ABSTRACT

Laboratory-derived petrophysical measurements confirm that the sealing shale's largest interconnected pore throats can limit the size of hydrocarbon columns. These largest interconnected pore throats define the seal capacity of the shale. Interpreting displacement pressure from high-pressure mercury injection porosimetry (MIP) data permits calculating seal capacity, the hydrocarbon column-limiting capillary property of the rock. Displacement pressure is the pressure at which the nonwetting phase (i.e., mercury in the laboratory tests) begins to displace the wetting phase from the largest interconnected pore throats. The 12 well-indurated nonsmectite shales studied range in age from Precambrian to Jurassic and vary in mineralogy, porosity, permeability, cation exchange capacity, organic content, and stratification. The shales are treated as two distinct groups with respect to interpreting displacement pore throat size: nonorganic shales and organic shales. Estimation of mineral percentages by X-ray diffraction analysis, and classifying the shales according to silt/clay ratios, laminations, and major nonclay/nonsilt mineralogy, permit petrographic prediction of seal capacity for nonorganic shales. Quartz content of the matrix is the best predictor of the displacement pore throat size for nonorganic shales. Sandy mudstones have the largest measured tabular displacement pore throats for nonorganic shales and are in the 30-40 nm range. This pore throat size range can limit the size of very large gas columns. Clay-rich and calcareous shales have such small displacement pore throats (<15 nm) that they are excellent capillary seals. The organic shales studied have large displacement pore throats relative to their low porosity when compared to nonorganic shales. Volume reduction of the matrix associated with hydrocarbon generation contributes to the largest pore throats in organic shales.