Arc flash mitigation and arc-resistant switchgear

January 14th, 2015, Published in Articles: Vector

Application of arc-resistant switchgear to help mitigate arc flash hazards can be a very effective way to enhance safety for electrical workers.

Not only the selection of protective device types, but also selecting the settings for adjustable devices is important in the mitigation of arch flashing. Settings must be chosen to protect equipment properly while still allowing for normal load currents and routine temporary overcurrents (e.g. motor starting current) to flow without causing a trip.

Settings also ideally result in co-ordination between different levels of device – the overcurrent protective device closest to the fault or overload is the only one which trips, so service is interrupted to a minimal portion of the system. This need for co-ordination between various levels of device typically means that overcurrent protective devices closer to the source are set with higher pickup levels and/or with longer time delays than devices further downstream. This gives the downstream devices time to react and to clear an abnormal condition before a large feeder or main device operates, perhaps interrupting power to a large portion of the facility. Of course, since clearing faults quickly is one of the keys to arc flash reduction, this philosophy may not always lend itself to arc flash mitigation.

One way to provide protection while minimising the impact of mis-coordination is the use of so-called “maintenance” switches. These are external switches wired into a circuit breaker or relay to allow an operator to select between “normal” and “maintenance” settings. In “normal” mode, the breaker or relay is typically set for normal selective co-ordination, which may result in a high-incident energy level downstream. This may be acceptable as long as no workers are present.

When work is being performed, the switch is turned to the “maintenance” setting, which modifies the trip settings of the device to reduce the incident energy levels downstream. This may sacrifice selective co-ordination but the idea is that the “maintenance” setting is to be used only when workers are actually present. When work is complete, the system is returned to “normal” mode.

Since maintenance switches result in locations where arc flash levels vary (depending on the position of the switch), they require some additional consideration, including determining how the equipment should be labelled, modification of work procedures, worker training curriculum, etc.

Relay system design

The basic design of a protective relay scheme can help reduce arc flash levels in a system. For example, bus or transformer differential protection typically allows for faults inside the zone of protection to be cleared quickly, without creating concerns over co-ordination issues. Since they typically operate quickly, they are also effective at reducing arc flash levels, so their use may be considered for locations where differential protection might not have been used in the past.

Virtual main

A virtual main system seeks to solve a typical arc flash issue – the high-incident energy typically present at the low-voltage side of a substation transformer – which would affect at least the low-voltage transformer compartment and the main section of the downstream switchgear and, at worst, the entire low-voltage switchgear/switchboard.

At such locations, the overcurrent protection for an arcing fault is provided by a relay or fuse on the high-voltage side of the transformer.

If CTs were installed on the transformer secondary bushings and ran to a relay set to quickly detect and send a trip signal for a low-voltage arcing fault, the problem of detecting the fault would be solved. But what should the relay trip? Even if there is an LV main breaker present, it cannot protect for arcing faults on its line side so, at best, there would still be a high level of incident energy available in the main section of the equipment.

But if the relay could be wired to trip an overcurrent protective device such as a feeder breaker on the high-voltage side of the transformer, the entire circuit would be protected. Fig. 2 shows a typical configuration – the relay at Sub A sends its trip signal upstream to the MV feeder breaker.

Two issues must be resolved before a virtual main system can be applied successfully. First, there must be something upstream for the relay to trip. This may not be a problem when dealing with a large system with MV circuit breaker switchgear. MV disconnect switches, however, cannot interrupt fault currents, and if the utility owns the MV equipment, it may not allow a customer relay to control its operation.

Fig. 1: Virtual main configuration.

Fig. 1: Virtual main configuration.

The second consideration is co-ordination. In Fig. 1, a fault at sub A which tripped the MV breaker would also interrupt power to subs B and C. A maintenance switch at the virtual main relay can help minimise potential exposure to mis-coordination.

Optical relaying

Quick fault clearing is key to arc flash mitigation, but breaker or relay settings near the source of power may have to have significant time delays to allow for co-ordination of devices further downstream. One way to deal with this conflict is to use relays which detect the presence of arcing faults by looking not only for the characteristic current flow but also for the flash of light associated with the arcing fault.

Typically, both quantities must be present before an arcing fault is detected – either high current or a burst of light alone will not cause one of these relays to operate. But when both conditions are present, the relay can operate very quickly to clear the fault, typically through an overcurrent protective device, but sometimes through activation of a shorting switch which creates a bolted fault that clears the arc even more quickly than a circuit breaker could operate. Optical relays could also be used as the protective relay in a virtual main configuration.

System grounding

The method of system grounding can have an impact on arc flash hazards. The majority of facilities today are solidly-grounded – there is an intentional, low-impedance connection between the system neutral and ground.

Solidly-grounded systems are required by code in many instances. Some systems may be ungrounded, which means there is no intentional connection to ground. Each type of grounding has its pros and cons – for a single ground fault in an ungrounded system, no ground fault current flows, so the system can continue to operate. However, an arcing ground fault can produce high transient overvoltages. Solidly-grounded systems limit overvoltages during fault conditions very effectively but may allow a great deal of fault current (and energy) to flow, which can result in significant damage to equipment or personnel.

