Mitigating arc flash hazards in medium-voltage switchgear


Duration of the arc

The duration of the arcing fault has a direct impact on the available incident energy. Arcing faults, like all other faults, must be detected and cleared by the first upstream circuit protective device. Therefore, the total arcing time is the total clearing time of the device, which, in the case of circuit breakers, equals the sum of the relay or sensor time and the breaker operating time. Relay or sensor time depends on the setting of the relay and the fault current. Typical circuit breaker operating times are listed in Table 2.

Source: IEEE Standard 1584-2002, Table 1

Mitigating hazards in medium-voltage equipment

There are many reasons why mitigation of arc flash hazards is of greater concern in medium-voltage equipment. First, medium-voltage switchgear occupies a higher hierarchical position in most radial distribution systems. Consequently, medium-voltage protective devices must be set to operate with a greater time delay to allow the low-voltage downstream devices to operate first in the event of a fault. Second, medium-voltage circuit breakers take more time to clear a fault than do low-voltage circuit breakers. In addition, the arcing fault current is very nearly equal to the bolted fault current. The increased arcing time and the higher arcing fault current contribute to greater incident energy and HRC. Because of the higher hierarchical position, de-energizing the medium-voltage switchgear for maintenance work is often not an option because it would shut down a significant portion of a facility. Therefore, one must look seriously at various methods of reducing the HRC. 

Design alternatives that can reduce arc flash hazards in medium-voltage systems include:

  • Use of smaller and higher impedance transformers
  • Bus differential and transformer differential protection
  • Current limiting fuses
  • Maintenance switch
  • Arc flash detecting relays
  • Arc-resistant switchgear
  • Crowbar methods
  • Remote operator panels.

The engineer must evaluate each option and select one or more most appropriate for a given system.

Figure 2: This diagram shows bus differential protection of medium-voltage switchgear. Courtesy: CDM SmithSmaller and higher impedance transformers: Most distribution systems are radial. Instead of specifying one large-capacity, medium-voltage transformer to feed the plant, two or more small-capacity, higher-impedance transformers can be used to supply individual areas of the plant. The idea is to reduce the available bolted fault current and the arcing fault current. Reducing the arcing fault current does not necessarily increase the fault clearing time. Relays can be set to minimize the fault clearing time. For example, a 3,000 kVA, 13.8 kV/4.16 kV transformer with typically 6% reactance would be a source of 6,940 A of short-circuit current at the 4.16 kV switchgear, while a 1,500 kVA transformer with 8% reactance can supply only 2,603 A of short-circuit current. The incident energy in the event of an arcing fault would be reduced by 62%. However, the capital cost and the space requirements for two 1,500 kVA transformers would be more than those for the 3,000 kVA transformer. In addition, higher transformer impedance would cause a greater steady-state voltage drop and a greater transient voltage dip during motor starting. These drawbacks must be evaluated and weighed against the advantage of reduced arc flash incident energy. 

Bus differential, transformer differential protection: Differential protection is a means of clearing the fault inside the zone of protection without intentional delay and without interfering with the overcurrent protective device coordination. The zone of protection is defined by the location of the current transformers (see Figure 2). Another common instance where differential protection would considerably reduce the arc flash hazard is shown in Figure 3A. Transformer primary protection is provided by a fuse. The fuse is chosen to provide adequate protection to the transformer and to permit the magnetizing inrush current. A fault at the line side of the secondary main breaker must be cleared by the primary fuse only. Often the HRC for the line side fault in this situation is excessive. If the fuse is replaced by a circuit breaker and differential protection is provided, the line side fault would be cleared without delay and the HRC can be brought down considerably (see Figure 3B). 

Figure 3: Diagram A shows a system in which a line-side fault creates excessive incident energy. Diagram B shows how differential protection for this system reduces the incident energy Courtesy: CDM SmithFigure 3: Diagram A shows a system in which a line-side fault creates excessive incident energy. Diagram B shows how differential protection for this system reduces the incident energy Courtesy: CDM Smith

Current limiting fuses: Current limiting fuses have the capability to clear faults within a half cycle (less than 0.0083 sec) in addition to limiting the let-through current. Current limiting action of the fuse results from the melting of the silver filaments inside a sand filling inside the fuse, thus creating multiple arcs inside. Great reduction in the available incident energy is possible because of the fast clearing of the fault. However, this is possible only when the fault current lies in the current-limiting range of the fuse characteristic. For example, in a 15 kV 300 A current limiting fuse, the current limiting action takes place for fault current in excess of 6,000 A. The benefit of current limiting fuses can be realized only if the available short-circuit current is in excess of 6,000 A. One must also recognize that it is difficult to coordinate current limiting fuses with downstream protective devices. 

CARLOS , Non-US/Not Applicable, Mexico, 05/21/14 06:58 PM:

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