When a fault occurs somewhere in a facility's electrical system, ideally only the breaker closest to that fault should open, isolating the problem while everything else keeps running. Achieving that is not automatic; it takes deliberate engineering to grade every protective device so they trip in the right order. Protective relay coordination is that engineering, and its goal is selectivity: the nearest device acts first, and each device upstream waits its turn as a backup. This guide explains how time-current curves and ANSI device numbers are used to coordinate protection, why selectivity matters, and how it differs from any single breaker or relay in isolation.
Relay Coordination in one line: Protective relay coordination is the engineering study and settings work that grades a facility's circuit breakers and protective relays so that the device nearest a fault trips first while devices upstream hold off long enough to act only as backup. This selective tripping isolates the smallest possible portion of the system, keeping the rest energized. It is accomplished by plotting time-current curves for each device and separating them by a coordination time interval, and it is documented in a coordination study.
Every overcurrent protective device, whether a fuse, a circuit breaker, or a relay, has a characteristic that says how long it takes to trip for a given amount of overcurrent. Plot that on a graph with current on one axis and time on the other and you get a time-current curve, the fundamental tool of coordination. A device high on the curve is slow; a device low on the curve is fast. Coordination is the art of arranging these curves so that for any fault, the correct device operates first.
The principle is selectivity, also called discrimination. Consider a fault on a single motor feeder deep in a plant. The breaker on that feeder should trip and clear the fault, while the breaker feeding the whole motor control center stays closed, and the main breaker feeding the switchgear stays closed. If instead the main tripped, the entire plant would go dark for a fault that affected one motor. Coordination ensures the downstream device is fast enough to clear the fault before the upstream device even begins to trip.
To guarantee that ordering, adjacent devices are separated on the time-current curve by a coordination time interval, a deliberate time margin that accounts for breaker operating time, relay overshoot, and safety. The downstream device clears the fault within its portion of the curve, and the upstream device, seeing the same fault current, waits out the coordination interval before it would act, giving the downstream device time to succeed. If the downstream device fails to clear, the upstream device then trips as backup, so protection is never lost.
Protective functions are identified by a standardized numbering system, the ANSI device numbers, that lets engineers describe protection schemes precisely regardless of manufacturer. Common examples are device 50 for instantaneous overcurrent, device 51 for time-overcurrent, device 50G or 51G for ground overcurrent, and device 87 for differential protection. A single-line diagram annotated with these numbers tells any engineer exactly what protection sits at each point in the system and what each relay is watching for.
Coordinating those functions is the job of a coordination study, a formal engineering exercise that gathers the ratings and settings of every protective device, the transformer and cable data, and the available fault current at each point, then plots the time-current curves together to verify that they are properly graded. The study identifies places where curves overlap or cross, which would cause miscoordination, and prescribes the relay settings, fuse sizes, and breaker trip settings that restore proper selectivity across the whole system.
A coordination study is inseparable from a fault-current study, because the amount of current available at each point determines where on the time-current curve each device will actually operate for a real fault. The two are usually done together. The end product is not just settings but a documented rationale, so that when equipment is added or the supply changes, the coordination can be rechecked rather than rediscovered, which is why coordination is treated as a living engineering deliverable rather than a one-time calculation.
It is important to see how coordination differs from the protection provided by any single breaker or relay. A single circuit breaker protects its own circuit; it trips when it sees an overcurrent it is set to act on. Coordination is a system-level property that governs how many such devices behave together so that they trip in the right sequence. A facility can be full of perfectly good individual breakers and still be badly coordinated, tripping the main for a downstream fault and dropping the whole plant.
Because coordination is about relationships between devices, it is fragile in the face of change. Add a large new load, replace a transformer, upgrade the utility supply so more fault current is available, or swap a relay for a different model, and the carefully graded curves can shift out of alignment. That is why coordination is revisited whenever the system changes, and why a plant's coordination study is a document that ages rather than a permanent fact.
This is where system-wide visibility helps operations. A cloud SCADA platform such as Merobix reads breaker and relay status, trip flags, and, from modern protection relays, the specific ANSI function that operated, across every switchgear lineup and motor control center in a facility or across many sites. When a trip occurs, seeing which device operated and where confirms whether coordination behaved as designed, and a pattern of the wrong device tripping is an early flag that the coordination has drifted and the study needs revisiting before an unnecessary outage happens again.
The goal is selective tripping: for any fault, the protective device closest to the fault should trip first and isolate the smallest possible portion of the system, while devices upstream hold off and act only as backup if the nearest device fails. This keeps the rest of the plant energized instead of shutting everything down for a localized fault. It is achieved by grading the time-current curves of all the devices so they operate in the correct sequence.
A coordination study is a formal engineering exercise that collects the ratings and settings of every protective device, the equipment and cable data, and the available fault current at each point, then plots their time-current curves together to verify proper grading. It identifies places where curves overlap and would cause miscoordination and prescribes the settings needed to restore selectivity. It is usually done alongside a fault-current study, because available fault current determines where each device operates.
Because coordination is a relationship among devices, not a property of any one of them, it is sensitive to changes in the system. Adding a large load, replacing a transformer, upgrading the utility supply so more fault current is available, or swapping a relay can shift the graded curves out of alignment and cause the wrong device to trip. Whenever the electrical system changes, the coordination should be rechecked so selectivity is preserved and a downstream fault does not drop the whole plant.
Merobix reads your field devices into a cloud SCADA - the real thing behind these terms, live in days from any browser.