World Class CO2 Sequestration Potential in Saline Formations, Oil and Gas Fields, Coal, and Shale: The US Southeast Regional Carbon Sequestration Partnership Has It All

Abstract

Abstract The Southeast Regional Carbon Sequestration Partnership (SECARB), led by the Southern States Energy Board (SSEB) represents 11 southeastern states: Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, North Carolina, South Carolina, Tennessee, Virginia and east Texas. The SECARB Partnership region contains multiple regional-scale geologic storage opportunities, which offer sufficient capacity to sequester the region's major point source CO2 emissions for decades. These include deep saline formations, depleted oil and gas fields, organic-rich shale formations, Tertiary-age coal deposits of the northern Gulf of Mexico Basin, and coal deposits of the central Appalachian and Black Warrior Basins. Depleted oil and gas fields can provide excellent early sites for sequestering CO2 in known porous and permeable reservoirs overlain by proven seal formations (confining units). In addition, many oil fields within the SECARB region offer opportunities for integrated application of CO2 enhanced oil recovery (EOR) and CO2 sequestration, potentially helping to accelerate CO2 storage efforts. Depleted oil and gas fields could provide 29.7 to 34.7 gigatonnes (Gt, billion metric tons) of storage with nearly 24 million barrels incremental oil (otherwise stranded oil) that may be recovered. Sixty percent of this capacity is expected from offshore fields. Storage potential in deep saline formations is vast, estimated conservatively to range from 2,281 to 9,123 Gt. Recent assessment of one regional saline formation, the Upper Cretaceous age Lower Tuscaloosa Group and equivalent Woodbine Formation, estimates storage capacity of 19.8 to 79.5 Gt. Saline formations require comprehensive geologic characterization of the reservoir properties of the storage formation and the seal characteristics and continuity of potential confining units. Coal and organic-rich shale have significant adsorptive capacity for CO2 and offer potential CO2 storage with enhanced coalbed methane and shale gas production. Low-rank Tertiary coal of the northern Gulf of Mexico basin offers 20 to 28 Gt of potential storage capacity with an additional 1 to 2 Gt from coal seams of the central Appalachian and Black Warrior basins. However, the reservoir potential of Gulf of Mexico coal seams is largely unproven, whereas the Appalachian and Black Warrior basins host major coalbed methane operations. The CO2 storage capacity of the Barnett Shale in the Fort Worth Basin is estimated to be 19 to 27 Gt. Other shale formations include the Fayetteville Shale of the Arkoma Basin, estimated to have 14 to 20 Gt of capacity, and a range of shale formations that have yet to be assessed in the Black Warrior Basin and Appalachian thrust belt. These include the Conasauga Formation (Cambrian), Devonian shale formations, and the Floyd Shale (Mississippian). Field validation of CO2 injection and storage is critical for confirming CO2 storage estimates, and are the primary path forward to commercialization. Field tests validate the geologic characterization effort and reservoir models, specifically injectivity, capacity and containment, and advance the state-of-the-art in measurement, monitoring and verification. This paper presents recent updates to the current assessments of CO2 storage capacity for the SECARB region. The paper features the SECARB Partnership's recent Mississippi Saline Formation Injection Test as an example of a successful field test which validates key reservoir properties of one of the region's large capacity saline aquifers and lays the groundwork for the next phase large-scale demonstration of carbon capture with saline aquifer storage.