Geomechanical modeling of hydraulic fractures interacting with natural fractures — Validation with microseismic and tracer data from the Marcellus and Eagle Ford

Abstract

We have developed a new geomechanical workflow to study the mechanics of hydraulic fracturing in naturally fractured unconventional reservoirs. This workflow used the material point method (MPM) for computational mechanics and an equivalent fracture model derived from continuous fracture modeling to represent natural fractures (NFs). We first used the workflow to test the effect of different stress anisotropies on the propagation path of a single NF intersected by a hydraulic fracture. In these elementary studies, increasing the stress anisotropy was found to decrease the curving of a propagating NF, and this could be used to explain the observed trends in the microseismic data. The workflow was applied to Marcellus and Eagle Ford wells, where multiple geomechanical results were validated with microseismic data and tracer tests. Application of the workflow to a Marcellus well provides a strain field that correlates well with microseismicity, and a maximum energy release rate, or [Formula: see text] integral at each completion stage, which appeared to correlate to the production log and could be used to quantify the impact of skipping the completion stages. On the first of two Eagle Ford wells considered, the MPM workflow provided a horizontal differential stress map that showed significant variability imparted by NFs perturbing the regional stress field. Additionally, a map of the strain distribution after stimulating the well showed the same features as the interpreted microseismic data: three distinct regions of microseismic character, supported by tracer tests and explained by the MPM differential stress map. Finally, the workflow was able to estimate, in the second well with no microseismic data, its main performance characteristics as validated by tracer tests. The field-validated MPM geomechanical workflow is a powerful tool for completion optimization in the presence of NFs, which affect in multiple ways the final outcome of hydraulic fracturing.

Using geomechanical modeling to quantify the impact of natural fractures on well performance and microseismicity: Application to the Wolfcamp, Permian Basin, Reagan County, Texas

“…The concept of J integral has been used in many other industries that deal with fracture propagation, but to the best of our knowledge, it has never been quantitatively applied in the oil and gas industry prior to the introduction of the MPM geomechanical workflow . Because its introduction in modeling the interaction between HF and NFs in hydraulic fracturing problems, the J integral was found to be very useful in quantifying HF stage performance, and in some cases it shows interesting correlations with production logs Aimene and Ouenes, 2015;Yang et al, 2015). Because there are 32 stimulation stages modeled in this Wolfcamp well, we estimate 32 J integral curves (Figure 3, item 6).…”

“…This geomechanical modeling requires sophisticated computational tools that can account for a realistic distribution of the NFs. A new geomechanical workflow was recently introduced to the oil and gas industry Ouenes et al, 2014;Aimene and Ouenes, 2015) to quantify the impact of NFs on shale stimulations. The new workflow was validated in multiple unpublished projects and published case studies from the Marcellus (Aimene and Nairn, 2014), Eagle Ford Umholtz and Ouenes, 2015), and Montney formations ; the Longmaxi Formation in China (Yang et al, 2015); and the Fayetteville Shale (McKetta et al, 2016).…”

“…This geomechanical workflow includes new elements that try to solve many problems that previously hindered the industry-wide application of geomechanics to shale well stimulation and completion optimization. A major feature of this new workflow is the combined use of the material point method (MPM) computational tool to model the interaction between HFs and NFs Aimene and Ouenes, 2015) and the continuous fracture modeling (CFM) approach Jenkins et al, 2009) to model the distribution of the NFs. The new geomechanical workflow is also fast because it only takes a few hours to complete a well-scale simulation and it can easily be incorporated in current hydraulic fracturing design processes.…”

“…The workflow uses geophysics and geology to quantify the distribution of NFs in a realistic manner. These data are used as input into FracPredictor™, a particle-based geomechanical computation tool (Aimene and Nairn, 2014; Aimene and Ouenes, 2015). This new 3G workflow provides multiple outputs including horizontal differential stress Aimene and Ouenes, 2015), local maximum horizontal stress directions and the related origins of where stress rotations occur, , and strain resulting from the stimulation process and its correlation to microseismicity Ouenes et al, 2014Ouenes et al, , 2015Aimene and Ouenes, 2015).…”

Shale Reservoir Drainage Visualized for a Wolfcamp Well (Midland Basin, West Texas, USA)

“…Aimene and Nairn [39] and Aimene and Ouenes [40] introduced the Material Point Method (MPM) to facilitate the representation of the natural fractures in a multi-scale continuum problem. MPM combines Lagrangian and Eulerian descriptions of the material and in doing so overcomes the inherent drawbacks of methods relying on using only one perspective.…”