Generator Protection
Author: Torsten Schierz, OMICRON electronics Deutschland GmbH, Germany
Introduction
Generator protection systems are very complex systems with many different protective functions. The configuration of these systems depends on the rated power of the generator as well as on the power system structure, i.e. whether the generator is in busbar connection or connected to a unit transformer, as shown in Figure 4. This article will describe solutions for testing selected protective functions effectively for the above connection configurations. As a starting point, experience recommends to structure the tests according to the following criteria:
Step 1: Testing protective functions that only use voltage measurements (e.g. ANSI 59, ANSI 81, etc.)
Step 2: Testing protective functions that only use current measurements (e.g. ANSI 50, ANSI 87, ANSI 46, etc.)
Step 3: Testing protective functions that use both voltage and current measurements (e.g. ANSI 32, ANSI 90/40, etc.)
Test philosophy for overlapping protective functions
Generator protection systems can trip different breakers such as the network circuit breaker (CB), the generator CB, and the de-excitation CB. This so called trip command matrix depends on the activated protective functions, the technical philosophy as well as the power system structure.
Therefore it is recommended to test the correct behavior of each protection function. This is only possible without deactivating any protective functions during the tests.
Application examples
For the following protective functions, the relevant technical background will be explained and practical settings for testing will be derived:
- Testing the ANSI 90 protective function (underexcitation)
- Testing the ANSI 46 protective function (negative sequence / unbalanced load)
- Primary testing of the ANSI 59GN protective function (directional 90% stator ground fault)
Testing of ANSI 90
A synchronous generator always requires a sufficient DC voltage and thus a DC current flow through the excitation winding. This is necessary to maintain the synchronization to the connected power system.
The generator capability diagram defines the limits of active and reactive power resulting from the physical parameters of the turbine and the generator, see Figure 2.
The underexcitation area is especially critical for the stability of the generator. In this area, the generator can lose its stability, e.g. as a result of a short-circuit in the connected power system or a malfunction of the automatic voltage regulator.
The protective function ANSI 90 protects the generator from asynchronous operation in case of these events.
Depending on the manufacturer of the protective devices, this function uses the impedance measurement or the admittance measurement.
Note: The impedance measurement method is not part of this article, because it is possible to transfer all necessary relay settings directly in the impedance plane of a distance relay (Figure 1).
On the one hand, for protection devices which use the admittance measurement method, the calculation of the relay settings is a lot easier than with the impedance measurement, because the admittance plane of the turbo generator can be used directly, see Figure 3.
On the other hand, testing the following characteristics in the admittance plane is rather complicated. Therefore, in the following, a more elegant method of testing admittance characteristics shall be introduced. The idea is to transform the admittance characteristics to the impedance plane to use automated distance test routines for testing the underexcitation protective function.
The admittance plane can be reproduced in the impedance plane using a mathematical transformation, as shown bellow.
The constant voltage 
must be divided by the apparent power S. (equation 1)
must be divided by the apparent power S. (equation 1)
(equation 1)
By using this formula any point in the admittance plane can be transformed to the impedance plane. However, for the automatic testing of the ANSI 90, it is desirable to transform the complete characteristic curve.
For this purpose the straight line equations must be inverted. According to Figure 5 and equation 2 the inversion of a straight line in the admittance plane results in a circle in the impedance plane.
(equation 2)
With 
Figure 6 shows the settings which are used in this example.
The following example shows the transformation of the trip time characteristic No. 1 to the impedance plane (equation 3) and the resulting impedance zone (Figure 7).
(equation 3a)
(equation 3b)
The same transformation applies to the trip time characteristic curves 2 and 3. Figure 9 shows the results of this transformation.
Summary: With the transfer of the trip time characteristics from the admittance plane to the impedance plane, it is possible to use the same test philosophy as for a distance relay. In order to stabilize overlapping protective functions,such as the undervoltage protective function, it is required to use a constant test voltage, i.e. the rated voltage of the generator.
If the overcurrent protective function is active, its pick-up or trip may interfere for test points between 0 Ω and approximately -40 Ω in the impedance plane. For such cases the relay settings have to be checked.
Testing of ANSI 46
Unbalanced load conditions result in a positive and a negative sequence system, see Figure 8.
The negative sequence component rotates counter to the rotor movement and hence produces a flux which cuts the rotor at twice the rotational velocity. Thereby large currents with double frequency are inducted in the rotor causing severe heating.
According to the manufacturers it is possible to have different thermal trip time characteristics. This example is based on protective devices which use the ratio between the negative sequence current and the generator nominal current (I2/In). This function works with the current of only one side (side 1 or side 2) as well.
