Permeability is an important parameter relative to the production of hydrocarbons in shale oil/gas plays; however, the measurement of permeability in these nano-to microdarcy rocks remains a challenge. Results from different methods or from different laboratories are not consistent, and reasons are not fully understood. In the present study, permeability is measured for both plug and crushed-rock samples with different plug diameter or crushed-sample particle size to systematically investigate the permeability measurement to better understand and apply the measured results. A modified gas-expansion (MGE) method, which can measure permeability for plug samples under confining pressures, was established and applied to several Eagle Ford and Barnett Shale (mudrock) samples. Permeability results from this method are in fair agreement with those from the pulse-decay method. The traditional Gas Research Institute (GRI) method was applied to crushed-rock Eagle Ford Shale samples. The results were comparable to reported permeability for an Eagle Ford Shale sample. Particle or plug size has significant influence on permeability measurement. In general, permeability increases with increasing particle or plug size. For crushed sample with GRI method, the reason of increasing permeability is related to the limitation of the GRI technique and the data analysis method. Estimate of the permeability based on Kozeny-Carman Equation was conducted, and the results were used to evaluate the GRI permeability measurement. Particle size of 2-4 mm (5-10 meshes) is considered as an appropriate size for GRI permeability measurement. For plug sample, larger permeability with larger plug diameter is most likely caused by the artificial fractures. Higher confining pressure can reduce the influence of the fractures, but cannot fully remove it. A range of permeability, defined by the GRI permeability with 2-4 mm particles as the lower boundary and permeability of 1-in plug under high confining pressure (>5000 psi) as the upper boundary, 3 can be a more reliable measures to represent the shale matrix permeability. The range of the permeability also highlights the uncertainty in matrix permeability measurement for shale.

Although pore-network characterization of shale rock systems is being actively investigated, a detailed understanding of the pore network at the nanometer-to-millimeter scale has not been completed. This is because of the technical limitations of collecting and integrating data at the wide spectrum of scales necessary to understand the pore network. Permeability for a micrometer-scale volume can be estimated based on pore-scale modeling for the focused ion beam/scanning electron microscope (FIB/SEM) milled 3D pore network; however, it is not clear how representative this permeability is for larger volumes. In this study, an integrated method employing FIB/SEM, helium ion microscopy, and synchrotron X-ray micro-computed tomography (micro-CT) was developed and applied to a Barnett Shale sample for pore and organic-matter distribution network characterization and upscaling. Organic-matter particle network characterization using synchrotron micro-CT scanning is the key step that bridges the gap between nanometer-scale and macroscopic observations. A conceptual model and an empirical equation were developed for permeability estimation based on FIB/SEM and micro-CT image analysis and mercury intrusion data. Upscaled permeability estimation was produced based on the empirical equation and parameters from the image and mercury intrusion analysis. The resulting permeability values of 2-22 and 0.6-3 nD for parallel and perpendicular to bedding planes, respectively, are comparable to laboratory measurements of the same sample. The proposed technique provides a method for more basic understanding of the pore network and pore-permeability relationship for organicrich shale samples, and can serve as a basis for further upscaling to core and formation scale.

No abstract