Generator Protection

PAC World magazine : Generator Protection1 of 5 https://www.pacw.org/no-cache/issue/march_2013_issue/lessons_learned... Home . March 2013 Issue . Lessons Learned . Generator Protection 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 1/16/2015 5:29 PM see Figure 2. e..org/no-cache/issue/march_2013_issue/lessons_learned.. For this purpose the straight line equations must be inverted. On the one hand. In this area.PAC World magazine : Generator Protection 2 of 5 https://www. for protection devices which use the admittance measurement method. The admittance plane can be reproduced in the impedance plane using a mathematical transformation. The protective function ANSI 90 protects the generator from asynchronous operation in case of these events. as a result of a short-circuit in the connected power system or a malfunction of the automatic voltage regulator. On the other hand. The generator capability diagram defines the limits of active and reactive power resulting from the physical parameters of the turbine and the generator. (equation 1) (equation 1) By using this formula any point in the admittance plane can be transformed to the impedance plane.pacw. for the automatic testing of the ANSI 90. a more elegant method of testing admittance characteristics shall be introduced. in the following. Note: The impedance measurement method is not part of this article. The following example shows the transformation of the trip time characteristic No. However. this function uses the impedance measurement or the admittance measurement. Depending on the manufacturer of the protective devices. Therefore. The constant voltage must be divided by the apparent power S. see Figure 3. the calculation of the relay settings is a lot easier than with the impedance measurement. 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. because the admittance plane of the turbo generator can be used directly. 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 underexcitation area is especially critical for the stability of the generator.g. 1 to the impedance plane (equation 3) and the resulting impedance zone (Figure 7). because it is possible to transfer all necessary relay settings directly in the impedance plane of a distance relay (Figure 1). (equation 2) With Figure 6 shows the settings which are used in this example. synchronization to the connected power system. the generator can lose its stability. (equation 3a) 1/16/2015 5:29 PM . testing the following characteristics in the admittance plane is rather complicated. as shown bellow. it is desirable to transform the complete characteristic curve. In multifunctional machine protection relays. This function works with the current of only one side (side 1 or side 2) as well. For such cases the relay settings have to be checked.. One philosophy for testing this protective function is to deactivate the differential protective function before starting the test.such as the undervoltage protective function. however. because some protective functions may overlap during the test of the unbalanced load protection function. Summary: With the transfer of the trip time characteristics from the admittance plane to the impedance plane. This example is based on protective devices which use the ratio between the negative sequence current and the generator nominal current (I2/In). i. In order to stabilize overlapping protective functions. Figure 9 shows the results of this transformation. all necessary protective functions. its pick-up or trip may interfere for test points between 0 Ω and approximately -40 Ω in the impedance plane. the rated voltage of the generator. There is just a phase shift of 180° between the currents of side 1 and side 2. in the trip command matrix or overlapping protective functions. Testing of ANSI 46 Unbalanced load conditions result in a positive and a negative sequence system. it is required to use a constant test voltage. 1/16/2015 5:29 PM . The disadvantage of this method is that it is not possible to discover logic errors. This can cause problems. see Figure 8. Note: The phase shift between side 1 and side 2 depends on the position of the CT starpoint grounding. (equation 3b) The same transformation applies to the trip time characteristic curves 2 and 3.PAC World magazine : Generator Protection 3 of 5 https://www. it is possible to use the same test philosophy as for a distance relay. as shown in Figure 11. If the overcurrent protective function is active. The negative sequence component rotates counter to the rotor movement and hence produces a flux which cuts the rotor at twice the rotational velocity. Without a unit transformer in the protection zone. e.pacw. According to the manufacturers it is possible to have different thermal trip time characteristics. testing ANSI 46 with active differential protection is not too complicated. Thereby large currents with double frequency are inducted in the rotor causing severe heating.g. including differential protection are implemented in one device.org/no-cache/issue/march_2013_issue/lessons_learned.e. The situation is different. Therefore it is recommended to test without deactivating any protective function.. if there is a unit transformer in the same protection zone. The phase shift for the negative sequence current is 150° counter clockwise! Summary: As a conclusion. It is therefore necessary to confirm the theoretical values with primary tests. Secondary tests alone do not guarantee the correct function of the stator ground fault protection. In this example. because all settings were calculated based on theoretical grounding conditions. as shown in Figure 12. Primary testing of ANSI 59GN For generators with a maximum rated power lower than 50 MVA and busbar connection. Note: This solution is only possible.PAC World magazine : Generator Protection 4 of 5 https://www.pacw. For this function the very first commissioning test is to check the secondary current transformer ground connection. Note: For the positive sequence current the phase shift is 150° clockwise (transformer vector group 5 times 30°). the directional 90% stator ground fault protection (ANSI 59GN) is the standard protective function. Ven > = 4.9 V) were used. The transformer ratio and the CT ratios are not considered in this diagram. and if the stability of the 90% stator ground fault protection function is ensured. the vector group and the transformation ratio of the unit transformer must be considered. 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. 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. the settings of a 2.5 MVA generator (IEE > = 4 mA. if the generator is connected via cable and the star point is accessible. 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. the physical behavior of the symmetrical components depends on the transformer vector group. 1/16/2015 5:29 PM .org/no-cache/issue/march_2013_issue/lessons_learned. In this case. 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. Also the different CT ratios will have an influence on the calculation of the test currents for side 1 and side 2... . Biographies Biography: Dr. If the comparison between the measured and the calculated values reveals potential malfunctions. because the cable-type transformers have different magnetizing characteristics. 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. ANSI 46 and ANSI 59GN were introduced. Primary test with a ground fault inside the protection zone: A ground electrode is connected to the generator terminal. 90% of the generator stator. Commissioning and Technical Consulting. The presented approaches are illustrated in a way that allows for their application to similarly configured protective functions in relays of completely different manufacturers. At present he is a Senior Consultant.-Ing.PAC World magazine : Generator Protection https://www. These solutions have shown that secondary testing of complex multifunctional relays is possible even without deactivating overlapping protective functions. Torsten Schierz worked for 7 years at the University of Applied Sciences Zittau/Görlitz in the area of research and teaching. the voltage regulator is deactivated and the trip command is blocked. The remaining test steps are the same as for the previous test. especially in calculation and commissioning. Torsten is member of the VDE (Federation of Electro Technology Electronics Information Technolog Home | Current Issue | Tutorials | White papers | Books | Tools | Events | Advertising | Classified | Forum Terms and Conditions of Use and Privacy Policy © PAC World . Conclusions In this article. as well as more than 24 years of experience in teaching electrical engineering.Last updated: 04 May 2013 5 of 5 1/16/2015 5:29 PM . He has more than 16 years of experience in power system and rotating machine protection. as shown in Figure 13. the flowing ground fault current (IEE) and the displacement voltage (Ven) are high enough to protect approx. With a ground fault which is located inside the protection zone. solutions for secondary and primary testing of the protective functions ANSI 90. Primary test with a ground fault outside the protection zone (stability test): A ground electrode is connected to the feeder grounding point. Furthermore.pacw. The next step is to measure the ground fault current (IEE) and the displacement voltage (Ven).. When the generator runs at nominal speed the terminal voltage must be increased manually to the rated generator voltage. Since 1996 he has been an employee of OMICRON electronics Deutschland GmbH in the business fields Training.org/no-cache/issue/march_2013_issue/lessons_learned. it was pointed out why the additional primary test of ANSI 59GN to verify the calculated settings is essential. Figure 14 displays the test for this example. The theoretical value ∆I = 0A is not possible. the settings need to be adapted based on the measured values. 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.