The growth of hydraulically induced fractures can be very complex; this is especially true when fractures are initiated from horizontal wells that are drilled in naturally-fractured reservoirs (such as shale gas) where the hydraulic fracturing process leads to swarms of fractures forming complex three dimensional (3D) fracture networks. Traditional modeling methods, suitable for simple (penny-shaped) fracture geometries, oversimplify the 3D extent of a fracture swarm and fail to capture the real extent of the drainage volume, inevitably leading to unreliable production forecasts.

It is possible to estimate the extent of the stimulated volume for each stage of a hydraulic fracturing job from microseismic data. The Volumetric Fracture Modeling Approach (VFMA) then models the fracture network as a 3D volume with fracture properties described by variations of dual porosity parameters. The VFMA was successfully applied to modeling a horizontal well in the Barnett Shale with multiple hydraulic fractures. An automated history-matching procedure was used to estimate the productive volume from the initially stimulated volume.

The VFMA is especially suitable for multi-well or full-field simulation where other fracture modeling methods may not work due to gridding or simulator performance constraints. Using the VFMA, it is possible to obtain the real extent i.e. the drainage volume, of complex fracture networks in shale gas reservoirs. Understanding the drainage volume allows for well spacing optimization, which in turn determines the total well count, and ultimately the cost of field development.