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Unconventional Oil and Gas: Understanding and Monitoring Induced Seismic Activity


4 Statutory and Non-statutory frameworks for monitoring and mitigating seismic activity

4.1 Overview

Recently published regulations for onshore oil and gas (shale gas) exploration in the UK (DECC, 2013) contain specific measures for the mitigation of induced seismicity including: avoiding faults during hydraulic fracturing; assessing baseline levels of earthquake activity; monitoring seismic activity during and after fracturing; and, using a 'traffic light' system that controls whether injection can proceed or not, based on that seismic activity. Regulatory measures to mitigate the risk of induced seismicity are also in place in the US, Canada. In the US, much of this regulation is aimed at induced seismicity related to wastewater disposal in UIC wells, although this is also relevant to induced seismicity from hydraulic fracturing. These measures are broadly similar to those specified by DECC. The magnitude limit set by DECC for the cessation of hydraulic fracturing operations (0.5 ML) is considerably less than the limits in California (2.7 ML) and Illinois, Alberta and British Columbia (4.0 ML), and may be considered a conservative threshold. Local monitoring systems that are capable of reliable measurement of earthquakes with very small magnitudes will be required to implement this limit successfully.

4.2 Measures for mitigation of seismic risk

There are relatively few published measures for mitigation of seismic risk from hydraulic fracturing operations in unconventional hydrocarbon reservoirs. This is keeping with the limited number of examples of earthquakes that have been large enough to be felt that were induced by hydraulic fracturing for UOG, and the supposed low risk of the process inducing destructive earthquakes (NAS, 2012). Extensive experience of induced seismicity in Enhanced Geothermal Systems has led to a series of measures to address induce seismicity that is often considered as "industry best practice". For example, the U.S. Department of Energy "Protocol for Addressing Induced Seismicity Associated with Enhanced Geothermal Systems" (Majer et al., 2012) list seven steps for mitigating seismic risk. These are listed in Table 4.1 and include establishment of seismic monitoring and quantifying the hazard from natural and induced seismic events.

Table 4.1. The U.S. Department of Energy Protocol for Addressing Induced Seismicity Associated with Enhanced Geothermal Systems (Steps are listed in the order expected to be followed). Adapted from Majer et al. (2012).

Step 1

Perform a preliminary screening evaluation.

Step 2

Implement an outreach and communication program.

Step 3

Review and select criteria for ground vibration and noise.

Step 4

Establish seismic monitoring.

Step 5

Quantify the hazard from natural and induced seismic events.

Step 6

Characterize the risk of induced seismic events.

Step 7

Develop risk-based mitigation plan.

Majer et al. (2012) make the following four recommendations for baseline monitoring in the geothermal industry.

1. Monitoring needs to fully characterise background seismic activity and identify any faults with the potential to be affected by operations, and should not be biased in time or space in the vicinity of the potential geothermal project. The duration of the background monitoring may be relatively short (one month) if there is already existing monitoring that can detect small earthquakes with magnitude around 1. If there is no existing monitoring, the duration may need to be extended for as long as six months.

2. High resolution instrumentation will allow induced activity to be modelled and forecast more accurately. As the induced earthquakes may span several orders of magnitude, say from -2 to 4, the monitoring system requires a high dynamic range to ensure that data of sufficient quality is recorded. Also, borehole installations are better than surface sensors as the signal-to-noise ratio is better, and this allows smaller events to be recorded, increasing resolution and location capability. The monitoring network should be able to provide comprehensive background monitoring over an area at least twice as large as the area of geothermal potential.

3. Data processing must provide locations, magnitudes and source mechanisms. A typical geothermal project, consisting of one or two injection wells and several production wells in an area with a diameter of 5 km, will require at least eight monitoring stations distributed over the area of interest.

4. Monitoring should be maintained throughout the injection activity to validate the engineering design of the injection in terms of fluid movement directions, and to guide the operators on optimal injection volumes and rates. This will also allow induced events to be discriminated from natural seismicity and ensure that local vibration guidelines are being followed.

Experience of induced seismic activity in Enhanced Geothermal Systems (EGS) has also led to the development of 'traffic light systems' linked to real-time monitoring of seismic activity (e.g. Bommer et al., 2006; Majer et al., 2012). These are essentially control systems for management of induced seismicity that allow for low levels of seismicity but add requirements when seismic events may result in a concern for public health and safety. For example, Table 4.2 shows the traffic light system used in Basel, Switzerland and adapted from Bommer et al. (2006). This has four levels: green, where injection proceeds as planned; yellow/orange, injection proceeds with caution, possibly at a reduced rate; and, red, injection is suspended immediately.

