In hydraulic fracture treatment programs microseismic imaging is often used to determine geometrical dimensions of the fracture network. The geometrical dimensions can be measured using fracture lengths, widths, and heights, or as an estimation of the potential volume that will contribute to production typically referred to as the stimulated reservoir volume (SRV). These SRV values are often used in reservoir models to plan and optimize a completion plan. Most techniques involve simply fitting a volume to these events. However, microseismic events also provide information on the deformation, energy and stress release and other seismic parameters that can possibly be used to constrain and provide realistic SRV estimates. In this paper, we investigate how SRV values vary by comparing standard approaches, with values as calculated based on seismic deformation and by taking into account the source types and fracture orientations derived from Seismic Moment Tensor Inversion (SMTI) to define regions of Enhanced Fluid Flow (EFF), akin to SRV estimates for fracture networks with propped or opening components of failure. By using a representative microseismic dataset from a shale gas play in North America, differences in approach are considered, and we conclude that EFF derived SRV estimates are likely a better reflection and more accurate representation of potential yields and estimates of reservoir volume.