Nuisance Generator Differential Protection Trips in Real Time Situations.

The differential protection function of a generator relay uses the difference between current into and out of the generator in order to detect internal faults in the generator winding.

The sensitivity usually can be set to between 5-10% of the full load current of the generator, while the operation is instantaneous and trips the excitation, generator CB and also the turbine.

For a fault outside the protected area, the through fault current can be high, but correct operation of the differential means that it should not operate on such occasions. By through current, we mean the current flowing through the generator CTs and the generator winding, and it feeds the external fault.
In this report, we try to investigate two occasions in which the differential protection tripped for external high through currents and attempt to give an explanation to them.


1. Block Differential protection trip during a load rejection test

On this occasion the generator connects to the system via a step-up generator transformer. The generator is directly connected to the transformer and the generator CB is located at the HV side of the transformer. In this case, the differential protection is set up to protect the generator-transformer block and, therefore, it is known as block differential protection.

In the figure below, we can see CT inputs and trip outputs for the block differential protection configuration.



During normal loading conditions, the generator supplies up to full load current, which flows through CT1, CT2 and also the HV breaker.
Assuming a load with a lagging power factor, the loaded generator should supply positive MW and Mvars to the system.
When a load rejection test is performed, the CB is manually opened under load, so that the response of the turbine speed and the generator voltage can be tested.
The expected response is turbine speed increase due to the sudden stop of active power transfer, and also voltage overshoot due to the stop of reactive power transfer to the system.

This situation could lead to the generator protection relay tripping on overfequency or overvoltage respectively. The turbine speed controller and the AVR can then be adjusted to avoid such trips during load rejection situations.

During such an overvoltage situation, we experienced a block differential protection operation. Fault records in the relay during the trip showed zero current measured in HV side CT2, which is normal after the manual opening of the CB, but in CT1 there were currents of the magnitude of 12% FLC measured, which caused the differential function to trip.

The particularity of this site was that the generator voltage was set too high in order to achieve a lagging PF less than 0.8. causing the open circuit voltage to reach levels of 118-120% nominal during the load rejection.

In terms of field current provided by the exciter, the generator requires 1pu current at FSNL, while when on load the excitation current would be between 2-3pu. Therefore, the excess of excitation current has to be immediately lost in order to avoid tripping.

Our explanation is that when the circuit breaker opens CT2 immediately stops delivering current but CT1 carries the magnetising current of the 11kV transformer delta winding.  With the generator now unable to deliver either Megawatts or Megavars the terminal voltage is raised even higher, the transformer overfluxes and the magnetising current increases.  Hence the differential protection trips.

Power frequency overvoltage causes both an increase in stress on the insulation and a proportionate increase in the working flux. The latter effect causes an increase in the iron loss and a disproportionately great increase in magnetising current (PRAG ’87, p.279).

Based on power transformer manufacturers’ data, the magnetising current per phase in the primary circuit with In=1000A, against secondary voltage for an 11kV/30 medium size transformer is as follows:

Open Circuit



Current (% Io/In)


Current (A)

9900kV 0.09 0.9
11000kV 0.15 1.5
12100kV 0.44 4.4

The knee-point on the magnetising curve is defined as the point where a 10% increase in voltage would cause a 50% increase in magnetising current. So, from the table above, we can determine that the generator transformer LV side is designed to operate near its knee-point on the magnetisation curve. Therefore, large magnetising currents can be developed when it enters the non-linear region due to very high voltages. In this case, the magnetising current had to be above 100A primary per phase to cause the differential protection to operate. This is 20 times the current at 110% of the nominal voltage, which is already above the knee-point on the curve. The voltage overshoot recorded during the load rejection reached a value between 118-120%, which explains this sudden current increase.

Solution to the problem was to increase the AVR response in order to prevent the excessive voltage overshoot. This solution acted immediately on the root of the problem and no other measures were necessary.

2. Generator Differential trip during start-up of an HV AC motor

In this section we report another occasion, where the generator differential protection mal-operated for an external condition outside its protected area. The protected area was the generator only, without a generator transformer connected.

In this case, the reason seems to be due to the starting, and sporadically, during the stopping of an HV AC motor. The motor is directly connected to the 10kV local busbar, where a generator of smaller size is also connected. There is a constant but apparently weak grid connection present also at all times.

The reported trips were surprising, but the generator relay fault records verified differential currents measured on different occasions. The characteristic of all cases was that the currents were present only in two out of three phases at any time, varying from one fault to the other.

Differential trip levels in all recorded faults, apart from one, were marginally above tripping values, which indicates that tripping occurs irrespective of the loading conditions of the generator. Nevertheless, in one fault record the measured differential currents were upto 70% of the full load current with the generator loaded at full at that time. It is suspected that this was triggered during a motor stop.
The high DC component present in the inrush current could be an explanation for these trips and probably CT saturation. The reason is still unclear and extra information is required to make a judgement. Site tests and measurements might be necessary to collect extra data.