Poroelastic models for fault reactivation in response to concurrent injection and production in stacked reservoirs

We have evaluated workflows to quantify the mechanical impact of natural fractures (NFs) on the production performance of hydraulically stimulated stages in shale wells. Variations in fracture orientation and density can enhance or degrade the transport and effectiveness of fracturing fluids. Specifically, we studied the effect of a complex fault splay system on a horizontal Wolfcamp B reservoir well. A general workflow that combines geophysics, geology, and geomechanics (3G) was evaluated and applied to the well. The benefits of the 3G workflow are threefold. First, the quantitative impact of the NFs on the regional stress is provided through the differential horizontal stress variation, which impacts fracturing complexity. Then, the reservoir strain map, validated with microseismic data, gives insights into the stimulated drainage pathways. Finally, the ability of the J integral to predict poor hydraulic fracturing stages as a function of fracture density along the wellbore or as a function of t...

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 numerical prediction of production from stimulated Ultra-Low Permeability (ULP) media is highly correlated with the type of fracture model used in the simulator. Although there are some general rules about the applicability of these fracture models, there are no guidelines for the a-priori selection of an appropriate model — generally, the fracture model is selected based on the preference and/or familiarity of the person performing the modeling, rather than some "more technical" criteria. In that light, this work presents an effort to provide guidance for fracture model suitability for cases from the Eagle Ford, Bakken, Three Forks, and Wolfcamp formations. In this work, production data from multiple wells in the aforementioned reservoirs are history-matched using models commonly available in commercial reservoir simulators. We evaluate the ability of the equivalent continuum model (ECM), the dual porosity, the dual permeability, and the multiple interactive continuum model (MINC) to represent these wells. We determine that a correlation exists between the choice of the fracture model and the reservoir. However, the results of the study do not provide a sufficiently strong indication of model superiority which would support authoritative guidelines about applicability for a particular reservoir. Ultimately the choice of the most representative model depends on the particular well. The proposed recommendationsprovide guidance onthe appropriate fracture model to represent the studied reservoirs, thus enhancing their usefulness in the completion design process and the evaluation and prediction of production.

Developing Guidelines for Selection of Appropriate Fracture Models in the Numerical Simulation of Well Performance Behavior for Liquid Rich Ultra-Low Permeability ULP Reservoirs

Using Geomechanical Modeling to Quantify the Impact of Natural Fractures on Well Performance and Microseismicity—Application to the Wolfcamp, Permian Basin

Asset Evaluation Utilizing Multi-Variate Statistics Integrating Data-Mining, Completion Optimization, and Geology Focused on Multi-Bench Shale Plays

Fault and Fracture Characterization from an Integrated Subsurface and Seismic Dataset: Impact on Well Performance of the Wolfcamp Shale, Midland Basin, West Texas

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Fault and Fracture Characterization from an Integrated Subsurface and Seismic Dataset: Impact on Well Performance of the Wolfcamp Shale, Midland Basin, West Texas