ROCOF 81R (PFRC): Rate of Change of Frequency Explained

Short answer

Function 81R measures how fast frequency changes (df/dt, ROCOF). It is used in load shedding, generator protection and as one of the signals for islanding detection, because in a small island frequency changes faster than in the interconnected grid. Its difficulty is telling a real island apart from normal system disturbances. That is why many interconnection requirements no longer accept it as stand-alone anti-islanding protection: only as part of a hybrid logic, with direct transfer trip as the preferred method.

What 81R rate-of-change-of-frequency protection is

The 81R does not look at the frequency value, but at how much it changes per unit of time. It is expressed in hertz per second (Hz/s) and is called ROCOF (rate of change of frequency) or df/dt.

ANSI/IEEE C37.2: device 81 is used with the suffix R for rate of change.
IEC 61850: logical node PFRC.

In a large interconnected grid, the inertia of all the synchronous machines makes frequency change slowly, even after losing a generator. If part of the network becomes separated and is fed only by distributed generation, the inertia of that island is small. Any difference between the power generated and the power consumed changes frequency quickly. That fast change is what the 81R detects.

The 81R is a useful and widely used function, but on its own it is not an anti-islanding solution. Its limits, and what interconnection requirements usually accept, are explained below.

Where it is applied

Solar PV plants and distributed generation at the point of interconnection with the utility, as one of the islanding detection signals. Many utilities accept it only within a hybrid logic (see the section on interconnection requirements).
Distributed generation and on-site generation connected to distribution networks: small hydro, biomass, cogeneration, diesel or gas generation in industry. Some interconnection standards have used it as loss-of-mains protection, with increasingly less sensitive thresholds.
Industry with its own generation that must separate from the public grid when the grid is lost.
Load shedding schemes that use the rate of change to anticipate a severe frequency drop, as a complement to frequency protection 81.

Why islanding is avoided

An unintentional island is a risk for personnel who believe the line is de-energized, it can supply voltage and frequency outside the limits to customers and, when the utility recloser recloses, it can close two systems out of phase and damage generators, inverters and loads. That is why the grid’s reclosing 79 and the plant’s anti-islanding protection must be coordinated: the generation must disconnect before the dead time expires.

How it works

The relay calculates frequency continuously and obtains its derivative over a measuring window of several cycles. If the absolute value of df/dt exceeds the threshold for the set time, it operates. Common elements:

Threshold in Hz/s, for rising, falling or both directions.
Calculation window: a shorter one responds faster but is more sensitive to noise and phase jumps; a longer one gives stability at the cost of speed.
Additional operating time.
Undervoltage blocking, because with low voltage the measurement is not reliable.

Related to the 81R is vector shift (vector surge) protection, which detects the sudden jump of the voltage angle at the instant the island forms. Some manufacturers group it with the 78. It is faster, but also more prone to unwanted trips on nearby faults.

The non-detection zone

If generation and load in the island are almost balanced, frequency barely changes and no passive method detects it in time. That is why the 81R is combined with:

voltage protection 27 and 59, and frequency protection 81U/81O;
the active islanding detection methods of the inverters, which slightly disturb the output and observe the response (their tests are described in IEC 62116 and IEEE 1547.1);
direct transfer trip from the substation, the most secure method when the risk justifies it.

What interconnection requirements usually accept

Grid codes and utility interconnection requirements have changed the role of the 81R:

They ask generation to ride through system events with high rates of change of frequency without disconnecting, so the ROCOF threshold cannot be very sensitive. With such a threshold, a balanced island is not detected.
As a result, many of them do not accept ROCOF, frequency, voltage or reverse power as stand-alone anti-islanding functions, but only within a hybrid or combined logic. Vector shift is often discouraged for the same reason.
The method usually preferred as primary is direct transfer trip (intertrip). Where it is not technically feasible, an active inverter method is used.
For synchronous generators, ROCOF tripping is often restricted and must be justified to the system operator.

The specific method is agreed with the utility, and the settings are adapted to the local code and the utility’s requirements. The complete picture is explained in solar plant protection and in protection requirements for distributed generation.

