Petrophysics of Low-Permeability Medina Sandstone, Northwestern Pennsylvania, Appalachian Basin

James W. Castle: Clemson University, Clemson, South Carolina Alan P. Byrnes: Kansas Geological Survey, Lawrence, Kansas

Abstract: Petrophysical core testing combined with geophysical log analysis of low-permeability, Lower Silurian sandstones of the Appalachian basin provides guidelines and equations for predicting gas producibility. Permeability values are predictable from the borehole logs by applying empirically derived equations based on correlation between in-situ porosity and in-situ effective gas permeability. An Archie-form equation provides reasonable accuracy of log-derived water saturations because of saturated brine salinities and low clay content in the sands. Although measured porosity and permeability average less than 6% and 0.1 mD, infrequent values as high as 18% and 1,048 mD occur. Values of effective gas permeability at irreducible water saturation (Swi) range from 60% to 99% of routine values for the highest permeability rocks to several orders of magnitude less for the lowest permeability rocks. Sandstones having porosity greater than 6% and effective gas permeability greater than 0.01 mD exhibit Swi less than 20%. With decreasing porosity, Swi sharply increases to values near 40% at 3 porosity%. Analysis of cumulative storage and flow capacity indicates zones with porosity greater than 6% generally contain over 90% of flow capacity and hold a major portion of storage capacity. For rocks with Swi < 20%, gas relative permeabilities exceed 45%. Gas relative permeability and hydrocarbon volume decrease rapidly with increasing Swi as porosity drops below 6%. At Swi above 40%, gas relative permeabilities are less than approximately 10%.

The Effect of Differences of Multiphase Spatial Distributions on the Electrical Properties of Porous Media

Carlos A. Grattoni and Richard A. Dawe: T.H. Huxley School of Environment, Earth Sciences and Engineering, Imperial College of Science, Technology and Medicine, London, UK

Abstract: Water saturation is commonly estimated from well log resistivity measurements using methods based on Archie€s equations. An experimental study of the influence of flow displacement methods and fluid distributions on the electrical resistivity of partially saturated media has been carried out using visual, quasi two-dimensional (2D) models that allow the observation of the phase spatial distribution while the resistivity is being measured. A new technique has been developed to produce two liquid phases in situ with uniform distribution. We show that even if the water saturation has a macroscopic uniform distribution within the porous medium this is not always the case at the pore scale. Because the electrical current is transported by the ions in the water and because the electrical paths at the pore scale are made up of resistivity components (these are the basic elements for the overall resistivity of the porous medium), the rock resistivity will be affected by the water spatial distribution at the pore level. Using our visual observations of fluid saturations plus a qualitative analysis of flow and fluid spatial distribution at the pore scale, within our micromodels we demonstrate that the changes in makeup of the resistivity components such as partially invaded pores or throats and water films for our water-wet and oil-wet porous media have an influence on the macroscopic resistivity. We show that the fluid spatial distribution within the pore structure affects resistivity and that different displacement processes can affect the fluid spatial distribution and, hence, the resistivity. Thus, the estimation of water saturation must always be treated with caution.

Regional and Stratigraphic Distribution of Uranium in the Lower Permian Chase Group Carbonates of Southwest Kansas

John A. Luczaj: The Johns Hopkins University, Baltimore, Maryland

Abstract: This paper illustrates the regional and stratigraphic distribution of uranium in Lower Permian Chase group carbonates of southwest Kansas. The uranium distribution in these carbonates is quite variable, ranging from about 1 ppm to over 16 ppm in some units. In the Upper Chase group carbonates, the uranium concentration is highest along an east-west trend in the central portion of the study area. The uranium anomalies in the Upper Chase group are related to pervasive uranium-bearing dolomite cements and replacements that were a product of basin-wide reflux of brines associated with the precipitation of Late Permian evaporites overlying the Chase group (Luczaj, 1995). Elevated uranium concentrations may be inversely correlated with permeability for these units (Doveton, 1994). In units of the Lower Chase group, the petrographic character of the uranium-bearing phases is less well known. Some evidence suggests a similarity between spectral gamma ray log responses for at least one of these units and the Texas Austin chalk trend, where uranium anomalies reflect precipitates of uranium-bearing minerals along natural fractures. Higher uranium concentrations may correlate with higher permeabilities in these rocks.

Acoustic Velocity and Porosity Systematics in Siliciclastics

Lev Vernik: ARCO Exploration and Production Technology Company

Abstract: Using several well characterized data sets, including logs and laboratory velocity measurements in fluid-saturated sandstone/shale sequences, it is shown that improved porosity and lithology prediction from sonic logs is possible if unique trends related to sediment deposition, compaction, and diagenesis are recognized. Realistic, petrographically observed evolution of the pore geometries in consolidated, grain-supported sandstones (less than 25% to 30% porosity and less than 15% clay volume) can be successfully modeled using effective medium theories, resulting in a quasi-linear velocity-porosity relation deviating from linearity within the accuracy of velocity measurements. These relations are 1) well defined for clean arenites (essentially pure quartz sandstones) and arenites (slightly shaly sandstones with Vcl £ 12%), 2) largely stress independent, and 3) yield an improved porosity prediction when compared to the Raymer-Hunt-Gardner equations. Poorly consolidated grain-supported sandstones and sands are characterized by a much steeper gradient of velocity increase with porosity reduction as compared to their consolidated counterparts. The effect can be explained by competing mechanisms of grain rearrangement and initial cementation during early diagenetic history of the sediments. The impact of clay in poorly consolidated sands is diminished, while the dependence on the grain sorting, loading history, and pore fluid chemical activity is increased. The compilation of experimental and log data on acoustic velocities in essentially clay matrix-supported siliciclastics (Vcl > 12%), including shales and wackes (substantially shaly sands), suggests that their bedding-normal elastic stiffnesses vary nonlinearly in the entire range of porosity reduction from around 80% to almost 0%. Theoretically motivated empirical models are given for the dry frame elastic moduli of the three major petrophysical groups of sandstones (clean arenites, arenites, and wackes) in the porosity range from 0% to 40%, which can be utilized in porosity prediction or fluid-substitution modeling. Gassmann equation-based fluid-substitution modeling for arenites and comparison with water-saturated core measurements at ultrasonic frequency suggest that 1) a substantial pore fluid sensitivity is only typical of poorly consolidated sandstones and sands, and 2) frequency-related velocity dispersion in poorly consolidated sands is relatively minor.