to be of finite extent (see Appendix H for the calculation of the pore pressure induced by injection into a disc-shaped reservoir).
At the early stage of injection, the size of the bulb will essentially depend on the diffusivity of the rock and
to be of finite extent (see Appendix H for the calculation of the pore pressure induced by injection into a disc-shaped reservoir).
At the early stage of injection, the size of the bulb will essentially depend on the diffusivity of the rock and on the duration of injection (equal to the ratio of injected volume over the injection rate). The maximum induced pore pressure is equal to the ratio of the injection rate over the permeability times a function of the duration of injection. This means that the bulb size increases but the maximum pore pressure decreases with increasing rock permeability, everything else being equal. In other words, the induced pore pressure dissipates faster with increasing permeability. At the late stage of injection, the induced pore pressure does not depend on the injection rate and on the permeability, because it becomes proportional to the ratio of the volume of fluid injected over the storage coefficient.
The extent of the induced pore pressure field and the magnitude of the induced pressure are both relevant when assessing the risk of induced seismicity. A larger pore pressure increase brings the system closer to the conditions for initiating slip on a suitably oriented fault, if such a fault exists; a larger region of disturbed pore pressure will increase the risk of intersecting and activating a fault.
Inducing a significant seismic event requires an increase of the pore pressure above levels that have existed prior to fluid injection and over a region large enough to encompass a fault area consistent with the magnitude of the earthquake. For example, an earthquake of magnitude M 3 results from a rupture area of about 0.060 km2 (corresponding to 15 acres). Such a situation was encountered at the Rangely, Colorado, oilfield starting in 1957, when sustained waterflooding operations (secondary recovery to improve petroleum production) over a period of several years caused the pore pressure to increase (Box 2.4). Eventually, pore pressure reached a level about 17 MPa (170 bars)2 above the preproduction pore pressure, a threshold at which a series of seismic events began to occur; the largest of these events was M 3.4. However, waterflooding would not be expected to cause any significant seismic activity if the pore pressure did not exceed the initial pore pressure in a reservoir. Operators generally do not exceed preproduction pore pressure during waterflooding projects because they tend to maintain relative balance between the volumes of fluid injected and extracted. Exceptions to this generally balanced condition for waterflooding and resulting induced seismicity are cited in Appendix C.
Observations and monitoring of hydraulic fracturing treatments indicate that generally only microseismic events (microseisms, M < 2.0; see Chapter 1) are produced because the volume of fluid injected is relatively small (see also Chapter 3 for further details). Despite the fact that hydraulic fracturing does increase pore pressure above the minimum in situ stress (typically σh), the area affected by the increase in pore pressure is generally small, remaining in the near vicinity of the created fracture.
2 MPa = megapascal; 1 MPa is equivalent to 10 bars or about 10 atmospheres of pressure.