Induced seismicity frequently is in the news, especially in Arkansas, Texas, Oklahoma and Ohio, where an increase in the number of earthquakes may be tied to injection wells.
Induced seismicity frequently is in the news, especially in Arkansas, Texas, Oklahoma and Ohio, where an increase in the number of earthquakes may be tied to injection wells.
Induced seismicity has been definitively tied to only one hydraulic fracturing procedure in the U.S. (Okla. Geological Survey, 2011), but seismicity has been associated with a small percentage of disposal wells that, in comparison to hydraulic fracturing, inject much larger volumes over longer periods.
These injection wells are regulated under the Safe Drinking Water Act, Underground Injection Control Program (UIC) as Class II wells, and are used for disposal of fluids associated with oil and gas production. EPA reports that 144,000 Class II wells in operation in the United States inject over 2 billion gallons of brine every day. (Should you wonder–Class I wells are used for disposal of industrial and municipal waste, and Class VI wells are for geological sequestration of CO2.)
Thirty-three states, including many oil and gas producing states, have been granted primacy by EPA to regulate Class II wells. Of the oil and gas producing states EPA, rather than the state, regulates Class II wells in Kentucky, Michigan, New York, Pennsylvania, Tennessee, and Virginia. Other oil and gas producing states– California, Colorado, Indiana, Montana and South Dakota–have joint state/EPA regulation of Class II wells.
Until recently there were no specific guidelines or rules for managing injection wells that were associated with increased seismic activity.
In January 2014 the Environmental Protection Agency (EPA) issued a report (work product #2011-3) titled “Minimizing and Managing Potential Impacts of Induced Seismicity from Class II Disposal Wells: Practical Approaches.”
The report defines three components that are necessary for significant injection‐induced seismicity: (1) pressure buildup from disposal activities, (2) faults of concern, and (3) a pathway for the increased pressure to communicate with the fault. The report then provides a decision model for assessing the three components and recommends procedures for mitigating seismicity that may develop in the vicinity of an injection well.
EPA points out, “the decision model [provided in the report] is not required to be used but simply provides a tool to assist regional or state underground injection control programs in determining what actions may be appropriate when attempting to minimize or manage the potential impacts of injection-induced seismicity…”
As an example of EPA regulation of induced seismicity, a Pennsylvania 2013 injection permit stated: “The SDWA regulations for Class II wells do not require consideration of seismicity… Nonetheless, because of public concerns about injection-induced seismicity, EPA evaluated factors relevant to seismic activity … and established a maximum injection pressure in the draft permit designed to limit the potential for seismic events.”