There is a long history of injection of fluid at great depth causing seismicity, but the SIRGE conditions differ from those cases in several important ways. The fluid-induced seismic events are well understood and caused by changes in pore fluid pressure and stress state in the subsurface in the presence of faults with specific properties and orientations [McGarr et al., 2002; Garagash and Germanovich, 2012; Cappa and Rutqvist, 2012; NAS, 2013; Elsworth et al., 2016; Keranen and Weingarten, 2018; Atkinson et al., 2020; Ge and Saar, 2022]. Seismicity associated with fluid injection tends to be triggered along preexisting faults that are hydraulically or poroelastically connected with injection points (McGarr et al., 2002; Schultz et al., 2020; Atkinson et al., 2020), and induced earthquakes typically occur at depths of ≳ 103 m (Keranen and Weingarten, 2018; Cappa and Rutqvist, 2012; Atkinson et al., 2020; Ge and Saar, 2022).

The increase in fluid-induced seismicity seen in North America is related to the deep reinjected disposal of the large volumes of “wastewater” (brines) produced during hydrocarbon extraction (NAS, 2013; Elsworth et al., 2016). To date, the largest earthquake occurred near Pawnee, Oklahoma, in September 2016, had a moment magnitude, M, of 5.8, and was a strike-slip event on a NW-SE trending fault at the depth of 5.4 km [Manga et al., 2016; Zoback and Kohli, 2019]. This is 3 km deeper than the Arbuckle formation, where the wastewater was reinjected, and is unrelated to hydraulic fracturing (HF) for shale gas in Oklahoma (Zoback and Kohli, 2019). It is a well-recognized misperception that increased hydraulic fracturing for shale gas is the reason for the increase in induced seismicity (NAS, 2013; Elsworth et al., 2016; Ge and Saar, 2022).

SIRGE injections are based on the process of hydraulic fracturing (HF). Although hydraulic fracturing is capable of triggering slip on pre-existing fractures and faults in the formations surrounding the hydraulic fractures (Zoback and Kohli, 2019), the resulting earthquakes are expected to be small with M < 0 (Garagash and Germanovich, 2012). Monitoring of hydraulic fracturing treatments shows that indeed HF stimulation is typically accompanied by such small‐scale fracture events (M < 0) because the volume of fluid injected is relatively small (NAS, 2013; Schultz et al., 2020) and the nucleation patch of the dynamic slip is at its minimum size (~ 1 m) on critically stressed (favorably oriented) faults (Garagash and Germanovich, 2012).

Events with M < 2 are not large enough to generate ground motions that people feel and termed “microseismic” (NAS, 2013; Atkinson et al., 2020).  It is now well understood that the HF process does not pose significant risk for inducing felt (M > 2) seismic events [NAS, 2013; Schultz et al., 2020; Ge and Saar, 2022]. The United States currently has over 35,000 producing wells for shale gas development (EIA, 2022), and each of these wells has been HF-stimulated. Yet only 6 exceptional cases have been identified when the earthquakes could be felt (M ranging from 2.7 to 4) and may have been HF-induced (Schultz et al., 2020; Atkinson et al., 2020; Ge and Saar, 2022). Worldwide, only 12 such cases are known (Schultz et al., 2020; Ge and Saar, 2022), and in all of them HF took place at the depth of ≳ 103 m and caused reactivation of preexisting faults.

The SIRGE hydraulic fractures are envisioned at a depth less than a few hundred meters.  The stored energy at this depth is too low to induce seismicity that could cause concern, which is backed up by the quantitative analysis (Garagash and Germanovich, 2012). As the SIRGE injections are intended to take place sufficiently far from both mature and immature faults, the corresponding seismic risk is deemed to be insignificant. Moreover, most of the applications we envision would involve injection into weakly cohesive sediments, which are unlikely to create any significant seismicity when deforming. Therefore, it is unlikely that induced seismicity will be important during SIRGE, even though it is important in other subsurface fluid-injection applications.

Nevertheless, to mitigate the seismic risk, the SIRGE method involves site characterization that is similar to other applications and includes in-situ stress analysis as well as determining the dominant geological controls on induced seismicity such as formation lithology, layering, cementation, permeability, and the presence of pre-existing faults (Keranen and Weingarten, 2018; Zoback and Kohli, 2019).  At a minimum, the potential SIRGE-related seismic risk does not exceed that associated with the existing fluid-injection activities and can be managed by the existing methods (NAS, 2013; Templeton et al., 2021; Foulger et al., 2022).

It should be noted that the induced micro-seismicity (M < 0) caused by SIRGE injections is expected even in non-cohesive sediments and can be used as an additional tool for monitoring SIRGE fractures (Gwaba et al., 2018).