Setting criteria

Utility interconnection requirements and the applicable local code. Remember that in many of them the 81R cannot be the anti-islanding protection by itself.
Ride-through capability: IEEE 1547 requires distributed energy resources to stay connected for certain rates of change of frequency according to their category. The 81R threshold must not be more sensitive than what the standard or the utility requires the plant to ride through.
Maximum time to cease energizing the island, set by the standard or the utility, and the dead time of the grid’s reclosing.
Inertia and expected balance of the island, which determine which rates of change actually occur.
Measuring window and undervoltage blocking, according to the manufacturer’s recommendations.

There is no universal value. The settings must come from the interconnection study and the protection coordination study.

How each manufacturer implements it

Siemens SIPROTEC includes rate of change of frequency and vector shift in generator and interconnection relays. It is configured in DIGSI.
SEL offers rate-of-change-of-frequency elements in its feeder, generator and interconnection relays, with supervision and configurable logic in AcSELerator QuickSet.
Relion (Hitachi Energy 670/650; ABB 615/620) has rate of change as a function of its own, named after the IEC 61850 logical node, configured in PCM600.
GE Vernova (Multilin) includes rate of change in feeder and generator relays, configured in EnerVista.
Schneider MiCOM / Easergy offers df/dt and vector shift in interconnection and generator relays, configured in MiCOM S1 or Easergy Studio.
NOJA Power includes protection functions for distributed generation, rate of change among them, in its reclosers.

What changes is the calculation window, whether the setting is per direction, how low voltage blocks it and whether vector shift is part of the same function. That is why an 81R setting designed for one brand is not copied to another.

Why it trips or blocks

System event without an island: the loss of a large generator or a system separation changes the frequency of the whole grid. If the threshold is too low, many plants disconnect at once and make the event worse.
Phase jump from a nearby fault or from switching: the calculated frequency shows an apparent spike.
Measuring window too short.
VT failure or low voltage without proper blocking.
No trip on a real island: load and generation almost balanced, in the non-detection zone.
Late trip: the grid’s reclosing closed before the plant disconnected.

Start by looking at the oscillography and comparing the relay frequency with the one recorded at the substation or on the system. If the whole grid saw the event, the problem is the setting, not an island.

How it is tested

With the Omicron CMC 356, frequency ramps with a controlled slope in Hz/s are generated and the following are checked:

the operating threshold in both directions;
the operating time from the start of the ramp;
stability for ramps below the threshold and for phase jumps;
undervoltage blocking;
coordination with the other interconnection protections and with the trip of the plant breaker.

It is done during secondary injection as part of the plant commissioning.

Did your relay trip or block on this function and the cause is not clear? At Tiza Group we review the events and settings remotely. See remote relay configuration or contact us.

References

IEEE C37.2, device function numbers.
IEEE 1547, Standard for Interconnection and Interoperability of Distributed Energy Resources with Associated Electric Power Systems Interfaces.
IEEE 1547.1, Standard Conformance Test Procedures for Equipment Interconnecting Distributed Energy Resources with Electric Power Systems and Associated Interfaces.
IEC 62116, test procedure of islanding prevention measures for utility-interconnected photovoltaic inverters.
IEC 60255-181, functional requirements for frequency protection.
IEC 61850-7-4, logical node models.
P. Kundur, Power System Stability and Control.

Frequently asked questions

Why did the 81R trip my solar plant when there was no island?

The usual causes are a system event that changed frequency quickly (loss of a large generator), a phase jump when a nearby fault was cleared, a measuring window that is too short or a threshold that is too sensitive. Interconnection requirements now ask generation to ride through a certain rate of change of frequency without disconnecting.

Can the 81R be used as the anti-islanding protection of a plant?

Usually not as the only function. Because generation must ride through high rates of change of frequency, a ROCOF threshold that respects ride-through cannot detect a balanced island. Many utilities accept it only within a hybrid logic, and prefer direct transfer trip or, where that is not feasible, an active inverter method.

Does the 81R replace the inverter's anti-islanding protection?

No. Inverters have their own active islanding detection methods, tested according to IEC 62116 (IEEE 1547.1 in North America). The 81R in the relay at the point of interconnection is a passive function that only adds value within a hybrid logic together with other signals.

What happens if generation and load in the island are almost balanced?

Frequency barely changes and the 81R does not detect the island. This is the non-detection zone of passive methods. It is covered with direct transfer trip from the substation or with the active methods of the inverters, which are the ones usually accepted as primary anti-islanding protection.