Frictional properties of a faulted shale gas play: implications for induced seismicity 

2021 ◽  
Author(s):  
Michael John Allen ◽  
Tom Kettlety ◽  
Daniel R Faulkner ◽  
J. Michael Kendall ◽  
Nicola De Paola
Keyword(s):  
Shale Gas ◽  
Induced Seismicity ◽  
Spatial Clustering ◽  
Energy Transition ◽  
Fault Reactivation ◽  
Fluid Injection ◽  
Exact Nature ◽  
Friction Coefficients ◽  
B Values ◽  
Frictional Behaviour

<p>Injecting fluids into the subsurface is necessary for a number of industries to facilitate the energy transition (e.g., geothermal, geologic CO<sub>2</sub> sequestration or hydrogen storage). One of the biggest challenges is that fluid injection induces seismicity, which can lead to damaging events. It is currently not possible to predict the exact nature of seismicity that will occur due to fluid injection prior to operations.</p><p>Using laboratory friction experiments and in-situ microseismic analyses, we investigate the role frictional behaviour may have on the rate and magnitude of induced seismicity. This study focuses on the Horn River Basin shale gas play (British Columbia, Canada), where hydraulic fracturing activity has resulted in felt induced seismicity. Microseismic data from this field highlights fault planes that cut across the stratigraphy, including overburden and reservoir shales of varying mineralogy and underburden dolomites.</p><p>Our experimental friction results on samples recovered from core at reservoir depths show that both the frictional strength and stability vary considerably across the different lithologies; transitioning from very velocity-strengthening with friction coefficients of 0.3 – 0.4 in the overburden shales to more velocity-weakening and friction coefficients of 0.55 – 0.7 in the reservoir shales and an analogue of the underburden dolomite.</p><p>Spatial clustering analysis of the microseismicity allowed us to discriminate the operationally induced fracturing from fault reactivation events. We then examined the variations in the seismic b-value of the event magnitude-frequency distribution. These events were further differentiated by depth, separating them into their lithological horizons. The results show, for both fracturing and faulting events, higher seismic b-values of 1.4 – 1.5 <span>occur </span><span>in the overburden shales, which then decrease into the upper reservoir shales to 0.8 – 1.1, and then increase into the lower reservoir shales and underburden dolomite to 1.1 – 1.4. These trends correlate well with the laboratory measurements of frictional a-b values that define the degree of velocity-strengthening to velocity-weakening in the different gouges across the same lithological units.</span></p><p>These results suggest that knowledge of the frictional behaviour of the subsurface prior to operations, derived from mineralogical compositions and laboratory testing on cored material, may help improve our understanding of the potential rate and magnitude of induced seismicity that may occur due to subsurface fluid injection.</p>

Discrete element modeling of fluid injection–induced seismicity and activation of nearby fault

2015 ◽  
Vol 52 (10) ◽  
pp. 1457-1465 ◽  
Author(s):  
Jeoung Seok Yoon ◽  
Günter Zimmermann ◽  
Arno Zang ◽  
Ove Stephansson
Keyword(s):  
Shale Gas ◽  
Induced Seismicity ◽  
Fluid Pressure ◽  
Discrete Element ◽  
Fault Reactivation ◽  
Fluid Injection ◽  
Enhanced Geothermal Systems ◽  
Discrete Element Modeling ◽  
Geothermal Systems ◽  
Element Modeling

Enhanced geothermal systems, shale gas, and geological carbon sequestration all require underground fluid injection in high-pressure conditions. Fluid injection creates fractures, induces seismicity, and has the potential to reactivate nearby faults that can generate a large magnitude earthquake. Mechanisms of fluid injection–induced seismicity and fault reactivation should be better understood to be able to mitigate larger events triggered by fluid injection. This study investigates fluid injection, induced seismicity, and triggering of fault rupture using hydromechanical-coupled discrete element models. Results show that a small amount of fluid pressure perturbation can trigger fault ruptures that are critically oriented and stressed. Induced seismicity by rock failure shows in general higher b-values (slope of magnitude–frequency relation) compared to seismicity triggered by the fault fracture slip. Numerical results closely resemble observations from geothermal and shale-gas fields and demonstrate that discrete element modeling has the potential to be applied in the field as a tool for predicting induced seismicity prior to in situ injection.

scholarly journals Real‐Time Imaging, Forecasting, and Management of Human‐Induced Seismicity at Preston New Road, Lancashire, England

2019 ◽  
Author(s):  
Huw Clarke ◽  
James P. Verdon ◽  
Tom Kettlety ◽  
Alan F. Baird ◽  
J‐Michael Kendall
Keyword(s):  
Hydraulic Fracturing ◽  
Real Time ◽  
Shale Gas ◽  
Statistical Models ◽  
Induced Seismicity ◽  
Red Light ◽  
Fracture Network ◽  
Fluid Injection ◽  
Traffic Light ◽  
Subsurface Fluid

