Gas permeability tests on core plugs from unconventional reservoir rocks under controlled stress: A comparison of different transient methods

Abstract

Accurate and routinely applicable methods to determine porosities and permeability coefficients are needed in order to ensure effective hydrocarbon recovery in shale and tight sandstone plays. In this study 129 gas uptake measurements (“GRI method”, “inflow” experiments) were performed on core plugs from three unconventional reservoir lithotypes (oil shales, gas shales and tight gas sandstones) under elevated effective stress conditions. The results were compared to those from “flow-through” tests (standard pulse decay) under similar experimental conditions, e.g. the same gas type and pore pressure range. The samples covered a porosity range from 1.3% to 12%. Equilibration times ranged from 102 s to 104 s and permeability coefficients from 10−18 to 10−21 m2. In order to successfully determine apparent gas permeability coefficients and porosities and to reliably interpret fluid dynamic effects from gas uptake data it is necessary to ensure a sufficiently high excess pressure drop during the uptake tests. This can be controlled by adjustment of the reservoir to pore volume ratio and initial differential pressure. Permeability coefficients derived from uptake tests on all six samples do not show any systematic deviations from those obtained from flow-through measurements. Best results were achieved for a core plug from the Lower Palaeozoic Alum Shale (Djupvik, Öland, Sweden), where Klinkenberg regressions of inflow and flow-through differ only by 4% (slope) and 10% (y-axis intercept). Here, the gas storage capacity ratio was ≈2.5 and excess pressure drops ranged from 0.1 to 1.2 MPa. Generally, measurement errors were lowest when excess pressure drops during uptake were at least 0.05 MPa for all samples. Excess pressure drops of less than 0.05 MPa resulted in coefficients of variance of single apparent gas permeabilities of ≈10%–100%, whereas excess pressure drops of >0.05 MPa resulted in coefficients of variance of ≈2%–15%. We show that it is possible to adjust the initial conditions of inflow measurements such, that Klinkenberg-corrected permeability coefficients and gas slippage factors can be readily determined. This will contribute significantly to a better understanding of the effects of anisotropy and/or the pore structure on the transport properties of unconventional lithotypes under elevated stress conditions. However, standard deviations of single apparent permeability coefficients derived from inflow experiments are higher by up to one order of magnitude than for those obtained from flow-through tests under all tested conditions.