Conventional reservoir simulators are proven inadequate for shale reservoir simulation because they incorrectly estimate drainage areas, recovery, and economic life of wells. This problem can be alleviated by rigorous modeling and simulation of shale gas reservoir production by considering the effect of heterogeneity, pore-wall slippage, gas rarefaction and desorption on production rate and drainage area of hydraulically-fractured horizontal wells. The present approach is shown to predict longer productive life of shale reservoir wells conforming to field observations.


Ultra-low permeability shale gas wells are hydraulically fractured to enhance the productivity of wells by improving reservoir contact and providing high-conductivity pathways for movement of the gas. The horizontal well completions usually implement several stages of hydraulic fractures intersecting with wellbore at different locations along the lateral. Organic-rich shale gas reservoirs are characterized by a quad-porosity structure that consists of pores in organic material, inorganic material, and natural and stimulation fractures. Each has distinct petrophysical properties, and because of their nanometer pore scale, many of the standard equations and assumptions of the conventional simulators are incorrect.

Effects of gas rarefaction, slippage, and desorption on transport through tight porous media, such as organic rich shale, and the heterogeneity of the organic distribution in shale formations are particularly important. The diameter of extremely narrow pores and flow paths encountered in tight shale formations is comparable to the size of gas molecules. Thus, gas transport occurring in tight formations does not necessarily follow Darcy's law for all flowing conditions (Civan 2010, Andrade et al. 2010, Andrade et al. 2011, Michel et al. 2011a, Michel et al. 2011b, Sigal, 2013). Under these conditions, the slippage of gas molecules occurring at the pore walls is not negligible. Frequently, a semi-empirical model is resorted to correct the intrinsic permeability for accurate representation of slip, transitional, and free-molecular flows (Beskok and Karniadakis, 1999). Additionally, at these nanometer-size pores, the sorption phenomenon occurring in activated pore walls can significantly alter both porosity and permeability (Xiong et al., 2012, Sigal, 2013, Sigal et al., 2013).

This paper simulates the shale gas reservoir production by proper modeling of the physics of fluids in nanometer scale porous media and the microstructure inferred by SEM studies. This is accomplished by incorporating the relevant features and modifications into a commercial simulator. Comparisons of well performance predicted by the simulation runs are presented for several reservoir conditions. Comparisons of results indicate simulations that fully honor the nature of the shale gas reservoir provide production histories, drainage details, and ultimate economic production that can be considerably different from those obtained on comparable models with currently available approaches. These differences result in part from not properly describing the complex pore geometry and fracture system, using storage models that do not properly account for adsorption, and transport models that do not properly account for adsorption and such effects as slippage and rarefaction. Comparison demonstrates the importance of considering the various effects encountered in nanometer-scaled porous materials for predicting the ultimate gas recovery and, ultimately, economics of production for shale-gas wells.

URTeC 1582681

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