ABSTRACTEarthquakes induced by subsurface fluid injection pose a significant issue across a range of industries. Debate continues as to the most effective methods to mitigate the resulting seismic hazard. Observations of induced seismicity indicate that the rate of seismicity scales with the injection volume and that events follow the Gutenberg–Richter distribution. These two inferences permit us to populate statistical models of the seismicity and extrapolate them to make forecasts of the expected event magnitudes as injection continues. Here, we describe a shale gas site where this approach was used in real time to make operational decisions during hydraulic fracturing operations.Microseismic observations revealed the intersection between hydraulic fracturing and a pre‐existing fault or fracture network that became seismically active. Although “red light” events, requiring a pause to the injection program, occurred on several occasions, the observed event magnitudes fell within expected levels based on the extrapolated statistical models, and the levels of seismicity remained within acceptable limits as defined by the regulator. To date, induced seismicity has typically been regulated using retroactive traffic light schemes. This study shows that the use of high‐quality microseismic observations to populate statistical models that forecast expected event magnitudes can provide a more effective approach.

scholarly journals Effects of Different Penetration Patterns on a Fault during Underground Fluid Injection

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-15 ◽  
Author(s):  
Xiaochen Wei ◽  
Qi Li ◽  
Xiaying Li ◽  
Zhiyong Niu ◽  
Xiangjun Liu ◽  
...  
Keyword(s):  
Finite Element ◽  
Site Selection ◽  
Induced Seismicity ◽  
Anthropogenic Activities ◽  
Fault Reactivation ◽  
Fluid Injection ◽  
Barrier Effect ◽  
Hydraulic Connection ◽  
Shengli Oilfield ◽  
Fault Structures

At underground fluid injection sites with natural faults, understanding how to avoid the subsequent fault reactivation and induced seismicity plays a crucial role in the success of subsurface anthropogenic activities. In this work, with the objective of avoiding risky faults in site selection in the Shengli Oilfield, we investigated the faults that are usually encountered in the target demonstration zone; based on the geophysical observations of fault structures, we designed different fault tectonic scenarios to investigate the different penetration patterns of faults. We used the finite element-based numerical method to assess the influence of the effective lateral and vertical reservoir transmissivity in each fault penetration pattern. Our results indicate that when a permeable fault intersects into the target reservoir, it presents both barrier effect to reservoir transmissivity within the target reservoir and hydraulic connection between reservoirs. The effective lateral reservoir transmissivity is dominated by the barrier effect of the fault, and the effective vertical reservoir transmissivity is dominated by the hydraulic connection between reservoirs. Relatively impermeable faults with less contact with the target aquifer make higher effective lateral reservoir transmissivity and lower effective vertical reservoir transmissivity, which would mitigate the risk of caprock failure and the magnitude of the induced seismicity.

Fault Reactivation and Induced Seismicity During Multistage Hydraulic Fracturing: Microseismic Analysis and Geomechanical Modeling

SPE Journal ◽  
2019 ◽  
Vol 25 (02) ◽  
pp. 692-711 ◽  
Author(s):  
Fengshou Zhang ◽  
Zirui Yin ◽  
Zhaowei Chen ◽  
Shawn Maxwell ◽  
Lianyang Zhang ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Seismic Activity ◽  
Induced Seismicity ◽  
Fault Reactivation ◽  
Fluid Injection ◽  
Fluid Viscosity ◽  
Multistage Hydraulic Fracturing ◽  
Budget Analysis ◽  
Casing Deformation ◽  
The Impact

Summary This paper presents a case study of fault reactivation and induced seismicity during multistage hydraulic fracturing in Sichuan Basin, China. The field microseismicity data delineate a fault activated near the toe of the horizontal well. The spatio-temporal characteristics of the microseismicity indicate that the seismic activity on the fault during the first three stages is directly related to the fluid injection, while after Stage 3, the seismic activity is possibly due to the relaxation of the fault. The fault-related events have larger magnitudes and different frequency-magnitude characteristics compared to the fracturing-related events. Three-dimensional (3D) fully coupled distinct element geomechanical modeling for the first two hydraulic fracturing stages and a shut-in stage between them is performed. The modeling result generates features of microseismicity similar to that of the field data. The energy budget analysis indicates that the aseismic deformation consumes a major part of the energy. The simulated fault shear displacement is also consistent with the casing deformation measured in the field. The model is also used to investigate the impact of possible operational changes on expected seismic responses. The results show that lower injection rate and lower fluid viscosity would be helpful in reducing casing deformation but not in mitigating seismicity. Decreasing the total fluid injection volume is an effective way to mitigate the seismicity, but it may hinder the stimulation of the reservoir formation and the production of the well.

scholarly journals Modelling fault reactivation with characteristic stress-drop terms

2019 ◽  
Vol 49 ◽  
pp. 1-7 ◽  
Author(s):  
Martin Beck ◽  
Holger Class
Keyword(s):  
Induced Seismicity ◽  
Shear Failure ◽  
Fault Reactivation ◽  
Mechanical Responses ◽  
Flow Processes ◽  
Failure Event ◽  
Characteristic Values ◽  
Shear Slip ◽  
Stress Drops ◽  
Characteristic Stress

Abstract. Predicting shear failure that leads to the reactivation of faults during the injection of fluids in the subsurface is difficult since it inherently involves an enormous complexity of flow processes interacting with geomechanics. However, understanding and predicting induced seismicity is of great importance. Various approaches to modelling shear failure have been suggested recently. They are all dependent on the prediction of the pressure and stress field, which requires the solution of partial differential equations for flow and for geomechanics. Given a pressure and corresponding mechanical responses, shear slip can be detected using a failure criterion. We propose using characteristic values for stress drops occurring in a failure event as sinks in the geomechanical equation. This approach is discussed in this article and illustrated with an example.

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