Table 4.2. Seismic response procedure used in Basel, Switzerland (and adapted from the traffic light system proposed by Bommer et al. (2006). The system is based on three independent parameters: (1) public response; (2) local magnitude (ML); and, peak ground velocity (PGV))

Traffic Light

Earthquake Activity

Earthquake Magnitude

Ground Velocity




ML < 2.3

< 0.5 mm/s

Regular operation. Continue pumping.



ML ≥ 2.3

≤ 2.0 mm/s

Continue pumping but do not increase flow rate



ML ≤ 2.9

≤ 5.0 mm/s

Maintain well head pressure below stimulation pressure


Widely Felt

ML > 2.9

> 5 mm/s

Stop pumping. Bleed off to minimum wellhead pressure

Any traffic light system requires the definition of acceptable limits for the cessation and recommencement of operations. These limits are generally based on levels of ground motion which may represent a hazard or a public nuisance. In some cases, the cessation of operations at a given limit may not be sufficient to preclude further seismicity. For example, in the case of Basel, 2006 (Giardini, 2009), operations were stopped when the traffic light threshold of 2.9 ML was exceeded, but this was still followed by a number of larger magnitude events. Bachmann et al. (2011) present an alternative probability based statistical approach that is used to describe and forecast features of the observed induced seismicity at Basel in 2006. This approach has the advantage of not being dependent on a single magnitude threshold but on many small events, which increases robustness. It also integrates injection rates and allows forecasts of the hazard/risk to be made.

In addition, an effective traffic light system depends on a real-time seismic monitoring system that can provide reliable automatic locations and magnitudes for events that are at least one or two orders of magnitude smaller than the lowest specified limit. For conservative thresholds, this may require accurate determination of source parameters for very small events with magnitudes of -1 ML or even less. Sensors may need to be deployed in boreholes to achieve this. Site specific monitoring systems in the geothermal industry often consist of several three-component sensors (geophones or accelerometers) installed in boreholes surrounding the volume of rock to be stimulated, at distances of 100 m to 10 km from the injection well. The sensors are generally placed at a range of depths (~100 - 2000m) with those sensors at greater depths designed to withstand high temperatures and pressures.

4.3 Regulation in the UK

Following the induced seismicity near Blackpool, UK in 2011, the UK Department for Energy and Climate Change (DECC) published a regulatory roadmap[3] to provide an indicative overview of the permitting and permissions process for exploratory work in oil and gas development, onshore in the UK, and to help operators understand the regulation process for onshore oil and gas (shale gas) exploration in the UK. The roadmap outlines the numerous steps, permitting and permissions required for exploratory work for onshore oil and gas development to proceed, from the award of the Petroleum and Exploration Development License (PEDL) through to well testing post drilling. Once a consent to drill has been granted (following the award of relevant permits and notification of all relevant consultees), the operator is responsible for the formulation of an outline 'Hydraulic Fracture Plan', to be agreed by DECC. The Hydraulic Fracture Plan must 'establish arrangements to control seismicity and provide a detailed plan for monitoring hydraulic fracturing operations' (DECC, 2013), achieved in part by the agreement of an appropriate 'traffic light' system. Following the approval of the Hydraulic Fracture Plan, DECC will then grant the operator the right to start hydraulic fracturing operations. The specific measures for the mitigation of induced seismicity are summarised in Table 4.3.

Table 4.3. Measures for the mitigation of induced seismicity set out in the DECC regulatory roadmap.


Use all available geological information to assess the location of faults before wells are drilled to avoid hydraulically fracturing near faults


Use British Geological Survey records to assess baseline levels for seismic activity (vibrations of the earth's crust)


Inject as little fluid as necessary into the rock during fracturing


Monitor seismic activity during and after fracturing


Adopt a 'traffic light' system that controls whether injection can proceed or not, based on that seismic activity

Green et al. (2012) suggest that since the number of fluid injection induced earthquakes depends on the injected fluid volume and formation pressure, reducing the volume of fluid and implementing flow back, where appropriate, is also likely to reduce the probability of significant earthquakes.

