High‐Rate Fluid Injection Reduces the Nucleation Length of Laboratory Earthquakes on Critically Stressed Faults in Granite

Ji, Yinlin; Wang, Lei; Hofmann, Hannes; Kwiatek, Grzegorz; Dresen, Georg

doi:10.1029/2022gl100418

Cited by 23 publications

(7 citation statements)

References 78 publications

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“…However, slip velocity and associated AE rates remain similar. This is in contrast to previous injection experiments performed on saw-cut faults in almost impermeable granite samples, where stress drops decrease with progressive fluid injection ( 48 , 51 ). We attribute the increasing slip and stress drop to changing surface roughness in our sandstone samples with progressive slip and possibly different fault hydraulic properties.…”

Section: Discussioncontrasting

confidence: 99%

“…Extensive geophysical surveys document the occurrence of induced earthquakes being affected by fluid pressure, injection rate, and fluid volume injected ( 38 – 41 ). Theoretical models ( 42 – 44 ) and laboratory experiments ( 45 – 48 ) also suggest causal relations between stimulation parameters and seismic activity. In addition to fluid injection parameters, complex injection-induced slip behavior may emerge depending on background stress states ( 49 – 51 ), pressure-dependent frictional properties ( 36 ), and the interplay between permeability change and fault slip ( 37 , 52 ).…”

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confidence: 93%

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Fault roughness controls injection-induced seismicity

Wang,

Kwiatek,

Renard

et al. 2024

Proc. Natl. Acad. Sci. U.S.A.

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Surface roughness ubiquitously prevails in natural faults across various length scales. Despite extensive studies highlighting the important role of fault geometry in the dynamics of tectonic earthquakes, whether and how fault roughness affects fluid-induced seismicity remains elusive. Here, we investigate the effects of fault geometry and stress heterogeneity on fluid-induced fault slip and associated seismicity characteristics using laboratory experiments and numerical modeling. We perform fluid injection experiments on quartz-rich sandstone samples containing either a smooth or a rough fault. We find that geometrical roughness slows down injection-induced fault slip and reduces macroscopic slip velocities and fault slip-weakening rates. Stress heterogeneity and roughness control hypocenter distribution, frequency–magnitude characteristics, and source mechanisms of injection-induced acoustic emissions (AEs) (analogous to natural seismicity). In contrast to smooth faults where injection-induced AEs are uniformly distributed, slip on rough faults produces spatially localized AEs with pronounced non-double-couple source mechanisms. We demonstrate that these clustered AEs occur around highly stressed asperities where induced local slip rates are higher, accompanied by lower Gutenberg–Richter b -values. Our findings suggest that real-time monitoring of induced microseismicity during fluid injection may allow identifying progressive localization of seismic activity and improve forecasting of runaway events.

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Section: Discussioncontrasting

confidence: 99%

mentioning

confidence: 93%

Fault roughness controls injection-induced seismicity

Wang,

Kwiatek,

Renard

et al. 2024

Proc. Natl. Acad. Sci. U.S.A.

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“…The transient permeability increases in the pressurized zone upon local slip may accelerate fluid flow in mainly the fault-parallel direction and the rapid transfer of high pressure at distance from the fluid source. Moreover, as shown in previous studies, high-rate fluid pressurization could enhance the seismic hazard (e.g., Goebel & Shirzaei, 2020;Ji, Wang, et al, 2022;Passelègue et al, 2018;Rudnicki & Zhan, 2020;Wang et al, 2020). Thus, the competition between pressurization and frictional processes in fracture/fault stability is a dominant factor in the trade-off between increasing reservoir permeability and the mitigative impact of slowing or ceasing injection on seismic hazard.…”

Section: Discussionmentioning

confidence: 65%

“…However, when the fracture slip occurs at higher effective pressures (cf., Goebel et al, 2012Goebel et al, , 2017Goebel et al, , 2023Ji, Wang, et al, 2022;Ji, Hofmann, Rutter, et al, 2022;Ye & Ghassemi, 2018, 2020, the presence of wear particles and any associated colloidal seal are anticipated to have a notable impact on the transient fracture permeability evolution during fluid injection, in addition to the velocity-dependent process (e.g., . Specifically, the combination of pore throat expansion through shear dilation (cf., Im et al, 2018) and fluid pressure migration during injection (e.g., Passelègue et al, 2018) is likely to favor the flux-driven unclogging of the fracture, potentially leading to further transient permeability enhancement.…”

