ABSTRACT Characterizing unconventional reservoirs involves the investigation of a wide range of potential source-rock targets at various stages of thermal maturity. These samples may contain a mixture of kerogen, bitumen, oil, and pyrobitumen within their fabric. Thus, it is critical that we properly identify and examine each organic phase to better understand reservoir properties. In the present study, we have selected samples of gilsonite from a naturally occurring solid hydrocarbon deposit to serve as an analog for characterizing the bitumen phase of generation. Gilsonite is an aromatic-asphaltic solid bitumen found in vertical veins along the eastern portion of the Uinta Basin, Utah. It is thought to be an early generation product from oil-prone Green River Shale source beds and is similar to low-maturity crude oil in composition. It has a high nitrogen content, low sulfur content, and high melting point (fusibility) and is soluble in organic solvents. We have used a variety of analytic methods to characterize this material, including standard optical organic petrology and scanning electron microscopic imaging to examine the occurrence of organic porosity. Optical organic petrology analyses using both air and oil immersion objectives show that the polished gilsonite surfaces are typically dark grey and featureless. Optical evidence for the presence of macerals and inorganic constituents is absent. Visual estimates suggest that fractures make up approximately 1% of the conchoidal fracture plane, whereas the pencillated variety contains approximately 2% fractures along with 5% shallow pits. Scanning electron microscopic images also show the occurrence of fractures within gilsonite, but the matrix contains no evident organic porosity. The results of our analyses suggest that, unlike pyrobitumen, pre-oil solid bitumen represented by gilsonite was found to contain no significant occurrences of organic nanoporosity within its matrix. Gilsonite does have minor pitting and fractures, but these do not represent an effective interconnected pore network and are probably artifacts of weathering/sampling. Thus, this material would not represent a potential candidate for in-situ petroleum storage capacity. Whether this is typical of all naturally occurring solid bitumen is debatable, considering that gilsonite has undergone some secondary alteration via devolatilization and limited biodegradation. Nevertheless, the pore-scale imaging of this solid bitumen provides potentially important new insights for unconventional reservoir characterization.

Abstract Carbonate and interbedded siliciclastic-carbonate rocks of the Upper Cambrian Gatesburg Formation represent deposition on, and proximate to, the great American carbonate bank (GACB), a broad, rimmed platform of low relief that was subject to periodic sea level changes. This environmental setting produced a series of complex mixed carbonate and carbonate-siliciclastic sequences (dominated by carbonates) with limited lateral continuity between outcrops and wells. Many of the rocks formed on the GACB are targets of active petroleum exploration in western and north-central Pennsylvania, as well as in other areas of the Appalachian Basin. Potential reservoir targets include the Upper Cambrian Upper Sandy member of the Gatesburg Formation (Rose Run Sandstone of Kentucky and Ohio) and paleotopo-graphic highs and paleokarstin the Mines Member of the Gatesburg Formation below the Knox unconformity (considered to be part of the Beekmantown throughout much of the Appalachian Basin). Although the latter typically are seismic plays, with companies searching for both stratigraphic and structural traps, knowledge of the patterns of sedimentation on the GACB is also critical to exploration efforts. Mixtures of carbonate and siliciclastic rocks resulted from spatial and temporal variability in depositional systems across the GACB, creating acute and complex reservoir heterogeneities. The distribution of porous and permeable sandstone and carbonate facies within the Cambrian sequence, as well as the juxtaposition of sandstones and paleokarst beneath the Knox unconformity, undoubtedly influenced the migration of fluids, including brines that diagenetically altered many of the rocks, primarily through dolomiti-zation. The spatial distribution of reservoir seals, reservoir compartmentalization, and dia-genetically controlled pore geometry are partially or wholly sedimentologic features.

Abstract Most Upper Devonian and Lower Silurian reservoirs in Pennsylvania have stratigraphic traps (pinch-outs, porosityture trends throughout western Pennsylvania probably influenced the migration of fluids and the diagenesis of sediments. Reservoirs comprise a variety of quartzose, lithic, and feld- spathic sandstones whose diagenetic histories included formation of authigenic clays, cementation, dolomitization, solution of cements and grains (resulting in secondary porosity development), and recementation. Permeabilities and porosities (most of which are secondary) tend to be low.