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.

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Recently, we have developed a new methodology to model hydraulic fracturing-induced fracture networks and subsequently simulate a shale gas reservoir as a dual-porosity system. The reservoir geological, geophysical and petrophysical characteristic data are integrated to build geological framework and property models. Microseismic responses are used to delineate stimulated reservoir volumes. Microseismic events and/or natural fracture intensity are utilized to estimate the initial intensity of this induced fracture network. The fracture intensity is further calibrated using hydraulic fracturing job data and reservoir geomechanical properties through a fracture propagation mechanism. In this paper, we show a significant extension of the modeling methodology to handle more general scenarios of stimulated shale reservoirs. We introduce a superposition technique to process the overlapping of microseismic mapping responses from different stages of "simul-frac" and/or "zipper-frac" operations in a single well or in multiple wells. The improved method takes into account different fracture network geometries. Various models for volume expansion by stimulation are investigated for proppant placement estimations. In the ideal viscous fluid-proppant transportation scenario, proppant and fracture conductivity distributions can be calculated with mass conservation corresponding to different fracture network geometries and volume expansion models. Both fracture intensity and fracture network conductivity are used to create dual porosity simulation model inputs. Considering that for most shale gas wells there is no microseismic data, we introduce a modeling procedure incorporating treatment data and geomechanical parameters in which the fracture network geometry can be specified based on well completion data and field experience. We also present the general workflow through a demo case from data input, fracture network geometry configuration, calibration and calculations, and output of dual-porosity model parameters for reservoir simulation. This extended methodology can be efficiently applied not only to modeling of singlewell shale gas reservoir but also to modeling of multiple wells where their drainage volumes are inter-connected. A field example demonstrates the applications of the new modeling methodology, which provides a unique, effective means for modeling and simulation study as well as history-matching calibration of stimulated shale gas reservoirs.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNew innovative approaches are now available that enable three dimensional (3D) seismic data to be rapidly screened, evaluated, and interpreted in a period of weeks, rather than months. This provides a quick and effective way to identify and define prospective targets to help optimize exploration and production (E&P) activities leading to a major impact on the net present value (NPV) of the field.The rapid seismic screening process identifies major structural and stratigraphic features, blends the major stratigraphic features with 3D attributes, and locates amplitude anomalies via 3D Voxel screening. This process applied to 3D data from the Gulf of Mexico has revealed numerous large undrilled structures in the deeper section below and adjacent to existing fields associated with sand-prone low-stand facies. This approach for screening 3D seismic data sets reduces the risks normally associated with conventional evaluation methods. Its use significantly reduces 3D seismic evaluation time and increases information quality, helping asset managers find and evaluate drilling opportunities quickly and accurately.Improvements on project economics through the use of this process are demonstrated in a number of economic impact analyses. Typical values of production, commodity prices, and costs from a Gulf of Mexico region are used in various cases to quantify the economic benefits of the rapid seismic screening process. The economic impact of this rapid seismic screening and interpretation approach can be clearly shown.

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