Various attempts have been made to model flow in shale gas systems. However, there is currently little consensus regarding the impact of molecular and Knudsen diffusion on flow behavior over time in such systems. Direct measurement or model-based estimation of matrix permeability for these "ultra-tight" reservoirs has proven unreliable. The composition of gas produced from tight gas and shale gas reservoirs varies with time for a variety of reasons. The cause of flowing gas compositional change typically cited is selective desorption of gases from the surface of the kerogen in the case of shale. However, other drivers for gas fractionation are important when pore throat dimensions are small enough. Pore throat diameters on the order of molecular mean free path lengths will create non-Darcy flow conditions, where permeability becomes a strong function of pressure. At the low permeabilities found in shale gas systems, the dusty-gas model for flow should be used, which couples diffusion to advective flow. In this study we implement the dusty-gas model into a fluid flow modeling tool based on the TOUGH+ family of codes. We examine the effects of Knudsen diffusion on gas composition in ultra-tight rock. We show that for very small average pore throat diameters, lighter gases are preferentially produced at concentrations significantly higher than in situ conditions. Furthermore, we illustrate a methodology which uses measurements of gas composition to more uniquely determine the permeability of tight reservoirs. We also describe how gas composition measurement could be used to identify flow boundaries in these reservoir systems. We discuss how new measurement techniques and data collection practices should be implemented in order to take advantage of this method. Our contributions include a new, fit-for-purpose numerical model based on the TOUGH+ code capable 123 254 C. M. Freeman et al.of characterizing transport effects including permeability adjustment and diffusion in microand nano-scale porous media.

In this paper we analyze by means of numerical simulation the mechanisms and processes of flow in two types of fractured tight gas reservoirs: shale and tight-sand systems. The numerical model includes Darcy's law as the basic equation of multiphase flow and accurately describes the thermophysical properties of the reservoir fluids, but also incorporates other options that cover the spectrum of known physics that may be involved: non-Darcy flow, as described by a multi-phase extension of the Forschheimer equation that accounts for laminar, inertial and turbulent effects; stress-sensitive flow properties of the matrix and of the fractures, i.e., porosity, permeability, relative permeability and capillary pressure; gas slippage (Klinkenberg) effects; and, non-isothermal effects, accounting for the consequences of energy balance and temperature changes in the presence of phenomena such as Joule-Thompson cooling in the course of gas production. The flow and storage behavior of the fractured media (shale or tight sand) is represented by various options of the Multiple Interactive Continua (MINC) conceptual model, in addition to an Effective Continuum Method (ECM) option, and includes a gas sorption term that follows the Langmuir isotherm. Comparison to field data, analysis of the simulation results and parameter determination through history matching indicates that (a) the ECM model is incapable of describing the fractured system behavior, and (b) shale and tight-sand reservoirs exhibit different behavior that can be captured (albeit imperfectly) using some of the more complex options of the multi-continua fractured-system models. The sorption term is necessary to describe the behavior of shale gas reservoirs, and significant deviations from the field data are observed if it is omitted. Conversely, production data from tight-sand reservoirs can be adequately represented without accounting for gas sorption. All the other processes and mechanisms allow refinement of the match between predictions and observations, but appear to have secondorder effects in the description of flow through fractured tight gas reservoirs. IntroductionBackground. Tight sand and shale gas reservoirs have recently emerged as a potentially huge resource, and production from such reservoirs has seen an explosive growth over the last few years. Ultratight reservoirs present numerous challenges to modeling and understanding. These reservoirs typically require fracture stimulation, which create complex flow profiles. Additionally, according to Hill and Nelson (2000), between 20 and 85 percent of total storage in shales may be in the form of adsorbed gas. Production from desorption follows a nonlinear response to pressure and results in unintuitive and difficult-tomodel pressure profile behavior. Closed or open natural fracture networks in ultratight reservoirs introduce further complexity through interaction with the induced fractures.The explosion in production has not been accompanied with the same level of understanding of the basic principles th...

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Various models featuring horizontal wells with multiple fractures have been proposed to characterize flow behavior over time in tight gas systems and shale-gas systems. Currently, little is known about the effects of nonideal fracture patterns and coupled primary-/secondary-fracture interactions on reservoir performance in unconventional gas reservoirs.We developed a 3D Voronoi mesh-generation application that provides the flexibility to accurately represent various complex and irregular fracture patterns. We also developed a numerical simulator of gas flow through tight porous media, and used several Voronoi grids to assess the potential performance of such irregular fractures on gas production from unconventional gas reservoirs. Our simulations involved up to a half-million cells, and we considered production periods that are orders of magnitude longer than the expected productive life of wells and reservoirs. Our aim was to describe a wide range of flow regimes that can be observed in irregular fracture patterns, and to fully assess even nuances in flow behavior.We investigated coupled primary/secondary fractures, with multiple/vertical hydraulic fractures intersecting horizontal secondary "stress-release" fractures. We studied irregular fracture patterns to show the effect of fracture angularity and nonplanar fracture configurations on production. The results indicate that the presence of high-conductivity secondary fractures results in the highest increase in production, whereas, contrary to expectations, strictly planar and orthogonal fractures yield better production performance than nonplanar and nonorthogonal fractures with equivalent propped-fracture lengths.