Predicting long-term production from shale gas reservoirs has been a major challenge for the petroleum industry. To better understand how production profiles are likely to evolve with time, we have conducted laboratory experiments examining the effects of confining stress and pore pressure on permeability. Experiments were carried out on intact core samples from the Barnett, Eagle Ford, Marcellus and Montney shale reservoirs. The methodology used to measure permeability allows us to separate the reduction of permeability with depletion (due to the resultant increase in effective confining stress) from the increase in permeability associated with Knudsen diffusion and molecular slippage (also known as Klinkenberg) effects at very low pore pressure. By separating these effects, we are able to estimate the relative contribution of both Darcy and diffusive fluxes to total flow in depleted reservoirs. Our data show that the effective permeability of the rock is significantly enhanced at very low pore pressures (<1000 psi) because of the slippage effects. We utilize the magnitude of the Klinkenberg effect to estimate the effective aperture of the flow paths within the samples, and compare these estimates to SEM image observations. Our results suggest effective flow paths to be on the order from tens of nanometers in most samples to 100–200 nanometers in a relatively high-permeability Eagle Ford sample. Finally, to gain insight on the scale dependence of permeability measurements, we crushed the same core plugs and measured permeability again at the particle scale. The results show much lower permeability than the intact core samples, with very little correlation to the measurements on the larger cores.
A common characteristic of all shale gas reservoirs is their extremely low intrinsic permeability. To produce gas at any significant rate, the rock must first be hydraulically fractured to expose additional surface area and provide greater contact with the reservoir. While fracture properties (both natural and induced) may dominate reservoir performance early in the life of a well, it is the matrix properties that control how a well will perform over longer periods of time. This study focuses on the fluid flow properties of the matrix.
Understanding in-situ matrix permeability and how it evolves with depletion is a major challenge to shale-gas-reservoir characterization and is essential for accurate production forecasting. Therefore, there have been many research efforts to date aimed at this topic. Several of these studies have involved measuring the impacts of stress on matrix permeability. For example, Bustin et al. (2008) measured the sensitivity of permeability to confining pressure at a single pore pressure. In contrast, Kang et al. (2010) measured sensitivity of permeability to pore pressure at a single confining pressure. Kwon et al. (2001) measured intact plug permeability over a range of both pore and confining pressures. Other efforts have aimed at profiling permeability along a well log or length of core. For example, Yang and Aplin (2009) developed a permeability porosity relationship for mudstones using a large permeability data set consisting of both measured values and estimates based on clay content and pore size distribution; however, they did not investigate confining and pore pressure effects. Clarkson et al. (2012) developed a method for profiling permeability along a shale core sample, which was calibrated using pulse permeability measurements on plugs. Finally, several studies have involved efforts to perform rapid permeability on crushed shale samples (GRI, 1989; Luffel et al., 1993; Egermann et al., 2003; Cui et al., 2009).