Paul R. Knox
Shale smear factor, or shale gouge ratio, is commonly used to predict the potential sealing ability of faults. This approach assumes that all shales are of roughly similar character. Stratigraphic studies of fault-bounded stacked oil and gas reservoirs indicate that top- and lateral-seal competency vary more in relation to position of a shale within a cyclic stratigraphic framework than to its thickness.
A hierarchical stratigraphic framework was generated in a characterization study of the Oligocene Frio Formation reservoirs in the growth-fault-bounded West Fulton Beach field on the central Texas coast. The volume and type of trapped hydrocarbons, which are related to column height and, thus, top- and fault-seal capacity, were compared with the stratigraphy. A repetitive pattern of larger gas-dominated reservoirs transitioning downward to smaller, oil-dominated reservoirs, then to wet sandstones, then back to large gas-dominated reservoirs was noticed. These cycles are bounded by intermediate-frequency flooding surface shales as thin as 10 ft. In contrast, high-frequency flooding surface shales that separate individual reservoirs range up to 20 ft thick without having a discernable impact on the cyclic accumulation pattern. Intermediate-frequency shales appear to act as a master top seal to a series of accumulations, whereas high-frequency shales appear to act as baffles beneath the master seal to distribute the accumulation among the underlying sand packages. Such patterns are observed in settings as diverse as the Gulf of Mexico and the Vienna Basin of Austria, suggesting that quantitative shale smear analysis should incorporate stratigraphic setting to improve accuracy.
1Bureau of Economic Geology, The University of Texas at Austin, University Station Box X, Austin, Texas 78713; e-mail: email@example.com.