Abstract
Hydraulic fracture calibration in an unconventional environment is a complex process and is inconsistently practiced. Automated calibration methods are not effective or efficient in accounting for the heterogeneity and variation of constraining parameters. However, it is important to build a consistent methodology to calibrate hydraulic fractures incorporating the observed data. This paper covers the systematic "Seismic to Simulation" workflow for unconventional reservoirs to constrain a hydraulic fracture model to obtain a calibrated result.
For the hydraulic fracture calibration, injection fall-off tests, sonic logs and image logs are commonly used as the primary inputs to calibrate the geomechanical model. A new workflow is developed to be used consistently incorporating the learnings from the traditional fracture calibration methods. Impact of high stress barriers and height and pinchouts of fractures are incorporated in a geomechanical-flow model. Simultaneous matching of the observed net pressure trend, incorporating the effect of reservoir laminations on fracture height growth is made using a complex fracture model. The effect of the natural fracture networks (NFN) on pressure losses and proppant transport is also accounted for in the fracture geometry. Further, hydraulic fracture geometry is calibrated using the microseismic data. The production behavior was validated using numerical simulation for production history matching.
A case study from the Permian basin is considered for the paper. The fracture geometry and footprint obtained using the calibration workflow match very closely the observed surface and downhole measurements. We constrained the model by matching the net pressures and achieved simulated production to match within 10% error compared to the actual oil and gas production. The fracture geometry was calibrated using microseismic data and controlled by incorporating the effect of weak interfaces and laminations. This workflow successfully demonstrates hydraulic fracture model calibration using pressure matching, microseismic data and production history matching. Systematically and consistently using this workflow provides solutions for infill well planning and well spacing for asset optimization.
This paper explains a systematic fracture calibration procedure that can be easily adopted by the operators to obtain reliable results in unconventional wells. The effect of reservoir laminations and impact of natural fracture in calibrating the fracture geometry and fracture pressure trend is uniquely demonstrated in this study.
