Mitigating Arc Flash Hazards


Arc flash studies are a valuable part of implementing a National Fire Protection Association (NFPA) 70E program. Putting arc flash labels on electrical equipment, however, is not the only step needed to protect electrical workers. Most arc flash studies identify electrical equipment with incident energy at a given distance. We see many studies where dangerous above 40 cal/cm2 labels on electrical equipment warn workers of the high incident energy.

Having dangerous labels on electrical equipment is a good step to inform workers, but often workers still are asked to perform tasks on the equipment. Workers must understand labels. Labels do not mean no one can touch or work on the equipment; they simply give you incident energy at given distances. These often are worst case scenarios.

For example, if the system is a main tie-main, the incident energy often is given with the tie closed. If the distance or condition can be changed, then it might be possible to reduce the incident energy to which the worker is exposed. It is very important that facilities provide mitigation solutions to perform necessary tasks. These can range from written procedures to installing additional hardware to reduce the incident energy.


One of the simplest measures to mitigate incident energy is providing written procedures. For example, Figure 1 shows a single-ended substation with the line side of the 480V main breaker having 111.1 cal/cm2 . NFPA 70E does not address protective clothing for incident energy more than 40 cal/cm.2 This is because the blast hazard above 40 cal/cm2 is as much of a hazard as the burn hazard. Even if you could protect the worker from the burn, the blast would be more than the worker’s body could withstand. Therefore, no PPE is available to protect the employee while racking this breaker in on a live bus. Because the sub is single-ended, however, there is no reason to rack this breaker in on a live bus. The bus should be de-energized using the medium-voltage switch (PD-0002). The incident energy at the switch is only 5.6 Cal/cm.2 Site procedures should require that the main 480V breaker be racked in only on a dead bus.

Another example of a procedure is shown in Figure 2. The line side bus for the tie breaker (MV breaker 2) shows to be 45.7 Cal/cm.2 If necessary to perform a task such as phasing in the tie cell with phasing sticks, the incident energy would need to be determined. The labels on the gear would show “dangerous” and “45.7 cal/cm2 @ 36 inches.” If 6-foot phasing sticks are used and the worker is at least 4 feet (48 inches) from the exposed bus, then the incident energy at 48 inches would be 34.6 cal/cm.2 Therefore, a procedure should be written for phasing specifying a minimum working distance of 48 inches and wearing level 4 PPE.

Many times procedures can be written to perform work in areas of high incident energy, as shown in the two examples. The labels generated from most engineering studies convey the worst-case incident energy. This can be with multiple generators running or tie breakers closed. If generators can be taken offline or tie breakers open to lower the incident energy, however, then procedures should be written to instruct the worker on steps to mitigate the hazard while performing a task.


In areas where procedures cannot mitigate the hazard, new protective devices might need to be added. These include adding circuit breakers, arc flash relays, instantaneous relays and maintenance switches. Adding hardware can be expensive, but in many cases the added worker safety is a must. One of the most common issues observed is 480V switchgear being fed by a transformer without a main breaker. This makes all the feeder breakers in the switchgear very dangerous to work on (see Figure 3).

This high incident energy makes it difficult to rack or operate the feeder breakers safely. The incident energy can be reduced by installing a main breaker (as shown in Figure 1). Many times the cost and available footprint makes it very difficult to add a 480V main breaker. Therefore, instead of adding a 480V main breaker, it might be possible to add current transformers and an over-current relay on the output of the transformer and have the relay trip the upstream MV breaker. If the distance to the upstream MV breaker makes it impossible to wire in a trip scheme, then it might be possible to add a breaker in the place of the fused switch at the transformer and trip that breaker.

Often there are areas of high incident energy where procedures alone cannot mitigate the hazard. The equipment, however, may be worked on only while the facility’s at light load during maintenance windows. When there are areas of high incident energy on electrical equipment that is operated only during specified times, such as low production, often the least expensive solution is adding a relay that is active only when a maintenance switch is on.

Figure 4 shows a digital over-current relay that is enabled only when electrical workers are racking in the 480V feeder breakers downstream of this 13.8kV breaker. Because the system does not have a main 480V breaker, all of the feeder breakers have high incident energy on the line side. When the maintenance switch is not on, the incident energy is more than 65 cal/cm2 at the 480V level. When the maintenance switch is enabled, the incident energy drops below 10 cal/cm.2 In this application, the coordination of the circuit is affected greatly by the additional relay so it is enabled only during maintenance windows when a task is performed on the 480V breaker. This allows operation of the 480V breakers downstream without turning off all breakers.

Another common solution for arc flash mitigation is adding an arc flash relay to electrical equipment. Arc flash relays typically have fiber-optic sensors that look for an arc and current sensors that also look for an instantaneous over current at the same time as the arc. Arc flash relays are very good when used in metal-enclosed electrical equipment where you can put the sensors between the operator and the circuit breaker being racked out. Care must be taken in open-air frame circuit breaker applications because the arc of opening under load can be enough to cause the light sensor to operate. Therefore, light optic placement is very important and must be positioned so as not to see normal operating conditions or false trips can occur.