Section: Discussionmentioning

confidence: 99%

Fracture Permeability Enhancement During Fluid Injection Modulated by Pressurization Rate and Surface Asperities

Ji,

Zhang,

Hofmann

et al. 2023

Geophysical Research Letters

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We present a series of controlled fluid injection experiments in the laboratory on a pre‐stressed natural rough fracture with a high initial permeability (∼10−13 m2) in granite using different fluid pressurization rates. Our results show that fluid injection on a fracture with a slight velocity‐strengthening frictional behavior exhibits dilatant slow slip in association with a permeability increase up to ∼41 times attained at the maximum slip velocity of 0.085 mm/s for the highest‐rate injection case. Under these conditions, the slip velocity‐dependent change in hydraulic aperture is a dominant process to explain the transient evolution of fracture permeability, which is modulated by fluid pressurization rate and fracture surface asperities. This leads to the conclusion that permeability evolution can be engineered for subsurface geoenergy applications by controlling the fluid pressurization rate on slowly slipping fractures.

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“…Pa −1 [35] res [35] inj [35] decreases [35] inj rate 2D spring-slider [38] and Cyl granite samples [39] fluid injection [38,39] critical stiffness analysis [38] and strain gauge/AE hypocentre analysis [39] 0.25-1.0 [38] and 0.2-0.8 ml/min [39] res [38,39] inj [38,39] increases [38 ,39] (Continued.) [34] and Bayesian change point [40,41] natural gas production [34,40,41] fault slip [34] and statistical analysis [40,41] 2.5-10 m 3 /s [34] res [34] prod [34,40,41] insensitive [34] and increases [40,41] fault friction coefficient 2D coupled HM FEM [42,43] hydraulic fracturing [42] and water inj [40] fault slip [42] and poroelastic stress change [43] 0.20-0.60 [42] and 0.10-0.75 [43] res [42] and base [43] inj [42,…”

Section: (B) Young's Modulusmentioning

confidence: 99%

Effects of reservoir mechanical properties on induced seismicity during subsurface hydrogen storage

Burtonshaw,

Paluszny,

Mohammadpour

et al. 2024

Phil. Trans. R. Soc. A.

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The intermittent storage of hydrogen in subsurface porous media such as depleted gas fields could be pivotal to a successful energy transition. Numerical simulations investigate the intermittent storage of hydrogen in a porous, depleted subsurface reservoir. Various parametric studies are performed to assess the effect of mechanical properties of the reservoir (i.e. Young’s modulus, Poisson’s ratio, Biot coefficient and permeability) on the induced fault slip of a single through-going fault that transverses the entire reservoir. Simulations are run using a three-dimensional, finite element, fully coupled hydromechanical code with explicit representations of layers and faults. The effect of the domain mesh refinement and fault mesh refinement on the fault slip versus operation time solution is investigated. The fault is observed to slip in two distinct events, one during the second injection period and one in the third injection period. The fault is not observed to slip during the storage or withdrawal periods. It is found that in order to minimize seismic risk, a reservoir rock with high Young’s modulus (>40 GPa), high Poisson’s ratio (>0.30) and high Biot coefficient (>0.65) would be preferable for hydrogen storage. Reservoir rocks of low Young’s modulus (10–30 GPa), intermediate Poisson’s ratio (0.00–0.30) and low-to-intermediate Biot coefficient (0.25–0.65), at high injection rates, were found to have higher potential of inducing large seismic events. This article is part of the theme issue ‘Induced seismicity in coupled subsurface systems’.

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High‐Rate Fluid Injection Reduces the Nucleation Length of Laboratory Earthquakes on Critically Stressed Faults in Granite

Abstract: Fluid injection into the subsurface is known to potentially induce seismic activity, sometimes including large-magnitude earthquakes (e.g.,

Cited by 23 publications

References 78 publications

Fault roughness controls injection-induced seismicity

Fault roughness controls injection-induced seismicity

Fracture Permeability Enhancement During Fluid Injection Modulated by Pressurization Rate and Surface Asperities

Effects of reservoir mechanical properties on induced seismicity during subsurface hydrogen storage

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