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The Three Arc-Flash Mitigation Levers

Nov. 9, 2023
Understanding how energy, time, and distance impact an arc flash event’s potential risk to electrical workers

In the not-so-distant past, electrical workers routinely racked out breakers in the normal course of their jobs. They did this with little concern or knowledge of the hazards to which they were exposed. While all of us are more educated and knowledgeable today, many electrical workers still prefer the expediency of putting on a 40-cal suit over taking advantage of other available solutions.

Today, there are state-of-the-art remote racking and switching systems that allow a qualified electrical worker to interact with circuit breakers from a distance outside of the arc flash boundary. This is a big step in reducing safety risks related to arc flash. Remote racking systems require a significant investment and take time to learn. This can lead to them being under-utilized in cultures that fail to understand the consequences of an arc flash and the available strategies to mitigate arc flash severity and exposure.

Three factors affect arc flash incident energy level:

  1. Energy. The available fault current at a particular system location.
  2. Time. How long it takes to clear a fault.
  3. Distance. Proximity to the fault is exponentially proportional to its intensity.

These are the only levers available to reduce an arc flash event’s potential injury to electrical workers.


The first lever of reducing available fault current — energy — is the least useful. Facilities are commonly increasing the sizing (ampacity) of their power system equipment. Low-voltage switchboards of 4,000A to 5,000A are becoming increasingly more commonplace. This level of power is necessary for processes/manufacturing and to save cost over installing multiple smaller systems.

Outside the facility, the utility power system is designed to feed numerous systems (i.e., facilities). This translates simply into the idea that there’s plenty of fault current available, and there’s just not much that can be done about that (particularly at the service entrance). Arc-resistant switchgear is an attempt to mitigate these high-energy hazards. If you aren’t familiar with arc-resistant switchgear, picture military-tank-like switchgear with plenums (ducts) to route the force of a blast out of the room, thereby mitigating the likelihood of a switchgear explosion injuring a qualified worker.


The second lever is the time or duration that an overcurrent fault can persist before system protection isolates the overcurrent fault. Traditional power system protective devices are coordinated to obtain a balance between power system reliability and equipment safety (not qualified worker safety). This reliability factor allows overcurrent faults to occur and persist for a second(s) while the downstream breakers closest to the fault time out and trip. Please note that each system has its unique coordination settings that determine the time delay during a fault.

Fortunately, technology is evolving to provide improved safety for qualified electrical workers and system reliability, creating a win-win for the facility and the qualified worker.

Systems and technology categories to mitigate arc flash include:

  1. Arc flash relaying
  2. High-speed bus differential relaying
  3. Maintenance bypass switching
  4. Arc-quenching switchgear designs (not addressed in this article)

Systems that (dare I say) can largely eliminate arc flash:

  1. Gas-insulated switchgear (GIS)
  2. High-resistance grounding (HRG)

Arc flash relaying

Arc flash relay technologies work to trip faster than traditional overcurrent protection by using a combination of inputs. The typical inputs are fault current and light sensors and/or pressure sensors (Fig. 1). The sensors consist of fiberoptic point sensors or clear-jacketed fiber loops. Point sensors are typically installed in switchgear compartments (breaker enclosures). Fiber loops can be routed through several sections, such as bus compartments.

Trip and trip faster testing

These devices add a level of complexity to standard testing. Two tests are required to verify proper operation:

  1. A traditional overcurrent test to prove that the relay operates per its coordinated settings (time delay).
  2. The second test would be a combination of both the overcurrent and a light input.

An on-the-job learning moment

Attempting to simulate real-world fault scenarios is the best method to ensure that protective devices are operating as designed. For an arc flash protective feature test, a relay manufacturer recommended a particular camera flash model be used. We bought the flash model and wrote “the perfect” relay test plan. This plan would initiate an overcurrent fault and initiate the camera flash at the same instant in time — just like a real arc flash event. To our disappointment (and my frustration), the system failed to pass the test. Repeated attempts and double-checks of the camera model didn’t solve our problem. Why didn’t the camera flash work? The time-over-light (TOL) setting was new to me at that time. Like time overcurrent (TOC), the greater the fault current, the faster the relay operates. In the case of light, the more intense the light, the faster the relay operates (Fig. 2). The camera flash (even though it had been recommended) was insufficiently bright enough for long enough to meet the requirements.

The solution, while not ideal, was to use a flashlight to verify this TOL operation by introducing enough light over enough time (a few seconds) to activate the light sensor TOL pick-up element. Once the light sensor element was verified picked up, the fault current was initiated to verify that the relay tripped instantaneously (no intentional delay). Once the trip operation was proven, each loop or point had to be verified for the TOL pick up. Relays monitor each sensor to ensure that the fiber is intact. A final verification of the relay is to disconnect each sensor individually to ensure that the relay detects this loss and provides a notification.