An impedance-grounded system, where the neutral point is connected to ground through an impedance (typically a resistor), is a hybrid of the grounded and ungrounded systems and, as such, shares some of the characteristics of both. High-resistance grounded systems, which have the resistor selected to limit ground fault current to less than 10 A and which are most often used at 480 V, greatly reduce the available ground-fault current and therefore let the system continue to operate during a ground fault condition, at least for some period of time until the fault escalates. They are also fairly effective at limiting transient overvoltages.

Fig. 2: Incident energy versus distance for an LV switchboard.

Fig. 2: Incident energy versus distance for an LV switchboard.

More recently, some have promoted HRG systems as a means of arc flash mitigation. But how can system grounding affect the hazard or risk related to arc flash incidents when the calculation methods in IEEE 1584 are based on 3-phase faults? The idea is that since the majority of faults in power systems are either single-phase-to-ground faults (or they begin that way and then escalate), the fact that HRG systems inherently limit the energy delivered to a ground fault by limiting the available current can provide much protection.

Ground faults with such low current levels are unlikely to produce the explosion and intense heat characteristic of a typical arc flash event, and they are also less likely to escalate to multi-phase faults quickly.

HRG systems do not, however, eliminate the possibility of a multi-phase arc flash, and they do nothing to reduce the energy delivered to phase-to-phase or 3-phase faults which do occur. In fact, per IEEE 1584-2002, the incident energy from 3-phase arcing faults is actually slightly higher on impedance-grounded or ungrounded systems than for otherwise identical solidly-grounded systems.

One way to understand the mitigating effect of HRG systems is to reconsider the definitions of hazard and risk given in the “Mitigation strategies” section. An HRG system would make it less likely that a ground-fault in a system would escalate into a damaging 3-phase arcing fault, so the risk is reduced – though the actual degree of risk reduction is difficult to quantify.

What about the hazard? As long as only single-phase faults are considered, the hazard is also reduced significantly due to the reduction in available fault current. An HRG system does not guarantee that 3-phase faults will not occur, and does not mitigate their effect when they do, so neither the hazard nor the risk is eliminated. The incident energy calculations and equipment labels would still show the incident energy levels calculated based on the 3-phase fault, and worker PPE would not be reduced.

This is not to say that high-resistance grounded systems do not provide any benefit where arc flash safety is concerned; only that a user must be aware of what it will and will not do where arc flash mitigation is concerned.

Arc-resistant switchgear

The solutions mentioned so far are concerned with limiting the duration or frequency of high-energy arcing faults. Worker safety can also be increased by containing and redirecting the effects of an arcing fault which occurs in a piece of electrical equipment.

Arc-resistant switchgear is switchgear designed to meet performance requirements set forth in IEEE Standard C37.20.7-2007, IEEE Guide for testing metal-enclosed switchgear rated up to 38 kV for internal arcing faults.

Arc-resistant equipment provides protection from internal arcing faults to workers standing in front of  (type 1) or anywhere around the perimeter  (type 2) of the equipment, provided that the equipment is in its normal operating condition.

Equipment qualified to this IEEE guide has been lab-tested to show that an internal arcing fault will not:

  • Cause doors or covers to open or blow off during the event.
  • Fragment and eject parts within the protected area.
  • Allow the arcing fault to burn through the enclosure.
  • Allow cotton indicators spaced about the gear to ignite.
  • Have any of its grounding connections become ineffective.

The normal operating conditions are defined by the manufacturer, but typically include operation (opening and closing) of circuit breakers or switches, and inserting or removing withdrawable components. Table 130.7(C)(15)(a) in NFPA 70E-2012 shows that category 0 PPE is appropriate when performing such activities on arc-resistant switchgear. Normal operating conditions do not typically include operations with outer covers or doors open, or maintenance activities that involve replacement of primary active components such as fuses.

Passive arc-resistant switchgear

Passive arc-resistant equipment typically provides the increased protection through strengthened enclosures, venting of pressurised hot gases and other arc products.

Active arc-resistant switchgear

One drawback of traditional passive arc-resistant switchgear is that, while it may provide a significant degree of protection to workers, it may not do anything to reduce the intensity or duration of the internal arcing fault itself.

The equipment may be designed to contain the blast but the internal damage may be significant, requiring either significant re-work or even replacement of the switchgear before it can be returned to service. Conversely, active arc-resistant switchgear works to limit the arc energy.

In addition to providing protection for workers, this kind of active solution can reduce the amount of damage which the equipment itself sustains during the arcing fault event. Note that placing a device which limits arc energy in non-arc-resistant switchgear can meet the performance requirements of IEEE C37.20.7.

Several application issues must be considered when using arc-resistant switchgear, including ensuring that available fault current and fault clearing times are within the values defined for the equipment; ensuring that access is limited above and below the gear as protection is not provided in the vertical plane; observing required room dimensions, and if or how to vent hot gases and other byproducts of the arcing fault.

