Characterization and Measurement of Multi-scale Gas Transport in Shale Core Samples

This work introduces an experimental technique to probe simultaneously flow and diffusion of gas through shale. A core-scale pressure pulse decay experiment is utilized to study the upstream and downstream pressure responses of Eagle Ford and Haynesville shale samples. With the aid of numerical models, the pressure curves obtained from the experiments are history-matched, and gas and rock properties are obtained. The experiments are conducted at varying pore pressure and net effective stress to understand the sensitivity of the rock porosity and permeability as well as the gas diffusivity. A dual porosity model is constructed to examine gas transport through a system of micropores and microcracks. In this sense, the role of the two different size pore systems is deconvolved. In some cases, the micropore system carries roughly a third of the gas flow. The porosity, permeability, and diffusivity obtained assign physical properties to the macroand micro-scales simultaneously. Results bridge the gap between these scales and improve our understanding of how to assign transport physics to the correct pore scale. Introduction The shale revolution and the need to develop a mechanistic understanding to improve flow prediction capabilities have instigated extensive technical studies of gas transport through the microcrack and micropore networks of shales. Most of these studies focused on understanding the fundamentals of fluid transport in shales. Some of which focused on permeability measurements in shales as found in Javadpour (2009), Civan et al. (2012), Allan and Mavko (2013), Alnoaimi and Kovscek (2013) and Cui et al. (2009) and others on sorption measurements as found in Clarkson et al. (2013), Aljamaan et al. (2013), and Kang et al. (2010). Unlike conventional resources, the fraction of porosity associated to micropores in shale sediments (i.e., mudstone) is not negligible and has considerable influence on gas transport (Javadpour et al., 2007). The pore-size classification used in this study is as recommended by the International Union of Pure and Applied Chemistry (IUPAC) where macropores > 50 nm, mesopores range between 2 nm and 50 nm, and micropores < 2 nm. Shales consist of interconnected media: organic matter such as kerogen; inorganic matrix such as quartz, clays, calcite, and feldspar; natural; and induced microcracks (Wang et al., 2009). Micropores are mostly found in the organic matter and clays (Wang et al., 2009). Unlike transport in sandstones, gas adsorption to shale surfaces and diffusion cannot be ignored because micropores are abundant. Small pore size enhances gas slippage along pore walls and needs to be quantified. Shale rocks are extremely low-permeability heterogeneous systems that are a major source of gas storage and production. The variation in shale petro-physical properties is significant even for cores taken from the same field and depth. This makes the prediction of gas transport in shale a great challenge. Many references have proposed various physical and mathematical description of gas transport in shales (Bustin et al., 2008; Javadpour, 2009; Freeman, 2010; Ozkan et al., 2010). There is, however, no clear validation of the proposed physics and mathematical derivations of gas transport in the macroand micro-scale with laboratory data at core-scale. At reservoir scale, gas production is facilitated by the creation of hydraulic fractures and the use of horizontal wells. This makes the physics of gas production mainly governed by Darcy flow through fractures. With non-fractured core sample at the laboratory scale, however, the significance of Darcy effects is substantially minimized and diffusion processes are thought important. The references indicated previously simulated shale gas field production with the exception of Akkutlu and Fathi (2011) who matched core analysis with simulation results. URTeC 2014 Page 1140