Your questions answered: Designing to mitigate arc flash problems

Electrical engineers must understand the codes, standards and design requirements when engineering a facility’s electrical power system distributions for arc flash mitigation

By Zia Salami October 31, 2022
Courtesy: Consulting-Specifying Engineer

During the Sept. 27, 2022, webcast titled “Designing to mitigate arc flash problems,” several questions were left unanswered. Zia Salami, Ph.D., Management Specialist – SME: Electrical Power System, CDM Smith, Charlotte, North Carolina, answers several here.

Electrical engineers must understand the codes, standards and design requirements when designing to mitigation arc flash problems. Many factors go into mitigating the danger that electrical workers face; engineers must thoughtfully design systems to reduce and mitigate these incidents in the field.

Are specific codes or standards applicable in European countries?

Yes, there is one European/German standard, DGUV-I 203-077, for arc energy analysis. This methodology is used in several EU countries to comply with their regional electrical safety regulations. ETAP provides an integrated tool/calculator to determine arc energy based on this standard for both AC and DC system.

Do you know if other arc fault calculation software can produce a C-Curve, such as SKM Tools, or EasyPower?

As I mentioned in my presentation, this concept is from ETAP and currently is incorporated in ETAP software. I don’t believe SKM or Easy Power have C-Curve (or C-Area plot) capability at this point.

How would you implement a maintenance mode switch that has the ability to be fail-safe?

Not clear regarding this question, however, using maintenance mode is positive action to prevent high arc when it is available.

In an arc flash study, do we need to compute the minimum and maximum available short circuit? Why?

Yes, we need to consider both minimum and maximum available fault currents since the worst-case incident energy (IE) may be due to either fault currents. For example, minimum fault current may cause longer fault clearing time (FCT) and consequently higher incident energy.

Is maintenance mode an expensive component to have in a system?

No, it is not. Maintenance mode is part of LV circuit breaker function, assuming CB included this mode. During maintenance activity, this mode can be selected to trip a fault, if occurs, faster than normal operation settings. Make sure to change this mode back to normal operation/settings when maintenance activity is done.

Is the incident energy affected by both short circuit current and circuit breaker fault clearance time?

Yes, that is correct, the energy is function of time and current. Of course, based on methodology discussed in IEEE 1584-2018, there are other parameters such as voltage, working distance, gap between conductors, enclosure size will have impact on IE calculations.

Do facilities tend to shut down switchboards for maintenance whereas it’s more common to work on switchgear live? Is there code requirement for shutdowns? What are relevant codes?

There is not a unique approach; each facility may select a different approach based on its procedure.

Courtesy: Consulting-Specifying Engineer

When labeling low-voltage switchgear, does each unit get a label or just one overall based on the worst-case situation (VCB, HCB, HOA, other)?

It is better to use one label based on worst-case condition, less confusion. However, we may need one for the switchgear (bus) itself and one for the main CB, source side, assuming the main CB is adequately isolated from the bus. If that is not case, main CB is not adequately isolated from the bus, one label is need for both bus and main CB. In this condition, the upstream PD will become the main isolation device for this system.

What strategies can be used to accommodate equipment with ratings lower than the available fault current?

Recommend changing the device with higher ratings or add current limiting device such as CLF to your system in order to reduce the available fault current.

Why not prevent the arc flash from happening?

Yes, that is a good point. Prevention should be the first action. We should minimize human error and perform routine maintenance in addition to have the proper design and adequate equipment ratings.

Also, selecting arc-resistant equipment (e.g., switchgear) reduces the amount of energy to which the person is exposed to. Of course, it does not reduce the electrical energy stored in the circuit.

I have not seen fuses that comply with section 240.67. Do you have estimate of the price adder for a fuse with the arc energy reduction feature?

Current limiting fuse (CLF) is a good device candidate to help with arc energy reduction. Please refer to CLF vendor for estimated price.

Is it a good practice to have maintenance switch on the feeder breakers as well to extend the protection downstream of the switchboard?

Yes, when it is possible. Also, having backup protection and extending protection will help with system reliability.

Is there a viable calculation method for single-phase arcing current for arc flash studies?

IEEE 1584-2018 provides some references regarding single-phase system. Section 4.11 states that this model (discussed in this standard) does not cover single-phase systems. Arc-flash incident energy testing for single-phase systems has not been researched with enough detail to determine a method for estimating the incident energy.

Single phase systems can be analyzed by using the single-phase bolted fault current to determine the single-phase arcing current and voltage of the single-phase system can be used to determine the arcing current. The arcing current can then be used to find the protective device opening time and incident energy by using the three-phase equations provided in this guide. It is also states that the incident energy result is expected to be conservative. Note that this approach is implemented in most electrical software such as ETAP.

Will the maintenance mode switch on the motor control center main breaker help with line side IE in the example?

No. For line side, we need to assume the main CB is not in the picture and not used as main device isolation. In this condition, the upstream PD should be used as main isolation device.

Can you review what the amps versus time graph for nonelectrical engineers? What does the x-axis mean, what does the y-axis mean, what are the shaded regions, how do we know where we are in the shaded region and finally which quadrant are we trying to push our circuits to?

I suggest searching internet for “TCC Curve.” There are many sample curves and discussions that you can understand much easier than if I explain here.

What should be minimum limit of FCT setting without losing coordination?

