Pore Networks and Fluid Flow in Gas Shales

Abstract Favorable gas content, depth, and thickness, along with high brittleness of the Barnett Shale in the Fort Worth Basin, North Texas, have made the basin one of the best shale-gas plays in North America. Using recent pore images and geochemical data for the Barnett Shale, we investigated potential effects of organic matter on petrophysical properties, pore networks and fluid flow in gas-shale systems. Four types of porous media are present in productive gas-shale systems: nonorganic matrix, organic matter, natural fractures, and hydraulic fractures. Organic-matter pores, ranging from 5 to 1,000 nm, are especially important because they can adsorb gases as well as store free gases. Gas content and adsorption data from Barnett Shale also suggest that a significant amount of free gas is stored in organic matter. Porosity in organic matter can be five times higher than that in the nonorganic matrix. Organic matter is oil wet, and associated pores work as nanofilters for hydrocarbon flow, suggesting that fluid flow in organic matter is predominantly single phase. Owing to high porosity, predominantly single-phase flow, and the gas slippage effect, gas permeability in organic matter, significantly higher than that in the nonorganic matrix, tends to enhance gas permeability in gas shale. In addition, the pore network in organic matter, can be larger than that in the fractures, could be the hidden pathway to high gas production in gas shale when connected to natural and hydraulic fractures.