Summary

Natural gas produced from shale represents an important emerging energy supply not only in the United States but across the globe. Proper understanding of shale petrophysical properties is essential for accurate reserve estimations, recovery factor predictions, potential enhanced recovery techniques, and carbon sequestration. Due to matrix permeability in the range of a nanodarcy and porosity less than 10%, numerous challenges are faced to garner data in the laboratory regarding the physics and flow behavior of these shale rocks. The main question addressed here is the sensitivity of shale physical properties to the gas saturating the pore space. The paper presents apparent Klinkenberg permeability measurements at different pore and confining pressures. The advantage of using helium gas in this context is that it aids the study of slip flow without any complicating effects of gas sorption on permeability. Helium permeability and porosity are compared to nitrogen, methane, and carbon dioxide results for Barnett and Eagle Ford shale samples. The effect of sorption on permeability is inferred. Results show decreased permeability with increased sorption. Gibb's excess sorption is measured utilizing the volumetric method and confirms the impact of sorption on the storage capacity and permeability of shale. Because of the small size of helium molecules, initial speculation suggested that helium measured porosity is greater than the effective methane porosity leading to overestimated shale pore volumes. Experimental results reported here for several shale samples, however, indicate otherwise.

Introduction

Natural gas, composed mainly of CH4, is an important source of energy worldwide and is cleaner when combusted in comparison to coal and oil. Due to the large demand for gas and the decline of current conventional gas reservoirs, unconventional gas resources have been of primary interest, especially in the United States. One of the major challenges associated with shale is quantification of its petrophysical properties because of extremely low matrix permeability (order nanodarcy), that is hard to measure and examine accurately.

Better knowledge of laboratory-scale physics is important to improve understanding of transport mechanisms and flow behavior. Such understanding provides insights for better simulation models and the constitutive relations that such models require. Mechanistic understanding aids planning, and field development leading, to optimal gas production. It also improves our ability to evaluate concepts such as carbon sequestration in depleted gas shales, enhanced gas recovery, and the use of CO2 as a hydraulic fracturing fluid. Clearly, knowledge of the relationship among shale porosity, permeability, state of stress, and the gas saturating the pore space aids evaluation, planning, and development exercises. This paper presents a core-scale petrophysical characterization of Barnett and Eagle Ford shale samples. The main emphasis is the type of gas saturating the pore space and the role of gas in determining shale permeability. This work complements a prior study where we describe an X-ray computed tomography technique for imaging the spatial distribution of porosity in cores at the millimeter scale (Vega et al, 2013). Identical core samples are used in this and the prior study.

URTeC 1582146

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