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Shale gas production from organic rich shale formations is one of the most rapidly expanding areas in oil and gas exploration and production today. Because of extremely low permeability and low porosity, long horizontal wells in conjunction with multi-staged massive hydraulic fracturing treatments (HFT) are required to bring economic productions from shale gas reservoirs. It has been recognized that extensive fracture networks with massive contact surface areas are necessary to support economic productions from these reservoirs. Existing natural fractures observed from borehole images (mostly mineral-filled) and the low contrast of minimum and maximum horizontal stresses are some of the key factors in creation of the post-HFT network fracture system in many shale gas reservoirs. Currently, comprehensive design tools for hydraulic fracturing treatments of shale gas reservoirs appear not available. These tools should have the capabilities to incorporate stress field, natural fractures and lithology heterogeneity of the reservoirs and model complicated fracture networks in shale gas reservoirs. However, microseismic mapping has been widely used to monitor hydraulic fracturing job responses, to help control job execution processes, and to evaluate stimulation results. Microseismic responses reflect the collective effects of the reservoir characteristics and hydraulic fracturing treatments, and can be indicative for the productivity of the post-HFT reservoirs. This study presents a practical methodology to model hydraulic fracturing induced fracture networks in shale gas reservoirs as a dual porosity system. This approach decouples complex reservoir characteristics and geomechanical factors from production response. Microseismic responses are used to delineate stimulated volumes from a HFT. Microseismic events and/or natural fracture intensity, along with HFT data and production history-matching analysis, provide calibration for HFT fracture intensity. The calibrated post-HFT fracture network is crucial for production prediction.

The Mississippian Barnett Shale reservoirs have opened a new era for US gas production. Many reservoir characterization efforts have been made and completion practices established to help understand the Barnett Shale reservoirs. The borehole image interpretation, drilling-induced fractures and conductive/healed fractures, reveals stress regime orientation, fracture morphology and their orientations. The interpreted results guide the design of horizontal wells to control hydraulic fracture directions and intensities. Conventional logs and cores have been used to classify lithofacies and estimate petrophysical and geomechanical properties for well positioning and reserve calculations. The seismic survey is not only interpreted for structure horizons and faults, but also analyzed for 3D property evaluations such as lithofacies distribution, discrete fracture network, and stress field. On the operation side, longer horizontal wells are drilled and massive multistage, multicluster hydraulic fracturing treatments (HFT) are executed. Various well placement and HFT schemes are performed. The microseismic (MS) has played an important role in understanding the estimation of hydraulic fracturing stimulated reservoir volume (ESV) and fracture intensities. In spite of this tremendous effort and progress, a systematic methodology appears lacking in the literature to integrate the variety of information and obtain accurate reservoir characterizations. In this paper, we present an integration workflow that incorporates seismic interpretations and attributes, borehole image and log interpretations, core analysis, HFT, and microseimic data to construct reservoir models and discrete fracture networks that are then upscaled to dual-porosity reservoir models for numerical simulation. The application of this workflow in field studies has revealed important observations and provided better understanding of the reservoirs. This integration workflow demonstrates an effective methodology for capturing the essential characteristics of Barnett Shale gas reservoirs, and offers a quantitative means and platform for optimizing shale gas production. Introduction Driven by gas consumption demand and rising oil and gas prices in the past several years, Barnett Shale gas production has gained momentum. The characteristics of the Barnett Shale reservoir can be typically described as extremely low permeability (100-600 nano-Darcys), low porosity (2-6%), and moderate gas adsorption (gas content 50-150 scf/ton). The general Barnett Shale reservoir deposition settings, lithofacies, natural fracture characterization, and production evaluation can be found in Louks et al. (2007), Gale et al. (2007), and Frantz et al. (2005). In order to achieve economical production and enhance productivity, a large number of horizontal wells have been drilled and massive multistage HFT jobs have been performed. Due to the complex nature of the Barnett reservoirs which is vastly different than that of conventional or other types of unconventional reservoirs, it is difficult to obtain a clear understanding and an accurate description of the reservoir. To quickly acquire knowledge and guide imminent placement (well spacing and pattern) designs, various well spacing pilots (e.g., 500 ft, 1,000 ft, and 1,500 ft, etc.) were drilled and various hydraulic fracturing operation schemes such as "zipper-frac" and "simul-frac" have been invented and tested (Waters et al., 2009).

TX 75083-3836, U.S.A., fax +1-972-952-9435. AbstractProducing natural gas from shale gas reservoirs has gained momentum over the past few years in North America and will become an increasingly important component of the world's energy supply. A shale gas reservoir is characterized as an organic-rich deposition with extremely low matrix permeability and clusters of mineral-filled "natural" fractures. Shale gas storage capacity is defined by the adsorbed gas on the organic material within the shale matrix and free gas in the limited pore space of the shale rocks. Horizontal drilling and hydraulic fracturing are the primary enabling technologies to obtain economical production from the shale gas reservoir. This paper presents a comprehensive reservoir simulation model to study the impact of reservoir and hydraulic fracturing parameters on production performance of a shale gas reservoir. The simulation model was constructed as a multi porosity system with matrix sub-grids to account for transient gas flow from the matrix to the fracture. The extended Langmuir isotherm was used to model the desorption process of multiple components during the production. Primary hydraulic fractures perpendicular to the horizontal wellbore were modeled explicitly with thin grid cells that preserved the finite conductivity. The hydraulically-induced fracture network around the horizontal well was characterized by the matrix-fracture coupling factor (sigma) and permeability of the fractures.The study was aimed to quantify the influence of the reservoir and hydraulic fracture parameters using experimental design, including porosity and permeability of the reservoir matrix and fracture, matrix-fracture sigma factor, matrix subdivisions and, primary hydraulic fracture half-length, height, spacing and conductivity, rock compaction, non-Darcy flow coefficient, as well as gas content. Sensitivity tests were performed to identify the most influential reservoir and hydraulic fracture parameters and provided important insights into the impact of uncertainties on shale gas production forecasts, which can be critical for fracture treatment design and production scheme optimization.