In general, FCT is time that PD sense the fault/arc plus operating time of protective devices (e.g., CB, relay or fuse). There is no specific minimum time that we can define for having system coordination. Selectivity (coordination) should be evaluated between upstream and downstream devices that a) are not overlapping and b) there is adequate time differences between the TCC curves (e.g., 0.2 seconds).

Please explain how sight detection relay work.

Not much experience with this type of relay. In general, any device that can sense the arc and perform fast tripping action would consider as a viable mitigation strategy.

Does residential 200-amp 120/240 V/1-phase service require arc flash study?

In general, any system above 50 V may require arc flash attention and some type of evaluation. However, IEEE 1584-2018, Section 4.3 states “Sustainable arcs are possible but less likely in three-phase systems operating at 240 V nominal or less with an available short-circuit current less than 2000 A.”

What causes arc flash?

There are many reasons, the most important are due to human error, poor connections, pollution or moisture, mechanical failures, overvoltage, insulation failure, animals or material ingress.

Are you aware of any brand or model of breakers that will trip when the settings are changed to the maintenance mode?

Most LV digital power circuit breakers are equipped with maintenance mode and you can find out in CB specification.

Are you aware of any upcoming changes to Occupational Safety and Health Administration with regard to live work, especially relating to critical facilities and data centers?

Unfortunately, no, but I will look into this, thanks for the heads up.

What is the standard FCT for low- and medium-voltage fuses and breakers should be considered in the arc flash calculations?

There is no specific FCT that we can define for LV or MV system. Of course, faster FCT the lower IE. We also need to consider the amount of fault currents and not just FCT. The final product is IE, therefore, any FCT that satisfy your IE goal (e.g., 12 cal/cm2) is justified.

Can we say that the more transformers we have upstream, the less fault current?

That is correct, more transformers, more system impedances, and consequently less downstream fault currents. Of course, this is true if the fault currents initiating form the utility side and not from local on-site generator sources that are within facility and located close to downstream system.

Can designing systems with higher equipment impedances help to mitigate arc flash hazards? What’s the trade-off or consequence of this approach?

It may or may not. To evaluate IE, we need to consider both minimum and maximum available fault currents since the worst-case IE may be due to either fault currents, minimum or maximum. Higher equipment impedances resultant in lower minimum fault current and consequently may increase the FCT (i.e., PD will trip slower). One of the negative consequences of this approach increases voltage drop in the system and impact on equipment operation such as motor starting or sensitive equipment due to low voltage.

Is the two seconds assumed “time to escape” in IEEE 1584-2018 still valid?

Yes, it is. IEEE 1584-2018 in Section 6.9.1 states “If the total protective device clearing time is longer than two seconds (2 s); consider how long a person is likely to remain in the location of the arc flash. It is likely that a person exposed to an arc flash will move away quickly if it is physically possible, and 2 s usually is a reasonable assumption for the arc duration to determine the incident energy. However, this also depends on the specific task. A worker in a bucket truck, or inside an equipment enclosure, could need more time to move away. Use engineering judgement when applying any maximum arc duration time for incident energy exposure calculations, because there may be circumstances where a person’s egress may be blocked.”

Regardless of systems changes, we do an arc flash hazard study every five years. Is that required by law?

This is NFPA 70E requirements as states: “The incident energy analysis shall be updated when changes occur in the electrical distribution system that could affect the results of the analysis. The incident energy analysis shall also be reviewed for accuracy at interval not to exceed five years.”

The review of the arc flash study, for every five years, can be just to verify that there are no changes in the system, equipment has been maintained properly, and to show the original assessment is still valid (and not a full study).

Note that NFPA 70E standard itself is not law, it establishes the safety guideline which enable employers to comply with OSHA safety requirements.

Providing variable frequency drives, could this diminish the ICC (and consequently, the IE)?

VFD, if not in bypass mode, does not inject any fault current back to the system and also will limit the fault current to the load side, typically to 150% of its rated current. Therefore, VFDs may help to reduce IE, especially on the load side but not much on the source/utility side. I will recommend analyzing the VFD in bypass mode (to show the impact by connected motor) if this is possible in your system.

If five years is required per NFPA, where does it become a legal requirement? Per OSHA?

Directly not, but indirectly. NFPA 70E standard itself is not law, it establishes the safety guideline which enable employers to comply with OSHA safety requirements. Keep in mind that OSHA relies upon the consensus standards established by NFPA in its 70E Standard for Electrical Safety in the Workplace.

NFPA states “NFPA 70E requirements for safe work practices protect personnel by reducing exposure to major electrical hazards. Originally developed at OSHA’s request, NFPA 70E helps companies and employees avoid workplace injuries and fatalities due to shock, electrocution, arc flash and arc blast, and assists in complying with OSHA 1910 Subpart S and OSHA 1926 Subpart K.”

Is the incident energy affected by both short circuit current and circuit breaker fault clearance time?

Yes, that is correct as the main parameters with most impact. Of course, other parameters such as voltage, working distance, gap between conductors, enclosure size will have impact too.

What about increasing distance through remote operation of overcurrent protective devices?

Yes. In general, any remote operation (when possible) would consider as arc flash mitigation since it will keep personnel out of harm.


CDM Smith is a CFE Media content partner.

Author Bio: Zia Salami is a subject matter expert in electrical power systems at CDM Smith. He has more than 22 years of industry and academic experience in electrical power systems and has served in several roles as an advisory engineer, consultant and academic professor.