Summary

Integration of geology, core analysis, and log analysis of the low-permeability Medina Group in Northwestern Pennnsylvania, Appalachian Basin provides an understanding of lithologic controls on petrophysical properties, equations relating petrophysical variables, and guidelines for predicting gas producibility. Cores from 15 wells in northwestern Pennsylvania were studied (Figure 1). From these wells, 66 core plugs, representing the range in porosity, permeability, grain density, and lithology exhibited by the Medina in the study area, were selected for detailed investigation. Special core-analysis testing was performed on these samples including: routine and in situ porosity, routine air and in situ Klinkenberg permeability, determination of “irreducible” brine saturation at 600 psi air-brine capillary pressure, effective and relative gas permeability at irreducible brine saturation and determination of the Archie cementation exponent. Core lithologies were described and thin-sections of representative samples were examined.

Although routine porosity averages less than 6% and permeability averages less than 0.1 md, infrequent values as high as 18 percent and 1048 md were measured in samples from this area. Values of effective gas permeability at irreducible brine saturation (Swi) range from 60% of routine core-analysis values for the highest permeability rocks to several orders of magnitude less for the lowest permeability rocks. Sandstones having porosity greater than 6 percent and effective gas permeability greater than 0.01 md exhibit Swi less than 20%. Below 6-percent porosity, Swi increases rapidly with decreasing porosity to values near 40-50% at 3 porosity percent. Gas relative permeabilities exceed 50% at Swi values less than 20% but decrease rapidly with decreasing porosity below 6%. At Swi above 40-50%, corresponding to 3 porosity percent and less, gas relative permeabilities are generally less than 1%. Analysis of cumulative storage and flow capacity indicates that zones with porosity greater than 6% generally represent over 90% of the flow capacity and a major portion of storage capacity in any given well.

AAPG Search and Discovery Article #90928©1999 AAPG Annual Convention, San Antonio, Texas