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Abstract: We use here a fully hydraulically-mechanical coupled, 3-D model (Damjanac and Cundall, 2014) to simulate fault reactivation during a hydraulic fracturing treatment. Synthetic seismicity from the model helps quantify seismic energy released by the slippage on the fault. The model is based on a case study in the Horn River Basin by Snelling et al., 2013a. The multi-stage hydraulic fracture model is able to reproduce seismic deformation characteristics observed in field data. Results show that even stages distant from the fault have an influence on the slippage on the fault with a delayed effect. If the first injection stage is the closest to the fault, a large area will be slipping. Successive stages will have a lesser impact due to stress shadowing. If the first stage is farthest from the fault, then slippage on the fault will be gradual, reducing the amount of seismic moment release in a short period of time. This model can be used as a framework to examine the impact of other geomechanical characteristics or other operational factors, which could help establish best practices to mitigate seismicity when faults begin to be active. Introduction Induced seismicity has become a concern for hydraulic fracturing operations in British Columbia and Alberta, Canada. Seismic monitoring is now mandatory for stimulation of two shale formations in this region. The challenge of hydraulic stimulations in areas prone to induced seismicity remains because mitigation can only be achieved with a good understanding of the underlying mechanisms linking multi-stage hydraulic fracturing operations and induced seismicity. Geomechanical modeling is the best way to understand this link because it allows investigation of the interactions between multiple hydraulic fractures by modeling different injection scenarios and assessment of the sensitivity to different parameters. Many authors have proposed models to investigate induced seismicity (for instance, Goertz-Allmann and Wiemer, 2013; Rutqvist et al., 2013). Most find a strong correlation between pore pressure increase and areas where large magnitude events occur. The models indicate that the increase in pore pressure is caused by the hydraulic fracture following fluid injection. None of these models can produce synthetic seismicity for quantitative comparison with recorded seismicity. The multi-stage hydraulic fracture model presented here is based on a fully hydraulically-mechanical coupled, 3-D model (Damjanac and Cundall, 2014) which produces synthetic seismicity, which can help quantify the seismic energy released by slippage on faults (Zhang et al., 2015).
- North America > Canada > British Columbia (0.56)
- North America > Canada > Alberta (0.34)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.47)
Abstract: A 3D geomechanical model of a hydraulic fracture treatment in the Horn River Basin was calibrated by comparing synthetic microseismic events to field data. Using this calibrated model, sensitivity studies were performed to determine the effect of geological parameters and operational variables on the resulting fracture geometry and microseismic response. Microseismic geomechanics was shown to be a reliable calibration methodology for this model because changes in hydraulic fracture geometry were reflected by changes in the microseismic calibration. The results show that the orientation of the DFN is a key parameter driving the microseismic response. When hydraulic fractures intersect natural fractures at high angles, the pre-existing fractures are stimulated more and exhibit a greater microseismic response. Application of the calibrated model to optimize completion changes is demonstrated by investigating the effect of several potential changes on fracture geometry. Introduction Hydraulic fracturing of horizontal wells has been an important factor in the development of low permeability formations such as shales (Gale et al., 2007). The high-pressure injection of hydraulic fracturing fluid creates tensile fractures which may connect with and activate natural fractures. Hydraulic fracture modeling requires close coupling between the hydraulic (fluid flow) and mechanical models. For tight formations, the geomechanical aspect of the model is even more important than in conventional reservoirs, because natural fractures can play an important role in production. Hydraulic fracturing typically causes microseismicity, usually through shear deformation (slip) on natural fractures and bedding planes. This microseismicity is the only far-field measurement of fracture geometry, and can be used to calibrate geomechanical models of fracture geometry and proppant distribution. This paper presents a case study in which a coupled hydraulic-geomechanical simulator (3DEC, Damjanac and Cundall, 2016) is used to simulate hydraulic fracture growth in a naturally fractured formation and predict the corresponding microseismicity. The mechanical model is constructed with principal stresses, pore pressure and mechanical properties obtained from well logs, and a Discrete Fracture Network (DFN) is embedded in the stimulated area. The evolution of the mechanical deformation during the hydraulic fracturing process is simulated, including both the creation of new (hydraulic) fractures and the activation of pre-existing natural fractures. The model is calibrated by comparing the synthetic microseismic (MS) events with the field data.
- North America > Canada > British Columbia (0.91)
- North America > United States > Texas > Harris County > Houston (0.29)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Otter Park Formation (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin > Muskwa Field > Muskwa Formation (0.99)