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Summary Induced seismicity associated with hydraulic fracturing has become a significant regulatory issue in Western Canada, after the occurrence of felt events in three specific reservoirs. Seismicity results from elevated pressure of the stimulated fracture network reducing the effective clamping force and triggering slip of tectonically stressed faults. Several published examples indicate activation over progressively larger fault regions, as multiple stages interact with critically stressed faults in various relative orientations to the treatment well. Geomechanical modeling is used to examine progressive fault slip from multi-stage fracturing and the associated seismicity. The modeling explores different operational scenarios to examine progressive fault activation as hydraulic fracture stages sequentially pressurizes more of the fault. Testing these mitigation strategies on faults in different orientations provides potential operational guidelines to support seismic traffic light systems, typically used to mitigate injection induced seismicity. Simulations show that the amount of injected fluid interacting with the fault plane controls the intensity of observed seismicity for a specific fault. Stages farther away from the fault can have an impact on fault slippage but with a delayed effect. Sequence of propagation of the hydraulic fracture stages compared to fault orientation is important. If the first stage is closest to the fault, more of the injected fluid will interact with the fault, triggering a large slipping patch on the fault plane. Successive stages will have a lesser effect due to stress shadowing. However if the first stage is the most distant from the fault, slippage on the fault plane will be gradual, thus reducing the amount of seismic moment release. The sequence in which wells on a multi-well pad are stimulated could also impact the associated seismicity. Introduction There has been increasing occurrences of recent seismicity associated with fault activation during hydraulic fracturing, resulting from elevating pore pressure on optimally-oriented, pre-existing faults leading to triggered release of stored tectonic energy (Maxwell, 2013). Anomalous seismicity is similar to microseismicity, although larger magnitude fault seismicity corresponds to inelastic slip over a larger area. However, triggered fault slip has in certain conditions lead to felt ground shaking. For example, three Western Canadian reservoirs located close to the tectonically-active trust belt have experienced anomalous activity: specifically at localized regions of the Horn River Basin, Montney and Duvernay Shales (Atkinson et al., 2016). Operators and regulators in Canada have proactively engaged the issue, establishing operational practices including seismic monitoring for a traffic light system to guide seismic hazard mitigations strategies. Clearly the topic continues to be of concern and establishing mitigation best practices is increasingly important.
A coupled hydro-mechanical model is used to evaluate fault activation associated with hydraulic fracturing in the Horn River Basin. The model is used to simulate hydraulic fracture growth through a discrete fracture network, examining the pore pressure diffusion and associated fracture dilation and shearing. Based on the geomechanics, the seismic activity can be predicted and used to compare with the actual seismicity monitored during the fracture treatment. The synthetic microseismic prediction includes location, timing and magnitude of the activity and can be used to validate the geomechanical attributes and calibrate the model to match the field data. Applying such a microseismic geomechanics approach not only improves the interpretation of the microseismic image but also improves the understanding of the geomechanical response of the reservoir.
In this study, the impact of the hydraulic fracturing on a preexisiting fault was examined to quantify seismic hazard. A geomechancial model was created to investigate a Horn River Basin hydraulic fracture and the associated seismic magnitudes. The model was designed to investigate the mechanism of fault activation and the impact of fracturing at different locations around the fault. The study indicated that the stimulated fracture network had to grow directly into the fault in order for the injection pressure front to trigger fault slip. Geomechanical assessment of absolute seismic hazard can be used to modify the engineering design prior to operations to minimize the seismic hazard including the placement of the well, and modifiy staging along the well to avoid fracturing in the regions likely to lead to fault activation. In scenarios where induced seismicity occurs during the treatment, the method can also be used to examine operational changes to lessen the relative seismic hazard.
With hightened public concerns of environmental issues with hydraulic fracturing, attention is raising around the few isolated cases of injection-induced seismicity. An increasing number of reports have recently been made of felt seismicity associated directly with hydraulic fracture treatments or disposal of waste water from extraction of unconventional resources. In order to safely and efficiently develop unconventional reservoirs in areas of concern, industry protocols have been developed to deal with induced seismicity issues. Typically these protocols rely on local seismic monitoring to define traffic light systems, where operations are modified depending on the seismicity levels. As part of these protocols, methodologies are required to assess the seismic hazard both prior to the initiation of operations in addition to modifications to planned operations when required by traffic light levels.
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.
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).
Abstract Induced seismicity resulting from fluid injection is a growing concern with a number of operations, including hydraulic fracturing. The vast majority of hydraulic stimulations results in no felt seismicity. However, three examples of larger, anomalous seismicity have been attributed to hydraulic fracturing, which seem to be associated with operations in unique geologic and geomechanical settings. In response, a number of operational protocols have been developed and include specific requirements for seismic monitoring. Seismological aspects are obviously central to these protocols, including characterizing the seismic source strength and associated seismic hazard. The typical microseismicity recorded during hydraulic fracturing represents a small portion of the hydraulic energy associated with the injection. However, the energy balance of the relative amount of seismic energy increases in the cases of anomalous seismicity, which may provide a monitoring tool to potentially help mitigate induced seismicity. Although the number of cases with anomalous seismicity is relatively small, other examples have been observed from geothermal stimulations. In these cases, the ratio of seismic energy is relatively larger but of potentially interest remains significantly less than the hydraulic energy. Furthermore, the ratio of seismic moment to injected volume also increases but typically remains less than a limit suggested by McGarr (1976). Potentially the energy and volume balances could be useful monitoring tools to assist in ongoing operation decision processes.
Abstract A modeling exercise was performed investigating hydraulic fracture interaction with pre-existing fractures, based on a benchmark modeling exercise lead by ARMA (American Rock Mechanics Association). The modeled scenarios are based on interaction with two existing faults under different geomechanical conditions. Simulations were performed with a coupled hydraulic-geomechanical-seismological, discrete-element model. The results show that the hydraulic fracture aperture is restricted at the intersection with the faults, to a degree depending on the slip induced on the fault. The aperture restriction was found to also limit the extent of the proppant distribution. In scenarios with relatively more slip, the fault activation was found to occur above and below the injection layer and resulted in some hydraulic fracture height growth relative to the depth contained fracture occurring without fault activation. As expected, the fault slip and intensity of associated microseismicity is related to the geomechanical prepotency for slip. Fractures oriented at 30° to the hydraulic fracture and maximum principal stress direction, resulted in the largest microseismic magnitude and significant hydraulic fracture restriction at the fault intersection. With increasing angle, the magnitude decreased and the hydraulic fracture had a larger half-length. Increasing the differential stress resulted in increased magnitudes and decreased fracture half-length, as did the case of a weaker fault. The study demonstrates through a numerical-physics simulation how a hydraulic fracture system behalves as it interacts with a pre-existing fracture under various geomechanical conditions.