Energy Technologies: How They Work and Their Induced Seismicity Potential - Induced Seismicity Potential in Energy Technologies - page 63

the artificially created fractures and can be used as stress measurement tools (Appendix I
describes this kind of microseismic monitoring; see also Engelder, 1993).
After the hydraulic fracturing is completed, a process known as flowback occurs. The
well is opened and injected hydraulic fracture water is allowed to flow back from the forma-
tion into the well. For tight shale formations, between 10 and 50 percent of the hydraulic
fracture water is returned (King, 2010). The flowback water may be reused as fracturing
water for another hydraulic fracture procedure, may be disposed of in a wastewater injection
well (see next section), may be stored, or may be treated to a purity that would allow for its
safe release to the environment or for its use for other beneficial purposes. Two National
Research Council reports (NRC, 2010, 2012) describe in some detail the potential options
for management and beneficial use of wastewater from industrial activities.
The process of hydraulic fracturing a well as presently implemented for shale gas recovery
does not pose a high risk for inducing felt seismic events ( M > 2). Estimates suggest that over
35,000 wells for shale gas development exist in the United States today (EPA, 2011). Only
one case has been documented worldwide in which hydraulic fracturing for shale gas develop-
ment has been confirmed as the cause of felt seismic events. This event occurred in Blackpool,
England, in 2011 (De Pater and Baisch, 2011; Box 3.6). Three other possible earthquake
sequences have been discussed in the literature that may be associated with hydraulic fractur-
ing in Oklahoma, only one of which was related to shale gas production. In the most recent
case, in 2011, hydraulic fracturing for shale gas production was cited as the possible cause
of felt induced seismic events, the largest of which was M 2.8 (Holland, 2011; Appendix J).
The close proximity and timing of the earthquakes to the hydraulic fracturing well suggested
a possible, but not fully established, link. However, the quality of the event locations was not
adequate to fully establish a direct causal link to the hydraulic fracture treatment.
The two other possible cases in Oklahoma discussed by Nicholson and Wesson (1990)
are listed under “Less Well Documented or Possible Cases” in their original paper (see
also Appendix C). Both cases were associated in time with hydraulic fracturing related to
stimulation of a conventional oil and gas field, not for shale gas production. The older of
the two cases relates to a series of earthquakes that occurred on June 23, 1978, near the
commercial stimulation of a 3,050-m (10,000-foot) well near Wilson, Oklahoma. Seventy
earthquakes occurred in 6.2 hours (Luza and Lawson, 1980; Nicholson and Wesson, 1990).
In the third case, two earthquakes were felt in a sequence in Oklahoma in May 1979, during
the time that a well was vertically stimulated in three different zones, ranging from deep
to shallow (ranging from 3,700 to 3,000 m depth [~12,000 to 10,000 feet]). The largest
event in this third case was M 1.9. The well was located 1 km (3,280 feet) from a seismic
monitoring station. The first hydraulic fracture treatment at 3,700 m depth was followed
20 hours later by about 50 earthquakes that occurred over a 4-hour time period. Forty
earthquakes immediately followed the second hydraulic fracture treatment at 3,400 m, over
a time period of 2 hours. No earthquakes were recorded during the third hydraulic fracture