The DECC traffic light threshold for the cessation of hydraulic fracturing operations is 0.5 ML. An event of this magnitude is unlikely to be felt and does not pose any seismic hazard. It would only be detected by sensitive monitoring equipment in the vicinity of the epicentre.

United Kingdom Onshore Oil and Gas (UKOOG), the representative body for the UK onshore oil and gas industry, has also published guidelines for onshore shale gas wells in the UK[4]. These contain what is considered to be good industry practice and reference the relevant legislation, standards and practices. A key part of this process is that operators should develop a Hydraulic Fracturing Programme (HFP), following a risk-based approach, that describes the control and mitigation measures for fracture containment and for any potential induced seismicity.

4.4 Canada

In 2015, following seismicity in the Fox Creek area, the Alberta Energy Regulator (AER) issued Subsurface Order No. 2[5]. This order specifies requirements in relation to hydraulic fracture operations in wells within the Duvernay Zones. These include the following:

a) Assess the potential for induced seismicity and be immediately prepared to implement a plan to monitor for, mitigate, and respond to induced seismicity

b) Seismic monitoring conducted by or on behalf of the licensee pursuant to this order must be sufficient to detect a 2.0 ML seismic event within 5 km of any affected well.

c) Report any seismic events of 2.0 or above within 5 km of any affected well.

d) In the case of such an event, licensees must implement the induced seismicity plan to eliminate or reduce further seismic events caused by or resulting from hydraulic fracturing operations.

e) Immediately cease hydraulic fracturing operations if there are any seismic events of magnitude 4.0 ML or greater within 5 km of the affected well.

f) Suspended hydraulic fracturing operations may only be recommenced with written consent of the AER.

Similarly, following the seismicity associated with hydraulic fracturing in the Horn River area, the British Columbia Oil and Gas Commission (2012) published a number of recommendations for the mitigation of seismic risk in future hydraulic fracture operations for shale gas. These are listed in Table 4.4.

Table 4.4. Recommendations Investigation of Observed Seismicity in the Horn River Basin (BC Oil and Gas Commission, 2012)


Improve the accuracy of the Canadian National Seismograph Network in northeast B.C.


Perform geological and seismic assessments to identify pre-existing faulting.


Establish induced seismicity monitoring and reporting. Suspend operations on detection of a 4.0 ML or greater event


Install ground motion sensors to quantify risk from ground motion


Characterisation of any possible active faults in the region using all available data.


Submission of micro-seismic reports to monitor hydraulic fracturing for containment of micro fracturing and to identify existing faults

In addition, governments in all jurisdictions are increasing their monitoring of earthquakes, in cooperation with other jurisdictions, universities and stakeholders.

4.5 United States

There is no federal law whose primary purpose is to reduce the risk of seismic activity associated with fluid withdrawals or injections. States generally have the leading role in regulating shale gas development activities and regulation varies from state to state. While much of this regulation is aimed towards induced seismicity related to wastewater disposal in Class II Underground Injection Control (UIC) wells, much of this is also relevant to induced seismicity from hydraulic fracturing. Class II UIC wells are used specifically to inject oil and gas exploration and production waste for disposal, and for enhanced oil recovery through injection of water, gas, or other substances.

4.5.1 California

The California Code of Regulations section 1785.1 "Monitoring and Evaluation of Seismic Activity in the Vicinity of Hydraulic Fracturing" (2015) states the following:

(a) From commencement of hydraulic fracturing until 10 days after the end of hydraulic fracturing, the operator shall monitor the California Integrated Seismic Network for indication of an earthquake of magnitude 2.7 or greater occurring within a radius of five times the ADSA[6].

(b) If an earthquake of magnitude 2.7 or greater is identified under subdivision (a), then the following requirements shall apply:

(1) The operator shall immediately notify the Division[7] and inform the Division when the earthquake occurred relative to the hydraulic fracturing operations.

(2) The Division, in consultation with the operator and the California Geological Survey, will conduct an evaluation of the following:

(A) Whether there is indication of a causal connection between the hydraulic fracturing and the earthquake;

(B) Whether there is a pattern of seismic activity in the area that correlates with nearby hydraulic fracturing; and

(C) Whether the mechanical integrity of any active well within the radius specified in subdivision (a) has been compromised.

(3) No further hydraulic fracturing shall be done within the radius specified in subdivision (a) until the Division has completed the evaluation under subdivision (b)(2) and is satisfied that hydraulic fracturing within that radius does not create a heightened risk of seismic activity.

