Cubic-meter scale laboratory fault re-activation experiments to improve the understanding of induced seismicity risks

Abstract

To understand fluid induced seismicity, we have designed a large-scale laboratory experiment consisting of a one-cubic-meter sandstone with an artificial fault cut and fluid-injection boreholes. The sandstone block is assembled in a true triaxial loading frame and equipped with 38 piezoelectric sensors to locate and characterise acoustic emission events. The differential stress on the artificial fault is increased in stages to bring it towards a critically stressed state. After each stage of differential stress increase, fluids are injected at low pressures through boreholes to test the potential of fault re-activation. In addition, a high-pressure injection was conducted that created a hydraulic fracture from the injection borehole towards the artificial fault. The newly generated fluid pathway resulted in an activation of the complete block through a stick–slip movement. We compare acoustic emission measurements from the laboratory experiment with seismicity observations from the field-scale CO2 injection at Decatur, Illinois, U.S., and conclude that the existence of fluid pathways plays a decisive role for the potential of induced seismicity.

A laboratory study on fault slip caused by fluid injection directly versus indirectly into a fault: implications for induced seismicity in EGSs

“…The time delay of 3.2 s between the slip event and breakdown in the indirect injection case (figure 4c) indicates that the slip occurred after breakdown, suggesting that the fluid pathway provided by the hydraulic fracture is necessary for the fast slip event and strong pressure drop. This is consistent with the observation of the cubic-meter scale laboratory study by Oye et al [38]. The mechanical responses of fluid injection into granite samples suggest that the fault reactivation, in the case where fluid was injected indirectly into a fault and a hydraulic fracture was created to connect the injection well and fault, is associated with larger stick-slip stress drops and higher sample shortening rates, compared to injecting fluid directly into a fault.…”

“…If the permeability of the rock matrix were higher, the fluid viscosity lower, or the distance between the open hole and the fault shorter than those in our experiment, the fault in the indirect injection case might also be reactivated by fluid pressure diffusion from the injection hole to the fault without overpressure in the injection hole or any hydraulic fracture, which has been already observed in prior experiments [38,54]. Therefore, the fault slip in such an indirect injection sample without overpressure would be safer than the stick slip in the indirect injection case with overpressure in this study.…”

“…As shown in figure 4 d , prior to crack initiation, the monitoring pressure of 1.05 MPa was slightly higher than the initial value of 1 MPa with a linear increase of the injection pressure even though there was no fracture between the injection hole and the inclined fault. This subtle increase in the monitoring pressure might have been caused by fluid diffusion within the granite matrix, fluid compression in the fault owing to the pressure accumulation in the injection hole or both [38,54,55]. In addition, the injection pressure and the confining pressure are identical after breakdown as a result of the connection between the injected fluid and confining oil caused by the macroscopic fracture (figures 4 c and 5).…”

“…This is consistent with the observation of the cubic-meter scale laboratory study by Oye et al . [38]. The mechanical responses of fluid injection into granite samples suggest that the fault reactivation, in the case where fluid was injected indirectly into a fault and a hydraulic fracture was created to connect the injection well and fault, is associated with larger stick-slip stress drops and higher sample shortening rates, compared to injecting fluid directly into a fault.…”

Active‐Source Seismic Imaging of Fault Re‐Activation and Leakage: An Injection Experiment at the Mt Terri Rock Laboratory, Switzerland

“…During injection, increased reservoir pore pressures can lead to fault reactivation and leakage (Vilarrasa, 2016; Vilarrasa et al., 2019), causing increased permeability due to the opening of cracks and fractures, thus allowing CO 2 to escape from the storage interval (Rutqvist, 2012; Vilarrasa et al., 2011; Yeo et al., 1998). A common practice for detecting these reactivated faults is to monitor for micro‐seismic events passively; detecting these events gives insight into the location and mechanics of fault failure (B. P. Goertz‐Allmann et al., 2014; B. Goertz‐Allmann et al., 2017; Chen & Huang, 2020; Oye et al., 2022). However, this method is limited when monitoring reactivated faults in ductile clay‐rich sealing units, where faults may fail primarily aseismically (i.e., Guglielmi et al., 2021) or the magnitude of the seismic events are below instrument sensitivity.…”