Data collected from a passive instrumented monitor well was used to differentiate conductive fracture length and fracture density generated by three different completion designs in the Midland basin. The monitor well was drilled slanting laterally away from a nearby producer and instrumented with fiber optics and a pressure gauge array. The fiber and gauges were monitored during stimulation of the offset well to measure the evolution of created fracture geometry as a function of distance, as well as at various times during production to infer conductive fracture geometries. Integrating the data sets permitted comparison between created fracture geometry and productive dimensions over time while also providing a better understanding of the heterogeneity of conductive fracture lengths within and amongst stages.
Both fiber and pressure measurements complemented each other to discern clear differences in the conductive fracture lengths between the 3 completion designs. The maximum conductive half-length and the distribution of smaller fractures detected by fiber both showed trends in stimulated rock volume between the different designs, while also quantifying the non-uniformity of fracture lengths generated from each stage. These trends were confirmed by the pressure depletion from each stimulation design as a function of distance from the stimulated well, as well as a novel pressure analysis method to infer fracture density. Together, these results have informed on subsequent decisions on stimulation design and well spacing.