Researchers have studied microstructural controls on permeability of tight-matrix rocks, like coal and shale, in the recent years with growing interest in recovery of unconventional gas from deep rocks. Rock matrix in these reservoirs has significant proportion of microporoisty and, hence, the effective permeability is typically very low. Flow in tight-rock matrix is usually dependent on a complex and dynamic combination of pressure-governed Darcy flow regime in the fractures and macropores and concentration gradient-governed diffusive/non-Darcy flow regime in the meso- and micro- pores. Hence, multiple flow-regimes co-exist at any given pressure in these rocks. In this study, we present the experimental and modeling work carried out on tight coal from the San Juan basin and Marcellus shale. A methodology that uses pore size distribution to estimate the proportion of these dynamically changing and co-existing flow regimes in these rocks is presented. The appropriate proportions of Darcy and non-Darcy flow regime estimated using the methodology is then used in a flow model developed to assess the effective permeability variation of these rocks with depletion, that is, pressure decline. Finally, the stress path sensitivity is included in the model to estimate stress-dependent permeability variation in rocks. The developed model is validated against both coal and shale permeability data. The study establishes that effective permeability is dependent on pore size distribution and stress conditions since both dynamically affect the proportion of multiple co-existing flow regimes in these tight reservoirs.
|State||Published - 2022|