Modeling the Complex Stress Field - Incorporating Stochastic Models of Natural Fractures to Improve Completion Design in Unconventional Reservoirs

Unlike conventional reservoirs in which dual porosity/permeability is the primary rock property needed for fluid flow, unconventional reservoir permeability is created through hydraulic fracturing in which other key reservoir properties are needed. The success of a hydraulic fracturing job depends on the stress field around the wellbore. Unfortunately, the presence of faults and natural fractures creates a variability that could enhance the fracturing or prevent its success. Consequently, stress variability needs to be quantified to optimize the position of the fracture stages during hydraulic fracturing. This paper describes a combined use of geostatistical methods to simulate the distribution of the natural fractures and a geomechanical meshless material point method (MPM) method to account explicitly for their interaction with the regional stress. The geostatistical natural fracture network used as input in the MPM geomechanical tool enables the estimate of the complex stress field map. In resource plays such as the Eagle Ford, this can directly affect stimulation design around high density fractures. The combination of the new geostatistical natural fracture simulation method with the explicit representation of the simulated natural fractures in the MPM-based geomechanical approach is a powerful tool that could improve completion strategies in unconventional reservoirs.