Abstract A procedure has been developed to quantify oil saturation in the pore system of shales. The technique uses geochemical and rock property measurements of core samples (solvent extract yield, porosity, densities, and kerogen sorption capacities). The method takes into account the fact that many shales contain indigenous organic matter (kerogen) and that free hydrocarbons extracted from the shale may originate either from the sorbed fraction of the kerogen/mineral matrix or from residual hydrocarbons within the intergranular pore system. A study of the Eagleford Formation from east Texas shows that mineral surfaces of the shale most likely remain water wet and that residual oil saturation (S0) of the intergranular pore system attains the highest values during the intense zone of oil generation (calculated S o = 15 to 70%). The saturation values are examined as a function of burial depth and organic richness to establish typical trends for shales undergoing normal maturation. Relationships between pore saturations and Rock-Eval S 1 /TOC (total organic carbon) ratio are established so that the concepts can be applied in cases where only Rock-Eval data are available. Samples with S 1 /TOC ratios >120 mgHC/gC may contain some nonindigenous hydrocarbons, and those with values >200 mgHC/gC almost certainly do. These values were used to evaluate the residual oil contents and seal performance of various fine-grained rock facies. A case study from the Talang Akar Formation, Indonesia, shows that seal rocks with high entry pressures (from mercury injection capillary pressure [MICP] analysis) have low hydrocarbon contents in the range expected for in-situ generation. However, shales with the lowest entry pressures have very high hydrocarbon (HC) contents, indicating impregnation of the pore system with oil from an underlying accumulation. In such samples, the seal rock has most probably attained equilibrium with the maximum oil column height it was capable of supporting. The method complements existing mercury injection capillary pressure (MICP) measurements of seal capacity, and provides a rapid means for detecting seal failure or poor-quality reservoir “waste zones.”

Abstract The seal potential of various lithologies in the Upper Oligocene Talang Akar Formation (TAF) is evaluated in the BZZ area of offshore northwest Java. Seal potential comprises (1) seal capacity (the calculated amount of hydrocarbon column height a lithology can support); (2) seal geometry (the structural position, thickness, and areal extent of the lithology); and (3) seal integrity (rock mechanical properties such as ductility, compressibility, and propensity for fracturing). Seal capacity is determined by mercury injection capillary pressure (MICP) analyses. Seal geometry is derived by integrating seismic data, core, detailed well correlations, regional sedimentological/Stratigraphic relationships, and comparisons to known depositional analogs. Seal integrity is evaluated qualitatively by core examination, borehole imaging, and petrographic studies. These three variables were integrated and the totals were “ranked.” In the BZZ area, deltaic distributary channel sandstones and delta-front/mouth bar heterolithic sandstones comprise the main reservoirs. Possible seals include prodelta, delta-front, and delta-plain shales; channel abandonment silts; and transgressive shelf carbonates in both the upper and lower TAF. Seal potential is best in the delta-front shales, which have high seal capacity and are thick, lat-erally continuous, and very ductile. Seal potential is moderate in the thicker (upper TAF) transgressive carbonates. These rocks have high seal capacity and excellent lateral continuity, but are brittle and, hence, prone to fracturing. Delta- plain shales and prodelta shales are poor seals due to their limited seal capacity (delta-plain) or because they are too thin (prodelta shales). Channel abandon-ment siltstones have even poorer seal potential because of small lateral extent and limited seal capacity. The least favorable seal potential occurs within the thin (lower TAF) carbonates. These rocks are relatively thin, as well as being prone to fractures.

Abstract An integrated reservoir description of the Smackover Formation in Walker Creek Field in southern Arkansas was conducted in order to evaluate the field's hydrocarbon potential and to determine the best method of increasing recovery. Geologic, petrophysical and engineering studies comprise the multi-disciplinary reservoir description of Walker Creek Field. Evaluating the field's potential included optimizing current operations, proposing options that accounted for reservoir complexities, and planning future operations that would maximize the unit's economic value. The specific aspects of the reservoir description consist of: Determining the depositional and diagenetic controls on reservoir lithologies and the resulting reservoir geometry; Establishing the internal geometry of the reservoir for the purpose of 1) zonation of reservoir flow units, 2) discrimination of pay from non-pay intervals and 3) evaluation of the continuity of different pay zones and of barriers to flow; Relating facies to reservoir properties, including 1) petrographic evaluation of pore types, 2) relating depositional and diagenetic textures to capillary pressure (Pc) trends and 3) recognizing log responses associated with reservoir layers; Providing a depositional and diagenetic model of the occurrence and distribution of reservoir and non-reservoir units in Walker Creek Field, which may have applications to exploration efforts elsewhere in the Smackover Formation.