High-speed bus differentials

The waveform in Fig. 3 is a fault that was captured by a power system relay. Refer to A phase in the Figure. A worker who was in the wrong cubicle (and failed to verify the absence of voltage before applying grounds) unintentionally grounded an energized 13.8kV system conductor. Technician note: ALWAYS perform a live-dead-live check of your voltage detection meter. To everyone’s amazement (and good fortune), the only thing that happened was that the facility was plunged into darkness — no explosion, no arc flash, not even a scratch on the grounds. This fault, which was cleared by a high-speed bus differential relay, demonstrates the value of clearing faults quickly (three cycles in this case).

Maintenance bypass switches

Clearing faults quickly and at lower current values is the theory of operation behind maintenance bypass switches. As an example, to maintain system reliability, an instantaneous trip on a low-voltage main circuit breaker may be set to 32,000A (eight times the rating of a 4,000A breaker). This setting is great for reliability, but not for safety.

While racking a breaker in or out in a maintenance situation, the switch is used to turn on an alternate group of settings. In this alternate group of settings, the instantaneous value is changed to a lower setting. This means that instead of 32,000A, the breaker could trip instantaneously as low as 6,000A (depending on trip unit type). This reduces the amount of fault current necessary to activate the instantaneous element as well as eliminates the time delay to clear a fault, should one occur.

Testing these systems is straightforward. Test the breaker at its normal settings. Place the switch in maintenance mode. Verify the settings group changes. Verify that the breaker operates at the lower current setting. An important final note for power system reliability: Always remember to return the maintenance bypass switch to its normal position (Photo).

Two brief thoughts on GIS and HRG to eliminate arc-flash hazards:

  1. GIS gear in a nutshell. No exposed energized parts; no arc flash hazards.
  2. HRG. Most (but by no means all) arc flash events begin as a phase to ground fault. By installing a resistor in the ground circuit, HRG systems eliminate arc flash in these situations by limiting the fault current to as little as 5A. Systems provide alarming of a ground fault and many methods and components that allow for the identification of the faulted circuit.


Reference Annex F of the NFPA 70E.

  1. Eliminate the hazard. For example, use GIS.
  2. Reduce risk by design. Use HRG systems, arc-flash relaying, and maintenance bypass switches.
  3. Apply safeguards. Use remote racking and switching to put distance between people and hazards.
  4. Implement administrative controls. For example, the use of a maintenance bypass switch is most reliably used when added as a specific step in a maintenance procedure to enable the maintenance bypass switch and place in normal when maintenance is complete.
  5. Use PPE. The last line of defense, not the first line.

It may be difficult to alter your system by installing arc flash relaying or HRG systems. These take money and outage time to reduce the hazards of arc flash and still may not reduce the hazard to an acceptable level.

In contrast to other systems, the use of remote racking and switching is easier to implement. Depending on the manufacturer, no outages or gear modifications are required, and the training can be done on the job. By modifying how these common system tasks are accomplished, qualified workers can now remove themselves from the arc-flash boundary and still perform their jobs. For example, opening or closing or racking breakers in or out can be performed outside of the arc flash boundary or even from another room.


While modern technology and protective gear play crucial roles in mitigating arc flash incidents, it is equally important for individuals in an organization to be committed to their implementation. In most facilities utilizing multiple strategies will provide layers of protection as described in Annex F of NFPA 70E for their legacy power systems. As the opportunity presents itself, new power system installations and equipment upgrades can incorporate several of the strategies in the equipment design. By understanding and embracing these three key levers for arc flash mitigation, you will enhance workplace safety and can build a culture that prioritizes employee well-being and operational excellence.

Mose Ramieh III is vice president, business development at CBS Field Services and has been in the electrical testing industry for 26 years. He is a Level IV NETA Technician with an eye for simplicity and utilizing the KISS principle in the execution of acceptance and maintenance testing. Over the years, he has held positions ranging from field service technician, operations, sales, business development, and company owner across four companies. 

Electrical Testing Education articles are provided by the InterNational Electrical Testing Association (NETA), www.NETAworld.org. NETA was formed in 1972 to establish uniform testing procedures for electrical equipment and systems. Today the association accredits electrical testing companies; certifies electrical testing technicians; publishes the ANSI/NETA Standards for Acceptance Testing, Maintenance Testing, Commissioning, and the Certification of Electrical Test Technicians; and provides training through its annual PowerTest Conference and library of educational resources. 

About the Author

Mose Ramieh III

Mose Ramieh III is vice president, business development at CBS Field Services and has been in the electrical testing industry for 26 years. He is a Level IV NETA Technician with an eye for simplicity and utilizing the KISS principle in the execution of acceptance and maintenance testing. Over the years, he has held various positions including field service technician, operations, sales, business development, and company owner across four companies. 

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