4.5.2 Colorado

The Colorado Oil and Gas Conservation Commission (COGCC), part of the Department of Natural Resources, permits and regulates Class II UIC wells[8]. The UIC permit review includes a review for seismicity, using Colorado Geological Survey (CGS) geologic maps, the United States Geological Survey earthquake database, and area-specific knowledge to assess seismic potential. If historical seismicity has been identified in the vicinity of a proposed Class II UIC well, COGCC requires an operator to define the seismicity potential and the proximity to faults through geologic and geophysical data prior to any permit approval. The COGCC also designates a maximum surface injection pressure in order to minimize the potential for seismic events related to fluid injection.

4.5.3 Illinois

Regulations[9] state that when an identified well is suspected of triggering induced seismic activity, the permittee must consult with the Illinois Department of Natural Resources (IDNR) and the Illinois State Geological Survey (ISGS) to develop a plan for seismic monitoring, that includes the possibility of new monitoring stations in the vicinity of the well and reduction in rate or pressures of fluid injected. A traffic light system is also in place that allows low levels of seismicity but additional monitoring and mitigation requirements when seismic events are of sufficient intensity to result in a concern for public health and safety.

Illinois DNR must order any operator of a Class II injection well to cease operations immediately if conditions "create imminent danger to the health and safety of the public, or significant damage to property" under any of the following conditions:

1. If an identified well receives a third Yellow Light Alert and within the last year the same permittee received a Notice of Violation for the same well related to flow, pressure or mechanical integrity;

2. If an identified well receives any number of Yellow Light Alerts and there is confirmed property damage to a building or structure as a result of the earthquake event with a magnitude greater than 4.5.

3. If an identified well regulated by this Section receives a fifth Yellow Light Alert.

4. If an identified well receives a Red Light Alert and is within 6 miles of the epicenter of the earthquake event measured from the surface above the hypocenter.

A Red Light Alert is issued to all operators of Class II UIC disposal wells located within 10 miles of the epicenter of an earthquake of magnitude 4.0 or greater.

Yellow Light Alerts are issued by IDNR to all operators of UIC Class II disposal wells located within 6 miles of the epicenter of a seismic event with a magnitude between 2.0 and 4.0. If an operator receives three Yellow Light Alerts within a one-year period, they must immediately reduce injection rates and consult with IDNR and ISGS.

4.5.4 Kansas

A state action plan for induced seismicity was published in 2015. This included the following recommendation and proposals:

1. The state should fund a permanent network of seismometers that would allow earthquakes with a magnitude of 1.5 or greater to be detected and located.

2. The state should fund a portable seismic array that could be deployed to areas experiencing seismic activity in order to obtain more detailed information regarding seismic events.

3. A formula for giving a numerical score to seismic events based on various criteria. Scores above a certain number should prompt regulators to increase monitoring and evaluate whether other regulatory steps are appropriate for a particular injection well or area.

An order issued by the Kansas Corporation Commission in 2015 requires operators of injection disposal wells located in certain areas to measure daily injection volumes and pressures, and to report each month on the daily figures for the prior month

4.5.5 Ohio

The Ohio Department of Natural Resources Division of Oil and Gas Resources regulates oil and gas activity and Class II injection wells. After the Youngtown earthquakes in 2011 (Horton, 2012), the Department revised its rules regarding injection disposal to address the threat of induced seismicity. Regulation regarding permits for injection disposal[10] states that the Division of Oil and Gas Resources may require that the operator of an existing well to carry out pressure fall-off tests, investigation of potential faulting within the immediate vicinity of the proposed site, tracer or spinner surveys, and various logs. The Division also may require the operator to submit a plan for seismic monitoring. In addition, the Division may require that the Operator cease operations while the Division is evaluating submitted information. The regulations also give the Division the authority to "implement graduated maximum allowable injection pressure requirements based upon data provided".

Regulation regarding operation of injection disposal wells[11] states that all new injection wells must be continuously monitored using an acceptable method and that operators must install a device that will automatically shut off the injection well if injection pressures exceed the maximum pressure allowed by the permit for that well.

4.5.6 Oklahoma

Oil and gas activity and Class II injection wells are regulated by the Oklahoma Corporation Commission, Oil and Gas Division. Regulations[12] require that operators of injection disposal wells record injection volumes and pressures on a monthly basis. Additionally, for injection into the Arbuckle Formation, the state's deepest injection formation, operators must monitor and record injection volumes and pressures on a daily basis, keep the records for at least three years, and provide the records to the Commission upon request. The Commission considers such factors as seismicity in the area around the proposed well site and the proximity of the site to faults as part of the permitting process.

