Understanding generator restricted earth fault (REF) protection and testing

Electrical Tester - 25 February 2022

By Sughosh Kuber

Introduction

Generators are some of the most critical and expensive items of equipment in a power system and they therefore require adequate electrical protection from internal faults, external faults and abnormal system conditions. Because ground faults are more common and potentially more dangerous to personnel and equipment than phase faults, it is essential to design a robust ground fault protection. A ground fault in a generator may occur due to insulation breakdown that results in a phase-to-ground short. One popular scheme used to protect generators is differential protection. Phase differential protection can efficiently recognise phase-to-phase faults but may not detect very low ground fault currents near the neutral point of the generator winding. Because of this, the restricted earth fault (REF) element is often used to protect against ground faults in wye-connected windings. The location of current transformers (CTs) used in the scheme defines the zone of earth fault protection, which is why 'restricted' is included in the name of the element. In this article, the REF protection scheme is discussed specifically in relation to wye-connected generator windings . Different methodologies have been used over the years, but the REF protection element discussed in this article uses a comparison of zero-sequence components to detect the fault, along with directionality, to provide increased security. This implementation is usually recommended for solidly grounded or resistively grounded generators [1].

REF protection

The type of REF protection discussed in this article uses three CTs at the generator terminal end, i.e. the phase or line CTs, and a further CT at the neutral point of the generator winding. As already mentioned, the zone of protection is restricted by the placement of these four CTs, which means that the REF element will detect only the ground faults within the winding. It is important to note that line CTs cannot be connected in delta configuration for this scheme, as delta-connected CTs would cancel out the zero-sequence components which are the basis for the protection [1].

Any fault that occurs within the protected zone - i.e. between the line CTs and the neutral CT - is considered an internal fault. Figure 1 shows the REF implementation for solidly grounded and resistively grounded windings, as used by one of the popular relay manufacturers. The protective relay is connected so that it monitors current from the neutral CT as well as the residual current resulting from unbalance of the line CTs. Figure 1 shows only one line CT on the generator terminal side, but in reality, each of the three phases would have a CT.

This type of REF implementation operates on directional logic which uses currents from the line CTs as the polarising quantity and the current from the neutral CT as the operating quantity. The magnitude and direction of these two quantities are compared against the protection pick-up setting before deciding on operation. Directional logic helps the scheme to differentiate between internal and external faults.

Fault scenarios

Internal fault: When a fault occurs within the zone of protection, the direction of current flow (In) measured by the neutral CT is towards the neutral terminal, feeding into the fault. The residual current (lg) from the generator terminal flows towards the internal fault. Under these conditions, the REF protection element should operate. Figure 2 depicts the flow of currents for the internal fault scenario.

External fault: When a fault occurs outside the zone of protection, the direction of current flow (In) measured by the neutral CT is towards the neutral terminal. The residual current (lg) from generator terminal will flow towards the system feeding the external fault. The protection element should be restrained from operating since the fault lies outside the zone of protection. Figure 3 depicts flow of currents during an external fault scenario.

Directionality check

The directional logic measures the angle between the polarising quantity and the operating quantity to differentiate between internal and external faults. This logic does not operate for small currents or for phase differences close to+ or - 90° [1]. Different digital output signals are used to monitor internal and external fault conditions. Figure 4 shows the logic used to monitor directionality based on currents from CTs.

The green shaded region signifies relay operation for internal faults and the yellow shaded region for external faults. In this context, external faults are also referred to as reverse faults because of the direction of currents and angle of separation between them. Appropriate digital output signals should be configured for reverse fault trip monitoring. In this characteristic plot, there is a dead zone region between 80 and 100 and another between -80 and -100. In the dead zone regions, the relay will not operate.

As shown in Figure 5, when an internal fault is present and the generator breaker is open, the relay will not see any currents on the line side - it will see only the current from the neutral CT. This means that the polarising quantity required by the directional logic is missing and the protection will not operate. To overcome this challenge, bypass logic can be implemented in the relay. When the bypass logic is enabled in the protection settings, the scheme will consider the following:

Operating current higher than the pickup setting
Absence of polarising current to the relay
Relay seeing open breaker status
When these conditions are met, the protection will operate for the internal fault [1]

Figure 4: Directionality check (angle between polarising and operating quantities)

When the generator breaker is open and an internal fault is present conditions before operating:

Figure 5: Generator breaker open and an internal fault is present

Testing REF protection

REF protection can be tested with a test set capable of providing at least two current sources to replicate the residual current and the neutral current. Figure 6 shows the connections between a Megger SMRT test set and the relay under test. Connections are made from SMRT current channels to the IA phase terminal and the IN terminal on the relay. Since residual current is calculated by vector summation of all the three phase currents, the current injected to just one of the phases will be equivalent to the residual current seen by the relay. One of the test set’s binary inputs is connected to the relay output contact to allow monitoring of the operation of the protection element.

