Different Flow Behaviors of Low-Pressure and High-Pressure Carbon Dioxide in Shales

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Summary Understanding carbon dioxide (CO2) storage capacity and flow behavior in shale reservoirs is important for the performance of both CO2-related improved oil recovery (IOR) and enhanced gas recovery (EGR) and of carbon sequestration. However, the literature lacks sufficient experimental data and a deep understanding of CO2 permeability and storage capacity in shale reservoirs under a wide range of pressure. In this study, we aimed to fill this gap by investigating and comparing CO2-transport mechanisms in shale reservoirs under low- and high-pressure conditions. Nearly 40 pressure-pulse-transmission tests were performed with CO2, helium (He), and nitrogen (N2) for comparison. Tests were conducted under constant effective stress with multistage increased pore pressures (0 to 2,000 psi) and constant temperature. The gas-adsorption capacity for CO2 and N2 was measured in terms of both Gibbs and absolute adsorption. Afterward, the gas apparent permeability was calculated incorporating various flow mechanisms before the adsorption-free permeability was estimated to evaluate the adsorption contribution to the gas-transport efficiency. The results indicate that He permeability is the highest among the three types of gas, and the characteristic of CO2 petrophysical properties differs from the other two types of gas in shale reservoirs. CO2 apparent porosity and apparent permeability both decline sharply across the phase-change region. The adsorbed phase significantly increases the apparent porosity, which is directly measured from the pulse-decay experiment; it contributes positively to the low-pressure CO2 permeability but negatively to the high-pressure CO2 permeability.