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How Breaker Failure of The Power System Relaying Works?

Breaker failure relaying is a protection mechanism in power systems that ensures a fault is cleared if the primary circuit breaker fails to operate. When a fault occurs, the primary relay should trip the breaker to isolate the fault. If the breaker does not open, the breaker failure relay detects this and initiates a trip signal to open adjacent breakers, isolating the faulted section to prevent system damage.

How Breaker Failure of The Power System Relaying Works? (Photo by Sashi Commercial Co.)

Primary and Backup Relays

Primary relays function to address a fault within their protection zone swiftly, isolating the minimum number of system components to rectify the fault. Conversely, backup relays come into action if the primary relays are unsuccessful. These backup relays may be situated locally or at a distance. The focus here is on a specific group of local backup relays known as breaker failure relays.

We will delve into this significant subject more thoroughly. Figure 1 illustrates a basic layout of lines and transformers encircling a bus, with one circuit breaker assigned to each line or transformer for the time being.

Subsequently, we will examine the necessary variations in breaker failure to cater to different bus types.

A fault occurring at point F on line B–C should be cleared by the primary relays Rbc and Rcb, along with their corresponding circuit breakers. If circuit breaker B1 fails to clear the fault, this could be due to a malfunction of the primary relays, the current transformers (CTs), the potential transformers (PTs) that supply input to the primary relays, the station battery, or the circuit breaker itself.

Breaker failure relaying
Figure 1 – Breaker failure relaying for circuit breaker B1

The remote backup function, facilitated by relays at buses A, D, and E, is designed to clear fault F in the event that circuit breaker B1 fails to do so. Nevertheless, remote backup protection frequently falls short of expectations in contemporary power systems.

Initially, the coordination must be sufficiently slow to align with all associated primary relays. Therefore, the remote backup function at bus A needs to coordinate with the zone 2 relays of lines B–C, B–D, and the transformer B–E. Secondly, due to potential infeeds at remote stations, setting the remote backup relays to detect fault F from stations A, D, and E might be challenging.

Ultimately, the power delivered to the tapped loads along lines A–B and B–D is wasted due to the operation of remote backup. To protect against the failure of the primary relays at stations B and C, it is advisable to install a secondary set of relays at these points, denoted by R'bc at station B in Figure 2.

Primary, backup and breaker failure relays
Figure 2 – Primary, backup and breaker failure relays in a single-bus, single-breaker scheme

These relays function at a slower pace than Rbc and Rcb yet they trip the same circuit breakers. They provide coverage for the malfunctioning of the primary relays, their associated Current Transformers (CTs), the secondary windings of the associated Potential Transformers (PTs), and the DC distribution circuit for the primary relays as depicted in Figure 3.

However, the R‘bc relays do not protect against the failure of the circuit breakers themselves.

To protect against such contingencies, breaker failure relays are installed. Initially, when this system was introduced, it included a distinct protective relay, utilizing a separate set of current transformers (CTs), potential transformer (PT) secondary windings, and a DC circuit to trip the designated circuit breakers.

In Figure 1, for instance, breakers 3, 5, and 7 would be tripped by the breaker failure relays. Later advancements replaced the standalone relay with the control circuitry depicted in Figure 3.

In this system, any relay or switch triggering a trip activates a timer called the breaker failure timer. This timer is monitored by an overcurrent relay (50-1), which disengages once the current passing through the breaker drops to zero. Should the current not cease for any reason, the timer will expire and activate the lockout relay 86-1, which then trips and secures the circuit breakers 3, 5, and 7.

DC distribution for primary, backup and breaker failure relays
Figure 3 – DC distribution for primary, backup and breaker failure relays

The initial designs for circuit breaker failure logic utilized a breaker auxiliary switch instead of the overcurrent relay. Operated through mechanical or hydraulic linkages, this switch was crafted to replicate the primary contacts of the circuit breaker.

The auxiliary switch is often deemed unreliable, particularly when the circuit breaker struggles to clear a fault—a situation that breaker failure relaying should address. Mechanical linkages might fail, auxiliary switches or main contacts could freeze, or they may become inoperative for various reasons, even as the main breaker contacts remain operational.

There are occasions when a breaker is required to trip even in the absence of a fault current. Under these circumstances, a current detector is not applicable.

A typical instance where a station breaker is tripped without a fault current is when it's initiated by turbine or boiler controls. If there are irregularities in the boiler's pressure or temperature, or any other critical mechanical component of the boiler-turbine system, tripping the station breaker may be necessary. In these scenarios, employing an overcurrent detector to oversee the breaker failure protection would be inappropriate.

The Setting of The Breaker Failure Timer

The configuration of the breaker failure timer is governed by two key constraints. The minimum duration should exceed the breaker clearing time, with an added safety margin. As the breaker failure timer only activates after a tripping relay (or switch) has commenced the trip, the tripping relay's operation time does not influence the timer's setting.

The present scheme offers a distinct advantage. The timer's maximum setting should be shorter than the substation's critical clearing time for faults, which is established by transient stability studies. Typically, breaker failure timer settings range from 7 to 10 cycles in a 60 Hz power system.

This technical article focuses on the simple single-bus arrangement. However, for different bus configurations, a more complex procedure is necessary, as demonstrated in the subsequent example.

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