These are examples of settings related to REF protection in the example relay under test:

CT Ratio (Neutral) = 100
CT Ratio (Phase) = 500
REF Pickup setting = 0.4 pu

Figure 6: Test connections

Pickup test

Pickup tests need to be performed to verify the thresholds for the operating and polarising quantities. The operating quantity is the current injected into the neutral terminal and the polarising quantity is the current injected into the phase terminal. To perform the operating quantity pickup test, the per-unit setting needs to be converted to amps. The tester must also program appropriate digital signals in the relay output contact to monitor the operating pickup.

Op pickup (in amps) = (per-unit REF pickup setting) * (nominal secondary)
Op pickup (in amps) = 0.4 * 5 = 2 A

To perform the pickup test on the example relay, a current step ramp was conﬁgured with the start value as 85 % of the pickup value and step increments of 0.01 A.

When the current to the neutral terminal reached around 2.01 A, the relay output contact operated indicating pickup. Similarly, to test the polarising quantity pickup, the per-unit setting needs to be converted to amps. Appropriate digital signals should also be programmed in the relay output contact to monitor the polarising pickup. In this relay, the residual current seen by the relay should be at least 80 % of the REF pickup setting for the relay to pick up.

Pol pickup (in amps) = 80 % of (per-unit REF setting * ())
Pol pickup (in amps) = 0.8 * 0.4 * = 0.32 A

Where CTRN is the ratio of the neutral CT, CTRP is the ratio of the phase CT and ‘Nominal Secondary’ is the nominal secondary current of the CTs.

A current step ramp was configured with start value at 85 % of the pickup value and step increments of 0.01 A. When the current to the phase terminal reached around 0.319 A, the output contact of the example relay operated indicating pickup.

Figure 7: Operating quantity pickup test settings

Figure 8: Operating quantity pickup test result

Directional test (for internal fault)

To perform a directional test, the currents injected into the neutral and phase terminals should be above the pickup value and should be separated by a phase angle that is within the operating zone for internal faults, as shown in Figure 4. Appropriate digital signals should also be programmed in the relay output contact to monitor the directional trip for internal fault. The currents injected for this test were chosen to be greater than the actual pickup values. The relay internally compensates for the phase CT polarity.

The phase angle of the current injected into the neutral terminal is 90 which is compensated by the relay to -90 because of the polarity of the CT connection, as shown in Figure 1. To test the relay, the phase angle was increased from 90 to more than 100. This moved the point on the characteristic from -90 towards the boundary of the operate region for an internal fault. The relay tripped at 101.3 which is equivalent to -78.7 as seen by the relay. This is within the internal fault region of the directional characteristic shown in Figure 10. The reverse fault region could be validated in a similar way by performing another test where the phase angle is decreased until the relay operates for a reverse fault condition.

Figure 9: Test currents for directional test

Figure 10: Characteristic plot from dead band to internal fault zone

Internal fault test (circuit breaker (CB) open)

This test is performed to validate the bypass logic is actively seen by the relay [1 ]. To perform this test, the state sequencer was set up with pre-fault and fault states. A timer was also set up to capture the time taken by the relay to operate from the point of bypass pickup to the point of trip. In the pre-fault state, 1 A was injected into the neutral terminal of the relay and no current to the phase terminal. In addition, the binary output 1 was connected to the relay input terminal to simulate the breaker open status in both the pre-fault and fault states. The current injected into the neutral terminal in the fault state was 2.5 A. Two binary inputs were configured to monitor two relay output contacts, one of which was programmed for bypass pickup, the other for trip.

A timer captured the time between operation of these two output contacts. The pre-fault state was run for 2000 ms and during the fault state the relay tripped. The timer captured the operation time of 38 ms which translates to 2.5 cycles.

Internal fault test (time delayed tripping)

If required, the REF element can be configured with time-delayed tripping. In the sample relay under test, the inverse-time overcurrent element can be configured along with the directional logic. To test this functionality, a test was set up using the sequencer with pre-fault state and fault state. A timer was set up to capture the time delayed tripping.

In the fault state, two binary inputs were configured to monitor two relay output contacts, one of which was programmed for pickup, the other for timing. The test was performed at twice the pickup value. Currents were injected into the neutral and phase A terminals. According to the relay manufacturer, the timing calculation for current injection of twice the pickup value yields a theoretical operating time of 0.9 seconds.

The actual operating time measured by the test was 0.834 seconds. This test can be performed for different multiples of pickup current.

Figure 13: Pre-fault and fault state test values

Conclusion

REF protection is widely used to protect generators and transformers against earth faults, and various implementations have been developed by relay manufacturers and system designers. This article has provided an insight into the type of REF protection that uses comparison of zero-sequence components along with directional logic and, if required, time-delayed tripping. The article has also explained various tests for REF protection elements, giving details of the test approach and discussing the results. A good understanding of REF protection and different types of grounding helps protection engineers to design effective ground fault protection schemes and also helps relay technicians to thoroughly validate the schemes during testing.