| The organic-rich Middle Devonian Marcellus Shale of the Appalachian basin is a rapidly developing natural gas play. Stratigraphic boundaries of the Marcellus Shale in Westmoreland County, Pennsylvania were identified using geophysical logs from 10 vertical gas-producing wells in a 23 sq. km area. Gamma-ray, bulk density, and resistivity well logs were examined to assess hydrocarbon potential. Values of porosity, total organic carbon (TOC), and water saturation (SW) were derived and mapped by incorporating well-log data into Marcellus-specific formulas. Gamma-ray, penetration (minutes per foot drilled), and mud-logging gas (total gas) from 12 horizontal wells from within the study area were also examined. Total gas per unit volume of hole drilled was evaluated as an indicator of shale-gas resource potential. Well design parameters, which include lateral length, number of fracture stages, and sand per fracture stage, were examined to assess their influence on cumulative production. Geophysical log data from both vertical and horizontal wells indicate decreasing organic content stratigraphically upward through 3 Marcellus Shale intervals (lower, middle, and upper). From vertical well data, mean SW calculated from a modified Archie formula ranges from 0.016 in the lower interval to 0.166 in the upper interval, compared to 0.121 and 0.314, respectively, calculated from the standard Archie formula. Calculations from the bulk-density log yield 0.114 mean porosity and 6.9% mean TOC in the lower interval, compared to 0.082 and 4.9%, respectively, in the upper interval. High gamma-ray values (>230 API) and low bulk densities (< 2.55 g/cc) indicate a trend of increasing gas potential southwestward within the study area. For the horizontal wells, total gas calibrated for gas trap performance (TGTRAP) and total gas calibrated for penetration and hole-size (TGPH) correlate with 18 month cumulative production (R2=0.87 and R2=0.70, respectively) from the Marcellus Shale. TGTRAP and TGPH per lateral-ft also show correspondence with cumulative production per lateral-ft (R2=0.52 and R2=0.40, respectively). Cumulative production increases approximately 215 million cubic feet for every 1000 feet of lateral length and approximately 256 million cubic feet for every 4 fracture stages. Sand per fracture stage shows no correspondence with production. |
