Experimental investigation of matrix permeability of gas shales

Predicting long-term production from gas shale 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 conducted 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 (because of the resultant increase in effective confining stress) and 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 [<6.9 MPa]) because of the slippage effects. We use the magnitude of the Klinkenberg effect to estimate the effective aperture of the flow paths within the samples and compare these estimates to scanning electron microscopy image observations. Our results suggest effective flow paths to be on the order from tens of nanometers in most samples to 100–200 nm, in a relatively high-permeability Eagle Ford sample. Finally, to gain insight on the scale dependence of permeability measurements, the same core plugs were crushed, and permeability was again measured at the particle scale using the so-called Gas Research Institute method. The results show much lower permeability than the intact core samples, with very little correlation to the measurements on the larger scale cores. Copyright ©2014. The American Association of Petroleum Geologists. All rights reserved. Manuscript received February 11, 2013; revised manuscript received June 10, 2013; revised manuscript received July 29, 2013; revised manuscript received August 15, 2013; revised manuscript received August 19, 2013; accepted September 23, 2013. DOI: 10.1306/09231313023 AUTHORS Rob Heller ∼ Department of Geophysics, Stanford University, Stanford, California 94305; rjheller@stanford.edu Rob Heller earned his Ph.D. in geophysics from Stanford University in 2013. His thesis was titled “Multiscale Investigation of Fluid Flow in Gas Shales”, and his adviser was Dr. Mark Zoback. He earned his M.S. degree from Stanford University in environmental engineering in 2008, and a B.S. degree from Columbia University in 2007. John Vermylen ∼ Department of Geophysics, Stanford University, Stanford, California 94305; john.vermylen@gmail.com John Vermylen earned his Ph.D. in geophysics from Stanford University in 2011. His thesis was titled Geomechanical Studies of the Barnett Shale, and his adviser was Mark Zoback. Vermylen earned his M.S. degree in geophysics from Stanford University in 2008, and his B.S. degree from Princeton University in 2005. Mark Zoback ∼ Department of Geophysics, Stanford University, Stanford, California 94305; zoback@stanford.edu Mark Zoback is the Benjamin M. Page Professor of geophysics at Stanford University. His research focuses on in-situ stress, fault mechanics, and reservoir geomechanics with an emphasis of shale gas, tight gas, and tight oil production. He is the author of a textbook entitled Reservoir Geomechanics, published in 2007 by Cambridge University Press. He holds a Ph.D. and an M.S. degree in geophysics from Stanford University.