Backup line protection practice: Remote vs. local vs. breaker failure (logic and schematics)

Only if the primary protection fails…

When other protection fails or is unable to operate, such as when the proper circuit breaker(s) fail to trip, backup protection is supposed to kick in and clear the fault or detect the abnormal condition in the time allotted. The term “backup protection” is commonly used all around the world to refer to a type of safety measure that functions separately from certain components of the primary safety network.

The secondary safeguard can be a carbon copy of the first one, or it can be designed to kick in only if the primary one goes down.

By having a backup system in place, problems caused by a protective relay or switching device failing to function are mitigated. Either the primary and secondary safeguards (known as remote backup and local backup, respectively) can be located at separate substations.

The perfect secondary security system wouldn’t rely in any way on the primary system. There would be a second set of everything: secondary DC supply systems, trip coils, auxiliary tripping relays, and current and voltage transformers. This standard is rarely met in actual life.

Remote or Local Backup Protection?

A backup system is one that provides protection in the event that certain principal protective system components fail. It may be a carbon copy of the primary protection, or it may be designed to get in only when the primary protection is down (IEEE 100).

The Figure 1 protection at station G for the line GH serves as an example of the many types. The primary protection for the GH line is provided by relays installed at G, as illustrated. More than one of the primary relays is typically activated in response to line faults.

Figure 1 – Protection problem for protective relays at station G for line GH

Through redundancy, this provides primary backup. Completely separate protection, working from multiple CTs (and occasionally different VTs), separate DC supplies, and operating different trip circuits on the breakers are typically employed for particularly important circuits or equipment, notably at HV and EHV levels. One protective system is labelled as primary, and the other as secondary, which is somewhat misleading because they typically function at high speeds together.

To protect fault F1, the relays at G in the simple two-line system of Figure 1 must be programmed to operate for the exterior faults F, F2, and others out on line HS. As a result, relays G offer primary protection for line GH while also providing backup protection for bus H and line HS.

This is a backup that is done remotely. If the primary relays and associated circuit breaker(s) clear the F, F2, and other faults, the relays at G should work and remove the G source from the fault. Similarly, the backup operation of the relays at their remote terminals should clear all other sources delivering current to the uncleared fault.

Local backup should have a separate, independent set of relays, which should always be present for remote backup. This is possible using the previously mentioned independent primary and secondary relay systems, which are primarily used at high voltages. Low-voltage protection systems may lack this independence.

If this independence is not given, a failure in the protection may prohibit the opening of the local breakers to clear the problem. Under these conditions, only remote backup would be able to clear the fault.

Suggested Reading – Primary injection testing and CTs commissioning in power substations

Primary injection testing and CTs commissioning in power substations (for true engineers)

Backup: Remote, Local, And Breaker Failure

The previous section discussed remote versus local backup. Backup is described in further depth in this section. Backup protection is provided in two fundamental types throughout the protection chapters: redundancy and remote. Redundancy is the additional protection offered in the primary protection zone and, in some cases, the adjacent system.

To serve all three phases, an example would be three separate phase relays, as opposed to two or a single unit: phase relays as backup for ground relays, timed–overcurrent and distance-timed zones as backup for instantaneous or pilot relays, and in EHV and UHV, two separate pilot systems. Redundancy is proportional to the degree of independence between the numerous protection schemes.

For the voltage supply, a similar configuration is occasionally employed. This gives the greatest amount of redundancy that is economically feasible. The overlapping of primary relays in one protection area into neighbouring areas is referred to as remote backup.

As shown in Figure 2, relays 1 at station S, relays 5 at station T, and relays 8 at station R should provide backup for faults on line GH to the relays and breaker 3 at station G. In other words, if breaker 3 does not open for these faults, distant breakers 1, 5, and 8 must open to clear line GH faults.

Figure 2 – Power system configurations to illustrate backup protection: Backup on a single-bus system

As indicated, this becomes extremely challenging or impossible, particularly for faults close station H, due to the infeed effect of currents or other lines. This reduces the current or increases the impedance that the remote relays perceive. If remote relays can detect line GH faults, the operating time may be delayed due to coordination requirements necessitated by other lines being out of service.

Occasionally, these issues can be resolved through sequential remote tripping.

If one remote terminal is capable of operating on backup, its removal may result in a redistribution of fault current sufficient to power the remaining remote backup relays.

With the recent introduction of EHV and UHV systems, two issues have emerged. One was that initially, higher-voltage circuit breakers were subject to a higher failure rate than had been observed previously. The second was that system stability necessitated significantly quicker backups.

