Relative Permeability in a Shale Formation in Colombia Using Digital Rock Physics

Abstract

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.

Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale

“…Figure 4 shows a graph of porosity vs permeability with flow units expressed as a function of pore throat aperture (Aguilera, 2014) as shown in Figure 5. What was found is that a pore throat aperture for the available data was around 0.04 microns, which for the porosity range in the model gives permeability values that fall in-between the upper and lower curves defined by Cantisano et al (2013). Permeability values in this work were obtained from the equation (Aguilera, 2014),…”

“…Accordingly and after reviewing literature the porosity values used were: 5.5% for zone 1, 6.6% for zone 2, and 7.7% for zone 3. For the case of the permeability from Cantisano et al (2013). Figure 4 shows a graph of porosity vs permeability with flow units expressed as a function of pore throat aperture (Aguilera, 2014) as shown in Figure 5.…”

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

“…High‐resolution imaging techniques together with the advanced computational tools/algorithms permit a multi‐scale investigation of fluid flow in shales . The objective here is to simulate the spontaneous and forced imbibition of oil and water throughout a subdomain of the Eagle Ford shale containing a microfracture and investigate the role of microfractures and wettability heterogeneity in shaping two‐phase fluid occupancy profiles.…”

The lattice Boltzmann method for isothermal micro-gaseous flow and its application in shale gas flow: A review

“…Latterly the same techniques were applied but the computation was carried out using a pore-scale GPU-accelerated LB simulator (GALBS) which increases the computing speed (1000 times faster than the serial code and 10 times faster than the paralleled code run on a standalone CPU) [144]. The relative permeability of shale was also studied by Cantisano et al [145] and Nagarajan et al [102]. Nagarajan et al [146] calculated the gas-oil relative permeability of Liquid Rich Shale (LRS) with the LBM and compared their results with laboratory studies.…”