I present a stratigraphically layered dual-permeability model composed of thin, alternating, high (~9.2 x 10⁻²⁰ m²) and low (~3.0 x 10⁻²² m²) permeability layers to explain pressure dissipation observed during pulse-decay permeability testing on an intact Barnett Shale core. I combine both layer parallel and layer perpendicular measurements to estimate layer permeability and layer porosity. Micro-computed x-ray tomography and scanning electron microscopy confirm the presence of alternating cm-scale layers of silty-claystone and organic-rich claystone. I interpret that the silty-claystone has a permeability of 9.2 x 10⁻²⁰ m² (92 NanoDarcies) and a porosity of 1.4% and that the organic-rich claystone has a permeability of 3.0 x 10⁻²² m² (0.3 NanoDarcies) and a porosity of 14%. A layered architecture explains the horizontal (k [subscript H] = 107 x 10⁻²¹ m²) to vertical (k [subscript V] = 2.3 x 10⁻²¹ m²) permeability anisotropy ratio observed in the Barnett Shale. These core-scale results suggest that spacing between high-permeability carrier beds can influence resource recovery in shales at the reservoir-scale. I also illustrate the characteristic pulse-decay behavior of core samples with multiple mutually-orthogonal fracture planes, ranging from a single planar fracture to the Warren and Root (1963) "sugar cube" model with three mutually-orthogonal fracture sets. By relating sub core-scale matrix heterogeneity to core-scale gas transport, this work is a step towards upscaling experimental permeability results to describe in-situ gas flow through matrix at the reservoir scale. / text
| Identifer | oai:union.ndltd.org:UTEXAS/oai:repositories.lib.utexas.edu:2152/28229 |
| Date | 02 February 2015 |
| Creators | Cronin, Michael Brett |
| Source Sets | University of Texas |
| Language | English |
| Detected Language | English |
| Type | Thesis |
| Format | application/pdf |
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