The Basics - Induced Seismicity

What is induced seismicity?

Seismicity refers to the earthquake activity of a given area, i.e. the frequency and magnitude of seismic events. Induced seismicity is usually understood as microseismicity which results from human activity, such as 1) mining, 2) construction of large water reservoir impoundments with dams, 3) fluid injections into rock formations for waste water disposal or 4) stimulation of fluid flow using hydraulic fracturing in hydrocarbon or geothermal reservoirs. These activities involve changes in stress, pore pressure, volume and load in underground rock formations which can result in sudden shear failures in the subsurface, releasing pre-existing shear stress on weakness zones, such as fault structures or fractures.

For more information on induced seismicity see the Lawrence Berkeley National Laboratory Earth Sciences Division website as well as a recently published scientific research article by Durham University.

How does induced seismicity differ from naturally occurring seismicity?

Unlike naturally occurring seismicity (background seismicity), induced seismicity results from human activity. The main difference is that the vast majority of induced seismic events are of a small magnitude, usually below 0, which means that they cannot be felt by humans at the surface. In almost all cases the maximum magnitude of the induced seismicity is below the maximum magnitude of a naturally occurring earthquake in a particular region.

Physically there is no difference between induced and natural seismicity; both are characterized by shear slip on a fault or fracture. It can often be difficult to determine whether a given seismic event is of natural origin or induced, especially in the case of moderate to large seismic events. The reason is the pre-existing natural underground stress field and the often unknown significance of the added, human-induced contribution to the stress field. Clear rules and scientific methods to discriminate between natural and induced earthquakes are not yet well established or commonly accepted.

What magnitudes of seismic events may be expected from shale gas production?

When addressing induced seismicity in terms of operations related to shale gas production, the hydraulic fracturing process itself and the sometimes practiced injection of flowback or production water into disposal wells have to be considered. The vast majority of seismic events related to both hydraulic fracturing and waste water disposal in wells are in the range of micro or nanoseismicity (for definition, see Tab. 1). In general, hydraulic fracturing induces lower maximum magnitudes than water disposal in wells.

Tab. 1 Overview of different earthquake magnitude ranges, displacements, intensities and annual averages.

Magnitude range Class Displacement scale¹ Seismic event effects² Annual average³
8-10 Great 4-40 m serious to devastating damage ≥M8: 1*
6-8 Large 0.4-4 m can cause serious damage over larger areas M7: 17**
M6: 134**
4-6 Moderate 4-40 cm noticeable shaking, can cause major damage to poorly constructed buildings M5: 1319**
M4: 13000***
2-4 Small 4-40 mm felt, can cause slight damage M3: 130000***
M2: 1300000***
0-2 Micro 0.4-4 mm usually not felt, no damage
-2-0 Nano 4-400 µm not felt
-4 to -2 Pico 4-40 µm not felt
-6 to -4 Femto 0.4-4 µm not felt

1Bohnhoff et al. 2010
, 2for details, see USGS website, 3USGS; *Based on observations since 1900; **Based on observations since 1990; ***estimated.

There are plenty of data available on the magnitudes of induced seismicity from short term, high pressure hydraulic fracturing operations carried out in geothermal and unconventional hydrocarbon production. The final conclusion that can be drawn from these reports is that hydraulic fracturing causes a large amount of small seismic events, with the vast majority of events being too small to even be detected by geophones at the surface. An example of microseismic event distribution from a Barnett Shale hydraulic fracturing operation is shown in Fig. 1. The maximum magnitude recorded was -1.6 (negative seismic magnitudes exist since magnitude calculations are based on a logarithmic scale).

Fig. 1 Cumulative frequency distribution of microseismic events of different size in a Barnett Shale well (Worldwatch Institute 2010).

Higher maximum seismic magnitudes have been observed during long term, high pressure (waste) water injection into deep wells (for a review, see Nicol et al. 2011). In the case of long term water injection, much larger volumes of fluids are injected than in hydraulic fracturing operations. Additionally, long term water injections cover a timespan of several months or years, whereas hydraulic fracturing operations can be completed in a matter of hours or a day at the most. It should be noted that when larger magnitude seismic events occur, it is sometimes particularly difficult to establish whether these events were induced by fluid injection or were due to other processes.

