Multiscale investigation of fluid transport in gas shales [electronic resource]
Keywords: Geophysics.

This thesis focuses on developing an improved understanding of fluid flow in gas shales. The problem is studied at multiple scales, and using a variety of approaches spanning several disciplines. In Chapter 2, Adsorption of Methane and Carbon Dioxide on Gas Shale and Pure Mineral Samples, we present measurements of methane and carbon dioxide adsorption isotherms at 40°C on gas shale samples from the Barnett, Eagle Ford, Marcellus and Montney reservoirs. Carbon dioxide isotherms were included to assess its potential for preferential adsorption, with implications for its use as a fracturing fluid and/or storage in depleted shale reservoirs. To better understand how the individual mineral constituents that comprise shales contribute to adsorption, measurements were made on samples of pure carbon, illite and kaolinite as well. The resultant volumetric swelling strain was also measured as a function of pressure/adsorption. In Chapter 3, Experimental Investigation of Matrix Permeability of Gas Shales, we present 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 we used to measure permeability allows us to separate the reduction of permeability with depletion (due to 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) due to 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 10's 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, the same core plugs were crushed and permeability was again measured at the particle scale using the so-called GRI method (GRI, 1989). The results show much lower permeability than the intact core samples, with very little correlation to the measurements on the larger scale cores. In Chapter 4, Critical Evaluation of Pulse Decay Permeability Measurements, we describe in greater detail the approach used to measure the extremely low permeabilities presented in Chapter 3. In Chapter 5, Geomechanical Characterization of the Barnett-2 Study Area, we integrate well logs and other data in order to characterize the state of stress a study area of the Barnett shale prior to hydraulic fracturing. Applying this stress state to the mapped natural fractures indicates that there is significant potential for induced shear slip upon pressurization. The constrained stress state and natural fracture observations presented in this chapter serve as an input to discrete fracture network modeling in Chapter 6. In Chapter 6, Discrete Fracture Network Modeling of the Barnett-2 Dataset, the FMI log observations from Treatment Well 1 presented in Chapter 5 are used to build a discrete fracture network (DFN) for the Barnett-2 study area using a software package called FracMan. Given previously constrained stress state, we calculated the conductive (ie. critically stressed) percolating fracture surface area for each stage. We examined changes in percolation zone area between stages, and qualitatively compared these calculations with DTS production data, microseismic data and a seismic attribute map.