Summary

Many stimulated shale‐gas wells experience surprisingly low fracturing‐fluid recoveries. Fracture closure, gravity segregation, proppant distribution, and shut‐in (soaking) time have been widely postulated to be the contributing factors. This study examines the effects of these factors on fracturing‐fluid distribution and subsequent well performance using flow and geomechanical simulations. In the end, two real‐field examples are used to validate the findings in this study.

Geomechanical simulation is used to capture the complex post‐closure fracture geometry caused by nonuniform proppant distribution. The geometry is then passed into a series of 3D numerical flow models that are constructed using petrophysical parameters, fluid properties, and operational constraints representative of the Horn River shale‐gas reservoir. Within the flow simulation, the hydraulic fracture is represented explicitly in the computational domain by means of local‐grid refinement, and the physical process of fracture closure during shut‐in and production periods is modeled by adjusting the fracture volume and fracture conductivity dynamically. Non‐Darcy behavior caused by high gas velocity in the fracture and matrix desorption are considered. The results of the geomechanical simulation confirm the formation of a residual opening above the proppant pack in a partially propped fracture. The residual opening offers a highly conductive flow path for the gas, which is much more mobile than the water‐based fracturing fluid, and this difference in mobility further aggravates gravity segregation. Gravity segregation might lead to water accumulating near the bottom of a vertical planar fracture, but reduced fracture conductivity could limit the segregation and promote a more uniform fluid distribution. Water uptake into the matrix is influenced by forced and spontaneous imbibition caused by the large pressure differential across the matrix/fracture interface and matrix capillarity. Additional water is displaced into the matrix as pressure depletes and the fracture closes. Fracturing‐fluid‐penetration depth increases with shut‐in time, resulting in an enhancement in the initial gas rate, but lower late‐time production is also observed.

Analysis of the residual opening of a partially propped fracture and its role in fracturing‐fluid distribution in three dimensions is novel. Field examples suggest that considering the various physical mechanisms investigated in this study could improve the accuracy of the numerical model for history matching and the reliability of the ensuing production forecasting. The findings in this study might provide a better understanding of fracturing‐fluid distribution, which is useful for optimizing production strategies and operations concerning hydraulically fractured shale‐gas reservoirs.

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