Abstract

Permeability measurements made using innovative techniques on 36 intact samples from five wells in south Texas provide the basis for a dual-porosity reservoir simulation model for the Eagle Ford Shale (Upper Cretaceous). In the model, matrix storage feeds a network of progressively larger natural and induced fractures that carry hydrocarbons to the wellbore. The Eagle Ford consists almost entirely of interbedded marl and limestone. Across these rock types, permeability increases with increasing calcite content. The limestones are more permeable than the marls due to the presence of fractures. Permeability also increases with the degree of lamination but the mechanism is unclear. Finely laminated marls are more permeable than marls without any lamination. Scanning electron microscope microscopy shows that all of the intergranular pores in the Eagle Ford are lined or filled with solid hydrocarbon identified as both bitumen and pyrobitumen by visual kerogen analysis and solvent extraction. The bitumen is porous, but permeability is not related directly to the total organic carbon content.