Although the C37.20.7 guide only explicitly covers low and medium-voltage switchgear, manufacturers are beginning to offer “arc-resistant” versions of other products, such as low-voltage motor control centers. This is indicative of the performance requirements in C37.20.7 becoming a de-facto standard for arc-resistant equipment in general, and equipment meeting the performance requirements in the guide would be expected to deliver a similar level of protection as arc-resistant switchgear.

Remote operations

Reducing the duration of the arcing fault can be a very effective means to mitigate arc flash hazards. Increasing the effective working distance – that is, the distance between the worker and the location of the arc – is also a very effective mitigation strategy, as energy levels drop exponentially as the working distance is increased (see Fig. 3).

Fig. 3: Example of remote racking system with remote operating station.

Fig. 3: Example of remote racking system with remote operating station.

Based on Fig. 1, if the standard working distance of 46 cm (per IEEE 1584-2002) is the reference point, then doubling the distance to 91 cm means the available incident energy will drop to 32% of the reference value. Though the drop in energy is not as dramatic for other equipment classes, it is still significant, so looking for ways to operate or interact with equipment remotely is a powerful mitigation strategy.

Remote operation of circuit breakers or switches can be accomplished in a number of ways. While it does require the breakers to be electrically-operated and able to be shunt-closed and shunt-tripped, these features are available on a wide range of devices. Remote switching of devices may be done from remotely-mounted operating switches, pushbuttons, HMI screens, and even over networking through SCADA systems, network-connected relays or other devices. Some portable devices can be mounted temporarily to control switches or other operating mechanisms. In all cases, the ideal situation is for the remote operating point to be located outside the arc flash boundary of the equipment being controlled.

Anecdotally, many arc flash incidents occur when withdrawable components (e.g. circuit breakers and starter buckets) are inserted or withdrawn from equipment (“racked” in or out). There is an increasing number of remote racking options now available (see Fig. 3) for both LV and MV equipment, both from OEMs and third-party vendors. The principle is much the same as with remote operation – the remote racking device allows the operator to increase the working distance during these operations significantly, ideally to a point outside the arc flash boundary.

Maintenance

Maintenance should be considered in the system design phase. In facilities such as data centers where uptime is critical and business conditions do not allow for extended facility shutdowns for maintenance, “run to failure” should not be the response. Instead, redundancy should be designed into the system so that individual pieces of equipment can be taken out of service without interrupting power to critical loads. If redundancy is designed into a system, that redundancy must be maintained as well.

Continued load additions without regard to location or amount may eventually create situations where the load level has grown to the point where taking one transformer or UPS, for example, out of service will overload the remaining equipment.

To restore the ability to maintain the system effectively, the load must either be shifted to new services or more efficient equipment must be installed. In most cases, this simply means an end to many maintenance activities, which is far from ideal.

Fig. 4: Infrared viewing windows allow infrared scans without exposure to hazardous energy..

Fig. 4: Infrared viewing windows allow infrared scans without exposure to hazardous energy..

Maintenance design considerations can also include devices intended to simplify and extend maintenance activities beyond the more traditional methods. Infrared thermography is a routine part of the electrical maintenance programme in many facilities. Loose connections or other defects in electrical equipment may create hot spots which give early warning of impending failure and which are readily visible to infrared cameras. Since the goal is to detect heat, the inspections are typically done either with the equipment energised or within the first few minutes after a shutdown, before equipment has time to cool. Neither is ideal – the former exposes workers to energised equipment while the latter could require a rushed lockout-tagout procedure.

There are also relatively simple solutions available, such as installation of infrared viewing windows in equipment, which allow for infrared scans to be performed without exposure to hazardous energy (see Fig. 4). The windows, which are intended to allow for transmission of infrared radiation, are installed in the equipment covers at strategic locations so that key joints/locations within the equipment can be seen by the camera. Not only is hazard exposure reduced because covers do not have to be removed, but the entire process is made faster and less expensive.

Properly-placed thermal sensors can perform essentially the same diagnostics as thermographic scanning, but on a continuous basis. Partial-discharge monitors can detect degradation of insulation systems before they actually break down and cause a fault. Advanced trip units and relays monitor or predict breaker contact wear. These and other monitoring solutions can be wired to local alarming, facility-wide SCADA systems, or could even connect to the internet and set to alert operators of potential issues automatically.

Conclusion

Ideally, arc flash safety is taken into consideration when a facility’s electrical distribution system is designed, but many of the techniques discussed in this article are equally applicable as retrofits to existing systems. Devices such as speciality relaying and remote operating mechanisms intended to address arc flash are still relatively new, and future developments may add additional tools to the mitigation toolbox.
Although some of the product-based solutions result in increased electrical equipment cost, the alternative is not acceptable.

Contact Ntombi Mhangwani, Schneider Electric, Tel 011 254 6400, ntombi.mhangwani@schneider-electric.com

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