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.

URTeC 1562626

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