In the South Texas Wilcox play operators often design and execute hydraulic fracture treatments without the benefit of reservoir pressure and effective permeability to gas inputs in all zones. Without reservoir pressure and effective permeability data reasonable estimates of post-frac production performance cannot be made.1–3 Without a reservoir pressure input it is not always clear whether adequate gas reserves are present in each frac stage to recover the stimulation costs for that stage. The more rigorous Net Present Value (NPV) process depends upon realistic reservoir pressure and permeability values.4 Without permeability and reservoir pressure inputs lower quality zones may be treated that have marginal or negative NPV or higher quality zones may not be adequately stimulated to reach their full economic potential. If higher quality zones are combined with lower quality zones in a single frac stage it is not always certain that the higher quality zone will be stimulated at all, much less adequately stimulated to maximize NPV. If lower than expected post frac production rates occur, it is often difficult to determine if these rates are the result of a poor quality reservoir or an ineffective stimulation treatment. In most cases the recommended technique for obtaining reservoir pressure and permeability is a pre-frac transient pressure test. In the South Texas Wilcox, however, these are time consuming and costly and often not practical in wells that require multiple hydraulic fracture stages.
In the Bob West Lopeno Wilcox field one operator elected to acquire wireline reservoir pressures, core permeabilities, and production logs for all zones to aid in the fracture optimization process. From this data a model has been developed that relates reservoir pressure to pre-frac pump in test closure stress and fracture gradient data. A strong correlation was obtained between measured reservoir pressures and both prefrac pump-in test closure and ISIP measurements. An excellent correlation was also obtained between predicted and actual post frac production using the core-based log derived permeability along with reservoir pressure and 3-D frac model inputs. With this new reservoir pressure model and existing petrophysical models, estimates of in-situ stress, permeability, and gas deliverability can be made for all zones in all wells using only wireline logs and pre-frac pump-in test data. Model predictions were validated with post-frac production log results verifying the contribution of each zone at a measured flowing bollomhole pressure. The combination of the models and a simple well production performance model provides a tool to predict post-hydraulic fracture production results and optimize fracture designs in the Lopeno Wilcox formation While the specific equations for reservoir pressure are applicable only to the Bob West Lopeno sands, the methodology employed is relatively straightforward and can probably be adapted to other areas to obtain field specific models.