In areas of specific interest, the Commission requires operators to record injection volumes and pressures daily. These areas are defined as:

1. All locations within 10 km of the epicenter of an earthquake with a magnitude of 4.0 or greater.

2. All locations within 10 km of an earthquake swarm. Where a swarm is defined as an area consisting of at least two events with epicentres within 0.25 miles of one another and at least one event with a magnitude 3.0 or above.

3. All locations within three miles of a stressed fault, whether or not there has been seismic activity.

4.5.7 Texas

The Railroad Commission regulates oil and gas activity and Class II injection wells. Existing fluid injection regulations were recently revised in order to address and minimize the risk of induced seismicity. The amended Texas Administrative Code states that:

1. Applications for a permit for a new injection well to dispose of saltwater or other oil and gas waste must include USGS information on historical earthquake activity in a 100-square-mile area around the proposed injection site.

2. The Commission has the authority to modify, suspend, or terminate a disposal well permit if scientific data indicates that a disposal well has been determined to be contributing to seismic activity or is likely to be determined to be contributing to seismic activity.

3. The Commission can require operators to report injection volumes and pressures on a more frequent basis than the annual basis otherwise required if conditions exist that increase the risk that fluids will not be contained in the 'injection interval' and

4. The Commission can require an applicant for a new injection permit submit information not otherwise required for a permit application if the location proposed for the well is one where conditions exist that increase the risk of non-containment.

4.6 Discussion

Both the DECC and BC Oil and Gas Commission measures make it clear that avoiding injection into active fault zones and faults in brittle rock is likely to reduce the possibility of significant induced seismicity. However, identifying such faults may require a more accurate model of the sub-surface geology than is presently available in some areas. In the case of the Blackpool induced earthquakes in 2011, detailed 3D seismic reflection data was was not available in the vicinity of the well at the time of drilling/well stimulation.

Reviews of historical seismicity are required in many places where hydraulic fracturing operations are ongoing or planned, including the UK, Canada, Colorado, Oklahoma and Texas. The quantity and quality of information will vary depending on a number of factors such as previous monitoring and research. It is important to note that existing catalogues may be limited and the completeness will decrease with magnitude and with time. This may limit the amount of detail on the spatial variation of smaller earthquakes.

It is widely recognised that seismic monitoring is required for monitoring seismic activity during hydraulic fracture operations and as an essential part of any traffic light system. There are no accepted best practice guidelines on how this should be done in terms of numbers or types of sensors, although, for example, the AER state that any seismic monitoring must be sufficient to detect a 2.0 ML seismic event within 5 km of an affected well, which does place some constraint on any network of monitoring sensors.

In the UK, limit for the cessation of hydraulic fracturing operations (0.5 ML) is considerably less than the limits for California (2.7) and Illinois, Alberta and British Columbia (4.0). The detection of earthquakes with a limit of 0.5 ML requires suitably sensitive monitoring networks to be deployed near to active sites during and following hydraulic fracturing. Improved monitoring and measurement at much lower levels will be required to implement such a system successfully. By contrast, a magnitude limit of 4.0 would mean that events near the upper limit would be strongly felt in areas of higher population density such as the Midland Valley of Scotland.

The National Research Council in the U.S. (NAS, 2012) compiled a list of questions (Figure 4.1) that can be used to understand and possibly quantify the hazard and risk associated with induced seismicity associated with energy technologies. These primarily relate to the strength of the ground shaking and whether it can be felt and if it might represent nuisance to people or a risk to structures. This suggests that microseismicity, with magnitudes of less than 2, does not pose a risk. Earthquakes that result in weak or moderate shaking are unlikely to result in damage to structures but may represent a nuisance if they occur frequently.

Figure 4.1. Questions to be addressed to understand and possibly quantify the hazard and risk associated with induced seismicity associated with energy technologies (from "Induced Seismicity Potential in Energy Technologies", National Academy of Sciences, 2012)

Figure 4.1. Questions to be addressed to understand and possibly quantify the hazard and risk associated with induced seismicity associated with energy technologies (from "Induced Seismicity Potential in Energy Technologies", National Academy of Sciences, 2012)