Pore pressure is a critical input to a geomechanical model and impacts the mechanical stability of a well. It is also desirable to map the high pressure areas before drilling decisions are made as wells that intersect these zones are typically more prolific producers. A well-based workflow was developed that was able to predict the recorded pore pressure and then calibrate a geomechanical model which matched the wellbore measurements. This model was then tested on wells with the requisite log dataset and was able to replicate the observed mechanical wellbore behavior, highlighting the accuracy of the pore pressure prediction. The resultant models were then applied to a high-resolution 3D seismic inversion encompassing key elastic properties and facies prediction to produce a 3D understanding of the distribution of pressure and stress. 


Based on wireline logs, core data, and pressure information obtained during drilling, the various shale units within the Wolfcamp Formation in the Delaware Basin are known to be variably pressured with depth, and the pressure can change laterally within the same rock formation. Zones with anomalous high pressure are generally linked to wells with better production rates. Unknown overpressured areas are also considered a drilling hazard and being able to predict these cells is of high interest. Pore pressure prediction using on-shore seismic data is not trivial as the relationship between porosity and overpressure is complicated by a relatively complex geological history. In these environments, the typical variation observed in seismic velocities may not relate directly to changes in pressure; for example, the presence of gas, and the presence of TOC can both act to slow the velocity which mimics a pressure response that is actually erroneous. Pressure variations can be difficult to measure in these low permeability formations, making calibration difficult.