Shale gas is a growing resource worldwide as many basins are being explored and produced. However, little is still known and understood about two key parameters in gas shales: the gas-filled porosity and permeability. Digital rock physics technique, presented in this paper, contains three basic steps: (a) 3D CT imaging at 200 nanometer resolution, and/or FIB-SEM (focused ion beam combined with SEM) imaging at 3-15 nanometer resolution (b) segmentation of the digital volume to quantitatively identify the components, including the mineral phases, organic-filled pores, and free-gas inclusions; and (c) computations of TOC (Total Organic Content), porosity, pore connectivity, and permeability in three axis.A number of gas shale samples have been used, to specifically analyze the pore systems. The characteristics including dual porosity, organics distribution, gas-filled porosity distribution, and how these properties relate to the maturity of the organic material. Pore geometries (pores filled either with organics or free gas) of these samples fall into the following categories: (a) relatively large (up to 4 micron) with poorly disconnected pores; (b) pores connected by very thin (down to 15 nanometers) conduits; (c) dual porosity system where the large pores are interconnected by large conduits and very thin conduits are interconnected and also connected to the large pores. Within each of these three categories, the pore space may be (a) completely filled with organics or (b) partially or completely filled with gas.The latter is of most interest as it is a gas source. In such systems we observe various geometries of pore space, including (a) disconnected pores floating in the organics and (b) connected pores within the organics. TOC, open pore volumes, as well as pore-space connectivity are not just qualitatively estimated from the images but quantitatively computed for a given sample. Our ongoing effort is to relate the quantitative patterns thus computed to the maturity of shale.

As more organic rich mudstone resource plays are developed internationally, the need to understand flow potential and long term well performance increases dramatically. Many international locations have limited infrastructure for the economic development of these low permeability formations. Therefore, operators require comprehensive rock data and careful reservoir modeling to help reduce the risk of early-stage development. This paper describes the methods and results of a project designed to quantify the range of expected permeability and relative permeability in samples from a shale formation in Colombia.Porosity versus absolute permeability trends were determined for about 44 well samples using digital rock physics (DRP) methods. Results show rock quality that is equal or better than many prolific North American shales, including Marcellus and Eagle Ford. These samples average about 6% organic material content by volume. The total porosity range observed is from about 3 to 15%. For total porosity of 4% or above, the horizontal permeability is generally above 100 nanodarcy (nd). For porosity of 8%, horizontal permeability is typically 1000nd or more. From these 44 samples, several were selected for relative permeability analysis.Using a Lattice-Boltzmann numerical method, imbibition relative permeability computations (increasing fractional flow of water) were performed for oil-water systems for different scenarios including different contact angles ranging from oil to water wet, and different API values leading to different viscosity ratios.

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