Published: 10/15/2015
Published: 10/15/2015
A customer operating in the Western Canadian sedimentary basin needed to calibrate the maximum horizontal stress for completion and production optimization in an unconventional reservoir. The complex formation ranges in thickness from less than 3 ft [1 m] to more than 1,148 ft [350 m] and comprises many different types of rocks, such as dolomitic siltstone at the base, siltstone, dark gray shale, and finegrained sandstone toward the top. Because the formation permeability ranges from 0.0001 mD to 0.003 mD, stimulating the formation using multiple hydraulic fracturing treatments was the preferred method to produce a sufficient amount of hydrocarbons. To ensure maximum production, optimal hydraulic fracture treatment design and placement was the most critical task in the completion cycle.
Mangrove stimulation design was used to construct a 1D mechanical earth model (MEM) for the local part of the reservoir. Microseismic data were also recorded for several fracturing stages in the study wells, all of which showed that complex fracture networks had developed. Unconventional fracture models were constructed based on a 3D geological model, 1D MEM, and well completion details, and a discrete fracture network (DFN) model was constructed based on seismic attribute-based fracture detection.
Sensitivity analysis was also conducted to investigate the effects of the DFN model on simulated fracture complexity and calibration of the maximum horizontal stress. Using the originally estimated, uncalibrated maximum horizontal stress as input, unconventional fracture modeling was performed for three different DFN model scenarios with varying natural fracture density. The DFN model that provided the best possible unconventional fracture model geometry match to the microseismic data was used in the final modeling.
With the calibrated maximum horizontal stress and other geomechanical parameters, unconventional fracture modeling was performed for subsequent stages in Well A. The simulated fracture networks were also comparable to the microseismic events, which further validated the calibration of the maximum horizontal stress.
With a strong understanding of the geology, accurate characterization of natural fractures, and a fully calibrated MEM including the maximum horizontal stress, the use of Mangrove stimulation design simulated complex fracture network growth in unconventional reservoirs. The predictability of complex fracture network growth also provided opportunities for the operator to optimize design and execution of hydraulic fracturing stimulations. The operator can also use these modeling techniques to optimize well placement and density, fracturing stage design, perforation cluster locations, pumping schedule, and the selection of fracturing fluid type and proppant.
Challenge: Calibrate and understand the maximum horizontal stress and stress anisotropy in relatively deep formations for predicting the stimulated rock volume in a naturally fractured shale gas reservoir.
Solution: Use Mangrove engineered stimulation design in the Petrel E&P software platform to calibrate the maximum horizontal stress magnitude with microseismic data to improve the accuracy of the unconventional fracture modeling.
Results:
