The natural gas from Marcellus Shale can be produced most efficiently through horizontal wells stimulated by multi-stage hydraulic fracturing. The objective of this study is to investigate the impact of the geomechanical factors and non-uniform formation properties on the gas recovery for the horizontal wells with multiple hydraulic fractures completed in Marcellus Shale.

Various information including core analysis, well log interpretations, completion records, stimulation design and field information, and production data from the Marcellus Shale wells in Morgantown, WV at the Marcellus Shale Energy and Environment Laboratory (MSEEL) were collected, compiled, and analyzed. The collected shale petrophysical properties included laboratory measurements that provided the impact of stress on core plug permeability and porosity. The petrophysical data were analyzed to estimate the fissure closure stress. The hydraulic fracture properties (half-length and conductivity) were estimated by analyzing the completion data with the aid of a commercial P3D fracture model. In addition, the information from the published studies on Marcellus Shale cores plugs were utilized to determine the impact of stress on the propped fracture conductivity and fissure permeability. The results of the data collection and analysis were utilized to generate a base reservoir model. Various gas storage mechanisms inherent in shales, i.e., free gas (matrix and fissure porosity), and adsorbed gas were incorporated in the model. Furthermore, the geomechanical effects for matrix permeability, fissure permeability, and hydraulic fracture conductivity were included in the model. A commercial reservoir simulator was then employed to predict the gas production for a horizontal well with multi-stage fracture stimulation using the base model. The production data from two horizontal wells (MIP-4H and MIP-6H), that were drilled in 2011 at the site, were utilized for comparison with the model predictions. The model was then also used to perform a number of parametric studies to investigate the impact of the geomechanical factors and non-uniform formation properties on hydraulic fractures and the gas recovery.

The matrix permeability geomechanical effect was determined by an innovative method using the core plug analysis results. The results of the modeling study revealed that the fracture stage contribution has a more significant impact on gas recovery than the fracture half-length. Furthermore, the predicted production by the model was significantly higher than the observed field production when the geomechanical effects were excluded from the model. The inclusion of the geomechanical factors, even though it reduced the differences between the predictions and field results to a large degree, was sufficient to obtain an agreement with field data. This lead to the conclusion that various fracture stages do not have the same contribution to the total production. Based on well trajectory, variation in instantaneous shut-in pressure ISIP along the horizontal length, shale lithofacies variation and natural fracture (fissure) in the reservoir, it is possible to estimate the contribution of different stages to the production for both wells MIP-4H and MIP-6H.

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