A quantitative analysis of flow properties and heterogeneity in shale rocks using computed tomography imaging and finite-element based simulation

A quantitative evaluation of flow property influenced by micro-scale heterogeneities in shale rocks is presented. Micro-and nano-Computed Tomography images of shale rock samples obtained from Mancos, Marcellus and Eagle Ford formations are digitised into entities such as shale grains, organic matter (kerogen), shale minerals, pores and micro-cracks. Numerical computation on selected layers and sub-micron divisions of the geometries is then carried out using a computationally efficient finite-element based simulation algorithms. Parameters such as pore-volume distribution, porosity, permeability and heterogeneity factor within and across layers are computed as part of pre-and post-process operations. The results of these flow properties characterisation indicated that some shale samples have micro cracks while some do not have. Meanwhile, the presence of micro-cracks in the shale samples contributed to the observed wide variation in permeability and porosity. The static characterisation revealed that different shale rock samples will have different morphological properties. The highest variance in permeability within a layer is of magnitude 5 in Eagle Ford while a magnitude of 2 was computed for Mancos perpendicular. However, magnitudes of 1 and 4 are recorded across layers for Mancos perpendicular and Eagle Ford perpendicular respectively. Contrary to existing assumption that heterogeneity at pore-scale is negligible, it is established from the aforementioned analysis that micro-scale heterogeneity can be quantified. Furthermore, through the analysis of variance and root-mean-square values, it was concluded that tortuosity is inversely related to porosity, permeability and their degree of heterogeneity.