Fault activation by hydraulic fracturing in western Canada

Science ◽  
2016 ◽  
Vol 354 (6318) ◽  
pp. 1406-1409 ◽  
Author(s):  
Xuewei Bao ◽  
David W. Eaton
Keyword(s):  
Hydraulic Fracturing ◽  
Western Canada ◽  
Fault Activation

Coupled Poroelastic Modeling to Characterize the 4.18-Magnitude Earthquake Due to Hydraulic Fracturing in the East Shale Basin of Western Canada

2021 ◽  
Author(s):  
Gang Hui ◽  
Shengnan Chen ◽  
Fei Gu
Keyword(s):  
Hydraulic Fracturing ◽  
Solid Mechanics ◽  
Flow Behavior ◽  
Seismic Hazards ◽  
Integrated Analysis ◽  
Western Canada ◽  
Induced Earthquakes ◽  
Fault Activation ◽  
Coulomb Failure ◽  
Poroelastic Modeling

Abstract Recently, the elevated levels of seismicity activities in Western Canada have been demonstrated to be linked to hydraulic fracturing operations that developed unconventional resources. The underlying triggering mechanisms of hydraulic fracturing-induced seismicity are still uncertain. The interactions of well stimulation and geology-geomechanical-hydrological features need to be investigated comprehensively. The linear poroelasticity theory was utilized to guide coupled poroelastic modeling and to quantify the physical process during hydraulic fracturing. The integrated analysis is first conducted to characterize the mechanical features and fluid flow behavior. The finite-element simulation is then conducted by coupling Darcy's law and solid mechanics to quantify the perturbation of pore pressure and poroelastic stress in the seismogenic fault zone. Finally, the Mohr-coulomb failure criterion is utilized to determine the spatial-temporal faults activation and reveal the trigger mechanisms of induced earthquakes. The mitigation strategy was proposed accordingly to reduce the potential seismic hazards near this region. A case study of ML 4.18 earthquake in the East Shale Basin was utilized to demonstrate the applicability of the coupled modeling and numerical simulation. Results showed that one inferred fault cut through the Duvernay formation with the strike of NE20°. The fracture half-length of two wells owns an average value of 124 m. The brittleness index deriving from the velocity logging data was estimated to be a relatively higher value in the Duvernay formation, indicating a geomechanical bias of stimulated formation for the fault activation. The coupled poroelastic simulation was conducted, showing that the hydrologic connection between seismogenic faults and stimulated well was established by the end of the 38th stage completion for the east horizontal well. The simulated coulomb failure stress surrounding the fault reached a maximum of 4.15 MPa, exceeding the critical value to cause the fault slip. Hence the poroelastic effects on the inferred fault were responsible for the fault activation and triggered the subsequent ML 4.18 earthquake. It is essential to optimize the stimulation site selection near the existing faults to reduce risks of future seismic hazards near the East Shale Basin.

Hydraulic Fracturing and Seismicity in the Western Canada Sedimentary Basin

2016 ◽  
Vol 87 (3) ◽  
pp. 631-647 ◽  
Author(s):  
Gail M. Atkinson ◽  
David W. Eaton ◽  
Hadi Ghofrani ◽  
Dan Walker ◽  
Burns Cheadle ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Sedimentary Basin ◽  
Western Canada ◽  
Western Canada Sedimentary Basin ◽  
Canada Sedimentary Basin

2000-2020: Two Decades of Evolution of Hydraulic Fracturing-Induced Seismicity in the Western Canada Sedimentary Basin

2021 ◽  
Author(s):  
Germán Rodríguez-Pradilla ◽  
David Eaton ◽  
Melanie Popp
Keyword(s):  
Hydraulic Fracturing ◽  
Induced Seismicity ◽  
Sedimentary Basin ◽  
Unit Area ◽  
Critical Parameters ◽  
Seismic Events ◽  
Western Canada ◽  
Maximum Magnitude ◽  
Western Canada Sedimentary Basin ◽  
Canada Sedimentary Basin

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 km2 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.

Integration of outcrop, subsurface, and microseismic interpretation for rock-mass characterization: An example from the Duvernay Formation, Western Canada

2018 ◽  
Vol 6 (4) ◽  
pp. T919-T936 ◽  
Author(s):  
Mason K. MacKay ◽  
David W. Eaton ◽  
Per K. Pedersen ◽  
Christopher R. Clarkson
Keyword(s):  
Rock Mass ◽  
Hydraulic Fracturing ◽  
Distinct Element ◽  
Integrated Approach ◽  
Natural Fracture ◽  
Western Canada ◽  
Natural Fractures ◽  
Data Set ◽  
Fracture Geometry ◽  
Rock Mass Characterization

Identifying and characterizing geomechanical domains is important for understanding how a reservoir will respond to hydraulic fracturing, including interaction with natural fractures to create new permeable pathways. We have used a rock-mass characterization approach, which describes the mechanical reservoir package by combining parameters of the intact rock, such as brittleness, with inferred geometry and density of natural fractures. Insights from outcrop observations are important to complement the interpretation of fracture geometry and density derived from subsurface data, to give a more complete understanding of natural fracture networks. This integrated approach is applied to a data set from the Duvernay play in Western Canada. A synthetic model of the subsurface reservoir is constructed using data from well logs, cores, and outcrop analogs. Numerical simulation of the response of the artificial rock mass to hydraulic fracturing is performed using a distinct element code. Independent validation of the model is obtained by achieving an agreement between the simulated microseismic response and the observed distribution of microseismicity during hydraulic fracturing.

Fault Activation During Hydraulic Fracturing

2010 ◽  
Author(s):  
S. C. Maxwell ◽  
M. Jones ◽  
R. Parker ◽  
S. Leaney ◽  
M. Mack ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Fault Activation
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