EGS: What is the history and cause of seismicity in geothermal areas?
In the geothermal world, induced seismicity has been documented in a number of operating geothermal fields and EGS projects. Induced seismicity has been observed for over thirty years in a variety of sites in the US as well internationally. Such areas as Indonesia, the Philippians, South America, New Zealand, The Geysers and Coso geothermal in California fields have a long history of geothermal production and a range of induced seismicity. In the most prominent cases, thousands of earthquakes are induced annually. These are predominantly microearthquakes (MEQs) that are not felt by people, but also include earthquakes of magnitudes up to the magnitude 4 ranges. Recent sites such as Basel (Switzerland), Landau (Germany), and Soultz (France) have been in the news lately and have experienced moderate seismicity due to EGS activities. Although this seismicity has been short-lived, it has attracted the attention of the local communities because of its close proximity.
There are several different mechanisms that have been hypothesized to explain these occurrences of induced seismicity in geothermal settings:
- Pore-Pressure Increase: As explained above, in a process known as effective stress reduction, increased fluid pressure can reduce stresses, keeping the faults from failing and thereby facilitating seismic slip in the presence of an unbalanced stress field. In such cases, the seismicity is driven by the local stress field, but triggered on an existing fracture by the pore-pressure increase. In many cases, the pore pressure required to shear favorably oriented joints can be very low, and vast numbers of microseismic events occur as the pressure migrates away from the wellbore in a preferred direction associated with the direction of maximum principal stress. In a geothermal field, one obvious mechanism of induced seismicity is fluid injection. Point injection from wells can locally increase pore pressure and possibly account for high seismicity around injection wells. If the rock is of very low permeability (not many open fractures), then it may be necessary to inject fluids at higher pressures. At higher pressures, fluid injection can exceed the rock strength, actually creating new fractures in the rock, i.e., hydrofracture of the rock (as discussed above).
- Temperature Changes: Fluids interacting with hot rock can cause contraction of fracture surfaces, in a process known as thermoelastic strain. As with effective stress, the slight opening of the fracture reduces static friction and triggers slip along a fracture that is already near failure in a regional stress field. Alternatively, cool fluids interacting with hot rock can create fractures and seismicity directly related to thermal contraction. In some cases, researchers have detected nonshear components, indicating tensile failure, contraction, or spalling mechanisms.
- Volume Change Due to Fluid Withdrawal/Injection: As fluid is produced (or injected) from an underground resource, the reservoir rock may compact or be stressed. These volume changes cause a perturbation in local stresses, which are already close to the failure state. (Geothermal systems are typically located within faulted regions under high states of stress). This situation can lead to seismic slip within or around the reservoir. A similar phenomenon occurs where solid material is removed underground, such as in mines, leading to “rockbursts” as the surrounding rock adjusts to the newly created void.
- Chemical Alteration of Fracture Surfaces: Injecting non-native fluids into the formation (or allowing fluids to flow into the reservoir due to extraction) may cause geochemical alteration of fracture surfaces, thus reducing or increasing the coefficient of friction on the surface. In the case of reduced friction, MEQs (smaller events) would be more likely to occur. It has been hypothesized that if seismic barriers evolve and asperities form (resulting in increased friction), events larger than MEQs may become more common.
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