ALBERT

Description: 〈span〉〈div〉ABSTRACT〈/div〉The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (ϕ〈sub〉〈span〉e〈/span〉〈/sub〉), clay volume (〈span〉Vc〈/span〉), and supercritical CO〈sub〉2〈/sub〉 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO〈sub〉2〈/sub〉 storage volume supercritical CO〈sub〉2〈/sub〉 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO〈sub〉2〈/sub〉 storage reservoirs in this area.〈/span〉