Thus, local fallback systems for breaker failures were implemented. Instead of opening breakers 1, 5, and 8 in Figure 2 if relays or breaker 3 fail to open for line GH faults, local backup would open breakers 2, 6, and 7. This can be accomplished with minimal latency; optimal times as low as 150–250 msec are utilized.

When local backup is applied to lower-voltage systems, adequate relay redundancy should be carefully considered to account for all possible relay failures. Remote backup at a distinct location offers 100 percent redundancy for faults within their operational range.

Remote backup is still necessary for ring or breaker-and-a-half buses as a supplemental and ‘last resort‘ protection. Figure 3 depicts this concept.

Figure 3 – Power system configurations to illustrate backup protection: Backup on a ring or breaker-and-half bus system

For faults on line GH, bus G’s circuit breakers 1 and 2 are tripped. If circuit breaker 1 fails to open, the local backup circuit breakers on bus G (not shown) will trip. If circuit breaker 2 fails to open, local backup would trip circuit breaker 3, but the fault would still be supplied through circuit breaker 4 at station R.

Therefore, circuit breaker 4 must be opened. This is possible through remote backup operation of the relays at position 4. With the infeed through breakers 1 and 3 eliminated, it is more likely that relays 4 will detect faults on line GH. Another possibility involves the transfer trip of breaker 4 by the local backup at G.

Figures 4, 5 and 6 depict common local backup circuit breaker failure schemes. The diagram below depicts typical circuit breaker trip systems and auxiliaries for breaker failure-local backup where breakers have double trip coils, 94 relay coil, and the second trip coil 52 TC2 is connected in lieu of the 94 relay coil.

Figure 4 – Typical breaker failure – local backup DC (schematic): Typical circuit breaker trip systems and auxiliaries for breaker failure-local backup

Both redundant (independent) relay systems feature pilot-type trip circuits with operating times that can be as quick as, or even faster than, those of the primary system. The breaker’s primary coil directly energizes the trip coil, 52TC1, while the secondary coil energizes relay 94, which controls 52TC1.

When using two separate trip coils, the 94th element is unnecessary because the secondary circuit directly powers 52TC2.

Concurrently, the power is supplied to the auxiliary relays 62X and 62Y. Either relay controls a timer that is monitored by a 50 relay. This instantaneous non-directional overcurrent relay has a high dropout ratio and low pickup. Typically, it has a two-phase and ground connection. The maximum load should be handled by the phase units at their lowest settings.

Figure 5 – Typical breaker failure-local backup DC (schematic): Typical contact logic for breaker failure-local backup

This 50 relay checks the flow of current through the breaker and offers a last check on the flow of current through the breaker. It also has a quick opening that will stop the timer in the event that the breaker opens late. The functioning of the timer energizes a multi-contact auxiliary (86) relay, which is the only one that can be manually reset. This relay is the only one that has this capability.

The 86 relay contacts start the tripping of all of the breakers locally required to remove the fault, and they possibly also start a transfer trip signal to the distant terminal(s) to make sure that the relays have operated successfully for the internal problem.

There are many distinct permutations of the protocols and connections that are used for the different kinds of bus configurations.

Figure 6 – Typical breaker failure-local backup DC (schematic): Typical solid-state logic for breaker failure-local backup

There are breaker failure relays available that are based on microprocessors and have programmable logic. This gives the user the ability to select the logic that is most suitable for their needs and their philosophy.

1. Up to 34.5–69 kV – Directional time-overcurrent for phase or ground with non-directional or directional instantaneous overcurrent where applicable.

2. 34.5–115 kV – Directional distance (two or three zones) for phase, same as item 1 for ground, alternate-ground distance.

3. 69–230 kV – Pilot relaying for phase and ground as primary protection, backup as item 2.

4. 230 kV and above – Two pilot systems (primary and secondary) for phase and ground, additional backup as item 2.

5. For very short lines at any voltage level – Pilot wire or pilot type for phase and ground, backup as per 1 or 2, but coordination with other protection may not be completely possible.

6. Multiterminal and tapped lines – Pilot-type relays generally required, unless load-type impedance or transformer connections will permit proper discrimination for external faults.

Suggested Course – Learn How to Operate and Analyze Interlocking Schemes for Substation & Gas Insulated Switchgear (GIS)

Learn How to Operate and Analyze Interlocking Schemes for Substation & Gas Insulated Switchgear (GIS)

Sources:

1. Protective Relaying Principles and Applications by J. Lewis Blackburn Thomas J. Domin 
2. Distribution Automation by ABB