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Abstract A vast number of the reported cases of increased seismicity of moderate magnitude (Mw > 0) earthquakes seem to be tied to some form of fluid injection activitiy, being it wastewater disposal by injection into deep wells or high pressure fluid injection into oil and gas reservoirs to hydraulically fracture the rock and improve hydrocarbon recovery. Regulations have been proposed to implement traffic light systems to dictate the responses that the industry needs to take based on either the magnitudes or observed particle velocities or accelerations on the surface. In order to relate the seismic hazard potential in seismically active areas, empirical ground motion prediction equations (EGMPE) are used to relate event parameters like magnitude and location to site characteristics such as peak ground acceleration (PGA) or peak ground velocity (PGV) which tend to be how building codes are parametrized. Therefore, local hazard assessment near hydraulic fractures that generate relatively large magnitude events need to be estimated more precisely by developing and using local EGMPEs. Hybrid deployments combining 15Hz downhole and low frequency near-surface geophones can be used to accurately capture both the localized microseismic events and any large magnitude events associated with hydraulic fracture monitoring across North American basins – Horn River, Eagle Ford, Barnett, and Montney for example. In our studies events with M>0 are observed for completions in these formations. While in many cases the magnitude of these events is too small to be felt on the surface, there are reports of higher magnitude events which have been sensed by workers on site and the local population. The exact relationships between magnitudes and shaking are not necessarily one-to-one. Shaking also varies based on the stress release of the events. As summarized recently by Hough (2014) for other fluid-induced seismicity, the lower stress releases typical for these sequences results in on-average less shaking than is observed for equivalent magnitude tectonic events. In order to quantify shaking over a seismogenic volume, we show how to develop EGMPEs based on the North-American examples. The EGMPE methodology developed in this study can be extrapolated for similar earthquakes of larger magnitude and included into future probabilistic hazard and risk analysis for induced seismicity as related to hydraulic fracture stimulations.
In September, a technical workshop was held on the topic of injection-induced seismicity in Banff, Canada. It brought together industry and technical experts to discuss the increasingly important topic of induced seismicity associated with various injections during oil and gas activities. The event was cosponsored by the Society of Exploration Geophysicists (SEG), the Society of Petroleum Engineers (SPE), and the American Rock Mechanics Association (ARMA), serving as a follow-up to a previous meeting on the topic held in Broomfield, Colorado, in 2012. More than 120 professionals participated, with the majority traveling from the United States (60%) and Canada (30%), and some from Europe (10%) and one each from Japan and Colombia. The attendees represented oil and gas companies (34%), academia (25%), service companies (25%), and government organizations including national laboratories, geological surveys, and regulatory bodies.
Rodríguez-Pradilla, Germán (School of Earth Sciences, University of Bristol, UK.) | Eaton, David (Department of Geoscience, University of Calgary, Canada.) | Popp, Melanie (geoLOGIC Systems Ltd., Calgary, Canada.)
Abstract The goal of this work is to calibrate a regional predictive model for maximum magnitude of seismic activity associated with hydraulic-fracturing in low-permeability formations in the Western Canada Sedimentary Basin (WCSB). Hydraulic fracturing data (i.e. total injected volume, injection rate, and pressure) were compiled from more than 40,000 hydraulic-fractured wells in the WCSB. These wells were drilled into more than 100 different formations over a 20-year period (January 1st, 2000 and January 1st, 2020). The total injected volume per unit area was calculated utilizing an area of 0.2° in longitude by 0.1° in latitude (or approximately 13x11km, somewhat larger than a standard township of 6x6 miles). This volume was then used to correlate with reported seismicity in the same unit areas. Collectively, within the 143 km area considered in this study, a correlation between the total injected volume and the maximum magnitude of seismic events was observed. Results are similar to the maximum-magnitude forecasting model proposed by A. McGarr (JGR, 2014) for seismic events induced by wastewater injection wells in central US. The McGarr method is also based on the total injected fluid per well (or per multiple nearby wells located in the same unit area). However, in some areas in the WCSB, lower injected fluid volumes than the McGarr model predicts were needed to induce seismic events of magnitude 3.0 or higher, although with a similar linear relation. The result of this work is the calculation of a calibration parameter for the McGarr model to better predict the magnitudes of seismic events associated with the injected volumes of hydraulic fracturing. This model can be used to predict induced seismicity in future unconventional hydraulic fracturing treatments and prevent large-magnitude seismic events from occurring. The rich dataset available from the WCSB allowed us to carry out a robust analysis of the influence of critical parameters (such as the total injected fluid) in the maximum magnitude of seismic events associated with the hydraulic-fracturing stimulation of unconventional wells. This analysis could be replicated for any other sedimentary basin with unconventional wells by compiling similar stimulation and earthquake data as in this study.
The risks associated with induced seismicity have risen in prominence with the occurrence of several large earthquakes characterized as induced, which have caused public concern in multiple jurisdictions. As a result, regulatory bodies have mandated risk mitigation strategies to govern the associated activities. These include monitoring programs, which involve the deployment of real-time seismic networks. There are several challenges and options to consider when planning and realizing a monitoring network, including the choice of ground motion sensing technology. This study evaluates the performance of two types of instruments in terms of their suitability for induced seismic monitoring: broadband seismometers and geophones.
Two geophone and broadband seismometer pairs were co-located in a real-world induced seismic monitoring (ISM) deployment. The co-located geophone and broadband seismometer were positioned within 3m of each other and, as such, were subject to the same ground motion. The subsequent impact on key ISM network performance criteria, event magnitude measurements and ground motion computations, are examined for each sensing technology.
It was found that event magnitudes generated using the geophone data generally underestimate the broadband event magnitude, for events at typical ISM hypocentral distances, 10 to 50 km. This effect is the result of magnitude saturation, due to the inability of the geophone to measure low-frequency motions associated with large events. Further, it was found that peak ground velocities calculated using the geophone data were also underestimated for study events.
Presentation Date: Wednesday, October 19, 2016
Start Time: 8:50:00 AM
Presentation Type: ORAL