Seismic Induced Monitoring In Oil And Gas Production: What Is Really Required?
Dr Steven Taylor Principal, Weir-Jones and Associates, GeoEnergy Monitoring Systems, Inc

Although many countries are pursuing fracking in a bid to replicate the success of the United States in developing the Bakken and other shale plays, there is heightened concern among regulators and the public these days about how unconventional oil and gas production operations - including fracking - could impact local seismic activity. The article highlights innovative technologies in seismic monitoring to help mitigate the impact of induced seismicity and new and future regulations.

There is heightened concern among regulators and the public these days about how unconventional oil and gas production operations - including fracking - could impact local seismic activity.

With fracking now a major source of international economic growth as companies discover the value of tapping large reserves of oil and gas from shale formations, many countries are pursuing fracking in a bid to replicate the success of the United States in developing the Bakken and other shale plays. China alone is reported to have nearly as much shale gas in reserve as the US and Canada combined. Consequently, many nations will be looking at the early development of the industry in North America as particularly instructive on what they may wish to emulate or avoid in developing this industry. But in doing so, they must be aware of several negative aspects of fracking, including induced seismicity and regulatory restrictions that are being introduced in many jurisdictions to protect structures, people and the environment.

Fortunately, innovative technologies in seismic monitoring have been developed to help mitigate the impact of induced seismicity and new and future regulations.

During the past 40 years, a dramatic evolution in the technology has meant that engineers, with state-of-the-art digital recorders, tri-axial down-hole sensor packages and real-time data rendering, can now monitor geo-mechanical phenomena at depths of greater than 10,000 feet. In the oil and gas sector, production and fracking operations can be monitored in near real-time so precisely that they can shut down immediately if a safety or operational situation arises.

Previously, seismologists often assumed each injection facility or region needed a network of observatory grade sensors capable of detecting and locating events to magnitudes less than 0, which is a very expensive proposition. The new systems have been developed specifically for induced seismicity monitoring, working within the relevant ranges of magnitudes pertinent for frac monitoring and regulatory compliance: 0.5 magnitude and larger.

A new generation of induced seismicity monitoring systems has recently been introduced that offers a low-cost alternative to traditional PMMs, plus various other benefits, which have created a paradigm shift for induced seismicity monitoring. These are easy to deploy and efficient to operate and are designed for oil and gas operators who want to minimise the risk of mandated operational shutdowns, and regulatory penalties, resulting from the inducing of seismicity during fracking or fluid disposal.

Some are standalone systems designed, developed, and implemented by a highly trained earth scientists and engineers who have worked in the induced seismicity monitoring and regulatory sectors in the US, Canada, and overseas for more than 40 years. They aim to provide all stakeholders with greater peace of mind by ensuring that fracking operations are undertaken in a responsible manner in compliance with regulatory requirements.

Most O & G energy regulations rely on a ‘Traffic Light’ system which ties fluid injection activities (including fracking) to the location and magnitude of seismicity within a specified distance from a well. In North America, seismicity is usually monitored by state or province geological surveys in collaboration with national networks (e.g. United States Geological Survey or Natural Resources Canada).

In many areas, the government monitoring networks are sparse and epicentral errors can be as large as 10 kilometres. An area of 10 km can encompass many injection wells with different operators. Additionally, reported magnitudes from sparse networks can have significant random errors and can be biased high through a statistical phenomenon known as data censoring. The reported magnitude for an earthquake is the average of magnitudes from individual stations that detect the event and is usually based on peak amplitude measurements at each station which can show considerable scatter (random error). The positive magnitude bias occurs because of signal to noise (SNR) considerations. Induced seismicity magnitudes of concern (i.e. felt) are typically of moderate magnitude (e.g. 1.5 to 5).

On a sparse network, where some stations are noisier than others, the signals will not always be of high SNR. Further, earthquakes radiate seismic energy preferentially in different direction (radiation pattern) depending on the type of faulting that occurs. Thus, the only sparse network stations reporting magnitudes from moderate sized events may be those on a favorable portion of the radiation pattern and that have quiet recording conditions .

Because of the considerations above, the consequences associated with a traffic light system can be severe to an operator and may be unfounded. If the operator has access to seismic data collected near the affected facility it is possible to avoid a costly shutdown and instead implement mitigation efforts, such as reducing well pressures and volumes for a short period of time.

What is needed for an operator to comply with regulations and to mount a defense against poorly reported seismic locations or magnitudes ?
Most government (or university) seismic stations are observatory grade consisting of expensive data recorders broad band seismic sensors that are buried in the ground (in post holes or vaults). The systems are very expensive (upwards of USD 20,000), difficult to deploy and require significant power. The data from such systems is excellent and are capable of recording negative seismic magnitudes at local distances. However, traffic light regulatory systems typically call for no action on the part of an operator unless magnitudes are above local magnitude (ML) 2 within 3 to 5 km of a well. This means that seismic deployments necessary to meet regulatory requirements do not have to be overly expensive or complex. In many cases, a single station at a facility may be all that is necessary by providing event origin times, magnitude and distance (from S minus P arrival times). If seismic location is required then 3 or more stations are necessary. Event location has the benefit of visualising trends of seismicity and the possibility of locating fractures and faults.

Because background noise affects detection thresholds, a system such as QuakeMonitor developed by Weir-Jones and Associates and GeoEnergy Monitoring Systems, Inc, is designed to be placed on the surface typically at an injection facility (although seismometers can be buried as well). Noise levels at surface sensors are higher than those for buried sensors, but our deployments at injection facilities have shown that it is possible to detect ML = 1 to 1.5 events at a distance of 10 km and ML = 2 at 20 km. Although noise levels at a facility are higher than at some distance off site, there are advantages to placing units on site. First, finding sites and obtaining permits which can be time consuming and costly is not necessary. Security is also not a problem for on-site deployments. In cold weather regions, such as the Boreal Plans in Alberta, marsh like conditions can occur with many bogs which can make travel to remote sites difficult as well as sensor emplacement. Engineered soil platforms available at injection facilities alleviate many of these problems.

For remote operations, narrow-bandwidth Orbcomm or Iridium satellite communication is used to transmit parameter data. One of the key components of the system for remote operation is the capability of on-board processing on an Atmel AVR 32 bit microprocessor on a Linux operating system. Sophisticated on-board processing algorithms allow parameter data including arrival time picks, signal polarisation, amplitudes and signal diagnostics to be transmitted via narrow bandwidth Orbcomm or Iridium satellite. This greatly reduces power consumption and allows the QuakeMonitor to be very small, lightweight and capable of remote operation for long periods of time (e.g. 6 months).

On board processing algorithms are physically based and have sound statistical underpinnings. This allows for signal processing parameters to be set prior to deployment in an area where little or no ground truth calibration data are available. For example, the commonly used Short Term Average to Long Term Average (STA/LTA) power detector has been modified for both detection and picking. Through construction of appropriate hypothesis tests, both detection and P-wave arrival time picking using the same STA/LTA values can be made using five preset signal processing parameters; short- and long-term window lengths, SNR detection level, effective bandwidth and false detection rate. Using signal processing parameters to set thresholds eliminates much of the uncertainty associated with placing an instrument in an uncalibrated region.

Perhaps of more significance, these Next-Gen systems give operators the tools to remain compliant with all current and future regulations, while providing them with information to remediate their operations if necessary or required. Likewise, they can give regulators, interested third parties and the public greater piece of mind that frac operations can work within acceptable norms and regulatory requirements.