Evidence of boundary dominated flow behavior in long term production data enables estimation of the pore volume a well is draining.For some tight oil and shale gas wells,the bulk volume computed for an estimated formation porosity is considerably smaller than the stimulated rock volume estimated from expected values for hydraulic frac-ture half-lengths and heights based on models for the stimulation treatments,interwell in-terference observation,and/or microseismic surveys.Because a continuum model for this behavior results in anomalously short apparent fracture half-lengths,this study offers a new model for the observed behavior that accommodates fracture half-lengths consistent with other evidence.The model has an enhanced frac region (EFR)surrounding each hydraulic frac-ture.When multiplied by the number of created hydraulic fractures the enhanced permea-bility volume (EPV)can be matched with that estimated from observed boundary dominated flow.The effective permeability in the EFR is treated as homogeneous or as the bulk fracture permeability of secondary fractures opened by the hydraulic fracturing process.Between adjacent hydraulic fractures is an unproduced zone of much lower perme-ability characteristic of the shale or tight formation matrix.Sensitivity studies illustrate behavior expected for long term rate and pressure transient production behavior.Permeability estimated with this model can be considerably lower than that estimated form a continuum model.The new model is of critical importance to well design and for identifying well candi-dates for refracturing.The model recommends closer spacing of hydraulic fractures to avoid unproduced hydrocarbon between the fractures.Alternatively,refracture can be designed to target fractures in the unproduced hydrocarbon zones.