Protection Relay Testing: Types, Procedure and Equipment

Protection relay testing proves that a relay will detect a fault and trip the right breaker in the right time, and it is done in layers: secondary injection into the relay terminals to check pickup, timing and logic, then primary injection and end-to-end tests to prove the current transformers, wiring, communication and breaker as one scheme. A complete test compares every measured value with the value calculated from the approved settings and records the result before the relay goes back into service.

Checked on 11 October 2026 against the sources listed under this post.

Relays are the part of the power system nobody sees working until a fault happens, which is exactly why they are tested. This guide follows the order a protection engineer works in on site, using the curve definitions in IEC 60255-151 and IEEE C37.112, and the maintenance intervals in NERC PRC-005.

What are the types of protection relay testing?

Relay tests fall into a few families. Each answers a different question, so a commissioning test plan normally includes all of them.

How does secondary injection testing work?

Secondary injection is the everyday relay test. A test set injects currents and voltages straight into the relay's analogue inputs, downstream of the current transformers (CTs) and voltage transformers (VTs), and times the relay's output contacts. Because the instrument transformers are bypassed, the result shows whether the relay and its settings behave correctly on their own.

Modern test sets do much more than inject a single current. OMICRON describes its CMC 356 as "the universal solution for testing all generations and types of protection relays", with current sources strong enough for "high-burden electromechanical relays". Software modules then automate pickup ramps, timing points and characteristic searches.

Pickup and drop-off

Pickup is the input level at which an element starts to operate. To find it, the tester ramps the current slowly upward from below the setting until the element starts, then back down until it resets (drop-off). The measured pickup should fall within the tolerance the relay manufacturer publishes. Ramp slowly: a fast ramp overshoots and reads high.

Timing and IDMT curves

An inverse definite minimum time (IDMT) overcurrent element trips faster as the current rises. IEC 60255-151 defines the operate time as TMS × k / ((I/Is)^α - 1), where Is is the pickup setting and TMS the time multiplier. Relay manuals that follow IEC 60255-151, such as Protecta's overcurrent function description, list the constants: k = 0.14 and α = 0.02 for standard inverse, 13.5 and 1 for very inverse, and 80 and 2 for extremely inverse. North American relays usually use the IEEE curve family in C37.112, which IEEE says defines "the inverse-time characteristics of overcurrent relays" with "operating equations and allowances".

A timing test injects a step current at several multiples of pickup and compares the measured time with the calculated one. With TMS = 0.1, the expected times are:

These are worked from the curve equation above. Your acceptance tolerance comes from the relay manufacturer's published accuracy and your company's test procedure, not from this table.

In this short demonstration, Doble-Megger shows how a manual timing test is set up and run on a protective relay in its RTMS software: the fault quantity is stepped on, the trip contact stops the timer and the result is compared with the expected time. It is one of the lessons in our free Protection Relays: Settings, Testing and Commissioning course, which also covers OMICRON Test Universe modules for overcurrent, distance and differential testing.

When is primary injection needed?

Secondary injection cannot find a CT wired with the wrong ratio tap, reversed polarity or a phase swapped in the marshalling cabinet, because it never goes through the CT. Primary injection does. A high-current test set drives current through the primary conductor, the CT transforms it, and you check that the relay measures the right magnitude, phase and direction. OMICRON notes that commissioning engineers can check CT wiring and plausibility "by using primary injection of high currents from the test set."

Primary injection is typically done at commissioning and after any change to CTs or secondary wiring. Differential and restricted earth fault schemes get extra attention, because a single reversed CT makes them trip on a through fault. Our earlier post on becoming a commissioning engineer describes how these tests fit into a wider commissioning sequence.

What is a relay testing procedure on site?

The steps are the same whether the relay is a 40-year-old electromechanical unit or a numerical IED, but two points deserve emphasis.

• Isolation first. Before any injection, the trip outputs to live breakers are isolated, CT test blocks are opened in the right order so no CT secondary is left open-circuited, and the work is covered by your site's permit. An open-circuited CT secondary under load can develop dangerous voltages.
• Restoration last. Many relay misoperations follow a test because a link, a test switch or a setting group was left in the test position. A written restoration checklist and a final check for alarms on the relay and the SCADA screen are part of the test, not an extra.

The same discipline about isolation applies to every control circuit; our post on contactors vs relays covers the low-voltage auxiliary relays that often sit in the trip path.

How are end-to-end and IEC 61850 schemes tested?

End-to-end testing

Line differential and communication-assisted distance schemes involve relays at both ends of a line and the channel between them. Testing each relay separately does not prove they work together. In an end-to-end test, a test set at each substation plays the same simulated fault at the same instant. Megger explains that "the test systems at each line end must be synchronized so that test currents reach all relay terminals at the same time", usually with a GPS clock, because the relays exchange time-stamped data and a timing error can cause an unintended operation (Megger).

Digital substations

In an IEC 61850 substation, trip and interlock signals may travel as GOOSE messages over Ethernet, and currents and voltages may arrive as Sampled Values from a merging unit instead of copper wiring. The test set then has to speak the protocol. OMICRON states that its test set "simulates a merging unit (MU) in accordance with IEC 61869-9" when testing with Sampled Values. Testers subscribe to the relay's GOOSE trip message instead of wiring to a contact, and use the standard's test and simulation modes so live devices ignore test traffic. Our free IEC 61850 Substation Automation course covers GOOSE, SCL files and testing tools.

How often should protective relays be tested?

There is no single worldwide interval. Three common references:

• NERC PRC-005-6 (North American bulk power system). Table 1-1 of PRC-005-6 sets a maximum maintenance interval of 6 calendar years for "any unmonitored protective relay" and 12 calendar years for monitored microprocessor relays with internal self-diagnosis, alarming and waveform sampling. It applies to registered entities, and you should confirm which version is in force for your organisation.
• ANSI/NETA MTS-2023. The InterNational Electrical Testing Association's maintenance testing specification aims to assure that tested equipment is "suitable for continued service" and includes a frequency-of-maintenance guide. Its frequencies are guidance that depend on equipment condition and criticality.
• Owner's maintenance programme. Utilities and large industrial sites outside these frameworks set their own intervals, often guided by manufacturer advice and failure history.

How to learn relay testing

Relay testing sits where protection theory, instrument transformers and switchgear meet. A practical order of study:

1. Protection principles and settings: Protection Relays: Settings, Testing and Commissioning.
2. Fault levels and coordination studies: ETAP Power System Analysis.
3. The equipment the relay protects and trips: Testing and Maintenance of Transformers and Switchgear, and our companion post on transformer testing types.
4. Digital substations: IEC 61850 Substation Automation.

Then get supervised time with a real test set; theory alone does not make anyone competent to isolate and test a live scheme. When you show training to an employer, our guide to verifying engineering training certificates explains what they will check.

Every course is free in full. An optional EDWartens Certificate of Completion, from US$8.99, records that you finished the course. It is not a NETA certification or a licence to test, and it is not accredited; anyone can verify it at edwartens.com/verification.

Take the free course

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Protection Relays: Settings, Testing and Commissioning

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IEC 61850 Substation Automation: GOOSE, SCL and IEC 60870-5

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Testing and Maintenance of Transformers and Switchgear

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ETAP Power System Analysis: Load Flow, Short Circuit, Protection, Arc Flash and Stability