Proppant distribution directly affects the effectiveness of hydraulic fracturing treatment, and significantly impact well production. In most situations, proppants are not uniformly distributed in hydraulic fractures and most proppants cannot be effectively transported into the far ends of fractures from wellbore. As a result of uneven proppant distribution and the ductile and soft geomechanical properties of the Marcellus shale, the reduction in hydraulic fracture conductivity varies greatly from cluster to cluster in a shale reservoir during reservoir pressure depletion. However, the influences of accurate prediction of uneven proppant distribution in hydraulic fractures and geomechanics on well productivity have been ignored in previous simulation studies.
In this study, a reservoir simulation model for accurate prediction of uneven proppant distribution is developed. This dual-permeability model is coupled with reservoir geomechanics to illustrate the interaction of stress changing and multiphase flow within hydraulic fractures. History matching from a production well in the Marcellus shale is performed to validate our model. In addition, simulations using different matrix permeability are performed to demonstrate the impact of matrix permeability, along with the effect of proppant distributions and geomechanical properties on well performance.
The simulation results show that gas production varies significantly due to different proppant distribution and geomechanical properties. Coupled geomechanical simulation results clearly indicate that the proppant embedding effects are also noticeable due to soft rock mechanical properties and uneven proppant distribution. This paper provides operators with a clear insight of influences of uneven proppant distribution and geomechanics on shale gas performance, optimization of a well treatment design, and an extensive view about the long-term production behavior for the Marcellus shale.