored, CO2 plume dimensions, and the disposition of CO2 in the reservoir over time.