A generator protection scheme brings together protections for internal faults (differential, stator and rotor ground fault), for abnormal conditions (loss of excitation, unbalance, reverse power, overexcitation, frequency) and for system backup. Each protection is assigned to a trip mode that decides what opens: unit breaker, field, turbine or all of them at once.
What a generator protection scheme is
The synchronous generator is a rotating machine with an excitation system, a turbine and, almost always, a generator step-up transformer. It can suffer internal electrical faults, but also abnormal conditions that are not faults and damage it if they last: loss of field, unbalanced currents, motoring, overexcitation. It must also back up system faults that are not cleared in time.
The guide on the synchronous generator and its protections explains each function. This guide, part of the substation protection schemes series, covers how they are combined into a scheme and what each one opens.
Which protections make it up and how they are coordinated
Internal faults:
- Generator differential 87G, with CTs at the neutral and at the terminals.
- Overall differential of the generator-transformer unit, on large units, overlapping with the step-up transformer scheme.
- Stator ground fault: neutral overvoltage 59N on high-impedance grounded generators, supplemented to cover the zone near the neutral (third harmonic or injection, depending on the relay).
- Rotor ground fault 64R.
Abnormal conditions:
- Loss of excitation 40.
- Negative sequence 46.
- Reverse power 32.
- Overexcitation (volts per hertz) 24.
- Frequency 81 and out-of-step 78.
- Inadvertent energization with the machine at standstill.
System backup: distance 21 or voltage-restrained overcurrent 51V, and the 50BF of the unit breaker.
Synchronizing: synchronism check 25 on the unit breaker.
Trip modes
The scheme decides not only whether to trip, but what to open. The usual trip modes in generator protection practice are:
- Simultaneous (total) trip: unit breaker, field breaker and turbine at once. For severe internal faults (87G, stator ground fault).
- Generator trip: unit breaker and field, the turbine keeps running. Useful when it is better not to stop the machine.
- Unit separation: unit breaker only; the machine stays ready to resynchronize. Typical for system faults.
- Sequential trip: turbine first; when reverse power confirms there is no mechanical power, the breaker and the field open.
| Mode | Unit breaker | Field | Turbine | Typical use |
|---|---|---|---|---|
| Simultaneous trip | Opens | Opens | Closes | Severe internal faults: 87G, stator ground fault |
| Generator trip | Opens | Opens | Keeps running | When it is better not to stop the machine |
| Unit separation | Opens | Stays | Stays | System faults; the machine stays ready to resynchronize |
| Sequential trip | Opens afterwards | Opens afterwards | Trips first | Reverse power confirms there is no mechanical power |
Each function is assigned to a mode in the trip matrix, which is usually built with dedicated lockout relays 86.
Logic and sequence
For a stator ground fault:
- The 59N measures voltage at the neutral and operates after its time delay.
- It energizes the simultaneous-trip 86.
- The unit breaker and the field breaker open and the turbine is shut down.
- The 50BF of the unit breaker is initiated.
- The generator slows down; the records remain for analysis.
For a line fault that the system does not clear, the 21 or 51V backup separates the unit with a time coordinated with the line protections.
Variants by voltage level and size
- Low-voltage and emergency generators: a multifunction relay or the genset controller itself, with overcurrent, voltage, frequency and reverse power.
- Medium-voltage generators in industry and cogeneration: a complete generator relay; if they run in parallel with the grid, interconnection and plant separation functions.
- Power plant units connected at high and extra-high voltage: two generator relays, overall unit differential, protection of the step-up transformer and of the station service transformer.
Design criteria
- Settings based on data from the manufacturers of the generator, turbine and excitation system (rating, capability curve, thermal limits), not on typical values.
- Coordination with the system: frequency and voltage functions must coordinate with load shedding and with the system operator’s requirements. IEEE C37.106 covers frequency protection of generating plants.
- Coordination of the 40 and 24 with the AVR limiters, so the regulator acts before the protection.
- Redundancy in proportion to the importance of the unit.
How each manufacturer implements it
Generator relays in manufacturers’ current catalogs include, for example, Siemens SIPROTEC 5 7UM85 (DIGSI 5), SEL-700G and SEL-400G (AcSELerator QuickSet), Hitachi Energy REG670 (PCM600), GE Vernova Multilin G60 and 889 (EnerVista) and MiCOM P343/P345 (Schneider Electric and GE Vernova). The Multilin 489, still common in existing plants, is no longer manufactured. What changes is how 100 % stator ground fault coverage is achieved, the shape of the loss-of-excitation characteristic and, above all, how the trip matrix is built. That matrix is where most errors are found in the field.
Why it fails or misoperates
- Loss-of-excitation trip during a system power swing or during allowed underexcitation, because of a poorly set characteristic or delay.
- 46 trip with unbalanced loads that the generator can in fact withstand.
- Reverse power during synchronizing or at low load.
- Stator ground fault trip because the third harmonic varies with load.
- Wrong trip matrix: a system function that stops the turbine for no reason.
How it is tested
Each function is tested by secondary injection with a three-phase test set (for example, an Omicron CMC 356): characteristics in the impedance or power plane, thermal curves, time delays. The scheme is completed by checking the trip matrix function by function up to each breaker, the field and the turbine, and with tests at commissioning with the machine running when the procedure calls for them.
Did your generator trip with no clear reason, or do you need to configure a new generator relay? Our team reviews the events and configures the relays remotely. See remote relay configuration or contact us.
Related guides
References
- IEEE C37.102-2023, Guide for AC Generator Protection.
- IEEE C37.106-2022, Guide for Abnormal Frequency Protection for Power Generating Plants.
- IEEE C37.119-2025, Guide for Power System Circuit Breaker Failure Protection.
- J. L. Blackburn and T. J. Domin, Protective Relaying: Principles and Applications.
Frequently asked questions
Why does reverse power trip with a time delay and not instantly?
Because motoring is not a fault: the risk is to the turbine and it grows with time. The delay avoids trips during power swings or synchronizing, and in many schemes reverse power is used as the permissive for sequential tripping.
What is sequential tripping?
It is a mode in which the turbine admission is closed first and, when reverse power confirms there is no more mechanical power, the unit breaker opens. It avoids the overspeed that could occur if the breaker opened with the turbine still delivering power.
Does an emergency diesel generator need the same scheme as a power plant unit?
No. The scheme scales with the size, the importance and whether the generator runs in parallel with the grid. A small set in island operation may need few functions; a large one in parallel with the grid needs a complete scheme.