Seal evaluation and confinement screening criteria for beneficial carbon dioxide storage with enhanced coal bed methane recovery in the Pocahontas Basin, Virginia

Abstract

The geological storage of carbon dioxide in Appalachian basin coal seams is one possible sink for sequestration of greenhouse gases, with the added benefit of enhanced-coal bed methane (ECBM) recovery. The Pocahontas Basin (part of the central Appalachian Basin) of southwestern Virginia is a major coal bed methane (CBM) province with production mostly from coal beds in the Lower Pennsylvanian Pocahontas and New River formations. As part of the Southeast Regional Carbon Sequestration Partnership's Phase II research program, a CO2-injection demonstration well was installed into Lower Pennsylvanian coal bed-methane producing strata in southwest Virginia. Samples of siliciclastic lithologies above coal beds in this Oakwood Field well, and from several other cores in the Nora Field were taken to establish a baseline of the basic confinement properties of overlying strata to test seal competency at local and regional scales. Strata above CBM-producing coal beds in the Pocahontas and New River formations consist of dark-gray shales; silty gray shales; heterolithic siltstones, sandstones, and shales; lithic sandstones, and quartzose sandstones. Standard measurements of porosity, permeability and petrography were used to evaluate potential leakage hazards and any possible secondary storage potential for typical lithologies. Both lithic- and quartz-rich sandstones exhibit only minor porosity, with generally low permeability (< 0.042 mD). Interconnected porosity and permeability are strongly impacted by diverse cementation types and compaction. Analyzed siliciclastic lithologies are considered tight, with limited primary matrix permeability risks for leakage, providing an ensemble of redundant CO2-ECBM traps. One of the most promising confining intervals above the major coal bed-methane producing interval is the Hensley Shale Member. Analyses of 1500 geophysical logs in southwest Virginia indicate that this unit is moderately thick (> 50 ft, 15 m), laterally continuous (> 3000 km2), and a homogenous shale, which coarsens upward into siltstone and sandstone, or is truncated by sandstone. Calculations from two mercury injection capillary porosimetry tests of the shale indicate that a displacement entry pressure of 207 psi (1427 kPa) would generate an estimated seal capacity of 1365 ft (416 m) of CO2 before buoyant leakage. Scanning electron microscopy indicates a microfabric of narrow pore throats between quartz grains floating in a clay matrix. Modeled median pore throat size between micro-fabric matrix grains for the shale is estimated at 0.26 μm. These characteristics indicate that the shale, where fractures and joints are limited, would be an adequate regional confining interval for deeper CO2 storage with ECBM.