Can seismicity induced by fluid injection be avoided?

Successful approaches exist to minimize the risk of seismicity induced by fluid injection operations, such as water disposal in deep wells, hydraulic stimulation in geothermal operations or hydraulic fracturing of hydrocarbon reservoirs.

The Geomechanical Study of Bowland Shale Seismicity on the evaluation of unusual seismic activity close to a shale gas exploration site in spring 2011 in Lancashire, U.K, suggested measures to mitigate the magnitude of seismic events. Recommendations include rapid fluid flow back after the treatments and reduction of the treatment volume. This should be accompanied with seismic monitoring and appropriate action when seismic magnitude exceeds the limit set by a so-called traffic light system. 

The Protocol for Addressing Induced Seismicity Associated with Enhanced Geothermal Systems (EGS), published early 2012 by the U.S. Department of Energy (DoE), is a best practice guide addressing induced seismicity during short-term, high-pressure water injection in geothermal reservoirs. It summarizes the results from three international workshops on the topic and offers a detailed description of concrete steps that should be taken into consideration for minimizing the risk of induced seismicity. The stimulation techniques in geothermal systems are similar to hydraulic fracturing operations in hydrocarbon reservoirs and therefore the steps proposed in the protocol offer valuable information for evaluating and managing the effects of induced seismicity in shale gas developments.

Following the identification of hydraulic fracturing induced seismicity in the Horn River Basin in NE BC, the Canadian Association of Petroleum Producers (CAPP, 2012) also released a protocol which recommends to a) assess faults, lineations, background seismicity and other possible cases of induced seismicity in the area, b) develop initial operational protocols including tracking local seismicity and any felt events, and microseismic monitoring if available, and c) react and elevate monitoring if something is observed.

An example of how to reduce the risk of seismic events related to water disposal was published by Ake et al. 2005 (abstract). The authors evaluated the relationship between earthquake production and injection parameters (injection rate, duration of pumping and injectate chemistry) during large-scale and long-term deep salt water injection in the Paradox Valley, Colorado, U.S.. The results of this analysis allowed modifications to be made to injection operations in order to minimize the likelihood of larger, damaging earthquakes.

How is induced seismicity measured in hydraulic fracturing operations?

Seismicity caused by hydraulic fracturing operations is, like any seismicity, recorded using various networks of seismometers. Since the seismicity caused by hydraulic fracturing operations is of a small magnitude, only nearby surface seismometers or downhole geophones can detect these signals.

To record hydraulic fracturing microseismicity, a network of seismometers is installed at ground level close to an operation site and, if possible, in observation wells close to the injector well. This is because the opening of fractures in the shale during the fracturing process produces microseismicity which can be measured and used to monitor the fracture propagation in the shale. In contrast to common (active) seismic surveys, where seismic waves are generated by a seismic source (e.g. a vibrator on a truck), the technique in use here is called Passive Seismic Monitoring, because no artificial seismic source is used.

What are the risks of induced seismicity?

When a shallow seismic event exceeds a certain magnitude (magnitude > approx. 3, see Tab. 1), induced seismicity, just like naturally occurring seismicity, may pose a threat to human security, the environment and infrastructure such as buildings or, in the case of shale gas production, operating equipment.

Are there benefits from induced seismicity?


Operators generally benefit from induced seismicity in that the seismic cloud is the only feature that allows characterization of the spatial extent of the created hydrofracture. This information is important for operators since it defines the portion of the reservoir that has been fractured, thus increasing the shale´s permeability and promoting the natural gas stream from the rock to the production casing.

What is the difference between a “seismic event” and an “earthquake”?

There is no difference in terms of meaning. Both terms are used equally in scientific literature with regard to induced seismicity. “Seismic event” is the more general term, while the term “earthquake” often refers to seismic events of higher magnitudes that are felt by humans. On this website the term “seismic event” is used since seismicity related to fluid injection in the volume range used in shale gas production is, in the vast majority of cases, in the range of micro to nanoseismicity. These events are not felt by humans at the surface and do not create any damage.

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Induced Seismicity

The Basics