Differential relays are another economical means of mitigation arc flash. Most engineering software cannot input differential relays into the electrical system model to determine their effect on incident energy. Therefore, we often see engineering studies that do not include the incident energy reduction created by this type of relaying. Transformer, generator, motor or bus differential protective relays greatly reduce the available incident energy, and these values must be calculated and included in any valid engineering study. Many times differential relaying can be added to the site in a more cost-effective manner than adding expensive breakers or other hardware.

Performing an arc flash study by itself does not ensure electrical workers are safe. A study gives useful information to quantify the incident energy for most tasks. In areas with high incident energy procedures or more, in-depth analysis often is required. If procedures cannot mitigate the hazard, then many types of hardware additions can help protect workers. Critical solutions are provided to expect electrical workers to operate any electrical gear safely and efficiently.

Mark Pustejovsky is engineering manager at Shermco Industries. He brings many years of experience and expertise in electrical testing, power quality, arc flash evaluations and protective relaying. For more information on Shermco Industries, visit


The Future of Testing Reclosers, Sectionalizers for Smart Grid


Modern reclosers and sectionalizers are used as part of smart grid automation systems. A smart grid delivers electricity from suppliers to consumers using digital technology to save energy, reduce cost and increase reliability. This means reclosers and sectionalizers isolate the problem or fault and can be set to reconfigure circuits to automatically re-energize those customers not directly connected to the problem of the circuit. (They are located along distribution lines to reduce the area or number of customers affected by a problem on the system.)

The new digital controllers can trip, close or both 1-, 2- or 3-phase modes depending on the fault types and logic settings. This means only the faulted phase can be set to trip. They can detect an evolving fault and change their operations when a fault evolves into a multiphase fault. They also can detect a defective primary switch then activate logic to block reclosing.

The latest applications include auto restoration systems used in looped, underground systems or both. With these automatic distribution restoration (ADR) systems comes the need for checking synchronization of each phase before the circuit is automatically closed.

Digital controller settings are not likely to drift and contacts are not likely to corrode as did the electromechanical and solid-state controllers, but digital controller weaknesses can cause unexpected operations:

  • Circuit wiring is virtual wiring or logic,
  • Radio frequency interference (RFI) occurs,
  • Breakdown of metal oxide varistors (MVOs) happen, and
  • Firmware upgrades can be problematic.

For these reasons, the same tests performed on electromechanical controllers–such as finding the pick up with a 3 to 5 percent accuracy test system or checking the output contacts with a buzzer–do little to ensure proper operation of a digital controller or to find potential problems. New approaches to test digital controllers must be established.

The 2003 blackout in North America and previous blackouts have resulted in the North American Electric Reliability Corp.’s (NERC’s) changing the operating rules for the reliability councils of North America. They are auditing all utilities that fall within the guidelines of being able to impact the reliability of the bulk power grid. If the transmission utilities depend on the distribution utilities for load shedding, then they might have to show how these distribution utilities practices meet these guidelines.

NERC auditors require the utility to show detailed documentation to prove maintenance practices are being followed and being kept on schedule. The substance of their practices also is evaluated. New utility system testing programs require shorter times between scheduled testing cycles. This requires increasing complexity of testing; higher accuracy test equipment than has been used before; and the challenge to perform all of this with a growing lack of experienced people.

Some of the needed functions of a new test system include:

  • To simulate all signals and contacts that the device being tested would see when in service and monitor all critical signals given by the device being tested;
  • To set up programs that automatically will provide real-world system conditions and sequences for all test specifications;
  • To reproduce identical test conditions and compare results year after year on each device tested;
  • To create accuracies better than 0.1 percent for voltages and currents;
  • To create variable frequency with accuracies better than 0.001 hertz;
  • To operate several test systems in asynchronized mode to perform ADR system testing and troubleshooting (for many schemes at least four test sets are required);
  • To easily update the tests with the actual recloser or sectionalizer settings being used;
  • To perform tests in the field when supplied from a portable generator–or from the inverter in the vehicle–without loss of capability or accuracy; and,
  • To use high-impedance inputs to detect a damaged or leaking MOV before it causes a misoperation.

All details must be known about how the device is intended to operate for each set of system problems for which the power system is being protected or restored. The test must confirm the device operates when there is a problem and must confirm the device does not misoperate when there is no problem or only part of the system conditions exist.

There are a few final points to consider when looking at reclosers and sectionalizers in smart grid operations:

  • Communication system times and delays frequently cause ADR systems to fail.
  • Logic program errors are the next most common cause of system failures (the standard logic for the device and the communications logic errors).
  • Testing all related parts of the system together is the only way to ensure the whole system works as expected.
  • Lab testing accounts for the actual communications system being used in the field. Many problems are found in the field related to geography, structures and other forms of interference.

David Marble, a professional engineer, is an applications engineer at OMICRON electronics Corp. USA. He attended Vermont Technical College and the University of Vermont and has worked 26 years in utility engineering and management positions. Marble has designed numerous specialized testing interfaces for reclosers and sectionalizers at OMICRON.

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