**2. Effect of fluid injection on induced seismicity**

The occurrence of injection-induced seismicity is usually confined in both space and time, with pressure build-up and diffusion controlling the spatial and temporal pattern of the seismicity after a hydrofrac treatment. Spatially, the problem can be conceptualized as a scenario in which a wellbore in the vicinity of a critically-stressed fault is pressurized and the injected fluids diffuse towards the fault, increasing pore pressures and reducing the effective normal stress until slip is triggered along a portion of the fault. The transient nature of the fluid front as it radiates outward from the injection well allows for the triggering of events after injection and shut-in, referred to here as post-injection seismicity.

The importance of fluid pressure in generating induced seismicity was demonstrated in 1962 in Denver, Colorado, when it was observed that a series of seismic events were being generated shortly after a chemical weapons plant had begun injecting contaminated wastewater down a deep well. Detailed studies by Hollister and Weimer [1] and Healy et al. [9] confirmed the causal observations of Evans [10] that the seismic events were induced by the waste fluid injection. Similar relations between local seismicity and fluid injection were likewise observed at the Rangely Oil Field, Colorado by Pakiser et al. [11], Healy et al. [12] and Gibbs et al. [13], and in the Los Angeles basin by Teng et al. [14].

More recently, post-injection seismicity associated with gas shale and geothermal projects have entered the public spotlight with heightened sensitivity directed towards hydraulic fracturing practices and induced seismicity. Between 2000 and 2005, numerous seismic events were recorded at the European geothermal project in Soultz-sous-Forêts, France, with events as large as M=2.5 being recorded during injection and M=2.6 several days after shut-in (Charlety et al. [15]). For stimulations carried out in 2000, 2003 and 2004 the largest seismic events occurred just after or after shut-in. Similar experiences were encountered at Basel, Switzerland where induced seismicity reached a Richter Magnitude of 3.4 despite precautionary reductions of the injection rate, leading to suspension of its hot dry rock enhanced geothermal systems project (Haring et al. [16]).

Experiences with hydraulic fracturing treatments in gas shales have generated similar seismicity, generally viewed as low risk due to the remote nature of the locations. In the Bowland shale, Lancashire, UK, two notable events were recorded with Richter Magnitudes of 1.5 and 2.3. These occurred almost 10 hours after shut-in (de Pater and Baisch [17]). de Pater and Baisch [17] suggested that reducing the treatment volume is one means to mitigate induced seismicity. In a detailed study in the Horn River Basin in northeastern British Columbia, Canada, approximately 38 events ranging between Richter Magnitudes 2.2 and 3.8 were recorded between 2009 and 201l, with only one being felt on surface in this remote region (BCOG, [18]). In their 2012 report of the findings from this investigation, the B.C. Oil and Gas Commission found that several of the Horn River events greater than M 2.0 were located along faults intersecting the wellbores. They also note that there were other instances where faults intersected wellbores without anomalous events being detected (BCOG, [18]).