In multifunctional machine protection relays, all necessary protective functions, including differential protection are implemented in one device.
This can cause problems, because some protective functions may overlap during the test of the unbalanced load protection function.
One philosophy for testing this protective function is to deactivate the differential protective function before starting the test. The disadvantage of this method is that it is not possible to discover logic errors, e.g. in the trip command matrix or overlapping protective functions. Therefore it is recommended to test without deactivating any protective function.
Without a unit transformer in the protection zone, testing ANSI 46 with active differential protection is not too complicated. There is just a phase shift of 180° between the currents of side 1 and side 2.
Note: The phase shift between side 1 and side 2 depends on the position of the CT starpoint grounding.
The situation is different, however, if there is a unit transformer in the same protection zone, as shown in Figure 11.
In this case, the vector group and the transformation ratio of the unit transformer must be considered. Also the different CT ratios will have an influence on the calculation of the test currents for side 1 and side 2.
The phasor diagrams in Figure 10 (a and b) display the phase shift of the test currents between side 1 and side 2 for a unit transformer with the vector group Ynd5.
The transformer ratio and the CT ratios are not considered in this diagram.
Note: For the positive sequence current the phase shift is 150° clockwise (transformer vector group 5 times 30°). The phase shift for the negative sequence current is 150° counter clockwise!
Summary: As a conclusion, the physical behavior of the symmetrical components depends on the transformer vector group. It was shown that it is possible to test protective functions which only use one current measurement system (side 1 or side2) while the differential protective function is active.
Primary testing of ANSI 59GN
For generators with a maximum rated power lower than 50 MVA and busbar connection, the directional 90% stator ground fault protection (ANSI 59GN) is the standard protective function.
An alternative solution is the ground differential protective function with the displacement voltage as pick-up criterion and two cable-type transformers for ground current measurement, as shown in Figure 12.
Note: This solution is only possible, if the generator is connected via cable and the star point is accessible.
Secondary tests alone do not guarantee the correct function of the stator ground fault protection, because all settings were calculated based on theoretical grounding conditions.
It is therefore necessary to confirm the theoretical values with primary tests.
For this function the very first commissioning test is to check the secondary current transformer ground connection. Only one CT must be grounded.
The two primary tests (Figures 13 & 14) will check if the ground fault current is higher than the set pick-up value, and if the stability of the 90% stator ground fault protection function is ensured.
In this example, the settings of a 2.5 MVA generator (IEE > = 4 mA; Ven > = 4.9 V) were used.
Primary test with a ground fault inside the protection zone: A ground electrode is connected to the generator terminal, the voltage regulator is deactivated and the trip command is blocked. When the generator runs at nominal speed the terminal voltage must be increased manually to the rated generator voltage. The next step is to measure the ground fault current (IEE) and the displacement voltage (Ven), as shown in Figure 13.
Primary test with a ground fault outside the protection zone (stability test): A ground electrode is connected to the feeder grounding point. The remaining test steps are the same as for the previous test. Figure 14 displays the test for this example.
Summary: The comparison between the measured ground fault values for both primary tests confirms that the relay settings for the ground fault protection in this example are correct. With a ground fault which is located inside the protection zone, the flowing ground fault current (IEE) and the displacement voltage (Ven) are high enough to protect approx. 90% of the generator stator.
For the ground fault in the power system (outside the protection zone) this protective function is stable (no trip) and the difference between the parameterized pick-up value and the measured ground fault current (IEE) is high enough. The theoretical value ∆I = 0A is not possible, because the cable-type transformers have different magnetizing characteristics. If the comparison between the measured and the calculated values reveals potential malfunctions, the settings need to be adapted based on the measured values.
Conclusions
In this article, solutions for secondary and primary testing of the protective functions ANSI 90, ANSI 46 and ANSI 59GN were introduced. These solutions have shown that secondary testing of complex multifunctional relays is possible even without deactivating overlapping protective functions.
Furthermore, it was pointed out why the additional primary test of ANSI 59GN to verify the calculated settings is essential.
The presented approaches are illustrated in a way that allows for their application to similarly configured protective functions in relays of completely different manufacturers.
Biographies
Biography:
Dr.-Ing. Torsten Schierz worked for 7 years at the University of Applied Sciences Zittau/Görlitz in the area of research and teaching. Since 1996 he has been an employee of OMICRON electronics Deutschland GmbH in the business fields Training, Commissioning and Technical Consulting. He has more than 16 years of experience in power system and rotating machine protection, especially in calculation and commissioning, as well as more than 24 years of experience in teaching electrical engineering. At present he is a Senior Consultant.
Torsten is member of the VDE (Federation of Electro Technology Electronics Information Technolog
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